High time to fix the Spanish energy market

By Jordi Martinez Cuadrado

Please find the Spanish article here.

Spanish (and Portuguese) energy prices are among the highest of Europe. Making comparisons between electricity prices is always difficult, as the exact level of pricing depends on many site-specific parameters. The graph below is based on real life examples of client sites with comparable consumption patterns. Underlying wholesale values have been calculated back to average Cal 13 prices during 2012. The data fit our general observations about price levels in Spain compared to other countries.

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The table above is showing us two main issues regarding the electricity pricing in Spain:

 

  1. Spanish consumers are paying the second highest prices for grid fees & taxes, after Germany. It should be remarked, however, that many large German consumers enjoy a reduction on the very high grid fees & taxes which makes this price for them less excessively high.
  2. Confronted with the high prices of electricity in Spain, Spanish suppliers are often quite rapid in pointing at the high taxes. As you can see from the table above this is only partly true. Another reality is that retail add-ons on electricity in Spain are higher than in any other European country.

 

For natural gas, we cannot make the distinction between wholesale value and retail add-on, as Spanish natural gas is still billed according to old oil-indexed formulas and hasn’t switched to the more transparent Hub-pricing model of the other European markets. As you can see in the table below, this leads to higher prices, the second highest, just slightly below the German prices. But whereas in Germany, the problem is again situated in the regulated grid fees & taxes, in Spain what the suppliers are getting for their gas, the commodity price, is higher than in any other country.

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Both electricity and natural gas markets are resulting in higher prices in Spain than in most other European countries. Spain has failed to implement features of energy market liberalization that have been a reality in other countries for years. Policy failures are the obvious culprit for this. But over the years, we have observed that some aspects of energy market organization fail to move forward in Spain, due to a lack of willingness by energy suppliers to develop new products, adapted to the new realities of the market. When we speak about this with energy suppliers, they also blame the Spanish energy consumers who – according to them – are not really demanding such new solutions. Based on these figures, we want to point out six priorities for reducing the costs of buying energy in Spain.

 

  1. Switch towards the Hub-based market model for natural gas

 

Spain and Portugal are one of the few regions left in Europe where the pre-dominant model for billing natural gas is still the oil-indexed model. The consequences in terms of pricing cannot be denied. You can see it in the table for 2013 above. In 2014, we see that Spanish gas prices have continued to increase. Spanish gas consumers easily pay more than 34 euro per MWh for commodity at this moment. This compares to 24 – 25 euro for forward prices in most other countries and spot prices that have dropped below 20 euro per MWh.

 

At first sight, the Iberian peninsular looks like the perfect place for implementing a virtual hub. It has no less than nine injection points, seven LNG terminals, a pipeline connection to Algeria and to France. Creating a virtual Hub means that the responsibility for shipping and balancing gas from any of these injection points to the end consumers is passed on to the grid operator. It’s not difficult to see how this would facilitate gas trading in Spain. However, despite much talk, nothing much has developed in terms of Hub activity in Spain. At some point, two different initiatives started to compete with each other, the Iberian Gas Hub from Bilbao and the OMI, which is the organizer of the Iberian electricity exchanges. From these initiatives, it is also clear that in Spain and Portugal the role of a Hub is not clearly understood. Both are focusing too much on the development of financial trading, whereas a Hub should focus on the physical aspects of trading and leave the organization of the deal-making itself through exchanges and/or OTC platforms to other market participants.

 

Iberian Gas Hub and OMI have now announced that they will join forces. Let’s hope these joint efforts will be more insightful as to the function of a Hub. Let’s also hope it gets the full support from the transport grid operators. Considering the declining demand for natural gas in Spain, the abundance of import infrastructure and the geographical position of its LNG terminals, en route from the Middle East to North-Western Europe, we are convinced that there is serious potential for lower gas prices. This would not just be good news for its gas consumers. As the marginal electricity MWh’s are often produced in gas-fired power stations, lower gas prices could benefit the power consumers as well.

 

  1. Get complementary services fixed

 

Part of the high retail add-on for electricity in Spain is caused by the cost of complementary services, which has risen above 7 euro per MWh. With every power contract negotiation in Spain, you not only have to take a decision on the price level of the electricity itself. You also enter into complicated negotiations regarding the cost of complementary services. These are a sort of pass-through cost of fees that need to be paid by suppliers to the grid operators, a.o. for balancing the grid. Despite what many Spanish market participants think, there is nothing typically Spanish about these complementary services. Similar mechanisms exist in all the other countries as well. What is typically Spanish is that their cost has run up to unacceptably high levels.

 

It is true that the Spanish electricity grid has its particular challenges. The geographic spread of consumers and production plants is very wide, the market is isolated from the rest of Europe and, most importantly, Spain has a high percentage of wind and solar energy. The difference between a sunny, windy day and a cloudy quiet day in terms of plant commissioning requirements is indeed very big. But on the other hand, Spain has a production park that is well spread over the different technologies, which should lead to cost-efficient balancing. It specifically has a lot of hydro-electric capacity that should normally make it quite easy to balance the grid. We think that the high costs for complementary services in Spain should be seen as one of the many symptoms of the inability of its authorities of getting a grip on the regulatory framework. It should be fixed to lower the cost of consuming electricity in Spain.

 

What is even more annoying is that the system is based on an ad hoc calculation of costs incurred. This means that the cost for these complementary services is completely unpredictable and cannot be hedged. This leaves the consumer that wants to fix an electricity price on a forward basis with an uncomfortable choice that has to be made. Either he leaves the complementary services open, i.e. they will be billed at real, ad hoc cost, which means he is running the risk of unpredictable price increases. Or he fixes the complementary services. However, we have observed that suppliers will include a large risk premium in their fixing of the complementary services, which is logic, considering that they cannot be hedged.

 

If all other countries manage to get things like balancing costs regulated in such a way that it causes only minimal costs and no extra risks for end consumers, there is no reason why Spain couldn’t achieve this. This would lower the cost of buying energy in Spain and benefit the development of more retail market competition.

 

  1. Abandon the 6-period system for billing power commodity

 

The first thing that strikes anyone when buying electricity in Spain is the six (or three) period billing system for commodity. Most other countries have switched to just two periods, peak and off-peak. In Germany, we often see simplified commodity billing with just one price per MWh, regardless of when it is consumed. But Spain has held on to the old billing systems of its regulated markets. We can understand that as far as grid fees are concerned, but we don’t understand it for commodity billing.

 

If you look at the wholesale market in Spain and Portugal (www.omip.pt), you’ll notice that it has also implemented the dual structure baseload – peakload that you find in all the other markets. The problem is that the six periods such as defined for calculating grid fees, doesn’t fit with these two products. This means that a supplier that is billing his client on a six-period basis, risks having a mismatch between what his client is paying him and what he is paying to the wholesale market in the two periods. To make up for this risk, Spanish suppliers will include risk premiums. This explains why the difference between wholesale and retail prices is higher in Spain than in other countries. If Spanish suppliers would bill end clients based on a peak and off-peak system or like in Germany, a single price based on a percentage of baseload and a percentage of peakload, the price they bill their end customers would reflect much better the price they pay for hedging the supply in the wholesale market. Thanks to that they could lower their risk premiums for covering the difference between the six and the two periods. It’s actually very simple. The more a retail contract reflects what a suppliers needs to do in the wholesale market, the lower the retail add-on. It’s surprising that Spanish suppliers haven’t discovered this potential for lowering their prices and increasing their market shares yet. End consumers should realize this potential for savings and lobby actively for getting contracts where the commodity price is no longer based on the six-period system.

 

  1. Make flexible contracts available for small consumers

 

In a liberalization process, there is a certain pattern according to which contracts offered to mid-sized and large end consumers develop. In a first phase, fixed prices are offered as an alternative to the old regulated tariffs. Next, multi-click or tranche model contracts are introduced to give these consumers the chance of managing the risk of fixing an energy price in a volatile commodity market. In a last phase, the market reaches maturity as these clicking contracts develop into more advanced hedging products.

 

It’s normal that next phase contracts are introduced for large consumers first and then gradually trickle down to the lower market segments. Moreover, many smaller consumers don’t need the more advanced contract types and can achieve their risk management goals with simple multi-click or tranche model contracts. However, in Spain, the development of more advanced contract types seems to have stalled. Spain is now, for example, the only Western-European country where a 10 GWh power consumer has a hard time getting offers allowing him to fix his price in different moments to manage the risk. In other cases, there is only one supplier willing to offer a flexible contract, putting the buyer in a very uncomfortable position. And in the gas market, the services for swapping floating oil-indexed prices to fixed prices are poor compared to what we were used to in other European markets when they were still predominantly oil-indexed.

 

Again, it is strange that Spanish energy suppliers don’t seem to realize that offering more advanced price hedging services can help them to expand their market share. At the same time, they are telling us that this is because Spanish consumers are not asking for them and just want to continue fixing their prices in one moment, even when they consume large quantities. The Spanish wholesale electricity price has fluctuated by more than 20% in the last three years. Spanish mid-sized consumers should get access to the contracts necessary to deal with that risk. And all consumers should get access to better price hedging services.

 

 

  1. Reduce the costs of grid fees & taxes

 

A few years ago, when we made international price comparisons, Spain stood out as a country with relatively low electricity prices. That position has been lost, and more and more international clients are starting to question this. As you can see in the table above high Spanish power prices are also due to the fact that its grid fees and taxes are among the highest in Europe. However, you can also see that the Spanish grid fees and taxes are in line with other countries that – like Spain – have been among the early adapters of renewable energy, such as Germany and Belgium. There are some reasons for having high grid fees and taxes for electricity in Spain. It should be remarked however, that in these countries energy-intensive businesses have more possibilities of getting exemptions than in Spain.

 

The problem of keeping a lid on grid fees & taxes in Spain, is closely related with an overall crisis regarding the regulation of energy markets. It is for example closely linked with the problem of the complementary services. The Spanish government has built up a historical debt in the utility sector by freezing end consumer prices in the past. It is trapped in a fierce dispute on how to pay back this debt. This puts the government in a difficult position when they have to negotiate tariffs with utilities. Solving this problem is necessary to keep the cost of energy for the end consumer under control.

 

  1. Increase interconnection

 

Some of the problems cited above are linked to the fact that Spain and Portugal are an energy island. This is certainly the case for the electricity market. The geographical position of the Iberian peninsular is obviously the main cause for this, allowing for on-land connections with France only. But France in itself is well integrated into the North-West-European market and on top of that it has an abundance of nuclear power. It is therefore very strange that there is currently only 1.400 MW of interconnection available between Spain and France. As we have observed above, Spain’s electricity market has failed to develop market practices that are now commonplace in the rest of Europe. Better physical integration into the European market could get things moving.

 

As far as the gas market is concerned, Spain (and Portugal) is a strange case. Like electricity, cross-border connection with France is limited and the lack of North – South connection capacity within France is also problematic. But unlike electricity, natural gas can be transported by ship. With its seven LNG terminals lying on the shipping lanes from the Middle East (and Western Africa, and South-America) to North-West-Europe, you would expect the price surplus of Spain to North-West-European prices such as TTF to be quickly arbitraged away. But it’s not happening. Spanish gas suppliers quickly point at higher Asian and South-American prices as a reason for higher Spanish gas prices. But that doesn’t answer the following question: why is an LNG ship coming from Qatar sailing to the UK to sell gas over there when the price of the gas for the end consumer in Spain is at this moment more than 75% higher than in the UK?

 

The absence of a well-functioning Hub mechanism is a reason for that. But it’s not the only one. There are also failures in regulations and pricing mechanisms for key infrastructure such as LNG terminal slots, storage capacities or capacities on bottlenecks in the grid. Fixing the Spanish gas market will ask for more than just introducing a (well-designed) Hub. It will also necessitate the fixing of many other aspects of gas market regulation. Adding interconnection capacity to France could further improve the Spanish market situation. It should be remarked, however, that this should be combined with a reinforcement of the North to South gas pipelines within France. Doing so could connect Spain directly with the TTF market and create an interesting North-South corridor in the European gas grid. However, improving the conditions for LNG imports and exports in Spain should be the biggest priority as it could be a quicker and definitely less expensive solution.

 

 

As it has been explained before on this blog, it is widely disputed whether liberalization of energy markets leads to lower consumer prices. One thing is beyond doubt though, in a well-designed liberalization, the retail margin, what suppliers charge on top of the wholesale prices gradually decreases. We have observed this in many markets across Europe. Moreover, the service level in terms of price risk management normally increases. None of this has been observed in the Spanish market, showing that its liberalization process needs to be fixed. The six problems discussed in this blog article allow energy companies (suppliers and grid operators) to optimize their margins at the expense of the end consumers. Regulation flaws lead to windfall profits for energy companies that exploit them. Fixing these problems would stop the windfall, increasing the working capital available to Spanish industry. It could also lower prices paid by residential consumers, making more income disposable to the struggling Spanish households. It is clear that getting Spain’s energy market fixed could be a great support to its recovering economy. It should therefore be high on the list of its governments’ priorities.

 

One thing should be beyond doubt. Spain is not different. Of course, like in any other country, its market has its own characteristics, partly due to its geography and history. But the problems (or challenges) cited in this article have occurred in every single other European country as well. We don’t see any fundamental reason why Spain would be the only country in Europe that cannot solve them. Unfortunately, this ‘Spain is different’ mentality often keeps regulators, energy suppliers and even end clients from adopting solutions that have proven to be successful in other countries and could be just as successful in Spain. Success in Spain’s energy markets will be made by those that are willing to learn from the lessons learned in countries that have liberalized their markets more rapidly and more effectively. We as E&C are ready to use our experience across Europe and the US to help Spanish end consumers with that.

 

Un buen momento para ajustar el Mercado de energía español.

Please find the English version here.

Los precios de energía en España (y Portugal) se encuentran entre los más altos de Europa. Hacer una comparativa de los precios de electricidad siempre es difícil, ya que el nivel exacto de los precios depende de muchos parámetros específicos.

El gráfico de abajo está basado en ejemplos reales de puntos de suministro con patrones de consumo comparables. Los valores subyacentes del mercado mayorista, han sido calculados para la media del producto Cal-13 durante el año de cotización 2012. Los datos confirman nuestras observaciones sobre el nivel de precios en España en comparación con otros países.

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El gráfico anterior nos muestra dos conclusiones sobre el precio de la electricidad en España:

  1. Los consumidores españoles están pagando el segundo precio más alto para tarifas de acceso e impuestos sólo por detrás de Alemania. Sin embargo, cabe destacar que muchos grandes consumidores alemanes disfrutan de una reducción del elevado coste de las tarifas de acceso e impuestos, lo que hace que el precio no sea tan excesivamente alto.
  2. A menudo como respuesta a los altos precios de la electricidad en España, los comercializadores suelen apuntar a los altos impuestos. Pero, como se puede extraer del gráfico anterior, esto es solo parcialmente cierto, ya que en realidad habría que tener en cuenta que los márgenes de las comercializadoras sobre la electricidad en España son más altos que en cualquier otro país Europeo.

En cuanto al gas natural, no podemos hacer la distinción entre el valor del mercado mayorista y los márgenes de las comercializadoras ya que este mercado en España todavía se factura según la clásica fórmula indexada Brent-Tipo de cambio, y aún no se ha hecho la conversión a un mercado Hub más transparente como lo han hecho otros mercados europeos. Como se puede observar en el gráfico que se muestra a continuación, esto da lugar a que los precios en España sean los segundos más caros, solo superados por Alemania. Pero mientras que en Alemania el problema radica de nuevo en las tarifas de acceso y los impuesto, en España lo que los comercializadores obtienen por el gas, el precio de la commodity, es más alto que en cualquier otro país.

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En España, como resultado de todo lo analizado anteriormente, se están obteniendo precios más altos que en el resto de Europa tanto en el mercado de la electricidad como en el del gas natural. España ha fallado a la hora de implementar medidas para la liberalización del mercado de energía que han funcionado en otros países. Algunas decisiones políticas han sido obviamente las culpables de este fracaso. Pero a lo largo de los años hemos observado que algunos aspectos relacionados con la organización del mercado energético no se han establecido en España debido a la falta de voluntad por parte de los comercializadores para desarrollar nuevos productos adaptados a la nueva realidad del mercado. Cuando nos acercamos a los comercializadores para tratar este tema, ellos culpan al consumidor quien, según ellos, no está demandando esas nuevas soluciones.

Basándonos en estas cifras, nos gustaría resaltar seis prioridades para reducir el coste en la compra de energía en España.

  1. Cambiar hacia un modelo de Mercado basado en el Hub para el gas natural

España y Portugal son de las pocas regiones en Europa que continúan encasilladas en el modelo de facturación de gas natural basado en formulas indexadas al petróleo. Las consecuencias en términos de fijación de precios no pueden negarse. Esto puede observarse más arriba en las cifras de 2013. Actualmente los consumidores de gas españoles pagan fácilmente más de 34 euros por MWh. Llama la atención al compararlo con los 24-25 euros por MWh de los mercado a futuro de otros países, así como los precios spot que están por debajo de los 20 euros por MWh.

A primera vista, la península Ibérica parece el lugar perfecto para implementar un Hub virtual con sus no menos de nueve puntos de inyección, siete terminales GNL y un gaseoducto conectado a Argelia y otro con Francia. La creación de un Hub virtual significa que la responsabilidad de transportar el gas y balancear la red desde uno de estos puntos de inyección hasta el consumidor final pasaría a manos del operador de la red. Es fácil imaginar cómo esto facilitaría la compra y venta de gas en España. Sin embargo, pese a que se ha hablado mucho, apenas se ha desarrollado dicho Hub en España. En determinado momento, se iniciaron dos iniciativas para competir entre ellas, el Iberian Gas Hub de Bilbao y el OMIE, el cual es el operador del mercado de intercambio (Exchange) de electricidad en la Península Ibérica. Analizando estas dos iniciativas queda claro que en España y Portugal no se ha entendido el rol que debe de jugar el Hub, ya que ambas iniciativas se han preocupado demasiado en desarrollar sendos mercado financiero, mientras que un Hub se debe de centrar en los aspectos físicos del trading y dejar la organización de las negociaciones en sí mismas a otros mercados participantes a través de las plataformas OTC y/o exchanges.

Iberian Gas Hub y OMIE han anunciado recientemente que aunarán sus fuerzas. Esperemos que estos esfuerzos de unión se concentren en el correcto funcionamiento del Hub. Considerando la demanda decreciente de gas natural en España, la abundante infraestructura que permite importar el gas natural y la situación geográfica de sus terminales de GNL en la ruta desde Oriente Medio al Noroeste de Europa, estamos convencidos de que hay un importante potencial para bajar los precios del gas en España. Esto no es tan solo una buena noticia para los consumidores de gas, ya que a menudo el precio de casación marginal de la electricidad en España es producido por centrales de gas, por lo tanto este hecho podría beneficiar también a los consumidores de electricidad.

  1. Fijar los servicios complementarios

Parte de los altos márgenes de comercialización de electricidad en España son causa del coste de los servicios complementarios, los cuales han superado los 7 euros por MWh. En cada negociación contractual de electricidad en España, no solo debemos de tomar la decisión en cuanto a los precios de la electricidad per se sino que también debemos de entrar en complejas negociaciones sobre los precios de los servicios complementarios, así como la posibilidad de fijación de éstos. Los servicios complementarios son una serie de costos asociados a la gestión de la red que deben de ser pagados a través de los proveedores al operador de la red. A pesar de lo que piensan muchos de los agentes del mercado español, no hay nada typically Spanish en estos servicios complementarios. Mecanismos similares a éstos existen también en otros países. Lo que es realmente insólito en España, es que el coste se haya elevado hasta unos niveles inaceptables.

Es cierto que la red de electricidad española tiene sus retos particulares. La dispersión geográfica de consumidores y de plantas de producción es importante, el mercado está aislado del resto de Europa, y lo más importante es que España tiene un alto porcentaje de producción de energía solar y eólica. La diferencia entre un día soleado, ventoso y un día nublado y calmado en términos de requisitos de puesta en marcha de las plantas es, de hecho, muy grande. Pero por otro lado España tiene un mix de producción muy bien diversificado, el cual debería suponer un coste mucho más eficiente de gestión. En concreto, España tiene mucha capacidad de producción hidroeléctrica lo que debería hacer más fácil equilibrar la red. Nuestra experiencia internacional en mercados de electricidad nos hace pensar que el elevado coste de los servicios complementarios debería ser visto como uno de los síntomas de la inoperancia de las autoridades en lo que a las políticas regulatorias se refiere. Éstas deberían de estar dirigidas a bajar el coste del consumo de electricidad en España.

Lo que es todavía más irritante es que el sistema está basado en un cálculo Ad Hoc de los costes incurridos, lo que significa que los costes de estos servicios complementarios son completamente impredecibles y no se pueden ser cubiertos. Esto deja al consumidor que quiere fijar un precio de la electricidad en base a futuros en una incómoda decisión. O bien el consumidor decide dejar los servicios complementarios abiertos, i.e dichos servicios complementarios serán facturados en base a los valores reales, lo que significa que está asumiendo el riesgo de que los precios puedan aumentar, o decide fijarlos. De cualquier manera, hemos observado que los proveedores incluyen altas primas de riesgo en el momento de fijar dichos servicios complementarios para el consumidor, lo cual tiene lógica, considerando que no se pueden cubrir en ningún mercado financiero.

  1. Abandonar el sistema de seis periodos en la facturación de la commodity

Lo primero que llama la atención a cualquier comprador de electricidad en España es el sistema de seis (o tres) periodos de facturación de la commodity (la parte propiamente relacionada con la energía). La mayoría de los países se han adaptado a dos periodos, peak y off-peak. En Alemania, a menudo vemos la facturación simplificada de la commodity mediante un solo precio por MWh, sin tener en cuenta cuando se ha consumido. En cambio, España continúa anclada al antiguo sistema de facturación de sus mercados regulados basados en los seis periodos. Podemos entenderlo en lo concerniente a las tarifas de la red, pero no lo entendemos en la facturación de la commodity.

Si observan el mercado mayorista en España y Portugal (www.omip.pt), se darán cuenta de que también se ha implementado la estructura dual de baseload-peakload que se puede encontrar en otros mercados. El problema es que los seis períodos tales como se define para el cálculo de las tarifas de accesos a la red, no se ajusta a estos dos productos. Esto significa que un comercializador que está cobrando a su cliente en una base de seis períodos, corre el riesgo de tener una falta de correspondencia entre lo que su cliente le está pagando y lo que está pagando él en el mercado mayorista en base a dos períodos. Para cubrir este riesgo, los comercializadores españoles incluyen en sus facturas una prima de riesgo.

Esto explica que la diferencia entre el mercado mayorista y el minorista sea más alta en España que en otros países. Si los comercializadores pudieran facturar a los clientes finales en un sistema dual peak y off-peak o como en Alemania, un precio único basado en un porcentaje de baseload y un porcentaje de peakload, el precio que cobrarían a sus clientes finales reflejaría mejor el precio que ellos pagan por la cobertura de la oferta en el mercado mayorista. De esta manera, podrían reducir sus primas de riesgo para cubrir la diferencia entre los seis y los dos períodos. En realidad es muy simple. Cuanto mejor refleje un contrato de venta lo que un proveedor tiene que hacer en el mercado al por mayor para cubrir su posición, más bajo es el margen de venta. Es sorprendente que los comercializadores españoles no hayan descubierto todavía este potencial para la reducción de sus precios y el consiguiente aumento de sus cuotas de mercado. Los consumidores finales deberían darse cuenta de este potencial de ahorro y ejercer presión de manera activa sobre sus proveedores para conseguir contratos en los que el precio de la commodity ya no se base en el sistema de seis períodos.

  1. Poner a disposición de los pequeños consumidores contratos más flexibles.

En un proceso de liberalización, hay un cierto patrón según el cual los contratos ofrecidos a los consumidores finales se desarrollan. En una primera fase, los precios fijos se ofrecen como una alternativa a las antiguas tarifas reguladas. A continuación, los contratos multi-click o modelos de contratos por tramos se introducen para dar a estos consumidores la oportunidad de gestionar el riesgo de la fijación de un precio de la energía en un mercado volátil. En una última fase, el mercado alcanza su madurez a medida que estos contratos multi-click se convierten en productos más avanzados.

Es normal que dichos productos avanzados se introduzcan inicialmente para grandes consumidores y luego gradualmente desciendan hacia el resto de segmentos del mercado. Por otra parte, destacar que muchos de los pequeños consumidores no necesitan este tipo de contratos avanzados y pueden alcanzar sus objetivos de gestión de riesgo con simples contratos multi-click o modelos de contratos por tramos. Sin embargo, en España, el desarrollo de este tipo de contratos más avanzados parece haberse estancado. España es ahora, por ejemplo, el único país de Europa Occidental en el que un consumidor de energía de 10 GWh tiene dificultades para conseguir ofertas que le permitan fijar su precio en diferentes momentos para gestionar el riesgo de la compra. En algunos casos, sólo hay un proveedor dispuesto a ofrecer un contrato flexible y esto pone al comprador en una posición muy incómoda. Y en el mercado del gas, las opciones para cambiar los precios variables indexados al petróleo a precios fijos son muy pobres en comparación a lo que estamos acostumbrados en otros mercados europeos cuando aún predominaban las formulas indexadas al petróleo.

Una vez más, resulta extraño que los comercializadores de energía españoles no se percaten de que la oferta de servicios de cobertura de precios más avanzados puede ayudarles a ampliar su cuota de mercado. Los comercializadores argumentan que esto se debe a que los consumidores españoles no solicitan este tipo de productos y que sólo quieren seguir fijando sus precios en un momento único, incluso cuando se consumen grandes cantidades de energía. El precio del mercado mayorista de energía eléctrica en España ha fluctuado en más del 20% en los últimos tres años. Los consumidores de tamaño medio deberían tener acceso a los contratos que sean necesarios para hacer frente a ese riesgo. Y todos los consumidores en general deben tener acceso a mejores servicios de cobertura de precio.

  1. Reducir los costes de las tarifas de acceso a la red e impuestos

Hace unos años, cuando hicimos comparaciones de precios internacionales, España destacó como un país con precios relativamente bajos de la electricidad. Esa posición se ha perdido y recientemente, un mayor número de clientes internacionales están empezando a cuestionar esto. Como se puede observar en la tabla anterior, los altos precios de la energía española también se deben al hecho de que sus tarifas de acceso a la red y los impuestos están entre los más altos de Europa. Sin embargo, también se puede ver que las tarifas de acceso a la red y los impuestos españoles están en línea con otros países que – como España – han sido pioneros en la instalación de plantas de energías renovables, como Alemania y Bélgica. Hay algunas razones para tener tarifas de acceso a la red e impuestos de la electricidad altos en España. En cualquier caso se debe remarcar que en Alemania y Bélgica los negocios con un alto consumo energético tienen más posibilidades de tener exenciones que en España.

El problema de mantener un límite sobre las tarifas e impuestos de la red en España, está estrechamente relacionado con una crisis global en cuanto a la regulación de los mercados energéticos. Está, por ejemplo, estrechamente vinculado con el problema de los servicios complementarios. El gobierno español ha acumulado una deuda histórica en el sector mediante la congelación de los precios en el pasado. En estos momentos se encuentra atrapado en una fuerte disputa sobre la forma de pagar esta deuda. Esto pone al gobierno en una posición difícil cuando tienen que negociar las tarifas. Solucionar este problema es necesario para mantener el coste de la energía para el consumidor final bajo control.

  1. Aumentar la interconexión

Algunos de los problemas antes citados están relacionados con el hecho de que España y Portugal son una isla energética. La posición geográfica de la península Ibérica es, obviamente la causa principal de este hecho, permitiendo conexiones por tierra únicamente con Francia. Pero Francia en sí misma está bien integrada en el mercado del noreste europeo y además tiene abundancia de energía nuclear. Por tanto, es muy extraño que en la actualidad sólo haya una capacidad de interconexión de 1.400 MW disponible entre España y Francia. Como hemos señalado anteriormente, el mercado de la electricidad de España no ha logrado desarrollar prácticas de mercado que ahora son comunes en el resto de Europa. Una mejor integración física en el mercado europeo podría desbloquear la situación.

En lo que concierne al mercado del gas, España (y Portugal) es un caso paradójico. Como en el caso de la electricidad, la conexión transfronteriza con Francia es limitada y la falta de capacidad de conexión norte-sur dentro de Francia es también un problema añadido. Pero a diferencia de la electricidad, el gas natural puede ser transportado por barco. La península ibérica con sus siete terminales de GNL situadas en las rutas de navegación entre Oriente Medio (y en África Occidental, y América del Sur) y el noroeste de Europa, debería de permitir un arbitraje de precios que regule un aumento de precios en España con los precios del noroeste de Europa como el TTF. Pero no está sucediendo. Los proveedores de gas en España señalan rápidamente al aumento de precios en Asia y Sudamérica como la razón que empuja los precios hacía arriba en la península. Pero eso no responde a la siguiente pregunta: ¿por qué un buque de GNL proveniente de Qatar se dirige al Reino Unido para vender su gas cuando el precio para el consumidor final en España en este momento es un 75% más alto que en el Reino Unido?

La ausencia de un mecanismo Hub que funcione correctamente es una razón para ello. Pero no es la única. También hay fallos en la regulación y en los mecanismos de fijación de precios para infraestructuras clave tales como las terminales de GNL, en la capacidad de almacenamiento o en la capacidad de los cuellos de botella de la red. El ajuste del mercado gasista español pedirá algo más que la introducción de un Hub correctamente diseñado. También serán necesarios ajustes en muchos otros aspectos de la regulación del mercado de gas. El incremento de capacidad de interconexión con Francia podría mejorar aún más la situación del mercado español. Es importante remarcar sin embargo, que esto debe combinarse con una mejora de la capacidad de conexión norte-sur dentro de Francia. De este modo, podría conectar España directamente con el mercado TTF y crear un interesante corredor Norte-Sur en la red europea de gas. Sin embargo, la mejora de las condiciones para la importación y exportación de gas natural licuado en España debe ser la principal prioridad ya que podría ser una solución sin duda menos costosa y más rápida.

Como se ha explicado antes en este blog, es ampliamente discutido si la liberalización de los mercados energéticos hace bajar los precios de consumo. De lo que no hay duda, es que en una liberalización bien diseñada, el margen minorista que los comercializadores añaden a los precios de los mayoristas decrece gradualmente. De hecho, hemos observado esto en muchos mercados a lo largo de Europa. Además el nivel del servicio en términos de gestión del riesgo de precios normalmente aumenta. Nada de esto se ha observado en el mercado español, lo que demuestra que su proceso de liberalización necesita aún ser ajustado. Los seis problemas discutidos en este artículo del blog permiten a las empresas de energía (proveedores y operadores de la red) optimizar sus márgenes a expensas de los consumidores finales.

Imperfecciones y defectos en la regulación conducen a beneficios extraordinarios para las empresas de energía que los explotan. El ajuste de estos problemas serviría para detener dichos ingresos inesperados, incrementando el capital a disposición de la industria española. También podría reducir los precios que pagan los consumidores residenciales, poniendo a disposición más renta para los hogares españoles con dificultades. Está claro que conseguir ajustar correctamente el mercado energético en España supondría un gran apoyo para su economía en recuperación. Por lo tanto, debería ser prioritario en la lista de deberes de sus gobiernos.

De lo que no cabe duda es que Spain is not different, por supuesto, como en cualquier otro país, su mercado tiene sus propias características, en parte debido a su geografía y a su historia. Pero los problemas (o retos) citados en este artículo han ocurrido también con anterioridad en cada uno de los otros países europeos. Nosotros no vemos ninguna razón fundamental para que España sea el único país de Europa que no pueda solucionar dichos problemas. El triunfo en el mercado energético español vendrá dado por aquellos que estén deseando aprender de las lecciones aprendidas en los países que han liberalizado sus mercados más efectiva y rápidamente. Desde E&C estamos listos para utilizar nuestra experiencia adquirida a lo largo de Europa y Estados Unidos para ayudar en ello a los consumidores finales del mercado español.

Bedenkingen bij een nakend stroomtekort

Below you can find an interview in English about the Belgian situation

De angst voor een tekort aan stroom beheerst de krantenpagina’s. Terecht, want het stilleggen van drie kerncentrales maakt de kans op een (tijdelijk) deficit een stuk groter. In wezen is de situatie vrij eenvoudig. De combinatie van stroom invoeren uit Nederland en Frankrijk, industriële bedrijven tijdelijk uitschakelen en reservecapaciteiten aanspreken zou normaal gezien zelfs op een dag zonder wind en zon genoeg moeten zijn om het uitvallen van deze kerncentrales te compenseren. Problemen krijgen we wanneer het koud wordt. Dan verbruikt Frankrijk met zijn vele elektrische verwarmingstoestellen zijn stroom zelf en kan niet meer uitvoeren naar België. Dat maakt een stroomtekort waarschijnlijk.

 

Hoe dit stroomtekort zich zal manifesteren is een open vraag. De stroomvraag kan van uur tot uur zeer sterk verschillen. Daardoor zou een tekort zich maar gedurende beperkte tijd moeten voordoen. Wanneer elke stroomproductie installatie uit zijn voegen barst om voldoende te kunnen leveren, verhoogt uiteraard de kans op een echte black-out, een totaal stilvallen van het hele Belgische stroomsysteem. Het is de beheerder van ons transportnet Elia die dat moet vermijden. Zij lijken de nodige plannen daarvoor klaar te hebben. En Elia is een zeer gereputeerd bedrijf op het vlak van netbeheer. We mogen dus hopen dat het stroomtekort beperkt blijft tot enkele uurtjes zonder stroom in landelijke gebieden. Alhoewel ook dit voor de nodige ‘collateral damage’ zal zorgen bij bedrijven die toevallig in zo’n gebied liggen.

 

Als een stroomtekort zich al voordoet. Het zou ook opnieuw een milde winter kunnen zijn waardoor de vraag (in Frankrijk) niet piekt. Of koude dagen zouden met veel wind(-energie) kunnen komen. Of het zou kunnen blijken dat ons stroomsysteem over onverhoopte flexibiliteiten beschikt. Het is namelijk niet langer een systeem van alleen maar grote centrale productie-installaties maar van vele kleine installaties die in de rekenmodellen niet altijd correct in te schatten zijn. De kans op een tekort is verhoogd, maar het is geen certitude. Dit is wat beleidmaken inzake energie zo moeilijk maakt, zowel op de macro-schaal van een regering als de micro-schaal van een bedrijf dat zijn aankoop-opties overweegt. Over de toekomst kan je nooit iets met zekerheid zeggen.

 

Wat moet ik dan doen als bedrijf?

  • Goed opvolgen of je al dan niet in een zone ligt die Elia kan uitschakelen.
  • Samen met de technische mensen nagaan welke kritische processen je tegen stroompannes moet beschermen met noodaggregaten.
  • Indien een stroompanne grote economische schade kan aanrichten kan je verdere uitbouw van noodcapaciteit overwegen.
  • Indien je noodstroomvoorzieningen aanlegt, kan je zeker ook overwegen of je die kan gebruiken op uren waarin de spotprijzen hoog oplopen om ze op die manier wat terug te verdienen.
  • Bedenk bij dat alles zeer goed dat het geen certitude is dat een tekort met afschakelplan en hoge spotprijzen zich effectief voordoet. Kosten voor noodstroomvoorziening moet je dus in eerste instantie als een verzekeringspremie beschouwen.

 

Op economische vlak blijft deze situatie nu al niet zonder gevolgen. De prijs voor Belgische stroom in 2015 is al naar 50 euro per MWh gestegen. Dat is bijna 15 euro per MWh meer dan de prijzen die we momenteel zien in Duitsland en ook hoger dan in Nederland en Frankrijk. Enkel UK en Italië hebben op dit ogenblik hogere forward elektriciteitsprijzen dan België. Dit betekent dat iedereen die nu nog prijzen moet vastleggen voor volgend jaar een stuk meer betaalt. En ook hier moet je die forward prijs vooral als een verzekeringspremie zien. Indien we de winter beter doorkomen dan we dachten, dan zouden de spotmarkten wel eens flink onder die 50 euro per MWh kunnen handelen. Deze situatie toont nogmaals het belang aan van een goede energie inkoop strategie. Met een goed gedefinieerde strategie weet je precies hoe je op dergelijke situaties moet anticiperen en reageren.

Ook al doet het tekort zich straks niet voor, toch kan je er niet omheen dat de huidige situatie op een falend energiebeleid wijst in ons land. Dit is zeker zo wanneer je de problematiek in een bredere internationale context plaatst, iets wat ook de laatste weken maar al te weinig gebeurt. Het tekort aan productie-capaciteit in België doet zich voor in de context van een Noord-Europees overschot. De grote Europese stroombedrijven klagen op dit ogenblik vooral over het feit dat er te veel is geïnvesteerd. Dit maakt elke verklaring van het Belgisch probleem die veralgemeent zinloos. Professor Albrecht bijvoorbeeld, beweert dat een tekort aan investeringen in klassieke fossiele centrales onvermijdelijk is in een vrije energiemarkt waarin hernieuwbare energie wordt gesubsidieerd (zie hier). Dan luidt de vraag: waarom is er dan in Duitsland en Nederland wel geïnvesteerd? De vraag naar het waarom van de huidige situatie in België luidt dan ook best: “wat heeft België verkeerd gedaan waardoor de steenkool- en gascentrales in de omliggende landen en niet bij ons zijn gebouwd?”

 

Als ze deze vraag al durven stellen, dan beantwoorden politici ze vooral door naar elkaar te schieten. Politici die aan de nieuwe regering bouwen, schuiven de schuld van zich af naar de vorige regeringen. Politici die voordien het energiebeleid maakten proberen de handen in onschuld te wassen. Dat helpt ons natuurlijk niet veel vooruit. Feit is dat de Belgische politiek in de afgelopen vijftien jaar heeft gefaald in het voeren van een consequent energiebeleid. Op alle vlakken is er al te veel koud en warm tegelijkertijd geblazen. En met een grote diversiteit aan energieministers, omwille van de versnippering van bevoegdheden en vele regeringswissels, was er ook weinig coherentie. De volgende factoren in het bijzonder hadden een belangrijke bijdrage tot de huidige situatie:

 

  1. De oorlog die een aantal politici hebben gevoerd met eerst Electrabel en vervolgens GdF-Suez, waardoor onze grootste stroomproducent alle goesting om te investeren in zijn Belgisch productie-apparaat is verloren.
  2. Ondanks deze oorlog is de Belgische overheid er niet in geslaagd om de dominante positie van GdF-Suez echt te doorbreken. Daardoor was er sprake van grote koudwatervrees bij buitenlandse producenten om in België te investeren. Zoals een directeur van een buitenlandse energieleverancier het ooit tegen me zei: “De regering klopt zich op de borst omdat ze het aandeel van Electrabel in de productie van 90% naar 75% laten dalen. Voor mijn moederhuis is dat nog altijd een heel dominante positie en een rem op de zin om in België te investeren.”
  3. Dit probleem is aangewakkerd door het flip-flop beleid inzake de kernuitstap. Zonder zekerheid over de hoeveelheid (qua marginale kost goedkope) nucleaire productie waarmee je moet concurreren, is een investering in grootschalige stroomproductie uiteraard zeer riskant.
  4. Zelfs wanneer er al zin was om in België te investeren, is die volledig gesmoord in byzantijnse vergunningsprocedures. Zonder vergunningsproblemen had E-On een grote steenkoolcentrale gebouwd in Antwerpen, die goed van pas had kunnen komen volgende winter. Federaal minister Magnette had deze centrale een productievergunning gegeven, Vlaams minister Schauvlieghe weigerde de milieuvergunning. Een mooi voorbeeld van het totaal ontbreken van een gecoördineerd beleid. Het niet-bouwen van elektriciteitscentrales, van oplossingen voor het mobiliteitsprobleem of zelfs voetbalstadions maakt duidelijk dat het in dit land zeer moeilijk is geworden om grootschalige infrastructuurwerken vergund te krijgen. Daar moeten we ons toch vragen bij stellen.
  5. De vrijmaking van onze stroommarkt is onvoltooid. De overheid heeft zich enorm gefocust op de retailmarkt en weinig op de groothandelsmarkt. Zo is het financieel verzekeren van prijzen in de futuresmarkten nog altijd pover in vergelijking met andere landen. We hebben geen peakload en maar een beperkt aantal kwartaals- en maandenproducten beschikbaar op de Belgische futuresmarkt en de liquiditeit blijft laag. Wie een grote centrale bouwt wil goede hedgingmogelijkheden in een liquide groothandelsmarkt. Die hebben we dus niet in België.

 

De situatie die we nu kennen is dus eerder te wijten aan te weinig eerder dan te veel vrije markt. Het voorbeeld van omliggende landen toont aan dat een coherent energiemarktbeleid wel degelijk tot een positief investeringsklimaat kan leiden. Wat in vijftien jaar fout ging, krijgen we natuurlijk niet op een paar maanden tijd hersteld. Dit maakt de grootschalige verklaringen van de laatste dagen dan ook nutteloos. Johan Vandelanottes voorstel om kabels naar de omliggende landen leggen is een zeer goed idee. Zie hier. Maar de reeds geplande en vergunde kabel naar Duitsland bijvoorbeeld laat nog tot in 2019 op zich wachten, voor een kabel naar de Clauscentrale in Maasbracht moeten bij mijn weten de vergunningsprocedures nog opgestart worden. Ook de NVA-idee van een nieuwe kerncentrale is al even weinig een oplossing op korte termijn. Recente ervaring in Finland en Frankrijk heeft aangetoond dat tien jaar een minimum is om van de tekentafel tot productie te komen.

 

Bovendien lijkt nieuwe kernenergie nu ook niet zo’n goede idee, zeker niet in het licht van de huidige problematiek in Doel en Tihange. Proponenten van kerncentrales hebben altijd volgehouden dat deze betrouwbare, veilige en goedkope energie oplevert. De drie stellingen kan je in twijfel trekken.

 

  1. Zoals we op dit ogenblik in België merken is de betrouwbaarheid relatief. Door haar grootschaligheid maakt kernenergie onze globale energievoorziening net heel kwetsbaar. Een letterlijk klein probleem ter grootte van haarscheurtjes brengt onze hele energievoorziening in gevaar. Wanneer je de stroomproductie verdeelt over een groter aantal kleinere productie-installaties die verschillende technologieën gebruiken, ben je minder kwetsbaar.

 

  1. Net zoals Fukushima tonen de haarscheurtjes ook aan dat we qua veiligheid van kerncentrales niet altijd zo slim zijn als we denken. De veiligheid van kernenergie is altijd gepropageerd op basis van de lage kans op een ongeluk, wat op zich al een redeneerfout is (risico is namelijk de kans dat iets zich voordoet maal de ernst van de gevolgen, in het geval van kernergie maakt een zeer hoge ernst-factor de lage kansfactor ongedaan). Maar na Fukushima lieten geleerden weten dat de kans op een nucleair incident blijkbaar groter was dan tot dan toe was berekend. Onze kansrekening is dus niet zo robuust. Benieuwd met hoeveel de risicofactor gaat verhogen wanneer het haarscheurtjes-probleem terdege onderzocht is.

 

  1. En tenslotte is kernenergie helemaal niet zo goedkoop als velen beweren. De variabele productiekosten zijn inderdaad heel laag, wat hun marginale kost laag houdt. Maar kernenergie vraagt zo’n hoge investeringen dat energiebedrijven die maar willen maken mits flinke subsidies. De vaste kosten zijn immens. NVA zou er goed aan doen om eens naar het voorbeeld van de UK te kijken. EdF wil maar bouwen in de UK mits een gegarandeerde elektriciteitprijs van 92,5 pond per MWh gedurende 35 jaar. Dat is een pak meer dan wat we tegenwoordig in Vlaanderen aan subsidies betalen voor windmolens en zonnepanelen. Voor de 17 miljard pond die de UK wil geven aan een nieuwe kerncentrale kunnen ze een pak hernieuwbare energie en kabels naar de omliggende landen bouwen. Zeg me dus nooit meer dat kernenergie goedkoop is. Net zoals de regering in London zal ook NVA merken dat wij voor een nieuwe kerncentrale met flink veel subisidiegeld over de brug moeten komen. Is dat verstandig besteden van overheidsgeld wanneer de technologie minder veilig en betrouwbaar is?

 

Wat kunnen politici dan wel doen? Zij staan voor een zeer groot dilemma. Elke poging om als ingrijpende overheid de productie-capaciteit te verhogen, zal zich vertalen in subsidies die uiteindelijk bij de burger en/of stroomverbruiker terechtkomen. Denk maar aan de capaciteitsvergoedingen voor gasgestookte centrales. Is dat geld verstandig besteed wanneer er in de bredere Europese markt sprake is van overschotten aan stroomproductie? De keuze voor nieuwe kabels naar die overtollige MWh’en in de omliggende landen is dan ook economisch de beste. Voor een oplossing op middellange en lange termijn lijkt het me dan ook onontbeerlijk dat we nadenken over hoe we het vergunnen en bouwen van deze kabels kunnen versnellen. Moet het echt tot in 2019 duren voor die kabel naar Duitsland klaar is?

 

Nieuwe kabels leggen betekent echter dat we ons voor onze energiebevoorrading sterk afhankelijk maken van Europese solidariteit. En met name in het energiebeleid toont Europa zich daar niet altijd van zijn sterkste kant, waardoor een oproep tot meer eigen productie begrijpelijk is. Als we dus toch inzetten op meer inlandse stroomproductie dan lijkt het mij goed om vooral kleinschalige productie te stimuleren. We zouden bijvoorbeeld kunnen overwegen om de subsidie van wind, zon en WKK minder scherp terug te schroeven dan gepland. Investeringen in deze technologieën kunnen in kortere tijd gerealiseerd worden, de MWh’en die ze produceren dragen bij tot een verlaging van de commodityprijs en het behalen van de klimaatdoelstellingen. Ervaring in Nederland heeft aangetoond dat de WKK-capaciteit in de tuinbouwsector voor een mooi potentieel aan flexibele stroomproductie kan zorgen, wat de problemen van beschikbaarheid van hernieuwbare energie deels kan oplossen.

 

Over subsidies aan hiernieuwbare energie en WKK beslissen de gewesten, dus is eindelijk eens een coördinatie over de verschillende beleidsniveaus heen aangewezen. We kunnen alleen maar hopen dat de urgentie van de huidige situatie er toe leidt dat de nieuwe regering plaats maakt voor een energie-minister met daadkracht en een duidelijke bevoegdheid tot coördinatie van de gewestelijke initiatieven. Nationalistische gevoelens mogen dit niet in de weg staan. Onze markt is de Belgische markt en het probleem van de energievoorziening treft alle Belgen. Omdat de kabels erover heen lopen, zal een probleem met een stroomtekort niet aan de taalgrens stoppen.

 

Ondertussen is het voor komende winter “met de billen dicht”. Hopen op mild weer en/of onverhoopte flexibiliteiten in het systeem. De regering in lopende zaken heeft terecht aangegeven dat er in de afgelopen jaren wel degelijk één en ander is gebeurd om de flexibiliteit te verhogen door maatregelen te nemen inzake reserve productie-capaciteit, afschakelbaarheid van bedrijven en een noodplan. Het zou goed zijn dat politici nu kijken of er op korte termijn iets kan gebeuren om de mogelijkheden van deze maatregelen verder te maximaliseren. Zou het geen mooi gebaar zijn naar de Belgische burger dat de politici van de zittende en de zich vormende regering daarvoor samenwerken? De overheid moet ook duidelijk met de burger communiceren over het noodplan. Op die manier kunnen burgers en bedrijven zich voorbereiden. Inzake energiebeleid zijn er nu al lang genoeg politieke spelletjes gespeeld. Met een nakend stroomtekort is het tijd dat de politiek zich eens van zijn meest daadkrachtige kant toont.

 

E&C’s voorstellen voor het oplossen van het Belgische stroomprobleem zijn dus:

 

Op korte termijn (winter 2014 – 2015)
  • Kijken of de maatregelen inzake reservecapaciteit en afschakelbaarheid nog verder benut kunnen worden
  • Duidelijk communiceren over het noodplan
Op middellange termijn (winters 2015 – 2020)
  • Inzetten op kleinschalige productie door de subsidies van groen & WKK niet te snel terug te schroeven
  • Nagaan of de bouw van extra interconnectie-capaciteit met Duitsland en Nederland niet kan versneld worden
  • Onvolkomenheden inzake de werking van de Belgische groothandelsmarkt voor stroom wegwerken
Op lange termijn (na 2020)
  • In samenwerking met alle beleidsniveaus een strategisch plan voor het energiebeleid uitwerken dat België opnieuw aantrekkelijk maakt voor investeringen in productie-capaciteit
  • Het beleid inzake vergunningen van grootschalige projecten hervormen
  • Blijvend inzetten op energie-efficiëntie, daling van de vraag

 

End-consumers: beware of capacity payments

As of 2015, the UK will be the first European country to launch a capacity mechanism that aims at rewarding power plants for the MW’s they can produce. Similar plans for paying for MW’s are developed in other countries, including Belgium and Germany. We believe that there are serious reasons for concern as far as the end consumers are concerned because:

  1. The cost of paying for capacity will very likely be passed through to the end consumers, which are already suffering from excessively high power costs due to the sharp increases of the non-commodity part of the bill.
  2. On top of that, such capacity payments might be an expensive solution for a problem that doesn’t exist.

 

Why have capacity payments disappeared from energy pricing after liberalization?

Those among you that have been buying energy long enough to remember the regulated markets, will know that these prices contained important capacity components. The regulated tariffs paid for all elements of power supply: production, the supply itself and the grid utilization. As these tariffs were based on a dual structure of euro’s per kW (of capacity) and euro’s per MWh (of consumption), the single, monopolist utility received money (for the capacity payments) even when the consumption was very low.

When markets were liberalized, the different utility functions were split up. Grid utilization remained a (regionally) monopolistic market and continued to receive money based on a regulated tariff with the dual kW and MWh structure. That’s quite logical. Grid companies have high Capex and fixed costs, due to the high investments that are necessary for building the grids. A grid tariff with a high capacity component means that the grid companies continue to enjoy stable income, even when the number of MWh’s travelling over their infrastructure is going down sharply. The capacity-based payments are therefore creating a stable investment climate. This is precisely what the monopolistic utility deal is all about. The government gives the utility the certainty of clientele (the monopoly) and of stable income (fees independent of the consumption). The counter-side of that deal is the fact that the monopolistic utility is regulated. The government determines the tariffs and can make sure that this doesn’t lead to excessive profit-making by the monopolistic utilities.

The liberalization was all about introducing competition in the production and supply functions of the utilities, the so-called commodity part of the energy bill. Interestingly, the capacity components all but disappeared from commodity pricing. The whole market organized itself on a purely “per MWh” basis.

As far as the production or wholesale market is concerned, the powerful marginal cost pricing mechanism was introduced. Marginal cost pricing basically comes down to the following:

  • Let’s say that on a given hour, all the power stations within an electrical system (e.g. the Belgian market), can produce 12 million kW of capacity. (For simplicity’s sake, I’m disregarding the impact of cross-border trading.)
  • You can draw up for that hour a so-called “merit order” by ranking the power stations (and the KW’s that they can produce) according to their marginal cost, the cost that the power plant needs to make to produce the extra MWh. All fixed costs, such as Capex, are obviously excluded from marginal cost, as they have been made already. In the case of power plants, marginal cost is almost exclusively fuel cost, regardless of whether you produce the MWh or not. As a merit order goes from small to large, it will start with renewable energies, that have zero fuel costs, go on to the nuclear power stations, with their low fuel costs, and then, at the far end of the curve coal-fired and/or gas-fired power stations, depending on the relative cost of coal and gas at the moment. (For simplicity’s sake, I’m disregarding the impact of carbon prices on marginal cost pricing here. I’m also disregarding oil-fired power stations as they have become quite rare.)
  • Let’s say that during that hour the demand for power, what all consumers together need, is 10 million kW.
  • If we look back at our merit order now, we can draw a line, passing vertically through the curve exactly at 10 million kW.
  • Now let’s say that the power station that – according to the merit order – can produce that 10 millionth kW, is a gas-fired power station with a 50% efficiency, and the natural gas price at that moment is 25 euro per MWh. This means that this marginal power station has a marginal cost of 50 euro per MWh as you need 2 MWh’s of gas to produce 1 MWh of electricity.
  • Now here comes the nice thing. Let’s say that the market is willing to pay 50 euro per MWh for supply of electricity at that moment, i.e. everybody pays 50 euro per MWh for each of the 10.000 MWh delivered during that hour. This means that every power station on the merit order before the marginal power station will make a profit and that the marginal power station itself is break-even. In this case, the supply will exactly match the demand. If the market wants to pay only 49 euro per MWh, then the marginal power station will refuse to supply. A shortage occurs, pushing prices up until you reach the equilibrium.
  • If you repeat this search for the equilibrium at the marginal cost of the marginal plant for every hour, than you can make sure that no power station ever has to make a loss on variable cost, every producer is always sure that he has a positive cash-flow with more money coming in from the electricity sales than money flowing out for buying fuel.
  • For those power stations to the left side of the marginal power station on the merit order, these positive cash-flows are the money that they have available for covering their fixed costs.

Marginal cost pricing

Figure 1: Marginal cost pricing for power supply

The exact size of the marginal cost is depending on a variety of parameters:

  • The demand itself. In hours of high demand, the price will be higher than in hours of low demand.
  • The composition of the merit order. Expansion of the overall capacity of power stations with low variable cost will cause marginal costs to go down.
  • The fuel costs. If gas and/or coal prices go down, marginal costs go down.

Marginal cost economics have installed themselves in wholesale electricity markets (both spot and forward) in a way that I consider to be of almost aesthetic beauty (I am aware how geeky this sounds). I’ll come back on that in a later blog article. One of the reasons that power markets have so readily embraced marginal cost economics is the overall cost structure of power plants. In an almost perfect way, the power plants with the lowest variable costs have the highest fixed costs and vice versa. Being on the left side of the merit order, high investment-cost power plants like renewables or nuclear, will always be “in the money”, meaning that they can produce and turn in positive cash-flow whenever they are capable (unless their combined supply is larger than the demand, something we’ve seen recently in Germany, resulting in negative spot prices). As these are the power plants with the highest capex, it also means that they have most euro’s available for paying back the investments. On the other side of the merit order, gas-fired power stations might have less hours during which they turn in money, but then they also have the lowest investment costs.

In the retail markets, payments of the commodity (or the deregulated) part of the electricity bill is in almost every country of Europe on an exclusively per MWh basis. Some incumbent suppliers have continued to include capacity components in their commodity pricing, but most have now given up. Either they buy the electricity on a per MWh basis in the wholesale market. Or they have an opportunity cost in euros per MWh when they source directly from their production – they could have sold it in the wholesale market at a price in euro per MWh. Therefore, selling it on to their retail market customers in euro per MWh is the simplest, most transparent and lowest risk option, which explains why it has been widely adopted.

 

Why are governments thinking about introducing the capacity payments again?

Marginal cost pricing is by its essence more volatile than pricing according to tariffs that contain fixed cost elements such as capacity components. They will drop lower and rise higher. Volatility makes everyone nervous, including governments. Let’s explain this with the example of Germany. In the last three years, the wholesale prices of electricity in Germany have dropped to a historically low level due to a combination of factors:

  1. Like in most countries, power demand in Germany has dropped, meaning that the vertical line indicating the marginal power plant has moved to the left, causing plants on the right side of the curve to be ‘out of the money’ during many hours.
  2. Germany has seen an exponential expansion of its renewable power production. As all of these are on the left side of the curve, they have pushed the coal- and gas-fired power stations to the right, making it more difficult for them to be ‘in the money’.
  3. After the announcement of a nuclear phase-out in 2000, utilities in Germany and surrounding countries like the Netherlands have launched an intensive investment campaign in coal- and gas-fired power stations, due to which it is now quite crowded on the right side of the curve.
  4. Low coal and carbon prices have made the marginal cost price of coal-fired power stations drop dramatically, dragging the power price along with it.

price reduction

Fig. 2: German power cost reduction explained with marginal cost economics

Utilities are obviously complaining. They are not only seeing how assets are being pushed out of the money, the lower cash-flows on the assets in the money are also weighing on their profitability. The big losers are the gas-fired power stations. The combination of low coal, carbon and marginal prices with relatively high gas prices has pushed them far out of the money. These utilities are therefore lobbying actively for the installation of a capacity market or some other form of subsidizing power stations so that they continue to receive money even when they can’t sell their MWh’s because they are out of the money. Peter Terium, the CEO of large German utility RWE, for example, defends the introduction of a capacity markets with the words: “you don’t pay the firemen only when there is a fire” (Handelsblatt, 4th of March 2014).

The German Energy Minister Sigmar Gabriel seems to be hesitating whether he should give in to these calls for the creation of a capacity market or not. He calls for regional solutions rather than rolling it out on a national scale. Surprisingly, the UK, which was the first country to fully embrace energy market liberalization, is now also the first country heading for the introduction of a capacity market. The problem of the UK market is different from the problem in Germany. In the UK, policies to switch from coal- to gas-fired power generation, a nuclear phase-out and hesitant renewable energy policies have resulted in a production park with a very large share of gas-fired power generation (40%). You simply have a crowded right side of the curve of your merit order, meaning that too many power stations are out-of-the-money or just very slightly in-the-money. And as gas-fired power stations are (or were?) about the only ones for which it is (or was?) possible to obtain a permit, the government sees a need to intervene.

I find it very logical that energy companies are not happy with a situation of low profitability in which they struggle to pay back their investments. And giving its track record, I am not surprised that utilities call for the governments to help, to subsidize. Because in the end, whatever shape it takes, capacity payments are a subsidy. It’s the government organizing an extra source of income for the utilities. You can call it a capacity market, but it will never be a real or natural market. With a natural market I mean a market where an actual need for goods or services is economically arranged. As far as power is concerned, this natural market is the euro per MWh market. Just like that other artificial market, the carbon market, the capacity market will only exist because the government has decided that it should exist. If the government decides to cancel the capacity market, it will cease to exist, and we will still be having power. If the natural euro per MWh market for power ceases to exist tomorrow, then our lights will go out.

Now why have politicians been convinced of the need to create this artificial market for capacity? Even if there is no natural need for it, does it cater for some deeper need that markets cannot detect? The argument in favor of capacity payments which is used by utilities and politicians is that the market in euro per MWh isn’t giving enough incentives to invest in power plant capacity in a way that safeguards long term security of supply. Utilities naturally exaggerate this risk, using the powerful political argument of ‘the lights shutting down’. I don’t agree with that point of view, first of all because of personal experience. I’m working in the energy sector for 15 years and during that whole period I have heard about these threats of running out of power production capacity. The lights are still burning … Germany now produces large amounts of renewable energy. Industry insiders have always said that the intermittency issues of renewables would cause problems. Well, Germany has an extremely low outage rate of 15 minutes per power consumer per year, one of the lowest figures in the world. Power supply systems have proven to be much more flexible and capable of adapting to changing circumstances than most analysts estimate. Utilities, analysts and politicians acknowledge that there is no problem at this moment. It would be very strange if they did so, considering that the low commodity prices for electricity at this moment have a solid basis in excess supply capacities. So, what the capacity payments are supposed to solve is a problem of the future. I was hesitating to write ‘potential problem’ here. But apparently, the proponents of capacity markets are not. They make powerful projections about a future in which a power supply shortage is certain to occur. That’s forecasting, and I’m always very skeptical of that, especially when it’s done by someone who has a conflict of interest, which is clearly the case for an industry representative lobbying to get an extra source of income. In particular, I think that in this case the forecasts of looming shortages are colored by a combination of neglect and exaggeration of the following aspects:

  1. The overall decline in power demand is often disregarded or minimized. Industry representatives link it too exclusively to the economic crisis. They assume (or hope?) that demand for power will start growing again as soon as the economic crisis is over. In doing so, they neglect more fundamental drivers of power demand decline such as delocalization of industry and most importantly the effects of climate policy. Just have a look at the reductions in capacity (Watts) of the lamps that you buy, and you will understand that consumption might nog just start growing again in a phase of economic expansion.
  2. Analysis of the long term capacity issues is too often limited to one country, neglecting the fact that cross-border trading can deliver a very important contribution to their solution. Shutting down gas-fired power stations in Germany might seem like a very big problem, but it is less so if you take into account the excess gas-fired power production capacities across the border in the Netherlands. EU Commissioner Oettinger is also against capacity payments and emphasizes the cross-border aspect. See for example the following article in the Frankfurter Algemeine. As far as the UK is concerned, for example, it is very curious that not more attention is paid to the idea of expanding the transmission lines across the Channel to continental Europe with its excess capacities and low prices.
  3. Many of the assumptions put forward by the proponents of capacity payments are simply not materializing. With more renewable energy on the grid, peakload – baseload spread would widen and spot markets would become excessively volatile. I really don’t see any proof of that. The system seems to be capable of absorbing much more variability than those who have designed and built in could have ever imagined. Still, many analysts continue to put these assumptions forward as a given and are followed in that by politicians, without anyone doing an attempt at providing empirical evidence.
  4. When utilities announce that they will shut down gas-fired power plants, they don’t always mean that these plants are taken offline definitively. There will be just a few cases in which the plants are actually completely shut down, with all the equipment dismantled. In many other cases, the utility will have the possibility of more or less rapidly re-opening the plant when prices (in euro’s per MWh) increase. Now, if we are really heading for a shortage of production, this increase is exactly what should happen. So, we might end up with a shortage of warm kW’s, power stations that are ready to start producing at any moment. That could cause prices to go up at certain moments. That would create an incentive for the utilities to warm up these kW’s again, something which might happen quite rapidly.
  5. Analysis of the market factors driving this situation is based on a static view of markets. In the last three years, the coal, natural gas, carbon price combination has been highly unfavorable for gas-fired power stations. It’s logical that utilities consider shutting down these ‘out-of-the-money’ plants. But when the gas-prices fall, these plants might get ‘in-the-money’ again quite rapidly. As a matter of fact, at this moment gas prices have dropped considerably. The spot price for gas has dropped below 16 euro’s per MWh recently, meaning that high-efficiency gas-fired power stations are turning in money when the electricity prices are in the lower thirties. Owners of gas-fired power stations should have been making reasonable amounts of money recently. Are they telling this to the politicians when they are lobbying for capacity payments?

 

What will capacity payments mean for the end consumers?

Very simple: the price of electricity will go up. The capacity payments will be compensated by adding an extra cost item to end consumers’ electricity bills. Some argue that this will be compensated by lower commodity (euro per MWh) prices. I don’t think so. If the capacity payments are handed out to existing power stations, nothing changes to the merit order curve. The power stations will still switch on and off at the same marginal prices as before, so nothing will change to the market price. The only thing that will happen is that utilities will benefit from a source of income that they didn’t have before. The capacity payments will simply be a transfer of cash from power consumers to power producers. Can such a transfer be justified at this moment in our economy? Yes, utilities are turning in less cash than before. But should their customers be victimized for that?

I can understand that for utilities the current situation isn’t nice. But they are not the first sector that goes through a phase of reduced profitability due to over-investment. That is the root cause of currently low prices. Utilities have over-invested in coal and gas-fired power capacity based on forecasts of a supply shortage that didn’t materialize. They have also invested a lot of money in renewable energy, raking in the subsidies that governments were giving for that. The marginal cost pricing made them win massive windfall profits on left of the curve assets in the 2005 – 2008 period when higher coal and gas prices caused marginal costs to go up to levels three times as high as what we currently see. Should the government step in immediately now that the wheel has spun around to the other side? Should they make the end consumer pay for that? Or should we rather say to the utility sector that it should accept normal entrepreneurial risk and don’t ask for a subsidy when their forecasts don’t materialize? Seeing assets turning in less money than expected is daily reality for businessmen in many different sectors. Why should the energy sector be an exception and get support from the government as soon as the weather turns bad on their investments? I see clients of mine in the food industry building large factories that in the best case will turn in just a few percentages of margin and assuming large risks in the soft commodity markets. They don’t ask for subsidies when they have a bad year.

For an end consumer, the conclusion is very simple. Mobilize your lobbying organization to avoid the introduction of capacity payments. At the same time, prepare yourself for its introduction by investigating you possibilities for reducing its impact with load management.

 

What are the alternatives?

From the above, it might be clear that as a policy option, the introduction of capacity payments should be carefully considered. Especially since I believe that there are alternatives:

  1. The first one is very simple: just let the market work. If there is a shortage of (gas-fired) power production capacity, prices in those hours when gas-fired power stations are needed will rise high, creating an incentive for investment in gas-fired power capacity. Yes, the different speed of changes in demand and changes in supply will create bust and boom cycles in the prices. But that’s not unlike many other businesses.
  2. I totally agree with Mr. Oettinger that capacity issues need to be addressed on a European and not on a country-by-country scale. Enlarging the overall electrical system for which the supply and demand need to be balanced can seriously reduce the overall shortage. Consumption peaks will not occur at the same time in the different countries. And enlarging the ‘copper plate’ will also lead to more diversity in sources of supply, leading to a more balanced merit order curve and hence less problems with the marginal cost economics. If anything, the current issues should be a strong incentive to invest in extensions of cross-border connections. Belgium in particular should work on this instead of a capacity payment mechanism.
  3. When a shortage of gas-fired power station occurs, prices during the hours of peak consumption will rise, creating an incentive for consumers to reduce consumption during these hours. Again, let the market work. Addressing a supply-demand problem by working on the demand side will always be less expensive than working on the supply side. If the government wants to do anything, it could give further support to demand side management by creating incentives for large consumers to switch off capacity at peak moments through the regulated grid fees.
  4. As the example of the UK shows, the biggest issues occur when a production park becomes unbalanced. Well-diversified merit orders are the best guarantee for a healthy supply – demand balance. If the government wants to intervene, it could use its classical legislative instruments such as permit regulations to safeguard the diversity of the production park. Nowadays, permit procedures often take years, meaning that valuable time is lost in the adaptation of the supply side to changes in the market dynamics. Governments should do all they can to avoid this loss of time. In the case of Belgium, for example, I am convinced that the horribly slow permit procedures and the flip-flopping in the overall energy police have made a larger contribution to the current problem of looming capacity shortages than market deficiencies.
  5. If after all these previous measures there is still a shortage of power capacity, ‘reserve capacity’ support should be in the shape of support to grid companies for keeping gas-fired power stations open for absolute peak hours.

Here’s my plan for an alternative to the introduction of capacity payments, a more cost-efficient and fairer way of reducing capacity shortage, avoiding unnecessary increases of energy prices for the consumers:

  1. Continue the climate policy measures aimed at reducing consumption.
  2. Expand cross-border capacities and stimulate cross-border trading initiatives such as market coupling.
  3. Continue to support renewable energy, especially now that its investment costs have dropped. Combined with the previous measure more capacity on the left side of the merit order curve can reduce the need for more capacity on the right side.
  4. Support demand side management where it is realistic.

The end result could be a market where we produce ever lower amounts of power in renewable power stations and in gas-fired power stations at peak moments. If the grid in which this electricity is balanced is large enough and there is a good cushion of demand side adaptations, I don’t think that this will result in the sort of price peaks and blackouts that energy industry representatives predict. Introduction of capacity payments should be the solution of last resort, not the first thing we should think about. I know that if we introduce them only when the supply shortages manifest themselves, it will take some time for the extra capacity to be built. But I would rather risk two or three years of high peak prices and short blackout periods than risk an unnecessary and massive shift of money from power consumers to producers for solving a problem that in the end never materialized. We shouldn’t lightly risk creating a massive subsidy scheme that could result in over-capacity of unneeded gas-fired power stations.

Les risques lies au marché français de l’électricité – The risks of the French electricity market

Please find the English version below.

Aujourd’hui, il est plus que jamais temps de se concentrer sur le marché de l’électricité. La fin des tarifs réglementés l’année prochaine et le risque d’une augmentation du prix de l’ARENH en cours de route nous impose de contractualiser dès aujourd’hui avec un fournisseur, dans un contexte de prix de marché actuellement plus bas que l’ARENH. Il est urgent de mettre en place des actions car la fenêtre des opportunités peut rapidement disparaitre.

Gérer les risques d’évolution du prix de l’ARENH et des prix de marché donc devenu un challenge et chaque décision peut avoir une influence directe sur votre budget. Le marché français est devenu le marché le plus complexe en Europe. Si vous voulez apprendre plus de ce sujet, vous pouvez demander le white paper « Les risques lies au marché français de l’électricité » écrit par Baptiste Desbois, notre expert sur le marché Français, par envoyer un email à joke@eecc.eu


Until recently, the challenges and the opportunities related to the gas market in France were still the main issue. Today, we need to focus on the electricity markets since a lot is changing. Not only will the regulated tariffs disappear at the end of next year, there’s also the risk of the ARENH tariff increasing.

The energy markets are declining in most of the European countries and the market prices in France too, are lower than the ARENH tariff. This opportunity could quickly disappear. Managing the risks of two prices, the market prices and the ARENH price is very challenging and every decision can have a direct impact on your budget. The French market has become one of the most complicated markets. Baptiste Desbois, our French expert wrote a whitepaper about the risks of the French electricity market.

If you’d like to read this whitepaper, please send an email to joke@eecc.eu to receive the full copy.

 

The gap between Belgian and German electricity prices

Belgian year ahead baseload power in the wholesale market is now more than 14 euro per MWh more expensive than German power. In the spot markets, prices since the beginning of this year have on average been 6,72 euro per MWh more expensive in Belgium compared to Germany. Two years ago the German price was still more expensive than power in Belgium. But then German power started to drop more rapidly. I see two main reasons for these cheap wholesale prices in Germany. First of all, the rapid expansion of renewable electricity in Germany has had an undisputed bearish effect on prices. On top of that, Germany is producing much more electricity from coal than Belgium. And as coal prices have declined, this has helped to push down wholesale power prices in Germany even further.

 

In the last three years, wholesale electricity prices across Europe (UK being the most notable exception) have generally been falling. Simple supply and demand economics are responsible for that. With pockets full of cash due to the windfall profits of high wholesale prices in the 2005 – 2008 period and inspired by reports of a looming supply shortage, European energy companies engaged in an intensive investment campaign in new production capacity. The Netherlands, for example, has expanded its power production capacity by 8.846 MW in the 2009 to 2014 period, and most of that is conventional gas-fired and even coal-fired capacity (Source: Tennet). The supply capacity boom was further enhanced by the fact that renewable energy expanded much more rapidly than anyone had ever expected, specifically in Germany. This unexpectedly rapid expansion was provoked by generous subsidies and solidified by rapidly dropping technology costs. At the same time, the economic crisis and successful climate policies caused an electricity demand decline rather than the expected increase. The result is a global European market of overcapacity for power production.

 

The stupefying thing, as far as Belgium is concerned, is that amid all this excess supply it has managed to put itself in the position of a country with a supply shortage. This and only this is the explanation for the price rift between Belgium and its surrounding countries. The spread between Belgian and German wholesale prices widened recently due to the outage of two nuclear power stations in Belgium on security concerns. But this might just give policymakers a too easy excuse for the current situation. In the past years, Belgian power production capacity has dropped. It is clear that Belgian energy policy has failed to create the conditions for attracting investments in capacity expansion. Germany has not failed in achieving that. And that’s why the wholesale prices in Germany are lower.

 

The main reason for this failure of Belgian energy policymaking has an institutional character. I don’t want to tire foreign readers of this article with the quagmires of Belgian politics, but still, the complexity of its institutions has contributed a lot to this policy failure. In the last decade, Belgium has had many different energy ministers from many different parties. Energy policy tends to be a heavily colored by ideology, so all these changes in ministers have caused multiple turnarounds and flip-flops. On top of that, in Belgium with its complicated structure, the responsibility for energy policy is spread over the federal and regional decision-making level. Even if the federal minister seems to have most impact on security of supply issues, important aspects such as renewable support mechanisms or authorization procedures are decided by their Flemish, Walloon and Brussels counterparts (yes, city-region Brussels has a separate energy policy). This institutional framework isn’t exactly beneficial for the creation of the consistent policy that you need to attract investments in energy infrastructure which are typically high capital cost investments with extended realization periods. Examples of these policy failures are:

 

  1. Belgian energy policymakers have often focused on fighting highly symbolic battles with incumbent supplier and producer Electrabel (now part of the GdF-Suez group). Despite the rhetoric, it took them a very long time to really do something about Electrabel’s dominant position, discouraging alternative suppliers to invest in Belgium.
  2. Belgium launched a nuclear phase-out policy and then renegotiated it, and renegotiated it and renegotiated it. This obviously created a lot of uncertainty and refrained energy companies from investing in large-scale fossil fuel-fired power production in Belgium.
  3. Belgium (i.e. the Flemish, Walloon and Brussels’ regions) launched ambitious, generous support schemes for renewable but then rapidly withdrew them as the cost of this for the end consumer became clear.
  4. Politicians kept dreaming about energy independence and only realized the importance of increasing cross-border capacity when the security problems with the two plants surfaced. For example, there still is no cross-border capacity with Germany, it is only planned to be operational in 2019. This is obviously especially painful at this moment when German wholesale power is so much cheaper.

 

At the end of this month, the Belgians go to cast votes not only for their European representatives but also for their federal and regional parliaments. Many are hopeful that after these elections, having a few years in a row without new elections will create the sort of stable political climate necessary to put en route necessary reforms. Let’s hope we can also see the sort of reforms of energy policy necessary to normalize energy pricing. Now that investment costs in renewable energy have dropped a lot, it should be carefully considered whether some extra support for renewable couldn’t be a cheap and climate-friendly part of the solution. And there is no doubt that in a context of supply shortage with excess supply capacities in neighboring countries, rapid investment in cross-border capacity is an inevitable option. With the current price differential between Belgian and German power in view, we highly recommend to speed up the Alegro project that connects both markets. Do we really need five more years to build that line? Supporting gas-fired power stations with capacity payments is a bad idea. It will cause extra cost as these subsidies find their way to the end consumers’ bills. And with their high marginal costs, I can’t see how these gas-fired MWh’s will reduce the commodity price.

 

With the price rift peaking, industry representatives were very rapid to complain about the disadvantage it creates for Belgian companies competing with German companies. We obviously have to highlight here that the wholesale power price is only part of the overall electricity bills. On top of that, a consumer pays a retail margin to its supplier, but these margins are minimal in both countries, so they are not creating much difference. The main difference can be found in the grid fees and taxes. These are much higher in Germany than in Belgium, but energy-intensive consumers can benefit from large reductions on these high grid fees and taxes. The situation is therefore as follows. If you’re a German company for whom electricity cost is more than 14% of its added value and with more than 7.000 hours of load duration, you will pay almost nothing for grid fees and taxes. But many German companies that don’t meet only one or none of these criteria pay a lot more for consuming power than any Belgian company. Nevertheless, coming on top of important differences in grid fees and taxes, large price differentials in wholesale prices are creating unnecessary competitive disadvantages within Europe. However, we have to consider that today’s winners may be tomorrow’s winners. Belgian industry representatives pleaded for a long time to increase cross-border capacity on the French border and not on the Dutch and/or German borders. This wrong choice of border is now contributing to the competitiveness problem.

Dernier appel pour une politique gazière efficace

This article is only available in French as it’s about the French gas market.

Les tensions actuelles entre la Russie et l’Ukraine exacerbent les pressions sur les prix alors même que la France continue de prendre une position radicale contre le gaz de schiste. En parallèle, la libéralisation du marché gazier français est encore loin d’être optimale. Les conséquences se sont clairement fait ressentir cet hiver pour certains consommateurs de gaz dans le Sud du pays : ils ont payé les prix les plus élevés d’Europe. La France ne peut plus se permettre de nier l’importance du gaz naturel dans le mix énergétique actuel. Cette situation est également la conséquence d’un manque de connaissance du fonctionnement du marché de la part des consommateurs. Baptiste Desbois, conseiller en achat d’énergie et Ingénieur des Mines d’Alès, vient de publier le livre « Panorama : le marché du gaz en France » pour faire le point sur ce sujet.

L’ouverture du marché a favorisé l’apparition de nouveaux fournisseurs et l’on pourrait légitimement s’attendre à un marché plus compétitif par le jeu de la concurrence. Pourtant, d’importants écarts de compétitivité existent entre les différentes places de marché de l’hexagone. Les prix spot du sud étaient par exemple plus de 40% plus élevés que les prix spot du nord en décembre 2013.

Par ailleurs, il est étonnant de constater que peu de consommateurs se sont tournés vers les nouvelles offres de marché malgré les économies possibles. Les tarifs réglementés historiques sont encore fortement indexés sur un panier de produits pétroliers dont les prix n’ont plus de liens avec les nouveaux marchés gaziers. Pourtant, 52% des sites industriels raccordés au réseau de distribution achètent encore le gaz sur base de ces tarifs réglementés.

La consommation de gaz représente aujourd’hui 29% de la consommation nationale d’hydrocarbures. Bien que la scène gazière internationale soit actuellement soumise à de vives tensions, le gaz pourrait prendre une place bien plus significative. Les centrales de production d’électricité à gaz sont par exemple un très bon moyen de soutenir le développement des énergies renouvelables. L’injection de biométhane dans les réseaux et le gaz comme carburant dans les transports pourraient également être des leviers très intéressants.

Le livre aborde l’ensemble des sujets : le gaz dans le bouquet énergétique français, la libéralisation du marché gazier, les infrastructures gazières, les fournisseurs actifs en France, le marché de gros, le marché de détail, la part hors molécule des factures et le gaz non conventionnel.

Désormais, l’acheteur doit passer du rôle de spectateur au rôle d’acteur afin de bien gérer son portefeuille d’achat de gaz et de ne pas rater les opportunités. De nouveaux outils sont proposés par les fournisseurs. Dans un tel contexte, il devient complexe de bien cerner le fonctionnement du marché actuel. L’ambition de ce panorama est alors de fournir au lecteur un outil descriptif complet pour en comprendre les caractéristiques principales. Le livre coûte 49,95 euros et peut être commandé sur le site d’E&C (www.eecc.eu). N’hésitez pas à nous contacter pour plus d’informations et pour toute demande d’interview.

Visitez la page dédiée (http://www.eecc.eu/Pages/MarchedugazFR.aspx) pour plus d’informations ou envoyez un email à Joke Bruneel (joke@eecc.eu), Marketing & Communications Officer.

Interview avec Baptiste Desbois : https://vimeo.com/87091803