E.H2 Solutions

As of last August, the financial world was already labelling CO2 as the best-performing raw material of 2018, with a nod to its price skyrocketing by 300% in one year (and nearly 400% if we take into account the peak of €25.16/tonne of CO2 reached on 10 September).

 Discussing the performance of a product that is generally seen as a tax seems provocative at the least! Are they saying that the CSPE [Contribution to the Public Electricity Service tax] is not very efficient because it doesn’t seem to have risen from €22.5/MWh since 1 January 2016? Have we tipped our hat to the performance of the CSG [general social contribution tax] which, as of 1 January of this year, leaped up 1.7 points from 7.5% to 9.2% (a performance of 22.6%!)?

These market shifts and envious comments are here to remind us (10 years after the great financial crisis and the fall of Lehman Brothers) that, when we’re talking about CO2 and its price, it’s not a raw material, nor is it a gas or thin air, but a financial product: the EUA (European Emission Allowances).

Our goal here is not to retrace the chaotic and sometimes inflammatory history of this product. As a reminder of this, we will make do with this diagram:

We are, rather, proposing that we shed some light on certain aspects and consequences of these changes in the market.

Reasons for this CO2 price increase

The progression of EUA prices already has a long history of being extremely volatile. As a market whose base is essentially regulatory in terms of the European Union, this market evolves as decisions are taken (or announced or expected). In the present case, the carbon market’s current performance is generally attributed to the market’s expectation of the January 2019 implementation of the market stability reserve (MSR), the key element of the UE-ETS reform adopted last year and published this year (Directive 2018/410 of 14/3/2018).

Impact on the price of electricity: A second CSPE

Electricity futures has also been a very ‘high-performing’ market these last twelve months! Over one year, the French baseload Cal ’19 contract rose from approximately €40/MWh to €60/MWh (turning in a respectable performance of 50%). Of course, the price of coal was also ‘high-performing’ at nearly 20%, but the primary factor in this increase continues to be the impact of the EUA price rise. This impact is even quantified in Article L 122-8.I of the energy code: 0.76 tonnes of CO2 per MWh (conveying the somewhat counter-intuitive reality of the French price’s serious dependency upon coal electricity). On this basis, the impact on the price of electricity may be estimated as falling between €15 and €20/MWh (i.e., 25-30%).

Impact on the consumer

Until now, the French consumer has been partially protected from this hike by the ARENH mechanism, which caps the cost of its basic supply at €42/MWh. However, this mechanism has a time limit (2025) and is capped for supply from suppliers who are EDF competitors (until now, the cap of 100 TWh did not apply, but with EDF’s market losses, this could occur as soon as the next allocations in November 2018).

Furthermore, following an additional mechanism implemented from 2016 (when the market price was below the ARENH price) for electro-intensive consumers (see Article L 122-8.I of the energy code), these consumers may be compensated for the CO2 impact on the price of electricity. But the basis for evaluating CO2 used for the compensation is only set at €5.91/tonne (it’s doubtful that this value will be revised), and this measure also has a time limit (2020).

These protections are therefore only partial, and the impact is already being felt by industrial consumers (and certainly will be felt soon by individuals).

Impact on the environment

Perhaps we should have started with this point, because it’s the aim of the European system of trading quotas of greenhouse gas emissions (SEQE in French), better known under its English name, the European Trading Scheme (ETS).

We could opt for cynicism and explore the changes in emissions in the French electricity sector, asking ourselves the simplistic question: what was the impact of this ‘double CSPE’ on emissions in the electricity sector?

From a wider standpoint, this limited impact of the ETS on the environment grew out of the debates and conclusions presented during the Conference on the ‘2018 State of the EU ETS’ in Paris on 13 June last (in the presence of the DGEC (Directorate General for Energy and Climate), EDF and a number of large industrial groups):

• The ‘Control & Command’ policies are what have impacted the reduced emissions in the energy sector.
• The role and impact of the ETS cannot be clearly identified as long as the price is below €30/tonne (i.e., until now).
• Most large industrial players still have a credit balance of free allowances.

If the prices of CO2 were to remain permanently at high levels (which, in view of the history, is not a given), demonstrating a genuine scarcity of allowances for large companies, we would enter into a new paradigm. This mechanism would shift from a system that subsidises large European industrial sectors to a system that would tax these same companies.

Will it become a zero-sum system, now that the system is living on outside the Kyoto Protocol (i.e., outside the non-EU objectives)? Ultimately, the EU member states as well as various European funds for research and innovation are benefiting from the auctioning off of these allowances, and this revenue may, in the end, come back to the industry. Doubts are to be expected, and the critics of such a system are not just on the other side of the Atlantic. Pope Francis already pointed it out in 2015:

‘The strategy of buying and selling “carbon credits” can lead to a new form of speculation which would not help reduce the emission of polluting gases worldwide. This system seems to provide a quick and easy solution under the guise of a certain commitment to the environment, but in no way does it allow for the radical change which present circumstances require. Rather, it may simply become a ploy which permits maintaining the excessive consumption of some countries and sectors’ (Encyclical: Laudato Si)

Philippe Boulanger

Contribution de l’électrolyse à l’intégration des énergies renouvelables et à l’optimisation du système électrique français

Paris le 10 octobre 2018

1. Le nucléaire en France au cœur de l’équilibre du système électrique

Avec 58 tranches de centrales nucléaires représentant une puissance installée de 63,13GW l’énergie nucléaire assure près de 80% de la production d’électricité en France (72,13% en 2016 et 77% en 2014)

Ceci est bien connu. Ce qui l’est un peu moins est que le nucléaire assure aussi une très grande part des besoins de modulation du réseau :

Réglage de fréquence :

Les centrales sont réglées pour fournir +/-7% de la puissance nominale en réglage de fréquence (+/-2% réglage primaire et +/-5% en réglage secondaire)

Modulation et suivi de charge

Toutes les tranches, sauf celles de la série CP0 (Fessenheim et Bugey représentant 8% de la puissance nucléaire installée) sont capables d’offrir une capacité de modulation de 80% de la puissance installée avec des rampes entre 3% et 5% par minute (le niveau de production doit être au minimum de 20% de la capacité installée)

Le parc nucléaire est donc actuellement encore en mesure de répondre largement aux besoins de flexibilité induits par le développement des renouvelables, mais au prix d’un taux de charge réduit des centrales et donc de perte de valeur importante.

• Estimation de la modulation du nucléaire

D’un point de vue économique autant que du point de vue des émissions de CO2, cette modulation correspond à une destruction de valeur.

C’est la raison principale pour laquelle, en termes d’émissions de CO2, le système électrique français de bénéficie pas du développement des énergies renouvelables :

(Source RTE)

La production d’hydrogène par électrolyse permettrait, par sa flexibilité et sa demande additionnelle en énergie renouvelable, de limiter très sensiblement cette modulation.

Nous avons quantifié, d’une façon conservative, cet apport à partir des données de consommations horaires de l’ensemble des groupes nucléaires disponibles sur le site de RTE pour les années 2014 et 2016

Pour chacun de ces groupes (hors tranches série CP0) nous avons identifié et quantifié cette modulation de la façon suivante[1] :

• Identification : à chaque fois que la puissance produite est comprise entre 20% et 86% de la puissance installée (si moins de 20% le groupe est à priori en dehors de la plage de flexibilité et au-dessus de 86% le groupe participe potentiellement en réglage de fréquence[2])

• Quantification : sur chaque heure identifiée, la modulation est quantifiée par la différence entre la puissance produite et 93% de la puissance installée (afin de rester disponible pour le réglage fréquence)

En annexe 1, nous présentons des exemples d’identification et de quantification

Résultat pour 2014

Le volume modulé (hors control fréquence) total représente près de 12 TWh (11,924TWh)

Résultat pour 2016

Le volume modulé (hors control fréquence) total représente plus de 8 TWh (88,228TWh)

• Apport de l’électrolyse de masse

Nous avons donc aussi quantifié le fonctionnement d’usines de production d’hydrogène par électrolyse qui limiterait au maximum cette modulation.

Nous avons fait les calculs pour des installations de 200MW à 900MW d’électrolyse.

Résultat pour 2014

• Une usine d’électrolyse de de 200MW aurait un facteur de charge de 89% (7802h/a), consommerait 1,56TWh et produirait 28 500 t H2

• Une usine d’électrolyse de de 500MW aurait un facteur de charge de 83% (7300h/a), consommerait 3,66TWh et produirait 66 500 t H2

• Une usine d’électrolyse de de 600MW aurait un facteur de charge de 81% (7110h/a), consommerait 4,27TWh et produirait 77 588 t H2

• Une usine d’électrolyse de de 900MW aurait un facteur de charge de 73% (6437h/a), consommerait 5,79TWh et produirait 105 348 t H2

Il est intéressant de rapprocher ces volumes de production d’hydrogène avec le Plan de Déploiement de Hydrogène présenté par le gouvernement le 1^er juin 2018 :

“Mesure 1 : 100 000 t H2 dès 2023“

Résultat pour 2016

• Une usine d’électrolyse de de 200MW aurait un facteur de charge de 82% (7201h/a), consommerait 1,44TWh et produirait 26 232 t H2

• Une usine d’électrolyse de de 500MW aurait un facteur de charge de 72% (6304h/a), consommerait 3,16TWh et produirait 57 413 t H2

• Une usine d’électrolyse de de 600MW aurait un facteur de charge de 69% (6034h/a), consommerait 3,63TWh et produirait 65 938 t H2

• Une usine d’électrolyse de de 900MW aurait un facteur de charge de 60% (5239h/a), consommerait 4,72TWh et produirait 85 872 t H2

• Conclusion

Avec Flamanville 3 (1600MW) qui va rentrer en service prochainement, 3 à 5TWh d’électricité renouvelable rajoutée chaque année sur le réseau électrique en France et une demande constante (tendance décroissante), le déploiement massif de l’électrolyse c’est ici et maintenant et à un rythme de plusieurs centaines de MW par an. La demande supplémentaire d’électricité renouvelable pendant de longues heures d’utilisation induite par cette production d’hydrogène ne générera aucune émission de CO2 additionnelle et permettra de décarboner d’autres secteurs : transport, industrie & chauffage.

C’est le principe de l’intégration trans sectorielle, une opportunité industrielle unique pour la France

Annexe 1 :

Exemple d’identification et de quantification (Blayais 2 et Chooz 1 en 2016)

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[1] Il s’agit d’une estimation simplificatrice et conservatrice indépendante de contraintes d’exploitation qui ne sont connues que par EDF.

[2] L’électrolyse par sa flexibilité serait en mesure d’assurer aussi une grande partie du réglage fréquence.

On 9 January, a Catholic church in Immerath, a city in western Germany, was destroyed to make way for the expansion of a gigantic coal (lignite) mine operated by RWE. This demolition took place in spite of protests by residents and environmental campaigners.

These images, which seem to come from another time, evoke the drama of the village of Tignes being swallowed up in 1952, the last inhabitants having to be evacuated by force by the police. But at the time, Tignes had to support efforts to rebuild the country, and the electricity involved was green (even if electricity then was colour-blind).

We’re also learning that, in Germany, the displacement of people in connection to coal mining is also affecting Lusatia, an eastern region near Poland, where entire villages have been wiped off the map. In 2007, a 750-year-old church was moved 12 kilometres from Heuersdorf to Borna (in the East) on two rolling platforms, at a cost of 3 million euros, in order to prevent its destruction.

Indeed, Immerath had already become a ghost town in 2013, when its 900 inhabitants, their houses, the 18^th-century Stations of the Cross and other village monuments were relocated to Immerath Neu, a new site sprung from the earth in the same municipality of Erkelenz, in North Rhine-Westphalia, as part of an immense relocation plan affecting a total of 7,600 inhabitants of the region.

The environmental campaigners, with banners covered in slogans such as, ’He who destroys culture also destroys people’, were powerless to stop it.

This ‘minor news item’ reminds us that, beyond political discourse, the reality of electrical power generation in Europe in general and Germany in particular continues to be dependent on coal: coal and lignite still produce 40% of Germany’s electricity.

The price of coal is therefore still the primary factor in the indexation and evolution of electricity prices on the continental plate. (see figure below):

While Germany has just created a new grand coalition government (CDU/CSU/SPD) with the signing of a new government contract (Koalitionsvertrag) introduced on 7/2/2018, we can legitimately ask ourselves: what will remain of October 2010’s Energiewende?

This energy revolution had been written into the Koalitionsvertrag of a similar grand coalition at the time, and called in particular for a 40% reduction in CO2 emissions by 2020 (with respect to the 1990 level), an 80% reduction by 2050 and a higher penetration of renewable energies in the electrical power generation market: 35% in 2020, 50% in 2030, 65% in 2040 and 80% in 2050.

Germany is ahead of the game in this latter goal, with 38% renewable energy, and the new government has even committed to reaching 65% from 2030 (i.e. 10 years early). On the other hand, the coalition agreement remains silent on the objective of reducing CO2 and specifies that the exit from coal must be made step-by-step (schrittweise).

In this respect, with a reduction of only 27.9% in 2015 (and a slight increase since then), the target seems permanently out of reach. Agora Energiewende even predicts that the 2020 target will be missed by…120 million tons of CO2 equivalent (i.e. more than 4 times the total emissions of the French electrical power sector in 2016).

It truly seems that, faced with the choice of a policy of industrial development (roll out of renewable energies) or of combating climate change, the decision-makers are clearly demonstrating their agnostic pragmatism.

And churches can fall…

Philippe Boulanger

The capacity market à la française is a complicated creation: the NOME [New Organisation of the Market for Electricity] law in 2010, a decree in 2012, two decisions in 2015 and 2016. The capacity market à la française is a cumbersome, 209-page-long body of rules (available in French only, because it’s probably very difficult to translate into another language). The capacity market à la française is also about change: a new decree, a new decision, and therefore a new, longer edition of the rules are expected in 2018.

On the other hand, one clear point seems to be emerging from this regulatory cabaret: the price of capacity!

The sole capacity auction in 2016 was framed by limited, simple parameters:

• Minimum volume up for sale: 25% of EDF’s certified capacities
• A maximum price:  set at €20,000/MW
• And therefore an auction result that sets the market reference price: at 10,000€/MW

A comprehensible and quite logical equation  seems to be emerging (where AL refers to the supply year):

In 2018, this algebra will quickly become complicated…

We won’t dwell on the auction of 27 April 2017 for the 2017 supply year which, with only 500 MW exchanged, had the virtue of confirming the price of the 15 December 2016 auction.

2018 supply year: things are becoming complicated with 2 auctions, on 9 November and 14 December. Astonishing! Not only is the capacity value not reaching 15,000€/MW ; the price is even (slightly) down! Fortunately, some consistency is emerging from these auctions, which seem to be a copy-paste of both the price (~€9,350/MW) and the volume (~11GW each; in total, on the same order of magnitude as the volumes exchanged in 2016).

This consistency therefore naturally leads us to revise our linear regression calculations which tell us (without going into the details or the level of sophistication of our calculations):

2019 supply year: the situation becomes even more complicated, to a significant extent

• We didn’t yet have the results of the second auction for AL2018 with its beautiful consistency before the AL2019 auction (simultaneous auctions scheduled for 14 December)
• For the only auction in 2017, the minimum volume up for sale had to be: [Max(25% of EDF certified capacities,50% of EDF available capacities]
• 4 other auctions planned in 2018 for AL2019, of which the first 3 have no requirements regarding volumes for sale (and still none regarding purchases)
• An uncertain competitiveness for the ARENH – with a market price around €41/MWh, the ARENH should be competitive over the year, very competitive in the first half, but possibly not in the second half – which makes the supply-demand balances regarding capacity for the key players just as uncertain

The somewhat disconcerting results of this auction clearly reflect the complexity of its parameters:

• A generous offering: over 40GW
• Extremely weak demand: less than 1GW market order (€40,000/MW), reflecting a certain disenchantment on the part of the suppliers. This may become a subject of concern for the proper functioning of the mechanism
• Very low volumes being exchanged: 1,220.20MW
• A discernible rise in the capacity price (€12,999.80/MW) without quite matching the price offered for nuclear capacity (which we strongly suspect to be around €15,185/MW)

Beyond a few concerns regarding the proper functioning of the market (certain disenchantment in terms of demand), we have to acknowledge that the number of parameters and unknowns surrounding the capacity market exceeds our ambition for finding the martingale that governs this market. One constant emerges, however: the French electricity sector is still very much dominated by nuclear generation, and will remain so until at least 2030-2035, with a share of over 50%. It is therefore logical that the cost of this production be clearly reflected in the price and in electricity, a price which is itself indeed made up of an energy component AND a capacity component.

Philippe Boulanger, Expert in Electricité

Up until this point, France has not been particularly noted for its punctuality in transposing the European Directives relating to the energy sector. In fact, it was only in 10 February 2000, that being more than a year late, that the Directive of 19 December 1996 concerning common rules for the internal electricity market was transposed into French law. As for natural gas, the Law of 3 January 2003 transposed the Directive of 22 June 1998 concerning common rules for the internal natural gas market over two years late and following an intense debate which led to nearly 700 parliamentary amendments.  Some have interpreted these delays as a lack of French enthusiasm for the process of opening energy markets.

On the other hand, as far as remuneration of capacities is concerned, France is moving into position as a pioneer in establishing a mechanism consistent with the principles defined by the European Commission, particularly as regards the subject of cross-border participation of foreign capacities in capacity mechanisms.

Be that as it may, with the launch of the Commission’s in-depth investigation of the French capacity mechanism in November 2015, the matter hardly seems like it’s off to a great start!

The intense negotiations and consultations with stakeholders, which came to a head in summer of 2016, resulted in the European Commission’s approval decision dated 8 November 2016 through the implementation of three pillars of action:

• Pillar for competition: 2017 supply year
• Pillar on the participation of cross-border capacities: 2019 supply year
• Pillar for promoting investment in new capacities: 2019 supply year

The rules of the French mechanism as published by the Order of 29 November 2016 have addressed the pillar for competition to the Commission’s satisfaction, and the other two pillars are the subject of a dialogue that is well underway, organised by the RTE [Electricity Transmission Network] since the spring of 2017.

As these changes will lead to a modification of the Decree of 14 December 2012, the (tight) schedule is as follows:

• September 2017: Decree proposals (publication expected December 2017)
• October 2017: Resume dialogue on new rules
• Mid-2018: Publication of new rules
• 2019: Entry into force of explicit participation and first calls for tenders for new capacities

The first items currently emerging from the consultations are the following:

Cross-border capacities: the first explicit participation of foreign capacities is planned starting from supply year (AL) 2019

• Step 1: determination (through a probabilistic study) of an aggregate volume allocated to the explicit participation of foreign entities (July-August 2018).
• Step 2: definition of a distribution key for this aggregate volume so as to grant a certain level of interconnection tickets per border where the hybrid solution is established (July-August 2018).
• Step 3: organisation, by border where the hybrid solution is implemented, of auctions on interconnection tickets (September 2018).
• Step 4: certification of border production/clearance capacities which have acquired interconnection tickets and monitoring of these capacities during the supply year (These capacities may participate in the EPEX Spot auctions for AL 19, 2 to 3 in 2018).

Long-term contractualisation: 3 auctions are planned in 2019 to cover the periods from 2020 to 2026, 2021 to 2027 and 2022 to 2028.

• Objectives: Competition, guidance throughout the energy transition, reduction of the cost for consumers, non-distortion of the market.
• Eligibility: The system is open to any new capacity which does not already have a support mechanism.
• Contractualisation: Contract for difference of 7-year duration.
• Selection: The selection will be take place via auction through the comparison of offers with a demand curve, which will integrate a probabilistic correlation model including market modelling and which will be adjusted in consideration of the value of the capacity on the market.

These modifications will not occur without posing some difficulties for the players.  To illustrate, we wish to bring up the case of the first capacity auction for AL 2019, scheduled for December 2017: on this date, parameters affecting the supply/demand balance will not yet be established. In particular, the actors won’t know the safety coefficient that will apply to their obligations (a factor which will increase depending on explicit participation selected), and these foreign capacities won’t yet be able to participate. In turn, multiannual contracting may complicate the reference cost of capacity for the supplier.

While the debate over the new package (the 4^th) is in full swing, including where reworking the Regulation of the European Parliament and of the Council on the internal electricity market is concerned, it seems already established that the French capacity compensation mechanism will be very much in compliance with this regulation (Article 22) – and by anticipation…

During the presentation of its results for the first quarter of 2017 on 9 May 2017, EDF highlighted the negative impact on turnover in France of ARENH (Regulated Access to Historic Nuclear Electricity) sales and market activity: -49 million € allocated ‘mainly to production and sourcing for ARENH subscription’; and causing Xavier Girre (CFO EDF) to state the following: ‘We’re deeming it also necessary and equitable to reform the ARENH mechanism so as to prevent it from being as biased as it is today’.

Having been established by the NOME [New Organisation of the Market for Electricity] law of 7 December 2010 and in place since 1^st July 2011, the ARENH mechanism is already an old story. It even seemed promised to become obsolete with the wholesale markets which, since December 2014, have maintained their position at levels below the price set for the ARENH (with the notable exception at the end of 2016) to the extent that the ARENH had not been the subject of any demand for the 2016 supply year.

Why revive this debate when a new decree on 21 March 2017 further framing the mechanism has just been introduced and has demonstrated its effectiveness during the window of 16 May 2017? Let’s analyse the current situation, put this third parameter of the price for electric energy into context and define its challenges.

First and foremost, let’s get back to the principle:

For a transitional period from 1^st July 2011 to 31 December 2025, the ARENH was established ‘in order to ensure the freedom of choice for the electricity supplier all while benefiting the attractiveness of the territory and all consumers in the French electro-nuclear facilities competitiveness’. The total volume provided is limited to 100TWh/year.

The ARENH product is annual by definition; however, in order to allow suppliers to adjust their needs according to the evolution of their portfolio, subscription takes place at two half-yearly subscription dates (November and May). With the aim of strengthening its annual nature and limiting arbitration opportunities, the system provides for a so-called ‘monotony’ clause forcing suppliers to ensure that their demand moves in the same direction during two consecutive half-yearly subscription dates. (Clause reinforced by the Decree of 21 March 2017)

The outcome:

The figure below (excerpt from the Competition Authority report dated 8/2/2017) is a good illustration of the success and effectiveness of the system as well as its correlation with wholesale market prices:

The mechanism’s rational has, in fact, been disrupted since, against the expectations of the 2010 legislator, the price of the ARENH is above market prices. Such disruption is even more significant when, in the space of a few months, market prices alternate being strongly below, strongly above, and then again strongly below the ARENH level!

The behaviour of the players during the window of 16 May 2017 displayed the effectiveness of the new decree: the volumes ordered for the first half of 2017 have been renewed for the second half, observing the product’s annual logic, whereas with the BL Q3 market prices: 32.15€/MWh, BL Q4: 42.85€/MWh and capacity to 10,000€/MW, the ARENH was out of the money by~4€/MWh!

So, we’re not too sure which ‘bias’ was implied (commercial asymmetry between EDF and alternative suppliers: payment periods,  dealing with the volume limit, portfolio adjustment, penalties…?). On the other hand, it seems more important to us that the debate now focuses on the issue of consistency among the 3 parameters defined by the NOME law, namely: market prices, the capacity price and the ARENH.

 ‘With nuclear production representing over 70% of the total, two items become paramount: (i) that the ARENH regains a level reflecting the complete cost of this French nuclear generation (see our article (1) on this subject), and (ii) that the capacity market matures to ensure the competitiveness of the ARENH (including capacity guarantees) vis-à-vis the wholesale market.

As the climax of a year which saw Brexit and the growing mistrust in member countries towards an organisation which is felt to be evermore intrusive, the European Commission stayed firmly on track, with no sign of any inferiority complex, when publishing its 6000-plus page Winter Package on 30/11/2017, focused on energy transition (4th Energy Package since 1996)! It consists of a series of documents (Decisions, Regulations, Draft Directives, Guidelines, impact studies, etc.) published under the title of:

Clean energy for all Europeans – Unlocking Europe’s growth potential

With the ambitious aim of:

Reducing CO2 emissions by at least 40% by 2030, while modernising the EU’s economy and creating jobs and growth for all European citizens

With a “European resolution proposal” from the Senate (16/02/2017) and an “Information report on the new organisation of the electricity market for the 4th Energy package” from the National Assembly (23/02/2017), the debate is well underway.

And so what if in the end, the positive proposals for energy, the economy and growth in the European Union should come from the Commission? There are many sceptics! We are offering a far from complete review of the contents of this package, the proposals it makes and the discussions taking place.

What does the package contain?

All the documents are available at the following address:

https://ec.europa.eu/energy/en/news/commission-proposes-new-rules-consumer-centred-clean-energy-transition

There are 86 documents available at this webpage (not including translations),  representing 37 texts, of very varied types and importance, including eight major legislative proposals, subject to the joint decision procedure (European Parliament and Council of the EU), which form the body of this fourth package the Commission has produced since 1996:

1. Regulation of the European Parliament and of the Council on the internal market for electricity (revision);
2. Directive of the European Parliament and of the Council on common rules for the internal market in electricity(revision);
3. Regulation of the European Parliament and of the Council, establishing a European Union Agency for the cooperation of energy regulators (recast);
4. Regulation on risk preparedness in the electricity sector (new);
5. Directive on energy efficiency (revision);
6. Directive on buildings energy performance (revision);
7. Directive on renewable energy sources (revision);
8. Ruling on EU energy governance (new).

(Documents shown in bold are of particular interest to our readers).

Let’s summarise the main measures

(This summary is not intended to be complete)

1. Renewable energy sources

• The goals for 2030 are: share of renewables in energy 27% (globally across the EU), share of renewables in electricity 50%.
• Expansion of available calls to tender and compensation payments.
• Implementation of technically neutral calls to tender.
• As regards heating (and cooling), promotion of policies to increase the renewables contribution by 1% a year, and provide conditional access to grids for renewable energy producers.
• Limitations on first-generation bio-fuels.
• The source guarantee system is made more coherent: it is also extended to non-renewable electricity production (nuclear, cogeneration, etc.) and to gas.
• Promotion of self-generation.

1. Energy efficiency

• The aim is to reduce consumption by 30% (15% during the period 2020-2030). We note that industries subject to ETS may be excluded from the calculation, as well as from home consumption of renewable energy.

1. Organisation of the electricity market: New market design

• Priority given to the consumer and the internal market.
• The main innovations relate to:
  1. Strengthening short-term markets
  2. Removal of price cap
  3. Strengthening market-based dispatching rules
  4. Strengthening the contribution from demand (load shedding)
  5. Disappearance of regulated and social tariffs
  6. Dynamic supply obligatory
  7. Restriction on the role of grids in storage
• Although this project restates trust in the market (energy only), as regards security of supply, it also recognises the possibility of the capacity mechanism. These mechanisms will however be strictly controlled, and must take account of cross-border availability, justifying their need (regional security analysis) in order to be considered compatible with guidelines relating to State aid.
• Creation of regional operational centres: ROCs for network managers
• Strengthening supra-national regulation (New prerogatives given to ACER)

So where does the debate crystallise?

With the Commission, which confirms it is moving fast with this package (Vice-president responsible for the Energy Union, Maros Sefcovic, announced on 1st February that he was planning for the legislative process to be launched on all texts by the end of 2017), the participants have quickly crystallised the debate on a number of points:

• A tendency to greater intrusion, sometimes overturning the principles of subsidiarity and proportionality
  • Possible jeopardy for the capacity mechanism (Senate, National Assembly, UFE).
  • Significant changes to ACER’s areas of competence: Unspoken and unwarranted slippage towards the setting up of a European regulator (National Assembly)
  • Creation of Regional Operational Centres (ROC), jeopardising the subsidiarity principle (RTE, National Assembly, UFE)
• Planned disappearance of regulated and social tariffs (National Assembly)
• Failure to recognise nuclear as the technology that contributes to the decarbonisation of electricity (Senate)
• Failure to mention a cap on CO2 price or carbon tax (RTE, Senate)
• Jeopardising compensation to suppliers by load shedding operators (CRE, National Assembly)
• Storage limitations too strict (RTE, National Assembly)
• Promotion of technological neutrality for renewables (Renewable Energies Syndicate, DGEC, RTE)
• Cap on first-generation bio-fuels (Renewable Energies Syndicate, sector members such as the Avril group)

It is clearly too soon for final decisions on these proposals, and as a provisional conclusion, we also want to paraphrase the European Business Commission of the National Assembly, in its report on 23 February 2017:

“Generally positive, but sometimes intrusive proposals” so “stay vigilant”!

Philippe Boulanger

Pas un jour ne passe sans que des nouvelles souvent contradictoires au sujet d’EDF fassent la une de nos journaux :

• Situation financière « alarmante », « catastrophique »
• Hinkley point « un très bon investissement » / « un investissement trop risqué »
• …

Je ne suis pas un spécialiste d’EDF et je n’ai pas accès à quelconques informations confidentielles.

C’est en tant que spécialiste du secteur de l’énergie, acteur de sa transition depuis la loi du 10 février 2000, que j’expose ma compréhension de la situation.

Quantification du problème : rupture entre coûts et revenus

Je ne regarderai ici que l’activité génération nucléaire

Coût

Pour la partie coût je me baserai sur le rapport de la Cours des Comptes sur le coût du nucléaire en France (mai 2014) et plus récemment sur le chapitre « La maintenance des centrales nucléaires : une politique de remise à niveau, des incertitudes à lever » du rapport public annuel de la Cours des Comptes (10 février 2016)

Le rapport de mai 2014 résumait les coûts de la façon suivante :

Le rapport annuel, évalue l’impact des investissements nécessaires par EDF à la fois pour améliorer la disponibilité du parc ainsi que le projet de « grand carénage »

Les chiffres retenus sont en lignes avec les chiffres qui avaient été annoncés par EDF (55Md€ sur la période 2014-2025). La cours des comptes retient pour la période 2014-2030, 75Md€ pour les investissements et 25 Md€ pour la maintenance.

L’impact sur le coût total (selon leur méthode) est donc faible et passe pour 410TWh de 59,8€/MWh à 62,6€/MWh

Ainsi il ressort de ces chiffres que sur une base de 410TWh/a les besoins « cash » de la production nucléaire annuelle (au moins jusqu’en 2030) sont à minima de 62,6€/MWh moins le loyer économique et la provision pour démantèlement. En prenant les chiffres du tableau 2013 nous obtenons :

62,6 – (8501+520)/410=40,6€/MWh

Que j’arrondirai à 40€/MWh[1]

Revenus

Ici nous devons regarder les prix sur les marchés à terme de l’électricité

(source EEX)

Il en ressort un prix pour les années 2017 à 2019 de l’ordre de 26€/MWh (tendance à la baisse)

Manque à gagner (défaut de trésorerie)

Sur la base d’une production vendue de 410TWh/a retenue par la Cours des Comptes ce manque à gagner en « cash » est au moins de :

(40-26) x 410= 5740 Millions €[2]

Diagnostique du problème 

Une organisation du marché inadaptée

Sans entrer dans les polémiques sur les coûts d’EDF, la réalité est que la France avec ses 63,2GW de capacité nucléaire en exploitation n’est pas en mesure de se passer à moyen terme de cette production et que le prix de vente doit couvrir ces coûts de production.

Le problème est dans une organisation de marché qui s’est progressivement mise en place depuis 2000 et qui ne rémunère l’électricité seulement que sur la part énergie (prix en €/MWh).

Il s’agit d’une organisation de marché classique pour les activités marchandes où les prix s’équilibrent tant bien que mal par le jeu de l’offre et de la demande : en cas de surcapacité les prix tendent vers les coûts marginaux de production pour refléter les coûts complets long terme quand des besoins d’investissement sont nécessaires compensant ainsi, par des créations de rente, les périodes de prix bas.

Cette organisation « Energy-Only » ne marche pas et ne peut pas fonctionner 

• En période de sur capacité les prix reflètent seulement les coûts marginaux cout terme de production (et ces coûts baissent avec le déploiement des énergies éoliennes et solaire et la baisse des prix des énergies fossiles)
• Par obligation politique, une situation de sous-capacité serait une solution anormale. En France notamment RTE doit veiller à la présence d’une marge suffisante en capacité.

Ainsi « si tout se passe bien » les acteurs sont condamnés à ne percevoir comme rémunération que le prix marginal court terme. Ce prix est actuellement basé sur le prix du charbon (il existe encore un potentiel de baisse)

Cette organisation n’a jamais fonctionné

Il est intéressant que ce modèle s’est déployé en Europe à partir de 2000 alors que le reste du monde et notamment les Etats Unis faisait marche arrière suite à la crise Californienne de 2000-2001. Le principal champion de cette organisation de marché à l’époque n’était autre que ENRON dont la déroute a contribué fortement à la crise financière de 2001

Pourquoi, me diriez-vous, la plupart des électriciens, E.ON en tête, vantait tant le marché Energy Only dans les années 2006-2010 et s’opposait violement à toute idée de rémunération pour la capacité?

Tout simplement car les prix se sont trouvés admirablement élevés !

En effet il y eu la conjonction de 3 éléments :

• Prix du pétrole, donc du gaz, élevé
• Les centrales gaz imposait le coût marginal (à tort ou à raison : des grands acteurs se sont vus infliger des amendes records pour abus de position dominante et rétention de capacité)
• La mise en place de l’ETS (marché CO2)[3] qui, avec une valeur de 20€/t pour des certificats largement alloués gratuitement, assurait une rente de l’ordre de 8€/MWh

Les conséquences immédiates de cette manne ont été de hisser les Electriciens aux sommets des capitalisations boursières puis de les entrainer dans une frénésie d’acquisitions qui n’a fait que rendre plus douloureux les lendemains qui déchantent

Remède

Abandonner le mythe d’une organisation « Energy Only » pour l’électricité

La Commission Européenne a lancé cet été en grande pompe la Réforme des Marchés de l’Energie et malheureusement le mythe est tenace et la Commission non seulement voit dans le développement du marché « Energy Only » la solution mais combat violement les initiatives, comme celle de la France, d’implanter un mécanisme de rémunération de la capacité.

Il convient aussi que le livre blanc allemand sur ce même sujet est sur la même ligne : rejet de tout mécanisme de capacité.

Ce mythe doit être contredit avec force mais pédagogie

La France est loin d’être isolée pour avoir posé des fondations d’un marché de capacité. La grande majorité des électriciens, revenus des excès de la première décennie du siècle, en supporte désormais le principe.

De toute façon, chaque jour apporte l’illustration du chaos actuel sur lequel repose le marché actuel

Dans un premier temps mettre en route le marché de capacité en France

Même si le dispositif est limité avec son plafonnement actuellement prévu (40.000€/MW soit au maximum environ 2,5 Milliards € pour les centrales nucléaires), c’est un pas urgent et nécessaire dans la bonne direction.

Evoluer vers un système de rémunération infrastructure pour les outils de génération électrique

Il faudra reconnaitre que la génération électrique est de plus en plus une infrastructure au même titre que les réseaux électriques. Dans le domaine de la distribution de l’eau, les usines de traitement des eaux ont un traitement similaire aux canalisations.

Conclusion

L’urgence de la situation nécessite des positions claires et tranchées pour faire avancer les idées avec pédagogie

Aucune organisation de marché ne peut se prétendre avoir le monopole de l’économie de marché

Philippe Boulanger 10/3/2016

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[1] Nous pouvons noter que la valeur de l’ARENH (Accès Régulé à l’Energie Nucléaire Historique) est fixée à 42€/MWh

[2] Cet ordre de grandeur se retrouve notamment dans la perte annoncée par E.ON pour 2017 : 7 milliards €

[3] Les effets négatifs de la mise en place de l’ETS pourront faire l’objet d’un autre article. Nous considérons que nous pouvons critiquer l’ETS et œuvrer pour la réduction des gaz à effet de serre et être favorable à un prix carbone