E.H2 Solutions

On 13 December, in an enthusiastic press release, the European Commission welcomed the political agreement reached on the same day between the European Parliament and the European Council on the Carbon Border Adjustment Mechanism (CBAM), whose principle is to tax the carbon content of imports. According to the Commission, this mechanism will be the Union’s reference tool for encouraging cleaner industrial production in third countries: “a European solution to a global problem!”

A reading of the European Council’s press release of the same day is much more discreet: this agreement is of a “provisional and conditional” nature, “the CBAM can only be formally adopted once the elements relevant to the CBAM have been resolved in other related dossiers” and that, in the first instance, it will be limited “to reporting obligations only”…

Thus, the establishment of this mechanism is closely linked to many of the initiatives and proposals made by the Commission when it presented its Green Deal on 14 July 2021. Therefore, a new (provisional) agreement between the Parliament and the Council was reached 5 days later, after 30 hours of negotiations. So, before detailing the CBAM mechanism, let’s look at the context in which this draft Regulation is set.

CBAM and its context

Its main context is the upward revision of the European ambition to reduce greenhouse gas emissions by 2030. This ambition is reflected in five highly interconnected texts[1], including a proposed revision of the ETS directive for the 2021-2030 phase (and the proposed CBAM regulation). These texts provide for:

• Raise the overall ambition of the ETS from a 55% reduction to 61%. (The agreement would be 62%).
• Extend the aviation ETS to the maritime sector.
• Create a new ETS for buildings and road transport. (This is to be in line with Germany… but with the introduction of some protection against excessive prices. According to the Council agreement, this price cannot exceed 45€/tCO2 or ~0,15€/l petrol or 8,33€/MWh, which is the level of impact of the French “carbon tax” which no longer says its name. German mechanism, French price!)
• Create the Social Climate Fund for the energy transition: the hoped-for antidote to the “yellow vests”, which could represent up to €86.7 billion.
• Strengthen the Innovation Fund (which could finance contracts for difference in the hydrogen sector, for example – the fund goes from 450 to 575 million allowances, ~€50bn).
• Revise the rules on free allocations, including a review of benchmarks and above all the phasing out of free allocations following the introduction of CBAM, with its total removal in 2035. This is the point that worries European manufacturers the most and this concern has been well conveyed by the Council. (Final consumers would also be entitled to be concerned).
• Maintain, as far as the Market Stability Reserve is concerned, the doubling of the thresholds and of the admission percentage until 2030 – i.e., admission rate: 24% threshold and minimum number of allowances to be placed in the reserve: 200 million allowances.

Furthermore, as the Council notes: “the financing of the administrative expenditure of the European Commission, which will assume many of the centralised administrative tasks related to the CBAM, will have to be decided in accordance with the annual EU budgetary procedure”.

The CBAM

The Commission’s proposal can be summarised as follows:

• The principle of the mechanism is to “create a historic tool to set a fair price on the carbon emitted during the production of carbon-intensive products entering the EU, and to encourage cleaner industrial production in third countries.”
• The scope of application are imports of the following sectors: cement, iron and steel, aluminium, fertilisers, electricity and hydrogen.
• The practical details are as follows:
• This mechanism will lead to the creation of new certificates that do not seem to be tradable. Their validity period is limited to one year and the surplus can be resold at the purchase price: CBAM Certificates. These certificates will be issued by Member States at the price set by the Commission (based on the prices of the latest auctions) and the proceeds will be “mostly” paid back to the Commission: “Although revenue generation is not an objective of the CBAM, it is expected to generate additional revenues, estimated for 2030 at more than €2.1 billion”. We should note that the issuance of these certificates will not be limited in their amount and its pricing fixing system is similar to that used by a consumer who could, ex post, buy electricity at the latest auctions prices.
• Each importer will have to calculate the intrinsic emissions of each product included in the applicable scope and surrender the corresponding number of certificates. This calculation will have to be done according to precise modalities and will be subject to verification.

To give this scheme a chance to be compliant with WTO (World Trade Organisation) rules, two provisions have been added:

• Article 31: “CBAM certificates to be surrendered […] shall be adjusted to correspond to the extent to which EU ETS allowances are allocated free of charge”.

This article does not make any reference to the inclusion of any CO2 compensation in the price of electricity for energy–intensive enterprises (cf. European Commission communication of 21 September 2020 on guidelines for certain State aid measures in the context of the greenhouse gas emission allowance trading scheme after 2021 (C [2020] 6400 final)).

• Article 9: “An approved registrant may request […] a reduction in the number of CBAM certificates to be surrendered in order to take account of the carbon price paid in the country of origin”.

Fortunately, any revenues potentially generated by the issuance of these certificates are not a CBAM objective; it seems sufficient that the exporting country taxes this export on the basis of the amount of emissions and the European CO2 price for the resulting revenues to remain in the country.

On the other hand, for the calculation of the intrinsic emissions of electricity, this regulation is more generous for non-EU countries than for EU countries: the cost of the ETS (via CBAM certificates) will only apply to the average emissions factor, whereas in Europe the price of electricity includes a carbon tax via the ETS in line with the marginal emissions factor. For example, for France, this emissions factor is estimated at 0.51t/MWh (Decree no. 2022-1591 of 20 December 2022, art. 1) whereas the average emissions factor is about 10 times lower.

Conclusion

On 18 April 2023, the European Parliament adopted the five texts concerned by the 18 December agreement. These texts were subsequently validated by the Council on Tuesday 24 April. The way now seems clear for the CBAM, which will require a certain number of implementing texts. Let us hope that this mechanism will be something other than a magic formula opening Europe’s doors to carbon-based or even delocalised products, but rather the protection of a strong and clean European industry!

Philippe Boulanger

Hydrogen, the most widespread atom in the universe, cannot claim to be a story in itself. The notoriety of this atom (or molecule: dihydrogen, H2, is commonly known as hydrogen) will exempt us from harping on about Captain Nemo’s vision of Jules Vernes’ Mysterious Island, or from plunging back into the debate on the advantages of lighter-than-air versus heavier-than-air for air transport (with its champion, Count Ferdinand von Zeppelin), or even from recalling more recent broken promises. And yet, with the announcement of the German, European and French plans (among others), it seems that with hydrogen, there is finally “something new in the state of energy”. On 17 February last, by ordinance, a new book (the 8th) was even dedicated to it in the French Energy Code. Is this new enthusiasm not rooted in the contrasting – even paradoxical – properties of hydrogen itself? Today, expectations are proportional to the resources announced (€7 billion for France alone). Success will certainly depend on a good mastery of these paradoxes.

Let’s go back over the main strategic plans around hydrogen

With the “Hulot” plan in 2018, France was the first to lay the foundations for the change of scale by setting out the objectives for 2020 in the PPE (Multiannual Energy Plan) decrees:

• Rate of decarbonized hydrogen in industrial hydrogen in 2023: 10% (~100.000t/year)
• Rate of decarbonized hydrogen in industrial hydrogen in 2028: 20% to 40% (~200,000 to 400,000t/year)

The announcement of the “National Strategy (Plan??) for the Development of Decarbonized Hydrogen in France” on 8/9/2020 not only confirmed the trajectory – 6.5GW of electrolysis in 2030 – but also budgeted financial resources: €7 billion including €3.4 billion for 2020-2023.

Finally, with the publication of the ordinance of 17/2/21 (which was provided for in the Climate Energy Law of 8/11/2019), a legal framework is being put in place; particularly by providing for a support mechanism for electrolysis production via calls for tenders (support in addition to remuneration and/or CAPEX).

Other European countries quickly followed suit by publishing ever more ambitious hydrogen plans, following the example of Germany in June 2020: 38 measures, €7 billion allocated to the promotion of hydrogen in Germany + €2 billion for international partnerships on hydrogen.

Obviously, at a European level, we are still changing scale: with the publication by the Commission on 8/7/2020 of “a hydrogen strategy for a climate-neutral Europe”, the objectives are moving towards:

• 6 GW electrolyser capacity by 2024
• 40 GW electrolyser capacity by2030

But hydrogen remains a paradoxical molecule

The high hopes of hydrogen for the transport sector (just like its too often postponed promises) are linked to its different energy density measurement: one of the highest densities per kg (more than 3 times the energy density of oil) but one of the lowest in volume (less than one third than that of natural gas), which obliges us to consider important compression levels – up to 750 bar – for mobility purposes.

Today, its most critical paradox lies in its impact on climate. Similar to electricity, hydrogen is a zero-emission energy carrier: its “combustion” only produces water. If the energy used for its production is clean, hydrogen will be clean (as is the case of hydrogen produced by electrolysis of water from renewable electricity). It is on this promise that the various hydrogen strategies have been developed as an essential technology for achieving carbon neutrality by 2050. But hydrogen can also achieve the worst carbon footprint per unit of energy: up to almost 1.5tCO2eq per MWh (in the case of electrolysis using coal-fired electricity).

At a European level, this risk does not seem to worry DG Clima which, looking ahead, is ready to deem as ‘clean’ any electricity drawn from the network since it will have to be clean in the long term. DG Comp, on the other hand, before approving the support mechanisms needed for the hydrogen sector (billions budgeted by the national plans) would like to know how to ensure at any given time that the H2 produced by electrolysis does indeed lead to the promised reduction in emissions.

No matter how boring this question may be, the credibility of the sector will depend on the quality of the answer.

An abundance of answers is currently under discussion: dedicated line / long term contract / PPAs / time correlation / geographical correlation, with renewable / low carbon / additional / subsidized / non-subsidized / certified by guarantees of origin / block-chain technology… and the sector is holding its breath waiting for clear rules.

In France, the electricity mix is already largely decarbonised, between the closure of the last coal-fired power plants scheduled for 2022, stable (or even decreasing) consumption and a Multiannual Energy Plan which foresees in its medium scenario more than 57 GW of additional solar and wind power capacity between 2019 and 2028. An “off-peak base ” operating mode (between 7500 and 8000 hours of annual operation and the capacity mechanism clearly indicates the hours to be avoided) should therefore satisfy the Commission.

In fact, if we extrapolate the monotone of solar + wind energy production in 2019 from this additional capacity, which represents more than 260% of the capacity in 2019, we obtain the following capacity values :

Thus, approx. 5GW of “new” renewable hydrogen will be available for nearly 8000 hours by 2028 and the 6.5GW planned for 2030 will also be able to claim the quality of renewable hydrogen.

The sector is waiting for the publication of the “Delegated Act” of the Directive on the promotion of renewable energies (RED 2) which must define the conditions under which hydrogen produced by electricity drawn from the network can be included in the national objectives for the share of renewable energies in the transport sector (objective of 14% by 2030). The publication of this Delegated Act by the European Commission is planned for the end of 2021 and is likely to set a precedent for the qualification of hydrogen produced by electrolysis, regardless of its final use. Therefore, it is not our intention to close the debate here, but rather hope that these projections will contribute to the current enthusiasm for the development of renewable and low-carbon hydrogen!

Philippe Boulanger

It is still France which, through its tax inventiveness, is at the origin of this trend. On 1 January 2016, the CSPE (Contribution to the Public Electricity Service) was replaced by the TICFE (Domestic Tax on the Final Consumption of Electricity). Many said it was “six of one and half a dozen of the other”, but this was neglecting an important feature of the TICFE: it does not increase! And this, even when public service charges have been increased by more than 40% between 2016 and 2021.

Today, with the reform of the German EEG (Erneuerbare-Energien-Gesetz – Renewable Energy  Act), we are witnessing a real change of scale: on 15 October last, the Bundesnetzagentur (BNetzA) (Federal Network Agency for Electricity, Gas, Telecommunications, Post and Railway) announced this good news to German consumers: the EEG contribution (EEG Umlage) for 2021 will drop to 65 €/MWh. Another consequence of this announcement: the federal budget will contribute with €10.8 billion to the development of renewable energies (this contribution alone represents almost twice the French support to renewable energies development in France).

Is Covid to take the blame, again?

Before analysing the scope of these announcements in more detail, we would like to go back over the history of the respective developments of the CSPE – TICFE and the EEG Umlage since their creation (2000 in Germany, 2002 in France).

We have represented their evolution, in the same graph, as an approximation of the cost of the support to renewable energies. For Germany, the special contribution to offshore wind energy should be added (+4,16€/MWh), while for France the support to renewable energies only represents about 60% of the public service charges considered in the CSPE.

Does the relative stability observed in recent years really reflect an inflection in the cost of supporting renewable energies?

In France, the answer is clearly no: and the PPE (Multiannual Energy Plan) even forecasts an increase of these costs by more than 30%, to peak beyond €8 billion in 2025. Formerly a “Contribution”, the CSPE has become a “Tax”: the TICFE, fixed by the finance laws (the carbon tax was supposed to complete the budget balance, but its evolution has been stopped since the yellow jackets crisis).

It is interesting to note that the Energy Regulation Commission, which was in charge of determining the amount of this CSPE – Contribution to the Public Electricity Service – in line with the charges to be covered, continues to carry out the CSPE calculation exercise… but this acronym now has a new meaning: CSPE = CHARGE of Public Electricity Service!

Let us return to the German case. The idea of the new law on renewable energies (EEG) (which has been approved by the cabinet but not yet voted) is similar to the French idea put in place by France in 2016: the contribution is transformed into a tax that is no longer earmarked for dedicated expenditure (France had initially set up a “Special Allocation Account”), with the budget to be balanced by future revenues obtained from the new CO2 tax included under this same law.

It so happened that, without waiting for this law to come into force, the Bundesnetzagentur, together with the Ministry for Economic Affairs and Energy, set the amount at the level provided for by the law – €65/MWh – by letting the federal budget subsidise this contribution (which has not yet been transposed into a tax) to the tune of almost €11 billion.

Without this aid, the amount of the surcharge and, therefore, the amount of the electricity prices, would have reached 96.51 c€/MWh for 2021, thus marking a new clear upward trend in the EEG Umlage.

In its communication, the Ministry clearly attributes the responsibility for this slippage to the health crisis we are currently going through:

This evolution of the cost of financing renewable energies is thus put under the account of the coronavirus crisis, which has weighed on demand and on wholesale electricity prices (renewable production not having been affected by the crisis), and the necessary money will come from the “Corona-Konjunkturpaket” and its 130 billion € which, like the 100 billion € of the “France Relance” plan, are largely financed by the State debt.

What developments are to be expected for the future?

France foresees, in its Programmation Pluriannuelle de l’Energie (PPE) (Multiannual Energy Plan), that the competitiveness of renewable energies will lead to a very significant drop in the need for support for these energies: less than €4 billion in 2035. Germany, for its part, is confident that the new EEG law will pave the way for a post-support mechanism era, a “paradigma shift”.

In fact, what happened this year with the Covid 19 crisis is a drop in demand and, therefore, a drop in the carbon marginality of the electricity mix (wind, photovoltaic and hydraulic production are not experiencing a health crisis). With the French (PPE), German (EEG 2020) and European (Green Deal – a revision of the ambitions of the Directive on renewable energies) ambitions, what we have experienced is, in fact, just some anticipation of what is foreseen by these policies: a drop in carbon marginality in the shaping of electricity prices in the market.

It seems to us that the inability of the “Energy Only” market to remunerate the full costs of power generation is once again largely underestimated. On the other hand, what is not underestimated by politicians, even in Germany, is the difficulty of showing the burden of renewable energies on electricity bills in a transparent manner!

Philippe Boulanger

3 December 2020

On Thursday, May 28^th, UNIPER announced its decision to bring back Irsching 4 & 5 CCGT power plants in Bavaria to the market as of October 1^st, 2020. Since these are the two most modern (built in 2010 and 2011, respectively) and most efficient gas power plants in Germany, with yields of 60.4% for Irsching 4 (561 MW) and 59.7% (846 MW) for Irsching 5, this announcement certainly poses the question: why were these power plants stopped?

As a matter of fact, this anomaly, this scandal, seeing as these power plants are in a country where CO2 emissions derived from the electricity sector exceeded 250 million tonnes in 2019, is as old as these machines, which have only operated sporadically and under various mechanisms (the so-called grid reserve regulation most of the time) since their commissioning ten years ago. The most recent precedent, an announcement which dates back to September 2019, called once more for their mothballing from October 2020. This situation arose due to complex economic considerations linked with the operation of the market (Clean Spark Spread, Clean Dark Spread, ETS, etc.); however, in view of the ambitions and budget announced as part of the European Green Deal, are these lines of argument still relevant and genuinely admissible?

Let’s take a closer look at the year 2019. According to public data from the German regulator (smard.de), production from the Irsching 4 & 5 power plants was practically non-existent (with 7 and 33 EOH, respectively):

It is well known that the ‘switch’ from coal to gas power plants, with the development of renewable energies, is the most powerful lever for reducing greenhouse gas emissions. The United States is the best illustration of this.

Thus, let us dream, the Irshing power plant had been in a position to avoid some coal production in Germany for the year 2019, with the following impact:

These units would have been operating around 3260h (average duration of use for German coal power plants in 2018) and would have saved nearly 3 million tonnes of CO2. Admittedly, these 3Mt are modest if compared to the 250Mt emitted by the German electricity sector (~1%), but they do, in fact, represent over 15% if compared to emissions from the French electricity sector.

While we’re on the subject, and were we to be even more ambitious, these  two units would have just as easily been able to avoid lignite production, given that their average period of use is nearly double that of coal (6490h on average in 2018); thus, the environmental impact would have been doubled (6Mt CO2), representing more than 10% of the reduction effort remaining to be completed in Germany in order to achieve the country´s 2020 target.

But, of course, in an economic system where neither the environment nor resources are taken into consideration, these production modes would have led to additional costs and as dealing with imported raw materials, would have also affected the German foreign trade balance.

In the case of an operation substituting coal plants (3260h), the added cost (based on the 2019 average future prices in 2018) would have been in the range of €52 million – compared with a trade surplus of $255 billion (0.02%). In the case of an operation substituting lignite power plants, the added cost would have doubled, but it’s the full cost of gas which would have affected the foreign trade balance, that being €350 million out of €250 billion (1.4%). Is such impact reasonable? Is it tolerable? In light of the situation in the United Kingdom (trade deficit of $223 billion) and France (trade deficit of $81 billion), it seems to us the answer is yes.

Let us translate these calculations in term of CO2 abatement costs, as this element is supposed to be taken into consideration in the EU Emissions Trading System (EU ETS), which seems to have, once again, demonstrated its inefficiency in this instance.

By using the average cost of gas and coal prices for the 2019 supply year recorded in 2018, this average additional cost is in the range of €17-18 per tonne of CO2 (whereas, as a matter of fact, the average EUA price in 2018 was €15!).

Despite the competitiveness of this path towards reducing emissions, a new 300 MW generation unit will be built on the same site (Irsching 6) for 2022… and will be solely dedicated to the network operator (TenneT) to ensure the stability of the system (consequently not preventing coal-fired power plants from emitting the million tonnes of CO2 that Irsching 6 could have been in a position to avoid annually).

Lastly, the coronavirus crisis is rearranging everything: the price of natural gas is collapsing (as well as that of coal, incidentally), the EUA price remains,, strangely enough, near its highest levels, Irsching will resume service and, against all odds (see our article from July 2018[1]), even Germany is well on its way towards achieving its ambitious 2020 greenhouse gas emissions reduction target (a 40% reduction compared to 1990)…

Once again, at the end of the day, Germany wins!

Philippe Boulanger

[1] http://eh2solutions.com/2018/07

Although the common belief now is that the debate on the post-ARENH system is as old as the ARENH itself, we must still recognise that the question has taken on a new dimension since the oft-mentioned glass ceiling of 100TWh was shattered (since the 2019 supply year). Further, we need to acknowledge that, following the ‘yellow vest’ crisis, the most recent Energy and Climate Law of 8 November made it possible to raise this ceiling to 150TWh and reaffirmed in the energy code that this ceiling is established ‘in order to contribute to the stability of prices for the end consumer.’ The government, which, due to ‘fear of Brussels’ and with a certain degree of illegality, did not raise this ceiling, therefore broke ground on the Nouvelle Régulation du Nucléaire Existant (NoRéNE) [New Regulation on Existing Nuclear Power] with an online consultation that opened on 17 January.

While the debates seem to have started with cool heads prevailing, the coronavirus health crisis is turning up the heat.

Let’s briefly look back at the proposed mechanism presented in the consultation document:

These principles were meant to be a response to a road map with the aim of  ‘guaranteeing that all consumers are protected against rising market prices beyond 2025 by allowing them to enjoy the competitive advantage relating to the investment made in the historic nuclear fleet, all while giving EDF the financial ability to ensure the economic sustainability of its means of production in order to meet the needs of the PPE [multi-year energy programme] under low-price scenarios’.

In terms of their economic impact on consumers, these positions could have been summed up with the slogan: ‘ARENH for all! Yes, but it’s not optional’.

When it comes to implementing rules, we encountered a combination of legal arrangements that allowed us to (with nostalgia?) revisit some of the significant mechanisms which interspersed the first twenty years of the opening of the energy markets to competition (i.e. the past twenty years):

• Nuclear power can be placed on the market through auctions that could be reminiscent of those held between 2001 and 2003.
• Financial compensation for suppliers could recall the TaRTAM mechanism (2006)
• The level of compensation is also drawn quite directly from the complementary remuneration mechanisms implemented in 2015.
• A new price corridor is being introduced. If this idea seems to be somehow favourable in Brussels (and in Germany: there are some references to the corridor in their future carbon tax), it is far from being unanimous (especially with the corridor width of €6/MWh as presented) among the players, some of whom, such as the UFE [French Electricity Union], are wondering about ‘the relevance of implementing a price corridor as opposed to a fixed price level, particularly with regards to the objective of price stability’.
• Volumes could be determined ex post, based on the current ARENH rules (average power in summer off-peak hours adjusted by a calibration coefficient).

The only major question that still seemed to be outstanding was that of the price, or prices if we’re talking about the floor and the ceiling (remember that the decree establishing the methodology never saw the light of day), and some preventive criticism have already been raised on whether the costs of Flamanville 3 would be taken into account.

But today, in the midst of the coronavirus crisis, it’s the volume-capacity issue that is now at the heart of the debate, while trajectories for consumption growth (assumed to be flat) and production by sector seem to be firmly established (although a certain number of players underlined that the price issue should also factor in the capacity value embedded in the ARENH on the capacity guarantees market).

Faced with the sharp decline of consumer numbers, alternative suppliers were quick to request that the force majeure clause be applied and referred the Conseil d’État to the CRE [Energy Regulatory Commission]’s refusal to share with RTE [the French Transport System Operator] the changes in ARENH volumes delivered by EDF to those suppliers who had decided to activate this force majeure clause. Following the CRE’s deliberation on 26 March and a decision by the Conseil d’État on 18 April, the Tribunal de Commerce [Commercial Court] will certainly be the one to have the last word on the merits.

For its part, in its press release of 16 April, EDF revised its annual estimate of nuclear power production to factor in the health crisis. This announcement was more or less foreseeable and expected. However, while players were planning for a drop in production in 2020 (now re-estimated at 300TWh), EDF’s new target is lower than anticipated, which is also just as true for the forecasts for the years 2021 and 2022 (estimated at between 330 and 360 TWh).

Of course, these volume-capacity effects are echoed in market prices: Brent has fallen from €60 to €20/bbl, spot gas prices are down to €5/MWh, EUAs (‘CO2’) prices dropped from €25 to €16 before bouncing back up to €21, and Calendar 2021 baseload electricity saw fluctuations of more than €5 in less than a month (the steep rises also following EDF’s 16 April press release).

Although EDF, in another press release dated 21 April, welcomed the decision of the Conseil d’Etat, the French operator of nuclear power plants also took the opportunity to reassert the need for a regulatory reform that allows for a fair remuneration of existing nuclear power production and, by contributing to climate preservation, for being a competitor in the energy transition.

The construction project was just beginning, and it shouldn’t be reduced to the mere introduction of new acronyms such as NoRéNE and SIEG (Services of General Economic Interest).

Philippe Boulanger

Less white than white, we (and comedian Coluche) suspect, must be light grey. We know what the colour green is…it’s green! But greener than green? That’s a new colour – it was just released!

I’m not looking to recite Coluche’s legendary sketch on advertising, but I couldn’t help making a reference to my favourite comedian when I heard the announcement made on 18 October that ‘Seven independent producers are launching the Électricité Verte d’Origine Contrôlée [Controlled Designation of Green Electricity Origin]’, made in the presence of Elisabeth Borne, Minister for the Ecological and Solidarity Transition, and Brune Poirson, Secretary of State to the Minister of the Ecological and Solidarity Transition.

It is true that green electricity offers have been quite common in France since the markets were opened up, and that, among all of these ‘no added cost’ green offers, watching suspicions and accusations arise that they are not contributing to the energy transition have become just as common – that the pure and simple purpose is that of ‘greenwashing’.

Let’s try to get an idea of what colour electricity is.

Electricity, like natural gas, can be produced using renewable sources and therefore can have a ‘green’ origin. But as soon as renewable-sourced energies are injected into the different networks it is no longer possible to tell them apart from those originating from a ‘classic’ production method.

This means that regulation is the key to defining the traceability of renewable electricity, through the implementation of Guarantees of Origin (GO):

• At European level, through European Union Directives
  • 2009/28/EC (Article 15)
  • as well as its ‘revision’, applicable since 01/01/2021, 2018/2001 (Article 19)
• At French level, through the Energy Code
  • On the Legislative side: Articles L314-14 to L314-17
  • On the Regulatory side: Articles R314-53 to R314-67

Thus, the French regulatory body – the Energy Regulatory Commission (CRE) – offers the following definition:

 ‘“Green” electricity refers to electricity produced from renewable energy sources (hydropower, wind, solar, geothermal power, etc.) or by cogeneration. Green offers provide electricity of renewable origin, certified by guarantees of origin.’

RTE (the French Transmission System Operator), for its part, elaborates on the guarantees of origin mechanism as follows:

 ‘The guarantees of origin system allow for electricity generation to be labelled in order to show the end customer that a portion or a set quantity of the electricity is of renewable origin or produced through cogeneration.

In order to transpose the new requirements of Directive 2009/28/EC on energy from renewable sources, Decree No. 2012-62 of 20 January 2012 was enacted to amend Decree No. 2006-1118 of 5 September 2006 establishing the guarantees of origin framework.

In accordance with this Decree, following a ‘call for tenders’ procedure, Powernext was appointed the responsible party for issuing and monitoring guarantees of origin from 1 May 2013.

For all information pertaining guarantees of origin, RTE invites you to visit Powernext’s “guarantees of origin” page.’

Thus, a supplier can guarantee 100% ‘green’ energy to its customer by using / cancelling out a number of guarantees of origin in an amount equal to this very customer’s consumption in MWh.

Still with me? ‘Keep moving – there’s nothing here to see!’ as the dearly missed Coluche would say.

Apparently, some problems arose in that a controlled designation label (by whom, incidentally? As of right now, the Institut National de l’Origine et de Qualité [French National Institute of Origin and Quality], a national public administrative body which manages, among other labels, AOCs and AOPs, doesn’t seem to be in charge of monitoring this new label) could be corrected through two types of commitment:

1. Investing exclusively in renewable sources of energy production;
2. Accelerating the construction and development of new renewable electricity generation plants in France.

Let’s forget the first commitment, which conveys a certain corporatist attitude as it seeks, somewhat heavily, to eliminate any company that would take the liberty of doing anything other than investing in renewable sources of energy production (this commitment would therefore not only exclude EDF and Engie).

Let’s take a closer look at the second commitment, which involves two aspects:

• Renewable energy is produced in France (thus, this certificate is perhaps ill-advised for consumers who consider wind turbines to be incompatible with the French countryside but are, on the other hand, in favour of renewable energy…in other places).
• The use of these guarantees would provide financial contributions to the building and development of new power plants. In this respect, ‘it is important’, as the European Directive reminds us, ‘to distinguish between green certificates used for support schemes and guarantees of origin,’ and to remember that, in France, the development of renewable energies is essentially
  • defined by the Programmation Pluriannuelle d’Energie [multi-year energy program] (PPE),
  • implemented by the ‘calls for tender’ made by the CRE (Energy Regulatory Commission)
  • and financed via the special ‘energy transition’ allocation fund (CAS), an account whose funds are mostly derived from the CSPE [Contribution to the Public Electricity Service tax] paid by the French consumer, in an amount up to €22.5/MWh (excluding VAT), regardless of the colour of the electricity they use.

For the first time, guarantees of origin for French facilities benefiting from a support scheme were put up for auction by Powernext on 18 September 2019, and over 4.4 TWh of GOs were sold at an average price of €0.42/MWh. This means that slightly less than €2M (or ~€12M if we extrapolate to the six auctions) will be contributing to the CAS. This is in comparison with €6bn, the current cost of supporting renewables…

Now we understand a bit better why these guarantees can be offered to consumers at no added cost by the supplier promoting them!

The current auction price does certainly not, in any way, anticipate the prices of the next auctions, nor the emergence of a new paradigm that will contribute to rendering renewable energy support obsolete. In the meantime, such an initiative will no doubt make its contribution to the current colour blindness surrounding electricity and reminds us that, rather than an ‘AOC[1]‘, the European scale of the Guarantees of Origin system in force bestows upon them an actual ‘AOP[2]’.

[1] AOC: Appellation d’origine contrôlée [Controlled designation of origin]ː this protects the naming of products in France

[2] AOP: Appellation d’origine protégée [Protected designation of origin]: European label that protects the name of a product throughout the European Union

Philippe Boulanger

For some time now, the world of energy has been watching the emergence of a new reference acronym: ‘PPA’. These three letters, often complemented with attributes such as ‘Corporate’, ‘Renewable’ or even ‘Long-Term’, seek to represent the future of the competitive development of carbon-free energies worldwide.

However, our understanding of these three words, ‘Power Purchase Agreement’, is that this kind of contract designates the large family of contracts where at least one of the parties purchases electricity. Therefore, we are a bit perplexed when we read in the specialized energy press that some problems could arise when developing PPAs in France (even nuclear power is often considered as the one to blame).

Apparently, when Jean-Louis Bal, Chairman of the Renewable Energy Association, says ‘In France, we have a real PPA competitiveness problem’, and despite the fact that many consumers in France can purchase electricity at prices that are among the lowest in Europe, it means that, in this context, PPA does not only refer to electricity purchase agreements, but to a more specific contractual form.

In light of this misunderstanding, it seems clear that some work needs to be done to define this term.

We have found an interesting definition in Directive (EU) 2018/2001 of the European Parliament and of the Council of 11 December 2018 on the promotion of the use of energy from renewable sources (Article 2):

Renewables power purchase agreement: a contract under which a natural or legal person agrees to purchase renewable electricity directly from an electricity producer;

Therefore, this definition  does not only eliminate any contract with an electricity end customer (only a supplier holding ad-hoc ministerial authorisation may sell electricity to an end customer), but also the famous ‘Exceltium’ contract – one which is nonetheless remarkable, representing a volume of 148 TWh over a period of 24 years – but that involves nuclear electricity…

On the other hand, all of EDF facilities under obligation of purchase contracts, or facilities under additional remuneration contracts, do fall under this definition, along with a vast amount of types of supply contracts.

Another relevant and more targeted definition is given to us by Voltalia in its press release of 26 June 2019 announcing the signature of the first very long-term direct power purchase agreement for approx.  150MW in France:

Power Purchase Agreement:

a contract under which a company agrees to purchase electricity directly from a renewable energy producer’s plant, either solar or wind, especially built for this purpose, and made possible by the extended term of the agreement.

Here, the restriction of this definition to only solar or wind power plants excludes, perhaps arbitrarily, biomass, biogas and hydropower (and, of course, nuclear power).

In fact, these definitions do not fully reflect the underlying spirit of this scheme, that being:

• Competitiveness in terms of market prices
• The lack of public support or subsidies (State Aid)

Competitiveness: actually, this can only be measured objectively along the liquid market horizon, that being three years, and such visibility is not yet available for the capacity component (certainly weak when it comes to solar power). The long-term vision, for its part, will very much depend on the ability of solar development to erase the still-persistent marginality of fossil generation tools during sunny hours. Even when taking into account that the evaluation of the sale of solar energy on the markets is currently showing a premium with regards to average prices (in the region of €2/MWh), the prices of the latest calls for tenders organised by the French Energy Regulatory Commission (CRE) still reveal a gap in competitiveness with respect to market prices: last August, the average price for successful tenderers for large solar farm facilities was €59.5/MWh. There may be some tenderers who, for the most part, will eventually contribute to the ‘energy transition’ special allocation fund (CAS), rather than receive additional remuneration. As debtors of the Contribution au Service Public de l’Electricité[1] (CSPE), we are grateful to them… while still noting that the multi-year energy programme (PPE) does indeed provide for a global increase in the costs for supporting renewable energies over its period (up to 2028).

State Aid: if the mechanism of ‘PPAs’ resulting from CRE calls for tenders is indeed considered as state aid, this aid is governed by European regulations and guidelines (Commission authorisation SA.46552 dated 29/09/2017) which impose constraints that may weigh on their competitiveness (treatment of negative prices, balancing responsibility, contractual duration). These constraints don’t necessarily exist in the same form in private ‘PPAs’.

Whatever the case may be, the PPE essentially (if not exclusively) provides for the development of renewable energies through CRE calls for tenders and it doesn’t seem likely that another State body should be in charge of supplementing this deployment with parallel procedures. In this context, the emergence of private initiatives, which would again  leave investment decisions resting solely on the shoulders of market mechanisms (‘the world of yesterday’, as EDF Chairman Jean-Bernard Levy recently referred to) could represent a ‘Back to the Future’ situation that is as sympathetic as it is unexpected.

[1] Public service levy on electricity paid by final consumers to cover the over cost of ENR.

Philippe Boulanger

In the beginning, it was only meant to be a bill for correcting a minor issue – practically a typo or oversight on the part of the legislator.

Faced with the calendar rectified by reality (as long as the opposite wasn’t true), François de Rugy, Minister of the Ecological and Solidary Transition, confirmed before the senators last October that the 2015 Green Growth Act (LTECV) would be ‘slightly’ altered in order to take into account the postponement of the objective of reducing nuclear power’s share of the energy mix at 50%.

But enacting legislation on energy in general and on nuclear power in particular often results in opening a Pandora’s Box. Between the Yellow Vests crisis on one side and EDF’s financial situation on the other, the question of Regulated Selling Prices (TRVs) for electricity and therefore of Regulated Access to Historic Nuclear Electricity (ARENH) didn’t take long to invite itself into the debate.

As a matter of fact, it’s the government who first took action in order to neutralise the impact of the rise in TRVs by 5.9% on the 1st of June:

On the same day that the draft legislation was presented to the Council of Ministers, 30 April, François de Rugy explained on BFMTV that a new method for calculating regulated electricity prices would be implemented in 2020. ‘I’m not resigned to this calculation method that was passed twice in Parliament under a right-wing majority in 2010 and a left-wing majority in 2015,’ declared the Minister of the Ecological and Solidary Transition, ‘the current calculation method doesn’t reflect the costs of producing nuclear energy. In the future Energy and Climate law, I suggest we change this calculation method. It will be applied from 2020 and will adhere more closely to production costs,’ underscored François de Rugy.

For his part, Jean-Bernard Levy, on the day before the increase was applied, was calling for those involved to ‘consider lowering taxes on electricity, since it does not emit carbon dioxide.’ ‘I remind you that, when we pay an electricity bill, we’re paying more than one-third in taxes.’ It’s like paying VAT at a rate of 55%,’ explained the Chief Executive of EDF, while acknowledging that ‘in other countries, there are high taxes on electricity more or less everywhere’.

And this intervention provided the minister with the opportunity to press on a few sore spots: ‘We won’t improve EDF’s situation by rejecting our responsibilities on taxes,’ responded François de Rugy, adding:

• ‘EDF is in debt because it can’t cover its production costs with its revenues’;
• ‘Every year, the Court of Auditors condemns the fact that EDF’s employees only pay 10% of the typical price for their electricity.’

Even the Constitutional Council gave a contribution: although the end of the regulated gas price had been accepted, the Constitutional Council censored the articles of the PACTE law [Action Plan for Business Growth and Transformation] regarding this termination. This measure, considered to be a ‘legislative rider’, will naturally be reinstated, via an amendment in the energy and climate law.

Finally, the government lay down its own ARENH amendment (amendment no. CE357) on 14 June.

This amendment proposes that the cap for the ARENH ceiling be set at 150 TWh from 2020 (the ceiling is, strictly speaking, set by a decision within the limits of the cap for the ceiling set by the law).

But this amendment also stipulates opening up the possibility for the Government to modify the ARENH price by a decision in order to take into account the financial impact of the ceiling increase on EDF, by extending the validity of the dispensation upon the system’s implementation through Article L337-16. Of course, ‘the evolution of these parameters and its calendar will be put to discussion between the Government and the European Commission’…

therefore, the draft legislation presented to the Council of Ministers on 30 April last will eventually not be limited to:

In Article L. 100-4, section I, 5° of the Energy Code, the words: ‘reducing nuclear power’s share of electricity production to 50% by 2025’ are replaced by the words: ‘Reducing nuclear power’s share of electricity production to 50% by 2035′.

And the next law is already being prepared: while presenting its amendment, the government mentioned the preparation of a new regulation that will succeed the ARENH, and could even replace it before its established 2025 end date, with the aim of ‘guaranteeing that consumers are protected against rising market prices beyond 2025 by allowing them to enjoy the competitive advantage related to the investment made in the historic nuclear fleet, all while giving EDF the financial ability to ensure its production fleet’s economic sustainability, even in low-price scenarios.’

Stay tuned…

Philippe Boulanger

Every day, energy market analysts comment, systematically and seemingly without any particular rules, on market movements and outlooks (bullish, bearish or stable) with respect to the expected BREXIT type (soft, hard, something in between, etc.) Thus, for example, any negative development on the outlook of the UK leaving with a deal will explain the bullish (or bearish or stable) progression of the day. The same is true for any lack of information or new outlook on this subject: the uncertainty surrounding Brexit will justify the bearish (or bullish or stable) trend of the day!

As we write this, the fateful date of 29 March has passed without the (unpleasant) drama arriving at its conclusion, and everything leads us to believe that many ‘series’ are already in the works. Must we, for all such reasons, delay our analysis of Brexit’s impact on energy markets even further? Here, we’ve taken the liberty of sharing a few reflections with you:

First of all, let’s look at what isn’t changing, or isn’t changing much:

• Customs tariffs:

By leaving the European Union, the United Kingdom will also leave the single market. This switch-over should only have slight consequences for energy markets because both electricity, oil and natural gas are not taxed as part of the WTO agreements. The essentials remain the same!

• Interconnections:

RTE [the French Electricity Transmission Network] and the CRE [French Energy Regulatory Commission] have taken the lead: from 30 March, all capacity allocations are explicit. In practice, this change will only concern daily allocations (other allocations already being made explicit). A change that should therefore only generate a slight (imperceptible) de-optimisation, which will allow for the remuneration of an additional trading activity.

The ETS (European Trading Scheme of carbon emissions quotas), for its part, requires some particular attention, as always:

• Strangely enough, the plan for an exit deal envisaged keeping the United Kingdom in the ETS. This would therefore not be the case in the event of a no-deal Brexit. This uncertainty therefore creates great volatility, as the system allows for ‘banking’ (placing allocations in reserve) and ‘borrowing’ (using future allocations), the latter option having been prohibited for British producers with the 2019 allocation freeze. The quota redeeming date for 2018 emissions is 30 April 2019. Should the UK leave the ETS, the banking effect will have bearish results, while the impossibility of borrowing will have a bullish effect (and vice versa, should the UK remain in the ETS. Or perhaps not!)
• Apparently, while 30 April appears at first to be beyond the fateful date, market actors don’t seem to be envisaging the radical scenario in which industry players would decide not to redeem the 2018 quotas. This would certainly contravene existing agreements, but… (the existing framework also permitted borrowing).

Let us now consider the effects on EU policies, since, in the end, this is where the consequences could be even larger. After leaving the European Union, the United Kingdom will no longer carry any weight in the negotiations for building the internal energy market, and Europe will therefore certainly lose a pragmatic and realistic (not ideological) approach to deregulating energy markets, as illustrated in this brief historical reminder:

• Though Great Britain was the pioneer of the obligatory pool system (early 1990s), it didn’t hesitate to abolish it in 2001, judging it to be too manipulable.
• Once it was determined that the ETS did not favour electricity generation using the more environmentally friendly (and often domestic) natural gas over coal (always imported), a floor price for CO2 was established in 2013.
• Generalisation of contracts for difference for low-carbon electricity generation.
• Commitment to nuclear energy: Hinkley Point negotiated in 2014-2015 with a contract for difference.
• Pragmatic (and controversial) policy in favour of shale gas.
• Capacity mechanism launched in 2014.

Indeed, the capacity mechanism question will allow the European Union to bring back good memories of the British: whereas the implementation of this mechanism in the United Kingdom raised no objections from the European Commission on 23 July 2014, the General Court of the European Union, in a ruling dated 15 November 2018 (and with an acute sense of timing), reversed the Commission’s decision not to oppose the aid scheme establishing a capacity mechanism in the UK.

Stay tuned… (the Commission opened an in-depth inquest into the UK’s capacity mechanism scheme on 21 February 2019) but, in the meantime, the European Commission continues to label capacity mechanisms as subsidies, the British capacity mechanism has been halted and, as a result, security of supply in the United Kingdom is compromised…

Philippe Boulanger

While the debate surrounding the ‘yellow vests’ seemed to focus primarily on the taxation of hydrocarbons – CO2-emitting fossil fuels -, the issue of the price of electricity – which, in France, rightfully crystallises around the evolution of regulated tariffs, as virtually all offers to individuals are indexed there – is beginning to gain momentum. It’s certainly not the prospect of having a ‘small’ law on energy at the start of 2019 that is going to put minds at ease. As is well known to all, electricity in France is largely low-carbon (between 50 and 100kg of CO2 per MWh on average currently), and French electricity consumers will be inclined to believe themselves shielded from any carbon price effects. Faced with the rumour, doubt sets in, and finally, the question is raised: does the cost of CO2 affect electricity prices? The answer is yes. A residential customer in France pays for CO2 emissions at a price equivalent to €92.80/Tn.

However, this time, the cause is neither the French CO2 tax, the Climate-Energy Contribution (CCE) – whose value according to the French Finance Law of 2018 is €44.6/Tn of CO2 in 2018, expected to be €55/Tn of CO2 in 2019 and €86.2/Tn of CO2 in 2022 – nor the CSPE, – which, thanks to the CCE, doesn’t seem to be rising from its rate set in January 2016 (€22.5/MWh) – but the value of CO2 in the European market, the European Union Allowances (EUAs) of the European trading system (ETS).

Here, we must include a disclaimer, as the ETS is a particularly sensitive subject in Europe, any questioning of which would be tantamount to opening a real Pandora’s Box. Even if the exercise of explanation sometimes requires demonstration of critical thinking, the author of this article wishes to express his complete commitment to the European environmental objectives in general and those established in the Paris Agreement in particular.

The value of EUAs has three-folded, even four-folded, in 2018 to reach a current price of approx. €25 (per tonne of CO2 equivalent) and, because of the organisation of the electricity markets, a €1 increase in EUAs rises the price per MWh of electricity by nearly €1… from Norway to France. This is a well-known phenomenon and is even quantified within the Energy Code[1] in France: €1 increase in the EUAs is reflected on average by a €0.76 increase for a MWh of electricity purchased on the French market.

On this basis, the market price of electricity in France (currently around €61/MWh for 2019) would include an estimated additional cost of 25×0.76=€19/MWh on account of the ETS. Thus, returning to the average of electricity production emissions in France (less than 0.1 tonne of carbon dioxide per megawatt hour), the weight of carbon taxes on electricity prices in France is therefore more than 19/0.1=€190/Tn of CO2! (More than 4 times higher than the CCE applied to fossil fuels!).

How can we justify that electricity is the most highly taxed energy for CO2 emissions in France?

France had placed limits on this incongruity by establishing the ARENH mechanism at €42/MWh, thereby largely eliminating the impact of the ETS (the difference between the market price and the ARENH is indeed in the order of the €19/MWh previously mentioned).

The current problem is that, for the first time since its establishment in 2011, on account of the competition’s development, the French Energy Regulatory Commission (CRE) announced on 29/11/2018 that the [ARENH] rights would be reduced for 2019. The part of regulated selling prices of electricity (TRV) that is market-driven will increase on account of this reduction (in the range of 25%). In their press release dated 29/11/2018, the CRE thus announced the next increase of the same regulated selling prices.

Until now, individual consumers were exposed to the market for the energy part of their supply that is not covered by the ARENH. Moreover, mainly owing to the low value of EUA prices in recent years, the difference between the ARENH price and the market prices was small (indeed, in certain years, like in 2016, the market price was even more competitive). However, the same cannot be said for 2019, as the consumer will suffer double the punishment: an increased part subject to the market price (on account of the ARENH reduction) and a higher market price resulting primarily from the increase of EUA prices.

In more specific terms, the average part of the ARENH rights in regulated prices is 68%[2]; thus, prior to ARENH reduction, 32% of the supply depended on markets prices. As the demand exceeded the ARENH ceiling, ARENH allocation will be reduced at 75.23% of the ARENH rights for 2019, and now such exposure increases to 48.84% of the supply. Thus, the ‘CO2 tax’ on account of the ETS is reduced to approximately 19×48.84%, or €9.28/MWh. Returning to a CO2 emission factor for French production of 100kg/MWh, this corresponds to a carbon tax of €92.80/Tn (which is doubled based on an emission factor of 50Kg/MWh!)

We’re sorry for the complexity of these explanations. Unfortunately, solutions to the current environmental taxation crisis (CSPE, CCE, TICGN [domestic consumption tax on natural gas], EUA, etc.) will only be found through the complete and open-minded understanding of mechanisms resulting from combinations of both national tax policies and European market-type mechanisms – combinations which, due to their nature, are poorly controlled.

Philippe Boulanger

[1] Article R122-14: ‘the emission factor for electricity consumed in France, cited under 2 in III of the same article, is set at 0.76 tonnes of carbon dioxide per megawatt hour. ’

[2] Deliberation by the Energy Regulatory Commission dated 12 July 2018 on proposed regulated tariffs for electricity sales.