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

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 22nd 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.

Buying energy in the land of the free

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In April 2014, E&C has opened its New York office and started working for clients in the US energy markets. This first birthday of our trans-Atlantic presence is a good moment to make a first round-up of our experiences with buying energy in the land of the free.

American energy markets go through a period of abundance. The rapid growth of production of natural gas and oil from shale layers has put the country on a path towards energy independence. Wholesale gas prices on a month ahead basis have traded in a $2 to $6 per MMBTU range since 2009. Recently, prices have dropped back towards the lower end of that range, with the month ahead currently trading at $2,684 per MMBTU. That is 8,63 euro per MWh, a price that European gas consumers can only dream of. In power production, coal-fired power stations are rapidly being replaced by stations using the cheaper natural gas. However, anyone thinking that all over the US, natural gas and electricity are cheap could be quite surprised. An industrial client of ours with his plant in Massachusetts pays an all-in electricity price of more than $125 per MWh (113 euro per MWh). When the (European) owner of this company expressed his wonder over the height of this price, we joked that he was unfortunate enough to have located his plant in the energy market equivalent of Germany in the US. Indeed, the high power prices in Massachusetts are partly caused by an ambitious renewable energy program, comparable to green zeal in Germany. What’s causing this diversity?

Transatlantic Energy Conference

The first thing that strikes European observers is that in the land of the free the energy markets are in many aspects not as free or liberalized as in Europe. For electricity, for example, only 16 States have a liberalized market as we traditionally understand it, namely with consumers having a free choice of electricity supplier. However, free enterprise is involved in many aspects of the American energy markets. Even if the end consumer markets are regulated in many States, the infrastructure for supplying electricity and natural gas to the Americans has been developed through a myriad of private initiatives and not centrally planned by a government.  Moreover, the US is a federal country with regulatory competences spread over the different levels (Federal, State and even local). This means that as a market place it is definitely less orderly than what we’re used to in Europe. Nevertheless, the basic challenge for an energy buyer is the same. As you can see from the $2 to $6 range of the gas prices, volatility is high. US energy buyers often have such big difficulties seeing through the complexity of the pricing in itself that they don’t manage to implement a hedging strategy to protect their companies against that volatility. A six-step comparison of US and European energy markets can offer some understanding of this complexity

  • Lack of a clear federal competence for energy market regulation

In Europe, energy market liberalization has been driven forward by the European Union which once started as the European Coal and Steel Community. The EU Member States have granted the EU the authority to decide how energy markets should be structured. The EU uses this power to draft Internal Energy Market Directives that Member States are obliged to implement in their national energy market legislation. This means that many main aspects of energy market design in the different European countries, such as third party access or unbundling, are very similar as they are all based on the same text in the Directive. The US Federal Government has less legislative powers in the energy markets, meaning that there is a much larger variety of systems in the different States.

  • Bottom-up versus top-down market development

Before liberalization, national governments in many European countries often had a strong impact on the organization of their national energy markets, not in the least because in many cases they actually owned the monopolist energy suppliers. That power was often used to build an orderly, centralized energy supply system. It was the national government that ordered where centralized power production plants and gas injection systems were to be built and it was that national government that designed the transport and distribution systems. They made the power- and pipelines neatly stop at the borders. Europe entered its energy market liberalization (as of 2000 in continental Europe) with energy markets largely organized in unified national systems. That made it easy to rapidly push through the liberalization in a top-down fashion.

As I’ve already remarked, the US energy infrastructure has been largely built on private initiative with the government (on a federal, State and local level) limiting themselves to granting authorizations and regulating prices. Some investor company at some point decided to build a power station or a gas production facility somewhere in the US. It was again that same company or another one that decided to start building the transportation infrastructure to bring the power or gas to the end clients in the surroundings. Those power- and pipelines didn’t stop at the State borders, so supply systems were created that crossed the State Borders and within one State different systems were supplying different parts of the State.

So, in top-down regulated Europe, in most countries, one market was created based on one nation-wide supply system. Regulations for organizing those national markets were similar as they were based on the same directives. All that was needed then, was the organization of cross-border trading to move towards one internal European market for energy, a process which is still going on. In bottom-up USA, State regulations had to be applied to different supply & transportation systems and one supply & transportation system is often subjected to different regulations as it’s supplying in different States. Moreover, as these regulations are not based on common Directives, they can diverge widely. In some cases, one supply and transportation system supplies energy to a deregulated, free-choice market in one State and a regulated monopoly market in the next State. The Federal Government has tried to bring some order to the electricity markets by grouping different supply systems in so-called ISO’s (Independent System Operators). But that hasn’t reduced much the regulatory complexity. Moreover, as I will explain in the next paragraph, it has even failed to reduce the often large locational price differentials that we see in the US.

  • No development of entry-exit zones

The places where energy is produced are not always close to the places where it is consumed. Moving energy from one place to another can be quite expensive. Moreover, in the US, with its wide diversity of companies operating transportation systems, moving natural gas or electricity around often means that you have to use the infrastructure of different companies, each of them charging you for the usage, or rather reservation of capacity on their system. Due to these many differences, large differentials in the pricing of energy occur. In the electricity market there are no less than 41 different wholesale price references for forward price fixing. And in the spot market, in Texas alone, you can find more than 4.000 different prices. For natural gas, the situation is somewhat different. The wholesale price of natural gas is almost always linked to the price at the Henry Hub, a physical location in Louisiana. However, for the end client, a basis price will be added to the wholesale value that for a large part consists of costs to buy access to the different transportation systems that a supplier needs to use to get the gas from the production site to the client’s site. Price differentials between two gas supplier’s offers can often be quite large as they might use different production sources and physical routes to go from those sources to a client.

One of the great accomplishments of European energy market liberalization has been the creation of so-called virtual Hubs to solve the problem of locational cost differentials. To understand how this works, I first have to give a clear definition of my usage of the container term “Hub”. In the energy world, a “Hub” is the location where the ownership of the energy is being transferred from seller to buyer. A virtual Hub will be defined as one large entry – exit zone, for example, the whole Netherlands with the TTF Hub. This means that wherever the seller puts its natural gas on the grid (entry) it is considered to be no longer his property, wherever the buyer takes that natural gas from the grid (exit) it is considered to be taken off the grid. The place where the ownership changes is the place where the gas is injected into the Dutch grid for the seller, the place where there is a connection with that Dutch grid for the buyer. Anything that happens in between that entry point and exit point is the responsibility of the transportation grid operator, which is one operator for the whole geographical area encompassed by the Hub. (Note: for a client connected to a distribution grid, the exit point is defined as the connection of that distribution to the transportation grid. However, this nuance doesn’t have any impact on the wholesale pricing).

The creation of such virtual Hubs over large geographical zones offers a myriad of advantages that facilitate the development of liquid, transparent wholesale and retail energy markets:

  1. Energy companies no longer have to go into the markets to obtain the capacity rights to get access to clients in different places within one of those large zones. That makes it much easier for them to launch commercial activities in those zones.
  2. Costs of usage of the transportation grid are no longer billed through commodity pricing but exclusively through the transport grid fee, which (in Europe) is regulated and one price regardless of the physical location. Therefore, there are no more differences in wholesale prices within those Hub zones. This causes the number of wholesale price references to go down.
  3. As one price reference is applied to a large geographical zone, the liquidity of the wholesale trading on that reference goes up, making it possible to develop exchange trading on that price reference. Such exchange traded wholesale prices make the energy pricing much more transparent for end users.
  4. Price levels offered by different suppliers converge more as there are no more differences based on routing of natural gas or electricity.

In the European electricity markets, straight after liberalization almost every country launched a Hub encompassing the whole country with the designation of a single transport system operator delivering balancing services in the whole countries. Today there is for as good as all the European countries one single wholesale electricity price, often traded on a reasonably liquid exchange. Attempts at unifying electricity pricing in the US have been taken through the creation of the 7 ISO’s, but so far they are not run as single entry – exit zones, leading to a huge proliferation of wholesale electricity price references.

For natural gas, many European countries now have one or maximum two Hubs (and price references) within their borders. Think about NBP for the UK, ZTP for Belgium, TTF for the Netherlands, NCG and GPL for Germany, the two PEG’s in France, PSV in Italy, Polpx in Poland, etc. The development of these Hubs have revolutionized Europe’s natural gas markets. Wherever you consume natural gas within these countries, your price will be based on the same wholesale price reference. In the US, no virtual Hubs for natural gas have been created yet. Therefore the buying of natural gas is more complex, with the physical routing having a material impact on the price levels in different places.

  • More complex, less transparent pricing

With a larger diversity of price references referring to the wholesale supply of natural gas and electricity, it is harder to get a good idea in the US of what energy costs. When we talk to European clients, they almost always have an idea of what the underlying price level is of the energy that they have to buy. That’s because European consumers can go and have a look at the websites where the wholesale energy for their market is traded and the price is published, wide and open for everyone to consult. That is impossible for the US. You can find information free of charge for Henry Hub in the natural gas markets, see Side 2 of this document: But there is no source where you can find all the information necessary to make an estimation of the cost of routing the gas towards your facility free of charge. And for electricity, daily pricing data on the 41 price references can only be obtained if you’re willing to pay for it. Therefore, we observe that compared to their European counterparties, most US energy buyers have much less insight into the daily movements of wholesale energy prices. Many of them only get an idea of how high or low the energy markets are by asking offers to suppliers.

To this lack of transparency regarding wholesale energy pricing, we can also add a lack of transparency regarding the non-commodity components of the energy bills. In Europe, grid fees and taxes are almost always regulated in a top-down manner with government sources disclosing information on their price levels. Also, we’ve seen governments in Europe impose transparency upon suppliers, obliging them to disclose full details of price components on their bills. In the US, energy bills are often very opaque with no details at all about the often complicated underlying pricing mechanisms of non-commodity components.

  • More market mechanisms for setting non-commodity price component

The lack of transparency in US non-commodity energy pricing is also due to the fact that in many cases market mechanisms are used to determine those prices, e.g. for the setting of reserve capacity prices. Whereas a top-down regulated grid fee or tax will only change when the government decides (and publicly announces) such a change, these market-based prices change the whole time. And again, there is a lack of transparency, so consumers are often unaware of such changes. Variable non-commodity price components also mean that as a client, you have to make a choice between fixing the price up-front (e.g. in a fixed adder to the commodity price) or leaving it open. But with no information on the price levels or even the structure of the price components, that choice is often very difficult to make.

  • Less usage of advanced price management techniques

It is often true that energy is cheaper in the US than in Europe. But that doesn’t make it easier to buy it. To resume the observations above, compared to Europe, the US energy markets have:

  • Less unity in legislative systems,
  • More geographical disparity,
  • More different pricing references,
  • Less transparency regarding those prices,
  • More market mechanisms influencing non-commodity components rather than having them fixed by a government.

Therefore, a US energy buyer has a much harder time than his European counterparts simply finding out what is on his energy bills and what the drivers are of those prices. He often completely depends on energy suppliers and brokers for information on the energy markets in all their different components. That complexity is often enhanced by the fact that US suppliers and brokers disguise as consultants. Many US companies remain stuck in the mud and never manage to develop the sort of advanced price management techniques that have been widely adopted by European companies. Price management is often limited to a choice between one-shot up-front fixing of the price or leaving it 100% open for spot market indexation. Only big US companies have rolled out contracts and fixing strategies for layered purchasing, fixing prices at different moments, using different forward products and the spot market. US energy companies are therefore often over-exposed to rapid increases of wholesale and non-commodity components of energy prices, such as witnessed in the cold winter of 2014. Fortunately, they now have E&C to help them see through the complexity and take firm control over their energy procurement.

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La fin de l’ « arenhisation » du marché Français

The English version of this article will be available in our E&C magazine. Order your free copy here.

Par Baptiste Desbois.

Deux types de modèles sont proposés aux clients français qui signent une offre de marché : une offre 100% marché ou une offre combinant un volume marché et un volume ARENH. Il semble aujourd’hui que l’ARENH a perdu ses lettres de noblesse en raison de l’attractivité des prix de marché et d’un problème de visibilité (et donc de risque) quant au nouveau prix du volume ARENH. En parallèle, les prix de marché sont devenus volatils.

Pour rappel, la France a mis en place un système très particulier au travers duquel les fournisseurs alternatifs et donc les clients finaux peuvent s’ils le souhaitent acheter de l’électricité produite par les centrales nucléaires d’EDF à un prix régulé appelé prix ARENH (le volume est actuellement plafonné à 100 TWh/an). Le 4 décembre 2014, la Commission de Régulation de l’Energie (CRE) a annoncé que le volume total d’ARENH demandé pour le 1er semestre 2015 s’élèverait à 15,8 TWh. En 2014, les volumes réservés étaient 36,8 TWh pour le 1er semestre et 34,5 TWh pour le 2e semestre. Les consommateurs français ont donc fait le choix de s’orienter massivement vers les prix de marché, délaissant l’ARENH. Ainsi, la CRE explique le plongeon des demandes ARENH par deux facteurs :

  • « l’absence de visibilité sur les évolutions à venir du prix de l’ARENH »

Celui-ci a été fixé à 40 €/MWh à partir du 1er juillet 2011 puis à 42 €/MWh au 1er janvier 2012. Un nouveau prix aurait dû être publié au plus tard le 7 décembre 2013 mais cela n’a pas été fait en raison de l’absence d’un décret du gouvernement fixant la méthodologie du calcul du prix. Un projet de décret a tout de même été établi en 2014 pour soumission à différentes autorités. L’examen de ce projet par la Commission Européenne est encore en cours et a conduit la France à reporter la réévaluation du prix de l’ARENH au 1er juillet 2015. L’annonce de ce délai a été faite le 4 novembre 2014, soit après la date limite de réservation des volumes ARENH pour les clients finaux (Les fournisseurs peuvent réserver les volumes avant la mi-novembre mais ne permettent en général pas à leurs clients finaux de le faire après octobre). Dans un souci de visibilité, beaucoup de clients ont donc opté pour des prix 100% marché. En parallèle, ce communiqué du 4 novembre indiquait que la CRE estime à environ +2€/MWh l’évolution nécessaire du prix de l’ARENH en juillet 2015, sur la base des informations disponibles aujourd’hui.

  • « la baisse des prix sur le marché de gros de l’électricité »

Il est arrivé à plusieurs reprises que les prix de marché tombent sous le niveau de l’ARENH, d’où une remise en question du choix de ce système par rapport à un contrat indexé uniquement sur les prix de marché. Si l’on s’appuie sur l’augmentation de 2 €/MWh estimée par la CRE, il est donc plus opportun de sécuriser aujourd’hui son prix pour les prochaines années sous les 42 €/MWh. Les prix ont cependant été volatils, en fonction des divers bruits de couloirs et annonces. Une hausse brutale avait été observée le 15 octobre 2014. A cette date, la CRE avait publié un rapport sur les tarifs réglementés dans lequel on pouvait lire qu’elle retenait pour certains calculs une hypothèse de hausse du prix de l’ARENH de l’ordre de 2 €/MWh et par an. Les prix se sont ensuite progressivement relaxés, bien que soutenu par la nouvelle estimation publiée le 4 novembre 2014 estimant une hausse de l’ARENH de 2 €/MWh en juillet 2015. Pourtant, dès décembre, les prix sont largement passés sous le niveau ARENH pour toucher les 38 €/MWh. Les acteurs de marché pensent-ils que le prix de l’ARENH ne montera pas ou que le mécanisme sera adapté ? Sont-ils en train de bouder ce système et plaident-ils pour un marché sans ARENH comme dans les autres pays européens ? Il est vrai que les niveaux de production sont relativement sains, les réserves hydroélectriques élevées et la demande orientée à la baisse. En parallèle, les prix dans les autres pays sont aussi en baisse. Est-ce la France qui influence ses voisins ou l’inverse ? Ce phénomène est d’autant curieux dans la mesure où l’effondrement des prix a eu lieu après avoir l’annonce d’une forte baisse des réservations de l’ARENH pour le premier semestre 2015 (signifiant que la demande sur le marché devient élevée). Par ailleurs, avec la fin des tarifs réglementés en France, les achats sur le marché sont logiquement appelés à croître, d’où une pression supplémentaire. Affaire à suivre…

baseload fr

Has the Ukraine Crisis affected gas prices in Western Europe?

French version available, written by Baptiste Desbois

It was hard for market observers to not fall asleep these past two years…European calendar year strips had stabilized at around 26 to 28 euros per MWh in the wholesale market. Then, the situation changed radically in 2014. An exceptionally warm winter decreased demand and drove prices down. Now, market observers have their eyes glued on the Ukraine crisis. Market fundamentals haven’t changed, but a « gas war » with Russia is in the back of everyone’s mind. Yet, after a tumultuous few months, a temporary supply deal has finally been reached: the risk of a supply shortage has been averted, for now. This has allowed consumers indexed on floating formulas to benefit from historically low prices. However, the threat of higher prices has not disappeared: we are still in the heart of winter and this temporary agreement stops at the end of March.

1. Gas and Geopolitics

Geopolitics play an important role in the gas market. The best example of this is the tense and shifting relationship between Europe and its main supplier, Russia. Their strong interdependence makes for a very complicated relationship. Russia has established a strong presence on the European market to affirm its position and secure the delivery points for its gas. The European Union needs this gas but is trying to diversify its supply to reduce its dependence on Russia. However, a solution is not yet within reach. Let’s not forget, after all, that it is these same European countries that wanted to create strong gas ties with Russia in the past. Strong European dependence on Russia gas was a choice, not an obligation.

Three conflicts involving natural gas have erupted between Russia and Ukraine since the 2004 Orange Revolution. The first conflict took place in 2006 when Gazprom decided to align Ukrainian prices with European prices. Following Ukraine’s refusal to abide by these new prices, Russia cut supplies for three days in the midst of a particularly harsh winter. It was revealed over the course of this conflict that Ukraine was illegally diverting gas intended for Europe for its own consumption. In 2008, gas shipments to Ukraine were cut back again due to outstanding debt. The third conflict broke out in 2009 around the same points of contention: gas prices and payment defaults. Gazprom responded once again by shutting off the tap, which resulted in a decrease in supply in Europe. In more recent news, the threat of another gas war is looming with the political crisis in Ukraine.

2. The fourth gas conflict

Russia reacted to the situation in April by announcing two back to back increases in Ukraine’s retail gas price. This included:

  • A first price hike due to the cancellation of a rebate granted in December 2013 following Ukraine’s late payments. The price rose from $268.5 to $385.5 thousand cubic meters.
  • In that same week, a second increase was announced. The new price climbed to $485 thousand cubic meters, one of the highest in Europe. This hike was attributed to the end of an exemption in export rights.

Kiev rejected what is considered to be an arbitrary price increase and refused to pay the bill. Nonetheless, Gazprom decided to implement a prepayment mechanism. If Ukraine were to violate its payment terms again, gas deliveries would be partially or completely stopped. As Russia had received no advance payments, tensions rose until finally it shut off the gas supply to Ukraine on June 16, 2014. Gazprom also indicated that Ukraine already owed a whopping 4.458 billion dollars (1.451 billion from November to December 2013 and 3.007 billion from April to May 2014)1. Luckily, gas shipments destined to other countries were honored.

After several months of negotiations and with the help of the European Union, an interim agreement was finally reached at the end of March 2015. This served to relieve tension hanging over the winter months. As per the agreement, Ukraine can now pay in advance for as much gas as it needs at the lower price point of $385 dollars per thousand cubic meters. Furthermore, it will not have to pay for previous breaches of its Take- or- Pay commitments2. Ukraine will also pay back $ 3.1 billion in debt. This sum was calculated based on a gas price of $268.5 per thousand cubic meters. The total amount of debt owed by Ukraine will be decided by the Stockholm Board of Arbitration. Ukraine has repaid the debt in two sittings and has provided an advance payment for one billion cubic meters in December for $ 378 million3. A transfer of $150 million will follow in January. The alternative of re-exporting gas from Europe to Ukraine from backhaul connections is a problem since it remains Russian gas4. Ukraine reported receiving less gas from the European Union via backhaul flows following Gazprom’s warning about the the legality of these operations5. In September, the manager of the Polish network Gas -System also indicated that the reductions in supplies from Russia had forced him to stop re-exports of gas to Ukraine6. This is therefore a very complicated issue…

3. Then why did prices drop?

During this episode, market prices were trending downwards. In fact, levels reached at the end of 2014 were historically low. Some volatility / nervousness was felt following successive announcements. After all, Russia supplies about 30 % of Europe’s gas. However, the halt of gas shipments to Ukraine has not fundamentally affected supplies to Western Europe. Dependence on Russian gas is much lower compared to that of some Central European countries. So what explains this downward trend? Here are three main factors behind lower prices:

  • Ukraine is not the only transit route for Russian gas to Europe. Russian gas can be shipped from the Yamal pipeline to Poland or to Germany through the North Stream pipeline under the Baltic Sea. Note that Gazprom cannot use more than 50 % of the capacity of its OPAL prolongation due to European regulations1. As a result, a large part of Russian gas does not transit via Ukraine. Russia does not seem to want to reduce the shipments delivered through these alternative routes. The risks are therefore much more limited than in previous gas crises, when fewer alternatives to Ukrainian transits existed. There are also many more connections between European countries then before and even some two-way transport capacities.
  • The mild winter reduced European demand. As a result, storage levels were very high throughout year. These were filled up to 66% at the time of the disruption of supplies to Ukraine and continued to increase to over 95 % in September. Aside from the mild weather, gas demand has been declining for the past three years amid an economic crisis, substitution of gas by coal and renewables, and improvements in energy efficiency. Société Générale predicts an 11% reduction in gas consumption in 20148.
  • A significant increase in natural gas liquefaction capacity is anticipated at the international level. If all goes as planned, Australia will surpass Qatar and become the largest exporter of liquefied natural gas before the end of the decade. The United States is also rapidly entering the race, with several upcoming projects. On the other hand, shipments delivered to Europe have reached historically low levels in recent years as they have been redirected to more profitable parts of the world such as Asia. However, spot prices in Asia have also trended down in recent months due to a drop in demand9. This has allowed in increased an increased in LNG shipments to Europe. For instance The Fosmax LNG terminal in the south of France reported beating its LNG unloading record in November.


Evolution of Seasonal Gas Prices on the TTF Exchange

Supply shortages could be repeated in the absence of a new agreement between Russia and Ukraine beginning in April 2014. However, a momentary interruption in gas supply at the end of winter will probably not have immediate consequences. The stress test conducted by the European Commission shows that prolonged rupture in supply would have a substantial impact on the European Union but indicates that protected consumers would remain unaffected if all countries cooperate with each other. However, prices could be affected. Furthermore, any unexpected event can occur at any time and upset the markets. Fukushima is the best example. Japan had to compensate for the sudden closure of nuclear power plants with thermal gas plants. Both demand and prices had climbed very quickly as a result. This tumultuous episode shows that we still have some ways to go before we can enjoy a risk-free market. Central European countries are particularly sensitive to this issue…

4. What can we do going forward?

Herman Van Rompuy considers that “we have let our dependence on Russian gas become too high.” Europe is trying to reorganize its energy market in response to this problem. This is a legitimate goal, but it will not be accomplished overnight. One must also keep in mind that new sources of supply will not necessarily come cheaper. LNG is one way to diversify. LNG shipments to Europe have decreased for the past few years but boosting imports would be easy. The market could take advantage of new liquefaction capacities in the coming years (depending on demand and the “willingness to pay”). For example, the largest LNG import terminal in Europe will be built in Dunkirk. However, regasification infrastructure would also need to be developed in countries most dependent on Russian gas, like Lithuania. A floating terminal, baptized “Independence” was installed in Klaipeda. This project, dubbed a “success story” by Oettinger11 will also relieve other Baltic countries. Other such projects are underway. Strengthening internal circulation routes is also a key. ACER indicates that at least one third of the connection nodes between E.U. member states are congested12. E.U. states have recently agreed to allocate € 647 million for the most important energy infrastructure projects13. The biggest allocation is intended for the construction of a gas network from Poland to Lithuania14. It is also necessary to strengthen the links between North and South. France could benefit from a new pipeline with Spain called Midcat. Spain is 100% independent of Russian gas. Discussions have been lingering for years, but this project is on the list of projects that are of strategic importance to the European Commission15. The pipeline would bring gas to Northern Europe provided that odor problems are resolved between France and its neighbors. In this scenario, Spain could cover 10% of Europe’s Russian gas imports from Europe16.

Europe is also working on its supply sources and is in favor of the development of the Southern European gas corridor that would link up to Azerbaijan via for example the SCPX, TANAP and TAP pipelines or even the Nabucco project, which has been left on the back burner. These pipelines can benefit from the recent abandonment of the South Stream gas pipeline from Russia to Austria, hampered in part due to European regulations relating to third party access to the network. Putin said he wanted to favor other markets because “that is the choice of our European friends”17… Finally, to reduce external imports, European production would need to be increased. Unfortunately, production levels have been falling steadily since 2004. This is why the controversial debate on shale gas has returned to the front of the stage … In Britain (where production has dropped sharply in recent years), the company Cuadrilla Resources has announced that it would be ready to produce shale gas within four years if a state of emergency was declared because of the crisis in Ukraine. Gas companies are obviously on high alert. But committing to shale gas is more complicated than simply striking a balance between economics and environmental risks. Improving energy efficiency and increasing the share of renewables is another way forward, despite the fact that gas power plants are a great way to overcome renewable’s irregularities in production. If such is the case, then why not make a transition towards bio methane? A small revolution in the world of networks began with injections of bio methane in fifteen European countries.18

These events have at least revived the debate. Significantly altering Europe’s energy supply will not happen overnight. It will take years. Moreover, Europe is linked with Russia by long-term contracts. These will first have to expire before alternative links can be created. Finally, even if Russia continues to defend oil-indexing, it is in its interest to not increase prices too much as higher prices would give energy alternatives a boost in Europe. A contained pricing policy may even ensure its continued dominance in Europe’s gas supply. This is not necessarily a bad thing for Europe from a strictly economic point of view. The cause of the tensions observed in recent years is also strongly linked to the accumulation of Ukraine’s debts. Russia hasn’t tried to disrupt the supply of gas to the European Union so far. Its deteriorating economic situation would make this unreasonable. Russia has guaranteed several times that shipments to Europe would not be affected. Securing transit zones is therefore as important of a goal as finding new supply sources. It will certainly be interesting to keep an eye on future developments.

La crise ukrainienne a-t-elle eu un effet sur les prix du gaz en Europe occidentale ?

You can find the English version here.

Par Baptiste Desbois, auteur du livre Panorama : le marché du gaz en France

Au cours des deux dernières années, le principal défi rencontré par les observateurs du marché  gazier était de ne pas s’assoupir… Les prix calendaires européens s’étaient stabilisés dans un tunnel de 26 à 28 euros par MWh sur le marché de gros. La donne a pourtant radicalement changée en 2014. L’hiver exceptionnellement doux a apaisé le marché sur le court terme, avec une diminution marquée de la consommation.  Pourtant, même si rien n’affecte physiquement les fondamentaux du marché, les acteurs ont les yeux rivés sur la crise en Ukraine.  Le terme bien connu de « guerre du gaz » avec la Russie est de nouveau sur toutes les lèvres. Après de multiples péripéties, un accord intérimaire de fourniture a finalement été signé, faisant s’éloigner le spectre d’une rupture d’approvisionnement en hiver. Les consommateurs indexés sur des formules flottantes ont alors pu profiter de prix historiquement bas, bien que très volatils. Cependant, l’hiver se durcissant, les risques sur les prix n’ont pas pour autant disparus d’autant plus que l’accord  s’arrêtera fin mars.

1. La dimension géopolitique du gaz

Comme pour le pétrole, l’aspect géopolitique est particulièrement important sur le marché du gaz. Le meilleur exemple en est la relation mouvementée entre l’Europe et la Russie, son principal fournisseur. Ce cas est très complexe, tant les interdépendances entre les deux ensembles sont fortes. La Russie est fortement implantée sur le marché européen pour assurer sa position et les débouchés de son gaz. Et cela fonctionne. L’Union Européenne a quant à elle besoin du gaz russe mais cherche à diversifier davantage ses sources d’approvisionnement pour réduire sa dépendance vis-à-vis de la Russie. Il est cependant utopique de penser qu’une solution sera trouvé rapidement. Par ailleurs, il ne faut pas oublier que ce sont les pays européens, pauvres en ressources, qui ont cherché à créer des liens gaziers forts avec la Russie de par le passé. La forte dépendance au gaz russe n’est que le produit d’une volonté historique.

Trois conflits gaziers se sont depuis produits entre la Russie et l’Ukraine depuis la révolution orange de 2004. Un premier conflit a eu lieu en 2006, lorsque Gazprom décida d’aligner les prix ukrainiens avec les prix européens. Suite au refus de l’Ukraine, l’approvisionnement fut stoppé pendant trois jours, dans un contexte d’hiver très froid. Cette opération démontra au passage que l’Ukraine prélevait illégalement des volumes destinés à l’Europe qui transitait par son territoire. En mars 2008, les livraisons vers l’Ukraine furent de nouveau diminuées en raison d’impayés de la part de l’Ukraine. Le troisième conflit eu lieu en 2009, toujours autour des mêmes problématiques : désaccord sur les prix et défaut de paiement. Gazprom décida de jouer avec le robinet et une baisse des volumes fut de nouveau constatée en Europe. Dernièrement, Le spectre d’une nouvelle crise gazière est réapparu avec la crise ukrainienne suite à la destitution d’Ianoukovitch et l’annexion de la Crimée.

2. Le quatrième conflit gazier

La Russie a réagi à cette situation en annonçant deux hausses successives du prix de vente du gaz à l’Ukraine au mois d’avril :

  • Une première augmentation liée à l’annulation d’une réduction accordée en décembre 2013, motivée par des retards de paiement de l’Ukraine. Le prix est passé de 268,5 à 385,5 dollars par millier de mètres cubes.
  • Au cours de la même semaine, une deuxième augmentation fut annoncée. Le nouveau prix est passé à 485 dollars par milliers de mètres cubes, un des prix les plus élevés en Europe. Cette augmentation est notamment due à l’annulation d’une exemption appliquée aux droits d’exportation.

Kiev ne l’entendit pas de cette oreille et n’honora pas ses factures. Gazprom indiqua alors se trouver dans l’obligation de passer à un paiement anticipé pour les livraisons de gaz. En cas de nouvelle violation des conditions de paiement, les livraisons de gaz seront partiellement ou entièrement stoppées. La Russie n’ayant rien reçu en avance, le ton s’est progressivement durci jusqu’à un arrêt des livraisons à l’Ukraine le 16 juin 2014. Gazprom souligna également que la dette de l’Ukraine s’élevait déjà à 4,458 milliards de dollars (1,451 milliard de novembre à décembre 2013 et 3,007 milliards d’avril à mai 2014). En revanche, les volumes nominés par les autres pays et transitant par l’Ukraine furent livrés, Gazprom rejetant la responsabilité sur Kiev si des quantités venaient à disparaître.

Après plusieurs mois de négociations et avec l’aide de L’Union Européenne, un accord intérimaire a finalement été trouvé jusqu’à la fin du mois de mars 2015, permettant de soulager les tensions qui pesaient sur les mois d’hiver. L’Ukraine peut réserver et payer en avance autant de gaz que nécessaire à un prix inférieur à 385 dollars par millier de mètres cubes et aucun manquement aux engagements Take-or-Pay ne sera répercuté. L’Ukraine remboursera aussi 3,1 milliards de dollars de dette, montant calculé sur un prix de gaz de 268,5 dollars par milliers de mètres cubes. Le montant total de la dette sera décidé par  la cour d’arbitrage de Stockholm. L’Ukraine a remboursé la dette en deux tranches et procédé au prépaiement d’un milliard de mètres cubes pour décembre pour 378 millions de dollars, suivi d’un transfert de 150 millions pour janvier. Par ailleurs, l’alternative consistant à réexporter du gaz de l’Europe vers l’Ukraine via les interconnexions rebours peut poser problème étant donné qu’il s’agit physiquement de gaz russe. L’Ukraine avait par exemple reporté recevoir moins de gaz de l’Union Européenne via les flux rebours en raison des avertissement de Gazprom quant à la légalité de cette opération. En Septembre, le gestionnaire de réseau polonais Gas-System avait également  indiqué que les réductions de fourniture de la Russie l’avait forcé à stopper les réexportions de gaz vers l’Ukraine. Il s’agit donc évidemment d’un sujet complexe…

3)  Pourquoi les prix ont-ils alors baissé ?

Pendant cet épisode, les prix de marché furent orientés à la baisse, si bien que les niveaux atteints à la fin de 2014 furent historiquement bas. Une certaine volatilité / nervosité s’est faite ressentir au fur et à mesure des annonces, la Russie livrant environ 30% du gaz européen. L’arrêt des livraisons à l’Ukraine n’a cependant pas fondamentalement impacté les fournitures à  l’Ouest de l’Europe. La dépendance au gaz russe y est bien moindre au regard de celle de certains pays d’Europe Centrale. Deux grands facteurs permettent de justifier cette tendance à la baisse :

  • L’Ukraine n’est plus la seule voie de transit du gaz russe vers l’Europe. Celui-ci peut par exemple être expédié par le gazoduc Yamal vers la Pologne ou vers l’Allemagne par North Stream passant sous la mer Baltique. A noter que Gazprom ne peut utiliser plus de 50% des capacités de son prolongement OPAL en raison des régulations européennes[1]. Ainsi, une grande partie des approvisionnements de gaz russe ne transite plus par l’Ukraine. La Russie n’a visiblement pas l’intention de réduire les volumes livrés via ces routes alternatives. Les risques sont donc bien plus limités que lors des précédentes crises gazières, lorsque moins d’alternatives au transit ukrainien existaient. Il y a également bien plus de connections entre les pays européens et quelques capacités de transport bidirectionnelles.
  • L’hiver très doux a fait baisser la demande européenne. Les niveaux de stockage étaient alors très élevés au cours de l’année. Ceux-ci étaient remplis à 66% à la date de la rupture des approvisionnements à l’Ukraine et ont continué à grimper jusqu’à plus de 95% en septembre. En parallèle, indépendamment de la météo clémente, la demande de gaz en Europe est en baisse depuis les trois dernières années sur fond de crise économique, de substitution du gaz par le charbon et les renouvelables ainsi que par les efforts faits sur l’efficacité énergétique. La diminution de la consommation de gaz en 2014 est estimée à 11% par la Société Générale.
  • A l’échelle mondiale, une augmentation marquée des capacité de liquéfaction de gaz naturel est anticipée. Si tout se passe comme annoncé, l’Australie dépassera le Qatar et deviendra le plus important exportateur de gaz naturel liquéfié avant la fin de la décennie. Les Etats-Unis entrent aussi rapidement dans la course, avec différents projets dans la file d’attente. Les volumes livrés à l’Europe avaient atteint des niveaux historiquement bas ces dernières années, les volumes étant jusqu’à présent réorientés vers d’autres régions du monde plus rémunératrices, comme par exemple vers l’Asie. Or, les prix spot y sont également orientés à la baisse depuis quelques mois en raison d’une baisse de la demande. Cela permet implicitement de relâcher progressivement les pressions sur les volumes de GNL livrés à l’Europe. Le terminal de Fosmax LNG dans le sud de la France a par exemple rapporté avoir battu son record de déchargement de méthaniers en novembre.


Evolution des cours saisonniers du gaz en Europe sur la place TTF.

En l’absence de nouvel accord entre la Russie et l’Ukraine à partir d’avril 2014, les risques sur l’approvisionnement pourraient se répéter. Une coupure de gaz momentanée à la sortie de l’hiver n’aura pourtant probablement pas de conséquence immédiate. Le ‘stress test’ mené par la Commission Européenne montre qu’une rupture des approvisionnements prolongée aura un impact substantiel sur l’Union Européenne mais indique que les consommateurs protégés resteraient alimentés si tous les pays coopéraient les uns avec les autres. Cela pourrait cependant toucher les prix. Par ailleurs, un autre évènement inattendu peut à tout moment se produire et bouleverser les marchés. Fukushima en est le meilleur exemple. Le Japon a en effet du subitement compenser la fermeture des centrales nucléaires par des centrales thermiques au gaz. La demande et les prix avaient alors rapidement grimpés. Cet épisode tumultueux montre qu’il y a encore du chemin à faire avant de tendre vers un marché exempt de risques. La problématique est d’autant plus importante pour les pays d’Europe Centrale.

4) Quelles sont les perspectives de développement?

Herman Van Rompuy juge que « nous avons dans le passé laissé notre dépendance au gaz russe devenir trop élevée ». En réponse à cette situation, L’Europe cherche alors à réorganiser le marché européen. Cet objectif semble légitime mais ne pourra se faire du jour au lendemain. Cela ne signifie pas non plus que ces nouvelles sources d’approvisionnement seront nécessairement moins couteuse. Le GNL est un premier levier de diversification. Les volumes de GNL livrés à l’Europe sont en baisse depuis quelques années et il serait facile de regonfler ces importations. Le marché pourrait par exemple profiter des nouvelles capacités de liquéfaction mises en services dans le monde dans les prochaines années (en fonction de la demande et de la « propension à payer»). Le plus grand terminal  méthanier d’importation d’Europe sera par exemple construit à Dunkerque. Il faudrait en revanche développer rapidement les infrastructures de regazéification dans les pays plus dépendants au gaz russe, à l’instar de la Lituanie. Un terminal flottant, baptisé « Independence », a été installé à Klaipeda. Ce projet, qualifié de « success story » par Oettinger, permettra également de soulager les autres pays baltes. D’autres projets de ce type sont en cours. Le renforcement des voies internes de circulation est également un point clé. L’ACER indique qu’au moins un tiers des points d’interconnexions entre les Etats membres sont congestionnés. Les États membres ont d’ailleurs récemment convenu d’allouer 647 millions d’euros à des projets d’infrastructures énergétiques prioritaires. La plus grosse enveloppe revient à la construction d’une interconnexion gazière Pologne – Lituanie. Il convient aussi de renforcer les liens Nord – Sud. La France pourrait ainsi bénéficier d’un nouveau gazoduc appelé Midcat avec l’Espagne, pays 100% indépendant du gaz russe. Les discussions trainent depuis des années mais ce projet est inscrit sur la liste des projets d’importance stratégique de la Commission Européenne. Ce gazoduc permettrait de faire remonter du gaz vers le Nord de l’Europe à condition de lever les problèmes d’odorisation entre la France et ses voisins. L’Espagne pourrait ainsi couvrir 10% des importations russes de l’Europe.

L’Europe travaille également sur ses sources d’approvisionnement et s’affiche en faveur du développement du corridor gazier Sud Européen qui ferait dans le lien avec l’Azerbaïdjan via par exemple les gazoducs SCPX, TANAP et TAP ou le projet Nabucco relégué à l’arrière-plan. Ceux-ci peuvent être favorisés par l’abandon récent du projet de gazoduc South Stream reliant la Russie à l’Autriche, la règlementation européenne en matière d’accès des tiers au réseau ayant en partie freiné son développement. Vladimir Poutine a affirmé vouloir favoriser d’autres marchés puisque « tel est le choix de nos amis européens »… Enfin, pour réduire les importations extérieures, il faudrait légitimement accroitre la production européenne. Malheureusement, les niveaux de production sont en chute constante depuis 2004. C’est pourquoi le débat controversé sur le gaz de schiste revient sur le devant de la scène… En Grande Bretagne (où la production a fortement baissée ces dernières années),  la compagnie Cuadrilla Resources a donc annoncé qu’elle serait prête à produire du gaz de schiste d’ici à  quatre ans si l’état d’urgence était déclaré suite à la crise en Ukraine. Les compagnies gazières sont donc sans surprise sur le qui-vive. S’engager vers le gaz de schiste relève néanmoins d’une équation bien plus complexe qu’un simple équilibre entre économie et risques environnementaux. Renforcer l’efficacité énergétique et la part des renouvelables peut être un des leviers, même si les centrales thermiques à gaz sont un excellent moyen de pallier à l’intermittence des énergies renouvelables. Dans ce cas, pourquoi ne pas s’orienter massivement vers le biométhane ?  Une petite révolution dans le monde des réseaux a commencé avec des injections de biométhane dans quinze pays européens.

Ces évènements ont au moins eu le mérite de réanimer les débats. Modifier significativement  l’approvisionnement énergétique de l’Europe ne se fera pas du jour au lendemain. Des années seront nécessaires.  Qui plus est, l’Europe est liée avec la Russie par des contrats de long terme. Il faudra d’abord que ceux-ci expirent avant de pouvoir créer de nouveaux liens de substitution. Enfin, même si la Russie défend l’indexation sur les produits pétroliers, il n’est pas dans son intérêt de trop faire grimper les prix pour ne pas encourager les alternatives en Europe. Par une politique de prix contenus, la Russie pourra peut-être garder la main sur l’approvisionnement européen, ce qui n‘est pas nécessairement une mauvaise chose pour l’Europe d’un point de vue strictement économique. La cause des tensions observée ces dernières années est aussi fortement liée à l’accumulation des dettes de la part de l’Ukraine. La Russie n’a ici pas cherché à perturber  les fourniture de l’Union Européenne. Sa situation économique dégradée ne lui permet pas de jouer à ce jeu. Elle a garanti à plusieurs reprises que les volumes nominés par l’Europe seraient fournis. Sécuriser les zones de transit est donc un objectif tout autant important que de multiplier les sources d’approvisionnement. Il sera certainement intéressant de garder un œil sur les développements à venir.

Par Baptiste Desbois

Mercado energético español: ¿qué nos ha dejado el 2014?

By Maria Martinez de Ubago

Durante el 2014 han tenido lugar cambios regulatorios en el sistema eléctrico español que han afectado profundamente la estructura del mismo. Entre otros destacan el nuevo y polémico sistema de subasta del servicio de interrumpbilidad, el establecimiento del fondo de eficiencia, el inminente cambio en la definición del sistema de periodos, las medidas para hacer frente a la sobrecapacidad, el nuevo impuesto de hidrocarburos con el que se pretender incentivar la exploración de pozos de petróleo marinos y el decreciente precio del petróleo que impacta directamente en el precio del gas en España. Este 2014 se ha caracterizado, al igual que el 2013, por la incertidumbre regulatoria. Incertidumbre que se trasladará al 2015, más aún teniendo en cuenta las elecciones generales de final de año.

El ministerio de Industria y Energía publicó en Agosto de 2014 un nuevo y polémico mecanismo para la asignación del servicio de interrumpibilidad durante 2015, según el cual los grandes consumidores reciben subvenciones por desconectarse de la red en momentos de saturación. Este mecanismo consiste en una subasta descendente en la que solo los pujantes más competitivos adquirirían ‘bloques interrumpibles’. La primera subasta celebrada, le costó al sistema 352 millones de euros, 325 millones de euros menos que en 2014 y casi 200 millones de euros menos que la previsión inicial para el 2015 realizada por el gobierno. Pero algunas industrias muy intensivas como Alcoa, muy descontentas con el resultado de la primera subasta, amenazaron con el cierre de dos de sus plantas y despidos colectivos. Tras un tira y afloja entre el gobierno y Alcoa, finalmente se llevó a cabo una segunda subasta para cubrir los MW que restaban hasta llegar a los 550 millones previamente previstos por el gobierno. Cabe destacar que este servicio no se ha usado desde 2009 y que España posee una capacidad instalada mucho mayor de la necesaria. A día de hoy queda pendiente la publicación de cuál será el coste de este servicio para los consumidores en 2015.

En Noviembre se publicó la liquidación del sistema Eléctrico así como la previsión del déficit de tarifa para 2015. Según esta circular, el déficit para 2015 sería cercano a cero. De esta manera, el gobierno justifica la congelación de los peajes en 2015. Esta medida tiene lugar un año antes de las elecciones generales y algunos tachan la medida de electoralista. Cabe destacar que, el servicio de interrumpibilidad que hasta ahora ha estado incluido en los peajes de acceso, va a pasar a devengarse como parte del precio de la energía. En parte por este hecho, el gobierno puede justificar la reducción del déficit de tarifa en la liquidación del sistema eléctrico.

En 2014, se ha creado un Fondo de Eficiencia Energética con el objetivo de cumplir con los objetivos de ahorro energético fijados por la UE para España. Este fondo será financiado por el fondo FEDER así como las distribuidoras y comercializadoras de gas y electricidad. Las comercializadoras se verán obligadas a aportar al fondo con carácter retroactivo. En diciembre de 2014, algunas comercializadoras ya han hecho pública su intención de trasladar el coste al consumidor.

El año termina sin claridad respecto a si se modificará o no el actual sistema de periodos así como si esto supondrá un incremento en la commodity para 2015. Algunos comercializadores han declarado que el nuevo calendario impactará en los precios. Sin lugar a dudas, este nuevo sistema de periodos hará que los peajes en Agosto se incrementen.

En Enero de 2015 se renovará el actual mecanismo de apoyo a las centrales de carbón nacional, tras la fuerte presión ejercida por dicha industria. Por otra parte, la UE obliga al gobierno español a reducir progresivamente las ayudas hasta que acaben en el 2018. A partir del 2018 solo podrán quedar en actividad las empresas mineras que sean económicamente rentables sin ayuda pública alguna.

El pasado mes de diciembre, el Ministerio de Industria publicó un informe de sostenibilidad ambiental para 2015-2020 en el que se prevé un fuerte crecimiento de las renovables y un retroceso en las centrales de gas y carbón con el objetivo de cumplir los objetivos europeos de eficiencia, renovables y emisiones para 2020 fijados el pasado 23 y 24 de Octubre en la cumbre europea sobre energía celebrada en Bruselas. Para cumplir con los objetivos marcados por Europa sería necesaria la instalación de aproximadamente 7000 MW de energía renovables, y un recorte en las energías convencionales de 7300 MW, principalmente en centrales de ciclo combinado. El sector está a la espera de la publicación de un real decreto que regule los mecanismos para hacer frente a la sobrecapacidad actual, cifrada en más de un 40%. Cabe recordar que el mecanismo de respaldo del sistema eléctrico se financia a través de los pagos por capacidad. Sería de esperar que una reducción de este backup, supusiese un ahorro para los consumidores finales.

En diciembre, el gobierno también aprobó un anteproyecto de ley en el que se incorpora un nuevo impuesto de hidrocarburos destinado a incentivar la exploración petrolífera en aguas profundas. Parte de esa recaudación irá destinada a las comunidades autónomas y ayuntamientos donde se localicen las prospecciones. Con esta medida el gobierno pretende ganarse la simpatía de los ejecutivos regionales que alegan daños medioambientales.

El precio del Brent tiene un impacto directo en el precio que pagamos en España por el gas, ya que la mayor parte de los contratos de gas están indexados al Brent y tipo de cambio. El panorama de continuo decremento en el precio del petróleo observado desde Agosto 2014, ha permitido que se hayan podido negociar contratos a 24 €/MWh frente a los 32 €/MWh observados en verano.

Como resumen, todos estos cambios regulatorios muestran los problemas a los que se enfrenta España a la hora de regular el mercado eléctrico. Los mecanismos que se crean son, con frecuencia, innecesariamente complicados y producen efectos secundarios que deben ser reparados mediante nuevas adaptaciones lo que al final no hace más que complicar las cosas. Para el consumidor final, las consecuencias de esta complejidad se traducen en un incremento del coste de la energía. Es por tanto esperable, que algunos de los cambios que hemos comentado en este artículo, se traduzcan en un incremento del precio. Desde E&C, haremos este seguimiento por ti.

The Spanish legacy of 2014

During 2014, many regulatory changes in the Spanish electricity system have taken place and some of them have deeply affected its structure. Among them we can highlight the new and polemic mechanism to finance the interruptibility, the establishment of the Efficiency Fund, the new definition of the six-period system (not implemented yet but expected to be soon), the measures to tackle the overcapacity, the new hydrocarbon tax which aims to promote the marine oil exploitation and the constant decrease in the oil price since August 2014 that has a direct impact in the gas price as most of the Spanish gas contracts are linked yet to the oil price. As in the previous year, 2014 has been characterized by the regulatory uncertainty. It is expected that this uncertainty will remain in 2015. Indeed it seems like it will be reinforced due the general elections taking place by the end of year.

The Ministry of Industry and Energy published in August 2014 a controversial mechanism to allocate the interruptibility service for 2015 where main consumers receive undercover subsidies for its grid disconnection in case of saturation events. The new mechanism consist of a reverse auction, where only the most competitive bidders will get “interrruptible blocks”. The first auction held, had a cost for the system of 352 million euros, 325 million euros less than the cost of this service for 2014, and almost 200 million euros less that the initial estimate of the government. Nevertheless some intensive industries, such as Alcoa, were dissatisfied with the auction outcome, and have threatened the administration with the closure of two of its plants and collective redundancies. After a tug-of-war between the government and Alcoa, a second auction was held at the end of December to offer extra power blocks up to a cost of 550 million euros as initially estimated. It is worth stressing that this service has not been used since 2009 and that Spain has an installed capacity much larger than the peak demand. To this day, the publication of the final cost of this service for the final consumers is still pending.

Last November, the 2014 system’s liquidation and the forecasted deficit for 2015 were published. According to this report, the tariff deficit will be close to zero for 2014. In this way, the government justifies the stagnation for 2015 of the access tolls. Some sources consider the stagnation in access tolls a populist measure considering that the general elections will take place by the end of 2015. It has to be borne in mind that the interruptibility service cost has been so far included in the toll access but, from January 2015, the cost of this mechanism will be passed on to the energy cost itself.

During 2014, the Spanish government set up an Energy Efficiency Fund to finance a package of measures in order to achieve the European Energy Efficiency Directive. This Directive established a common framework of measures for the promotion of energy efficiency within the European Union to accomplish the 2020 – 20% target on energy efficiency. The ERDF (the European Regional Development Fund), oil wholesale distributors and gas and electricity suppliers have started financing this fund retroactively as of October 2014. In the case of the suppliers, each of them will contribute depending on their market share. In December 2014, some suppliers have declared that this cost will be passed through to the end consumers, although many suppliers haven´t clarified its position yet.

Regarding the proposal of the new six-period system for the retail market calendar, it is still unclear when this new calendar will be applied. Although some suppliers have declared that it will impact the commodity prices, we consider it shouldn’t. What it is certainly evident is that the new calendar will affect the toll access, as August will no longer be entirely P6 anymore.

In January 2015, the mechanism that supports the power plants using national coal will be renewed as a consequence of the intense lobbying from the industry to maintain this subsidie . The European Union requires the Spanish government to progressively reduce these aids until 2018. As of 2018, only the profitable and without public aid power plants will keep its activity.

Last December, the Energy and Industry Ministry published an environmental sustainability report for 2015-2020. According to it, a big increase in renewable capacity is expected as well as a consequent reduction in the gas and coal power plants in order to accomplish the European targets in efficiency, renewables and emissions for 2020 set on 23rd and 24rd of October in the European Energy Summit held in Brussels. To fulfill these targets, the installation of approx. 7000 MW of renewables will be needed as well as a reduction of 7300 MW in conventional plants, mainly combined cycled plants. As part of this, a royal decree aiming at tracking the overcapacity is expected to be published in 2015. It is worth noting that most of the combined cycle plants aims at support the electricity system and that this back-up system is financed through the capacity payment and pay by all end consumers. It would appear reasonable to expect that a reduction in combined cycle plants will eventually result in a further saving.

Morevoer, in December´14, the government approved a draft law introducing a new hydrocarbon tax . This tax aims to promote the marine oil exploitation. Part of the collection will go to the autonomous communities where the exploration is located. This measure intends to win the local sympathy of the regional authorities who claims environmental damage.

In Spain, Brent price has a direct impact in the gas price as still most of the gas contracts are linked to the Brent and exchange ratio. Under the continuous fall of oil prices since August 2014, it has been possible to negotiate contracts at 24 €/MWh while in July the contracts negotiated cost the end consumer around 32 €/MWh for the commodity.

All in all, these regulatory changes show that Spain continues to struggle to regulate its energy markets in an orderly manner. The created systems are often unnecessarily complicated, giving rise to unwanted side effects which then need to be repaired by new adaptations which often do not much more than complicate matters even further. For the end consumers of energy, the consequence of this complexity is often cost increases. It is to be feared that some of the changes we comment in this article will have cost-increasing effects in 2015, we’ll keep track of those evolutions for you.

Declining oil price: geopolitics or just plain economics?

The main event in 2014’s energy market has been the sharp decline in oil prices in the second half of the year. In the first six months, geopolitical tensions regarding Ukraine & Russia still caused hick-ups in the oil markets, with Brent prices reaching 115,06 dollars per barrel on the 19th of June. But then the barrel started a bear correction that even brought it below 60 dollars per barrel on the 16th and 18th of December. Even if oil pricing has lost much of its importance for European industrial energy consumers, due to the decoupling of natural gas from oil prices, I obviously want to share some thoughts on this sharp bear trend.

“It’s the economy, stupid”

 In general, the press is always quick in looking for geopolitical explanations of oil price trends. Even seasoned oil traders often have one eye on CNN and the other on their trading screen. However, a look at supply and demand dynamics of 2014’s oil markets is telling much more than the images of war and political leaders that color the many ‘the world in 2014’ retrospectives that we currently see on television. First of all, demand is not growing as fast as before. Economic growth in Europe and Asia is sluggish, and the one economy which is doing well, the US, is switching towards other fuels and higher efficiencies. Moreover, the US is producing more and more of their petroleum needs themselves. According to the International Energy Agency, the US have grown their oil production in the first nine months of 2014 by 3,5% compared to the same period in 2013. The US is now solidifying its position as the world’s biggest producer of oil. And they’re not there yet, but they could be heading for the enviable position of net crude exporter.

The increase of oil production in the US is caused by the rapid development of shale oil production, the petroleum equivalent of shale gas. This boom is obviously attracting much attention. But we shouldn’t forget that oil production booms are happening in other countries as well. Still according to the International Energy Agency, Canada has grown its oil production in the first nine months of 2014 by 6,5% compared to 2013, thanks to the development of oil sands. And the deep sea oil production of Brazil, causes that country to report an 11,5% increase of oil production in October compared to one year earlier (source: Forbes).

Is Opec waging a price war?

All that increasing production in non-OPEC countries should obviously provoke a reaction from OPEC countries. Traditionally, we expect OPEC to cut supplies when prices hit historical lows. But that’s not what it is doing. On Monday the 22nd of December, the Saudi oil minister, Saudi-Arabia still being the most important OPEC-member, announced that OPEC would not cut supplies, however low the oil price would drop. This strongly confirms the decision at the latest OPEC summit at the end of November not to cut.

A hawkish interpretation of OPEC’s policy of not cutting supplies sees it as a price war. OPEC is consciously dragging down prices, hoping that it will undercut the economics of that new oil production in the US, Canada and Brazil. We’ve seen OPEC (and Saudi-Arabia) attempting similar price wars in the 1980’s, then mostly hoping to stop the development of North Sea and Gulf of Mexico offshore oil production. It failed spectacularly, with the competitors continuing their development and the Saudi budget fatally hurt by low oil prices. Price wars are a tough game. Mostly because of the way that supply and demand dynamics or price elasticity work. For understanding them, you need to make a firm distinction between fixed or investment costs and variable or operating costs.

Short term price elasticity is mostly influenced by operating costs. If the price of a product drops below the operating costs, producers will stop producing the product. In terms of crude oil, if the price of crude drops below the variable costs of operating a well, the producers will shut down production from that well. Now, as far as oil production is concerned, we need to make an important remark here. Operating costs of oil wells are often quite low. Wells are often quite expensive to drill, causing a high investment cost. This is especially the case for the US shale oil and Brazilian deep sea offshore wells. But once drilled, the costs of letting the oil flow out are not very high. To understand this, look at the situation of Brazilian oil producer Petrobras. They have just invested hundreds of billions of dollars to develop their deep sea offshore oilfields. Why on earth would they stop producing from those wells now? Of course, they and their American shale oil colleagues would prefer getting the 110 dollar plus prices for their oil of a few months ago. But the less than 60 dollars that they get at this moment is still giving them some return on their massive investments. Stopping production and getting 0 dollars per 0 barrel is not paying back anything.

With its combination of high investment and low operational costs, the oil market is not a good place to see short term effect in a price war. Price warlords should therefore aim for the long term effects of lower oil prices. Investors in the US, Brazil and Canada could be frustrated and stop investing in the oil developments in those countries. Lower stock prices of oil companies seem to point in that direction. This could have only limited effect on large scale developments like those that we’ve seen in Brazil. However, it could be more effective in hurting the US shale oil development. Shale oil wells typically have steep production decline curves, meaning that most of the oil is produced in the first years after drilling the well and then the production volumes per well drop rapidly. So, you need to maintain investment in drilling new wells to keep up the overall production rate. If lower prices would cause a decline in investment, the expansion of US shale oil production could be slowed down or even reversed. However, experience in the shale gas industry has shown that investment has been more resilient to lower prices than initially thought, especially since a fall in natural gas prices coincided with a drop in the investment costs due to the falling cost of the newly developed horizontal fracking technology. Therefore, it’s all but certain that a conscious price war by OPEC (and/or the Saudis) against further investment in new oil production could produce results.

Maybe, what we are seeing is far from a conscious attempt by OPEC to wage a price war, but a simple struggle for market share. OPEC cannot idly sit by and watch the US, Brazil and Canada steal away its market share. Oil supply growth is currently outstripping oil demand growth, meaning that the oil market is currently a buyers’ market and not a sellers’ market. In such a market, price wars are usually not fought in an offensive attempt at hurting competitors, they are fought as a defensive strategy for keeping market share. In the end, at the sellers’ side everybody is hurt and only the strongest survive. The Saudis could be hopeful that they will prevail with their low cost oil production.

Are Opec and the US working together?

Amateurs of geopolitical explanations of the events in oil markets are pushing an opposite theory. Saudi-Arabia and the US are not fighting each other, they are collaborating. Flanked by the economic sanctions of the EU, they work together to lower the oil price down to levels that really hurt the Russian enemy. Early in November, Vladimir Putin himself put forward this theory by stating that he believed that politics were the cause of the lower energy price. Whether this global conspiracy theory is true or not, it is indeed effective, if you see the turmoil of the Russian economy and currency in the last weeks.


All in all, these events are showing once again how utterly unpredictable energy markets are. Six months ago, Russia, an important oil producing country was engaged in a deep geopolitical conflict, with concerns over the impact on supply causing oil prices to increase. Anyone that would have said then that by the end of 2014 the oil price would drop below 60 dollars per barrel would have been declared a nutcase. But it happened. We can make educated guesses about its causes: simple supply and demand dynamics, a conscious commercial policy by OPEC or a complicated geopolitical intrigue? Or a combination of two or even all three of these options? Which explanation we choose, probably depends more on our own personal convictions than on empirical reality. Which obviously shows that we shouldn’t attribute any predictive quality to our theories. What has happened has happened. The oil price is historically low, benefit from it. And prepare for the next move which will come just as unexpected as this decline.

Copernican revolutions in international (energy) procurement

One of the main rationales for M&A activity in international business is the search for “synergy effects”. In procurement this means that companies hope to achieve cost savings by buying goods and services in a centralized manner. In the last decades, many international companies have gone through a Copernican revolution in their procurement divisions: buying decisions have been centralized. Buyers are buying goods and services for factories across the globe. Sometimes they carve up the world in zones. It always makes me smile when I see ‘EMEA’ on a business card. It means Europe, Middle East and Africa. That’s quite a big and diversified geographical zone, I would say. Other companies still have their procurement functions organized on a local or even on plant-level. And we have even talked with some companies that are turning their Copernican procurement revolutions back again, scaling down the centralized procurement organizations and bringing back the previously centralized buying decisions to local procurement people.


As often, there are no laws written in stone about this topic. Centralized buying has advantages and disadvantages. For some products and services the advantages will be larger than the disadvantages, for others it will be the opposite. In a general sense, the advantages of centralized buying decisions are to be found in the economies of scale that they generate. Bringing together the tons of goods bought in e.g. 20 different factories can lead to serious price reductions on the prices that each of these factories can obtain individually. And in services, things like joint account management or usage of IT infrastructure can make the pricing of centrally procured services cheaper. The potential for such cost savings is limited by transportation costs. If transport is an important cost component, locally supplied goods and services can be cheaper. Further advantages can be derived from the accumulation of procurement knowledge by the international buyers. Working in different countries in itself can provide a deeper insight into how markets work. And whereas local buyers might have a very broad range of products and services categories for which he has to buy, large centralized procurement organizations will allow for more specialization with category buyers that acquire a deep insight into the specific products and services for which they are responsible.


These advantages can disappear for goods and services for which local circumstances have a big influence on their value. Country- or even region-specific geographic, legal, cultural or other factors can have an important impact on the pricing, quality and/or service level. For centralization of procurement to be successful, it will be important that a company makes the distinction between the goods and services where the localization have an important impact and those for which they haven’t. A hybrid organization with central and local buyers working together is therefore often a good solution. Another problem of centralized buying can be the distance from the operational practice. The local buyer often has its office in the factory where the goods and services that he buys are being processed, giving him a better insight into, for example, quality and service levels that are required. Smart central procurement organizations will therefore make sure that there is sufficient travel budget to allow the buyers to go to the factories and see the results of their buying decisions in the operational practice. Unfortunately, we only see too often that in its cost-reduction attempts, companies first decide to centralize procurement and then to cut the travel budget. This will cause further disadvantage for those products and services for which frequent personal contact with the suppliers is necessary.


Finally, due to their size and their distance from operational reality, centralized procurement organizations can degrade into corporate bureaucracies. They can start to create unnecessary formalistic tender procedures that hamper rather than promote the signing of good deals. Local buyers will often have a more entrepreneurial approach to energy buying, working closely together with plant managers that really care about the budgetary impacts of buying decisions on their factories. Sometimes, local managers complain that the central buyers can take the decisions but they are the ones that get blamed when there is a negative impact on the profitability of a factory.


A smart centralized procurement organization will make a good combination of central and local decision-making. It will centralize the buying decisions for those categories of goods and services where the economies of scale and knowledge concentration can be beneficial. It will keep the buying decisions local for those categories where local presence is important. It will facilitate collaboration between central buyers and local buyers and plant managers and make sure that taking decisions also means taking responsibility.


Now, what does this mean for energy?


When thinking about the centralizing of energy procurement, organizations always think about negotiating cross-border electricity or gas supply contracts in the first place. We have to remark here that the potential for this is still limited at this moment as the electricity markets and to a lesser extent natural gas markets are still largely organized on a national level. Negotiating a cross-border electricity contract is still largely an illusion. Best case, you can get some sort of framework agreement under which different electricity contracts per country are brought together but the conditions per country will often be widely different. For natural gas, the negotiation of cross-border contracts has become much easier in the last years. At E&C we have assisted many international companies to negotiate contracts under which natural gas in several North-West-European countries is bought under one and the same (commodity) price arrangement. Other arrangements such as volume regulation, price fixing services or payment conditions can also be brought together for different countries. What advantages should you expect from such cross-border contracts?


Some economies of scale can be expected, but should not be exaggerated. An energy bill contains three main components: 1. The wholesale value of the energy, 2. The retail add-on, 3. The regulated component, the grid fees and taxes. Economies of scale can only impact on the second component, the retail add-on, but that component is just a few percentages of the overall energy bill, so you shouldn’t expect miracles in terms of savings on the total cost of energy. Non-price advantages will often be more important. For example the bringing together of volumes from different factories in different countries under one common volume arrangement. Or the reduced time for processing price fixing decisions when this can be done for a collection of factories rather than for each factory individually.


Accumulation of knowledge can bring important advantages. As the length of some of the articles on this blog illustrates, buying energy is a very knowledge-intensive activity. Local buyers that have to buy a large diversity of products and services often lack the time for acquiring all the knowledge necessary to buy energy. Having a central energy buyer dedicating 100% of his/her time on studying the energy markets is therefore no luxury. We have seen many companies taking large step forwards in e.g. their energy procurement risk management practices when specialized central buyers take over from local buyers.


However, as I have said before, energy markets are organized on a local scale, which can create the disadvantage of a lack of knowledge of local factors of a centralized buyer. Energy markets are organized by regulations, and these are different in every country. As far as the commodity component is concerned (the wholesale value plus the retail add-on), as markets mature the differences between the different countries become smaller. But for the regulated part of the bill, the grid fees and the taxes, these continue to vary widely across Europe. This regulated part is an important percentage of the overall electricity cost, and to much lesser extent for natural gas. Good energy procurement means that you have a good insight into this non-commodity component so that you can budget it correctly. Moreover, every country has is specific set of exemption rules which you have to know to make sure you’re not missing out on an energy cost reduction possibility. It’s impossible for a central buyer to have in-depth and up-to-date knowledge of these tariffs and reduction schemes in all the countries in which you have to buy energy, moreover since they are written in law texts in a large diversity of languages. Consultants such as E&C with a local presence in the countries can make up for this. But it is also a good idea to work together on this with local buyers or for example technical managers in the plants.


As far as the commodity part is concerned, the buyer needs to take decisions regarding signing contracts and making price fixings. For contract negotiations, in pre-mature markets the contact of a local buyer with the local suppliers can play an important role in obtaining a good deal. But as markets mature, it becomes increasingly easy for a central energy buyer to negotiate in the different countries. Moreover, the experience from other countries can help a buyer in negotiating good contracts. As an international consultant we have several times negotiated new contract types in different countries by explaining suppliers how their peers in other countries were solving this or that issue. One important aspect to consider is the volume issue. Lack of collaboration between the central and local level can lead to delays in the signature of contracts as the central buyer lacks knowledge of the volumes for which he is to negotiate the contracts.


As far as the price fixing is concerned, the most important advantages of centralized energy procurement pop up. An energy procurement strategy can be defined that covers the whole company, making sure that no local buyer in a distant country is taking too much risk. And the centralized buyer will often have more time available for following up the different wholesale markets leading to more timely decisions at opportunity moments.


Centralizing energy procurement can have important advantages for international companies. But as with centralizing procurement in general, too much of it can create problems, especially as far as the non-commodity component of the energy bill is concerned. Smart energy procurement centralization will start by focusing on the development of a common price fixing strategy, then gradually get more involved in the contract negotiation process and the budgeting and bill validation. It will set up collaboration with local plant people to facilitate communications regarding expected volumes and local regulations regarding grid fees and taxes.

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.



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.



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 (, 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.