La ola de frío hace estragos en el mercado energético español

Prefer the English version? Please find it here.

Los mercados energéticos españoles se comportaron de forma inestable la semana pasada. El jueves 19 de enero, el precio de la electricidad para el día siguiente cerró en 88 euros por MWh, este es el nivel más alto alcanzado desde el 6 de febrero de 2006. El nuevo Hub de gas natural, Mibgas, también alcanzó un máximo llegando a los 41,87 euros por MWh los días 12 y 13 de enero.

Hace frío en España y los turistas en busca de un clima agradable en invierno están siendo sorprendidos con tormentas de nieve y heladas. Las circunstancias siberianas son excepcionales y obviamente causan un pico en la demanda de electricidad y gas. El sistema eléctrico ha encontrado dificultades para hacer frente a este pico. En la Comunidad Valenciana 32.000 clientes se quedaron sin electricidad y la eléctrica Iberdrola tuvo que poner en marcha 23 generadores de emergencia.

Álvaro Nadal, nuevo ministro de Energía, advirtió a los ciudadanos españoles en un comunicado de prensa que se fueran acostumbrando a una energía más cara. El ministro cita todo tipo de argumentos para justificar los actuales precios, junto al aumento de la demanda de calefacción, señala también paradas nucleares, mayores exportaciones a Francia, baja producción de energía eólica y solar, mayor precio del crudo y un alto precio del gas natural. La situación actual muestra una tendencia muy alcista, pero los altos precios de la electricidad y el gas natural en España no son sólo un fenómeno de este invierno. Los mercados energéticos españoles son más caros que otros mercados europeos desde hace años.

Respecto a la electricidad, podemos ver que los precios spot españoles se alinearon con los precios spot alemanes hasta 2014, cuando comenzaron a subir estructuralmente. Los analistas señalan a menudo el alto porcentaje de energía renovable en España para explicar los altos precios de electricidad. Según datos de Red Eléctrica, el 49,9% de la capacidad de producción de energía eléctrica en España es renovable. El viento no siempre sopla y, hasta en España, el sol no siempre brilla, haciendo que los precios del mercado de día siguiente se eleven algunos días y los acontecimientos del último día parecen apoyar ese análisis.

Sin embargo, Alemania tiene un porcentaje aún mayor de energía renovables en el mix de capacidad de producción: un 52,43% de acuerdo con los datos de https://www.energy-charts.de/power_inst_de.htm. En Alemania, un volumen creciente de energías renovables en la red ha tenido un claro efecto beneficioso sobre los precios de la electricidad al por mayor. ¿Por qué no hemos visto el mismo efecto en España?

La situación actual de altos precios y apagones en algunas regiones parece señalar que en España hay escasez de capacidad de producción de energía. Sin embargo, como podemos ver en la página web de Red Eléctrica, el viernes 20 de enero la demanda alcanzó un máximo de 40.294 MW, esta cifra es muy inferior a la capacidad de producción total de 100.088 MW estando incluso por debajo de la capacidad instalada de producción tradicional de energía térmica (carbón y gas), que se sitúa en 41.154 MW. Además, en el momento de mayor demanda, las centrales nucleares españolas producían 7.100 MW, las centrales hidroeléctricas 6.168 MW, las turbinas eólicas 5.007 MW y las centrales fotovoltaicas 675 MW. Sumando estas cifras, realmente no se entiende el por qué los precios subieron tanto.

Es cierto que el equilibrio entre la oferta y la demanda en España está cada vez más ajustado. Con una economía en recuperación, España registra un aumento de su demanda de energía de 0,8% en 2016. Al mismo tiempo, la capacidad de producción cayó un 0,9%, debido al cierre de centrales de carbón. A pesar de ello no olvidemos que la situación general sigue siendo muy cómoda en comparación con otros países europeos como Bélgica o Francia cuando tienen centrales nucleares cerradas.

Entonces…¿Por qué los precios españoles son más altos?

Los productores de energía españoles parecen ser incapaces de entregar a la red una electricidad fiable y con un precio razonable. Los 194.530 MW de potencia disponible en Alemania produjeron 648,2 TWh de electricidad en 2016. Esa es una utilización del aparato de producción de 3.322 horas, siendo mucho mejor que las 2.500 horas de los productores españoles, con 100.088 MW de capacidad instalada produciendo sólo 250.266 TWh. Una vez más, el alto porcentaje de energía renovable en España no es una excusa, ya que Alemania tiene un porcentaje aún mayor.

El ministro Álvaro Nadal debería aprovechar la situación actual para hacer un llamamiento a los productores de energía y exigirles que mejoren su rendimiento. Por otra parte, como hemos mencionado antes, los sistemas que organizan la oferta de energía española y la logística de la demanda son bizantinos y disfuncionales. Súbase a un avión señor Nadal y vea cómo otros países europeos lograron organizar mejor sus mercados: una mejor organización que resulte en una mejor utilización del parque de producción de energía y menores precios de los productos básicos para los consumidores finales.

La semana pasada se podía escuchar en las noticias españolas que los altos precios se debían al uso de “costosas” centrales de gas de ciclo combinado. Sin embargo, en el momento de máxima demanda el viernes pasado, sólo había 2.229 MW de ciclo combinado en operación, lo que representa menos del 10% de la capacidad instalada total de 24.948 MW. Es un hecho, sin embargo, que el costo de producir electricidad con una central eléctrica de gas es mucho más caro en España que en otros países. Esto se debe al alto precio del gas en España.

La mayor parte del gas natural en el mercado energético español aún se comercializa a precios indexados a los mercados petroleros. Los recientes aumentos de los precios del petróleo han provocado por tanto un aumento de los precios del gas en España. Si nos fijamos en los precios de los otros mercados europeos, determinados por los hubs como el TTF donde la demanda y la oferta de gas natural fijan el precio, diríamos que el desarrollo del Mibgas en España es una excelente idea. Sin embargo, una idea sólo es buena cuando está bien ejecutada.

El verano pasado, vimos los precios del hub ibérico Mibgas operando a un nivel similar al TTF. En mayo y junio de 2016, incluso vimos un precio de Mibgas más bajo que el TTF algunos días, lo que generó esperanzas de que finalmente veríamos unos precios normales de gas en España. Sin embargo, a partir de agosto, el precio de Mibgas comenzó a subir por encima del TTF. El 13 de enero, el precio de Mibgas fue 21,14 euros por MWh más caro que el TTF u otros precios del norte de Europa.

Los abastecedores españoles de gas (y los analistas que lo apoyan sin argumentos) apuntan dos razones que causan esta situación:

1. El hecho de que los buques de GNL provenientes de Argelia por ejemplo, en lugar de llegar a la península Ibérica hayan decidido navegar a otros destinos como Asia, donde los precios del gas son actualmente altos.
2. La falta de capacidad de interconexión con Francia y los precios del Norte de Europa.

Sí, los precios asiáticos están reduciendo las exportaciones de GNL a Europa. Pero los 41,87 euros por MWh que encontramos en España a principios de este mes, fue el precio más alto de gas natural en todo el planeta en ese momento, así que ¿Por qué los buques no llegaron a España?

Por otra parte, la reducción de gas natural licuado debido a la alta demanda asiática afecta de la misma manera al TTF, así que ¿Por qué el precio en España es más del doble que en el norte de Europa?

La falta de conexión por gaseoducto hacia el Norte es también un hecho, pero no hay ningún país en Europa que tenga tanta capacidad (no utilizada) para importación de GNL como España. Sólo hay 1.305 kilómetros por mar entre los puertos de Zeebrugge y Bilbao.

El 13 de enero, un comerciante podría haber ganado 21,14 euros por MWh al cargar GNL en Zeebrugge y descargarlo en Bilbao, ese habría sido uno de los trayectos de GNL más lucrativos de la historia, pero ningún barco lo hizo.

España estará mal conectada con el resto del mundo mediante gaseoductos, pero está muy bien conectada con terminales de GNL, el problema es que estos no se están utilizando. ¿Por qué? Porque traer el gas a la terminal de GNL es posible, pero sacarlo de la planta de regasificación y venderlo en el mercado interno español parece ser casi imposible.

España ha sido el último de todos los países europeos en establecer un Hub. Preparándose para ese lanzamiento, España se centró más en cómo organizar los aspectos financieros que los aspectos físicos, pero la parte física es clave. Un Hub debería facilitar el acceso de terceros al sistema de gas mediante el establecimiento de una zona de entrada-salida a nivel nacional y la introducción de un sistema de equilibrio eficiente y rentable. Debido a los altos precios actuales y la falta de liquidez, está claro que Mibgas no ha logrado esto. Una vez más, España ha introducido sistemas que son diferentes de lo que vemos en el resto de Europa. Así que, Ministro Nadal, vaya a echar un vistazo al resto de Europa y arregle este desastre de mercado energético español.

A cold snap wreaks havoc on the Spanish energy market

Spanish energy markets were in turmoil last week. On Thursday the 19th of January, the day ahead electricity price averaged 88 euro per MWh. That is the highest level since the 6th of February 2006. The new Hub market for natural gas, Mibgas, went through the roof as well, racing to 41,87 euro per MWh on the 12th and 13th of January.

It’s cold in Spain. Tourists in search of mild winter weather were caught in snowstorms and frost. The Siberian circumstances are exceptional and obviously cause a peak in demand for electricity and gas. The power system struggled to cope with this peak. In the Communidad Valenciana, 32.000 clients were without electricity and utility Iberdrola had to rush in 23 emergency generators. Álvaro Nadal, the new Minister of Energy is all over the press, warning the Spanish citizens to get adapted to more costly energy.

The Minister is citing all kinds of reasons for the current peaks in prices: next to the increased demand for heating purposes he points out: nuclear shutdowns, increased exports to France, low output of wind and solar, the higher price of crude oil and the high price of natural gas. The current cocktail is indeed very bullish. But the high prices for electricity and natural gas in Spain are not just a phenomenon of this winter. Spanish energy markets are more expensive than other European markets for years.

If we look at electricity, than we can see that the Spanish spot prices were at more or less the same level as German spot prices until 2014 and then started to rise structurally higher. Analysts are often pointing at the high percentage of renewable energy in Spain to explain high spot prices: according to Red Electrica’s data, 49,9% of Spain’s power production capacity is renewable. The wind doesn’t always blow and even in Spain, the sun doesn’t always shine, causing spot prices to rise high on some days. The events of the last day seem to support that analysis.

However, Germany has an even higher percentage of renewable power production capacity: 52,43% according to data of https://www.energy-charts.de/power_inst_de.htm. In Germany, increasing amounts of renewables on the grid have clearly had a beneficial effect on the wholesale electricity prices. Why haven’t we seen the same effect in Spain?

The current situation of high prices and blackouts in some regions seems to point out that Spain has a shortage of power production capacity. However, as we can see on the website of Red Electrica, on Friday the 20th demand peaked at 40.294 MW. That is well below the total production capacity of 100.088 MW. It is even below the installed capacity of traditional thermal power production (coal and gas), which stands at 41.154 MW. Moreover, at the moment of peak demand, Spanish nuclear power stations were producing 7.100 MW, hydro power stations 6.168 MW, wind turbines 5.007 MW and photovoltaics 675 MW. Adding up the figures, you really don’t understand why prices were soaring that much.

It is true that the supply and demand balance in Spain is getting more tight. With a recovering economy, Spain is seeing an increase in its power demand, +0,8% in 2016. At the same time, production capacity dropped 0,9%, due to the closure of carbon-fired power stations. However, the overall situation still looks very comfortable compared to other European countries like Belgium or France when it has nuclear power stations shut down. Then why are Spanish prices higher?

The Spanish power producers seem to be incapable of delivering a reliable, reasonably priced electricity to the grid. Germany’s 194.530 MW of available power capacity produced 648,2 TWh of electricity in 2016. That’s a utilization of the production apparatus of 3.322 hours. That’s a lot better than the Spanish power producers’ 2.500 hours with 100.088 MW of installed capacity producing just 250,266 TWh. Again, the high percentage of renewable energy in Spain is not an excuse, as Germany’s having an even higher percentage.

Minister Álvaro Nadal would better use the current situation to call upon the Spanish power production companies to improve their performance. Moreover, as we have mentioned before, the systems that organize Spain’s power supply and demand logistics are byzantine and dysfunctional. Get yourself on a plane, Mr. Nadal, and go and have a look at how other European countries managed to get their markets better organized. A better organization that results in a better utilization of the power production park and lower commodity prices for the end consumers.

Last week you could hear in the Spanish news that the high prices were due to the usage of “expensive” combined cycle gas-fired power stations. However, at the moment of peak demand last Friday, there was just 2.229 MW of such combined cycle power stations at work, which is less than 10% of the total installed capacity of 24.948 MW. It is a fact however, that the cost of producing electricity with a gas-fired power station is much more expensive in Spain than in other countries. This is due to the high price of gas.

Most of the natural gas in the Spanish energy market is still traded at prices indexed to oil markets. The recent increases of oil prices have therefore caused Spanish gas prices to increase. If you look at the pricing in the other European markets, determined by Hubs such as TTF where the demand and supply of natural gas itself is setting the price, you would say that the development of the Mibgas Hub in Spain is an excellent idea. However, an idea is only good when it’s well executed.

Last summer, we saw Mibgas prices trading at a level similar level as TTF. In May and June 2016, we even saw a lower Mibgas price than TTF on some days. This sparked hopes that we would finally see normal gas prices in Spain. However, as of August, the Mibgas price started to rise high above TTF. On the 13th of January, the Mibgas price was 21,14 euro per MWh more expensive than TTF or other Northern-European prices.

Spanish gas suppliers (and analysts paying them lip service) point at two reasons for this:

1. The fact that LNG ships from Algeria for example, rather sail to Asia where gas prices are currently high.
2. The lack of interconnection capacity with France and the Northern European prices.

Yes, Asian prices are reducing LNG exports to Europe. But the 41,87 euro per MWh that you could get in Spain earlier this month, was about the highest price for natural gas on the planet at that moment, so why didn’t the ships come to Spain? Moreover, the “less LNG due to high Asian demand” counts for TTF just as well, so why is that price in Spain so much higher than in the North of Europe?

Lack of connection by pipeline to the North is also a fact. However, there is no country in Europe that has so much (unused) LNG import capacity as Spain. There is only 1.305 kilometer by sea between the ports of Zeebrugge and Bilbao. On the 13th of January, a trader could make 21,14 euro per MWh by loading LNG in Zeebrugge and sailing to Bilbao. That must be one of the most lucrative LNG trips in history. But no ships did it.

Spain might be badly connected to the rest of the world with gas pipelines, but it is well connected with LNG terminals. But these are not being used. Why? Because getting the gas into the LNG terminal is possible, getting it out and sell it in the internal Spanish market seems to be all but impossible.

Spain has been the last of all European countries to launch a Hub market. Preparing for that launch, Spain was more focused on how to organize the financial aspects than the physical aspects. Whereas the physical side is key. A Hub should facilitate third party access to the gas system by the establishment of a nation-wide entry-exit zone and the introduction of an efficient, cost-effective balancing system. From the current high prices and lack of liquidity, it is clear that Mibgas has failed to achieve this. Again, Spain has introduced systems that are different from what we see in the rest of Europe. So, Minister Nadal, go and have a look in the rest of Europe and get this mess of a Spanish energy market fixed.

New Hydrocarbons Law: Spain finally on the road towards Hub-based gas pricing?

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One of the most remarkable events of the last decade in Europe’s energy markets has been the switch away from oil-indexed gas pricing towards the so-called Hub-model. Oil-indexed pricing for natural gas is a relic from the past, when no open markets for the trading of gas existed. Sponsored by their national governments, monopolist gas companies set up long term agreements with producers of natural gas with durations of up to thirty years. Lacking a price reference for natural gas, it was decided to peg the price to that of the most important competing fuel at that moment: oil.

Even if oil-indexation was a clever marketing strategy in the days of the fuel-switch from oil products to natural gas, when markets are liberalized, it causes some serious issues:

• The long term agreements give important competitive edge to incumbent suppliers, it’s difficult for an alternative supplier to get a contract with a gas producer. Therefore, for getting supplies, these alternative suppliers often have to buy the gas from the very incumbent suppliers that they are supposed to compete with. In the early days of gas market liberalization, we saw that alternative suppliers were often nothing more than resellers of gas that was originally purchased by a large competitor under a long-term agreement. This was obviously a poor basis for alternative suppliers to exercise the sort of competitive pressure that brings down prices,
• Moreover, such long term agreements often contained exclusive rights to the usage of capacity on key infrastructure, such as cross-border connections for the import of gas, LNG terminals or storage sites. This makes it even more difficult for alternative suppliers to develop their business,
• Oil-indexed pricing has a certain degree of mathematical complexity. End consumers often fail to grasp it, making it impossible for them to make a correct assessment of the proposals that they get on their table,
• In some markets (e.g. Germany) the market came with a huge variety of different oil-indexed formulas, making it very difficult to get a correct idea of ‘the’ price level for gas in that country,
• The market of long-term, oil-indexed contracts is not a market with a clear wholesale – retail segmentation. End consumers can only guess what their suppliers pay for the gas to their suppliers. Hence, there is no transparency at all regarding margins, putting the end consumers at a disadvantage in the contract negotiation,
• This overall lack of transparency is also clear when price management services are offered. In many countries, suppliers have a long tradition of offering oil-indexed contracts with services that allow their clients to swap floating prices for fixed, fixed for floating and even swap between different formulas. The suppliers perform the oil market hedging operations necessary to execute such swaps. However, the end client often lacks the knowledge of the formula’s mathematics and the oil market operations to give a correct judgement of whether a fix price e.g. was correct or whether his supplier was abusing the fixing operation to make some extra margin,
• From a point of view of theoretical economics, the oil-indexation is also an ugly beast. It means that the price of one product (natural gas) is determined by the supply and demand dynamics of another product (oil). Hence, the price is not giving a correct signal to producers and consumers. It could be that natural gas is short in supply, but its price is low because of a large supply of oil. At that moment, the consumer is not getting the signal to reduce its consumption and the producer is not getting the signal to increase his production, hence, the market is not restoring the supply and demand balance. I’m pretty sure that Adam Smith would have disliked the idea of oil-indexation of gas,
• Moreover, there’s more natural gas left on the planet than oil. Hence, the chances of over-valuation of natural gas are quite high when you index it to oil. That obviously explains why producers, such as Russia’s Gazprom, have been such fierce defenders of oil-indexation of natural gas. And this is not just economic theory. We have indeed seen that in every country that switched away from oil-indexation towards a hub model, the price of natural gas for the end consumers declined significantly.

The Hub model was first rolled out in the US with its Henry Hub and in the UK. With the creation of NBP, the UK did something enormously interesting, namely the creation of a virtual Hub, on which I will come back. This model was then copied in Belgium (Zeebrugge), the Netherlands (TTF), France (PEG’s), Germany (NCG and GPL), Italy (PSV) and other countries. Today, in most of the countries in Europe, gas is bought based on the pricing on a Hub. We even witnessed market integration, with pricing in those wholesale markets converging and TTF becoming thé benchmark to which prices in end consumer contracts are pegged. For most large industrial gas consumers in Europe, the disadvantages of oil-indexed gas pricing described above have become a thing of the past. They enjoy more transparent gas pricing, and it comes with a better price management service. Moreover, as mentioned above, the switch towards Hub-pricing came with lower prices and important savings. However, some countries have been left behind and haven’t made the switch towards Hub-pricing. One of them is Spain. (Portugal as well, as the Spanish and Portuguese gas markets, like the electricity markets are well linked.)

After years of neglect, the Spanish government now seems to get serious about making the adaptations necessary to reform its gas market and introduce the Hub market model that has been such a boon for gas consumers in other European countries. On the 22^nd of May, the long awaited new Hydrocarbons law was published. Upon first lecture, it seems to contain some elements that could spark the development of a real Hub market on the Iberian Peninsula.

The most important element – no doubt – is the introduction of a virtual Hub. This virtualization of the gas Hub has been first tried out in the NBP with great results and then repeated in many countries, with TTF being the most spectacular example. From a contractual / legal point of view, the “Hub” is the place where the gas changes in ownership. In traditional physical Hubs such as Henry Hub or Baumgarten in Austria, this place is an actual physical location. Before that spot (often a valve on a pipeline), the gas belongs to the seller, after it, it belongs to the buyer. When a virtual Hub is created, the whole transportation grid is defined as being the Hub. Doing so, a whole geographical area, e.g. the whole of the UK or the whole of the Netherlands, becomes one big Hub or Entry-Exit Zone. This means that the seller can inject his gas at any point and it is considered to be delivered at the Hub, and the buyer can extract the gas at any point from the transportation grid, and it is considered to have been taken from the Hub.

Physical Hubs are not as beneficial to trading and retail market competition as virtual Hubs. Sellers of gas need to find access to that specific geographical location where the physical Hub is located and capacities to get there might be restricted, especially if capacity rights have historically been allocated to incumbent suppliers in the framework of long-term gas contracts. And a supplier needs to “route” his gas from that Hub to his end client. Capacity restraints can occur on that route, making it impossible for him to develop clients far away from the entry points at which he has sufficient capacity rights to get gas in. This is clear in the case of Spain, where the distances that are to be covered from injection in the Spanish system to an end client can be large. A supplier that gets his gas delivered in Huelva, on the Southern, Andalusian shore, might have difficulties routing this gas towards clients in the industrial heartland in the North and North-East of Spain. Nevertheless, we have seen the development of a market for locational swaps in Spain, where suppliers swap gas quantities that they can deliver in certain areas with quantities of other suppliers in areas where they can’t deliver. All in all, we can’t say that the Spanish market is suffering from a lack of diversity in offers. When we do gas tenders in Spain, we can easily collect up to ten different offers. What frustrates us, is that they all come with high prices (compared to other countries in Europe), oil-indexation and poor price management services.

The new Hydrocarbons Law talks about the introduction of a virtual Hub for the whole of the Spanish territory. That is a very interesting idea, as I believe that Spain or rather the Iberian Peninsula – contrary to what some suppliers say – has an almost ideal gas system for the introduction of a virtual Hub. The transportation grid is looking a bit like a giant bicycle’s wheel, with pipelines running along the coastlines and through the center (Madrid). Gas can be injected into the wheel at no less than ten places, the pipeline connections with France in the North and North-Africa in the South and eight LNG terminals. Connect all of that in one virtual Hub and you liberate suppliers from the difficulties of getting access to injection points near their clients and getting the capacity rights (or locational swaps) to go from entry to exit. You would expect that this will finally make Spanish gas suppliers and new suppliers develop the sort of competition that we’ve seen in other countries. This could bring important benefits for Spanish gas consumers, such as:

• A cost saving. Currently, we are seeing (oil-indexed) gas prices in Spain in the range of 24 – 25 euro per MWh. Prices on the North-West-European Hubs are in the 22 – 23 euro per MWh range. If due to the Hub development the prices in Spain converge with prices in the rest of Europe we could see a two euro per MWh saving opportunity. And it should be remarked that due to the drop in oil prices, the spread between prices in Spain and Hub prices elsewhere in Europe is historically low. In 2014 the spread was rather in the 10 euro per MWh range.
• Possibilities of buying energy in a different way, with spot indexation and forward products for securing future price levels.

Whether the new law will lead to a rapid development of such a more competitive Hub-based market on the Iberian Peninsula or not is unclear at this moment. The hydrocarbons Law is a general text, setting up the legal framework for developing the Spanish Hub. Whether it will function or not depends on how it will be worked out in decrees and other regulatory texts such as the code for the usage of the grid that is to determine the crucial balancing system. The Law announces the preparation of these important extra pieces of regulation. The devil will indeed be in that detail. The Spanish government has been working on the creation of a Spanish gas market Hub for a long time. As we have remarked here before, the officials seemed to be focusing too much on the financial aspects of the market, the creation of a platform to trade in spot and forward contracts for natural gas. Whereas the success of a Hub depends primarily on getting the physical aspects right, defining a large entry / exit zone and making sure that there are non-discriminatory access rights and balancing services in that zone. So we’ll have to watch carefully for the extra regulatory texts and see if they have the right elements for setting of the Hub market development in Spain.

What is a bit bizarre in the new Hydrocarbons Law is the definition of the entity that would be responsible for managing the balancing system. This is to be a company in which the transport grid company (Enagas) and the organizer of the exchange platform (OMIE/OMIP) would come together. In most other countries, the balancing system is simply run by the transport grid operator. Spain seems to aim at the introduction of some sort of independent system operator. Having the organizer of the exchange platform so tightly involved in the balancing is a reminder of Spain’s confusion of the Hub model with the organization of an exchange. And the preoccupation of the Law with getting involved in the financial aspects of the gas market is reminiscent of the dirigisme of Spanish lawmakers. Spanish energy policy, also in the electricity market, often fails to produce the best and cheapest results for the end consumers because of officials trying to arrange everything in too much detail. But we should give Spain the benefit of the doubt and hope that in the next months, a Hub market for natural gas becomes a reality for Spanish gas consumers, just as we have seen in other countries.

Spanish market: Complementary Services – Is it possible to manage the risk?

During 2013 we have seen a substantial price increase of flexible electricity purchase formulas based on the forward market OMIP. This surge is due to the evolution of the so-called Complementary Services (SSCC).

These complementary services are operations performed by the TSO to ensure a certain level of safety and quality on the energy delivery. Essentially, they are operating capacity reserves for active and reactive power, needed to maintain the technical balance between supply and demand.

The following graph shows the evolution of these costs since early 2011.

During 2011 the average price of the SSCC was around 3 Euro per MWh. However, these costs began to rise above this average during 2012, with price levels as high as 13 Euro per MWh. The main problem does not come from price anomalies. It arises from the growth of the average cost as well as the increase of the volatility. We are currently facing an average price around 5,5 Euro per MWh and a price volatility between 1 and 13 Euro per MWh.

How does the SSCC price evolution affect us when we buy energy? Suppliers must forecast the cost of these services for both fixed price contracts and forward flexible contracts with indexed formulas. As there is no organized market for such services, nobody can hedge the risk. Therefore, the estimation is based on past values, future forecast and a risk premium.

In the situation mentioned above, it does not surprise me that some suppliers faced losses. Could anyone imagine that the SSCC costs would double? Probably not and the suppliers were not able to charge this increase to the clients.

Why did the complementary services boost? Which fundamentals drive their evolution?

There are two main drivers. On one hand, the percentage of “non-manageable” technologies in the energy mix: renewables and nuclear power production. Managing the supply-demand balance for the TSO becomes more difficult using this kind of technologies. As a consequence, the operating costs increase.

For instance, we saw Red Eléctrica (TSO) giving an order to disconnect the wind mills of the grid in April 2013. Moreover, it forced the nuclear plants to reduce 20% of their capacity. This resulted in massive costs. Managing the imbalances between offer and demand with gas-fired plants, on the other hand, is easier and cheaper. Remarkably, Spain is currently using only 10% of its gas-fired installed capacity. On top of that demand levels itself also affect the SSCC price, as these costs are shared by all the consumers. Subsequently, less demand results in a more expensive unit price.

From a procurement point of view, it is essential to assess the risk to which we are exposed. Afterwards, we should evaluate the alternatives the market is giving to manage it.

The first question to be asked, without taking into consideration the volatility of the forward market, is whether your company can bear a 3-4 Euro per MWh fluctuation in the energy bill. If the answer is negative, then the only option is to accept the Spanish market situation and pay the Premium.

If your strategy allows a certain price volatility, keeping these costs as “pass through” could be interesting. Doing so you can avoid you having to pay the risk premium, but does not avoid you paying future price swings. This option is only available if you have an flexible contract indexed to spot market or if you ask for a flexible forward market formula with the SSCC costs not fixed.

Nonetheless, is it possible taking further measures? Is there any other alternative? It is a surging debate in the market. Take into account that the estimation of these costs is based on historical data plus a risk premium. Therefore, it there should be a possibility of having a clause in the contract that enables the client to close the SSCC in the course of the contract duration and before the start of the energy delivery. Such a clause should be transparent and reliable. For instance, the client is able to close the SSCC, using the TSO’s 12 month moving average as a basis plus a risk premium negotiated beforehand.

If the suppliers are willing to give this option, calculating the risk and monitoring the evolution will be possible.

Does anyone accept the challenge?