Dernier appel pour une politique gazière efficace

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

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

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

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

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

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

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

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

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

 

How will we pay the green energy bill?

The world is going through a green energy revolution. It started in Europe where governments in countries like Germany, Spain, Denmark or Belgium set up ambitious subsidy programs for renewable energy more than a decade ago. Technologies like wind and solar started to grow at rates that nobody had dared to anticipate at the onset. In the last three years 70% of all the new power production capacity installed in Europe was renewable. This rapid development has driven down sharply the technology cost. Solar and onshore wind have now reached grid parity, meaning that an investor no longer needs subsidies to have a reasonable payback on his investment on a windmill or solar panel. The savings he makes by not having to buy the electricity from the grid is sufficient for him to win back the money invested in a reasonable timeframe.

 

This grid parity may have important consequences. It could mean that the green energy revolution has become unstoppable. Home owners might decide always to put solar panels on their rooftops to cash in on the savings on the power bills. This could push the amount of solar energy available beyond the limits of what is needed or can be distributed over the grid. Grid parity could also mean that solar and wind develop more rapidly in countries that are less generous in handing out subsidies. We are indeed seeing that other countries are taking over from the usual European suspects in the top ten of renewable energy expansion. In US, for example, more than 99% of all the new power capacity installed in January was renewable.

 

However laudable this rapid development might be from an environmental point of view, the early adopters are currently suffering a serious hangover from their subsidy binge. In Germany or Belgium for example, early investors were guaranteed subsidies as high as 450 euro per MWh produced by solar panels for a period of twenty years. Germany has continued to compensate the grid companies that have to pay these subsidies by allowing them to pass through the cost to the end consumer. This has driven up the cost for the end consumer for green energy to unsustainably high levels: 62,4 euro per MWh (the wholesale value of the power itself is currently less than 36 euro per MWh). In Belgium, more particularly Flanders, the government has frozen grid fees, building up a liability for uncompensated green power subsidies of almost 2 billion euros, as my colleague Bart recently remarked. Similar problems can be observed in Spain where the government is facing a massive debt to energy companies for uncompensated renewables subsidies. The early adopter countries are now facing the massive question of how to pay back the green energy bill.

 

At least in Germany and Belgium, the problem is exacerbated by the fact that subsidies for renewable energy are passed through one on one in the bills of the end consumers. The subsidy schemes were created at the same moment that power markets were liberalized. In this mood, ‘market-based’ solutions were devised. Germany opted for a feed-in tariff system, obliging the grid companies to buy the green electricity at a pre-set price level, sell it at the market price and get immediate compensation for the differential between subsidy level and market price level in the shape of charge through payments by end consumers. In Belgium a system of tradable certificates was created. But as the governments of the different parts of Belgium failed to put the quota sufficiently high, grid companies had and have to buy excess certificates and are now demanding compensation for that in the shape of higher grid fees.

 

In Belgium, the chairman of the Green Party Wouter Van Besien has now uttered the idea of compensating the grid companies for excess green energy costs by pay-outs from the general budget instead of passing on the bill to the end consumer in the shape of higher grid fees. We could of course observe that this is a non-solution, as wherever the money comes from, it needs to be paid by the citizens in the end, whether that is as a taxpayer or as a power consumer. Nevertheless, I think it is an interesting idea. Energy has always been subsidized, just think about subsidies for nuclear power or coal which is then used to produce power. However, these nuclear or coal subsidies were not visible in the power consumer’s bill. Renewables are the first energy technology that is so visibly subsidized by passing subsidy costs through so directly. This nourishes the idea that renewable energy is very expensive, an idea which is particularly dangerous now that it has actually become that cheap. What we have to avoid by all cost is that the fatigue due to the problems with historical green power bills causes us to stop further development for renewable energy, especially now that it has become so much cheaper. Doing that would be like racing in a Tour de France stage in which you have already climbed four mountains and then abandon in the last 5 kilometers downhill.

 

If we pay (part of) the historic green energy bill from the general budget, we could also explore possibilities of reviewing the term over which we have to pay it back. In Germany CSU politician Ilse Aigner aired this idea of spreading the green energy bill over a longer period. She unfortunately described it as building up a debt for the future generations, which caused a rapid rebuttal of the idea by CSU President Horst Seehofer. It’s a pity, because it’s a good idea. The debt is already there, investors have been promised to receive subsidies over a twenty year period. Spreading it in time just means you take a decision over the time period over which you pay back that debt. Is it bad management to decide to go for a longer period?

 

I don’t even think the objection against spreading in time of inter-generational solidarity that some observers have uttered makes sense. The current generation has invested a lot in renewable energy. Why should it rapidly pay back that bill if the future generations will continue to benefit from the MWh’s that these windmills and solar panels are putting on the grid? And when the efforts of the current generation have driven down technology costs so that future generations will be able of building their own mills and panels at much lower cost?

 

In Germany, in Flanders and in Spain, solutions need to be found for a sustainable payback of the historical green energy cost. We need intelligent financial management solutions for this problem to make sure that the renewable investments can continue without hurting the current generation too much. And as my colleague Bart has rightfully commented on the situation in Flanders, stowing away the problem until after the next elections isn’t good management.

Voor de bom van de groenestroomcertificaten is meer dan 5 minuten politieke moed nodig

De kosten van de groenestroom- en warmtekrachtcertificaten in Vlaanderen stapelen zich op als een zwaard van Damocles dat ons boven het hoofd hangt. De bom onder onze elektriciteitsrekening wordt alsmaar groter. Net op een moment wanneer de bevoegdheid van de nettarieven wordt overgedragen naar de gewesten, de netbeheerders onderhandelen over een eenheidstarief en er zo nog meer onzekerheid dreigt. Hoog tijd om iedereen wakker te schudden en een grondig debat te voeren.

Na lange, aanslepende onderhandelingen werd met de zesde staatshervorming, het zogenoemde Vlinderakkoord, ons reeds bestaande Belgische labyrint verder uitgebreid. BHV is gesplitst en de Senaat ontmanteld. Buiten het feit dat de Gordel nu z’n identiteit kwijt is, werden er ook een aantal bevoegdheden overgedragen van het federale niveau naar de gewesten en gemeenschappen. Voortaan wordt de materie van de distributietarieven ondergebracht bij de gewesten. Vanaf 1 juli 2014 nemen de VREG, Cwape en Brugel deze taak over van de CREG. Maar zo ver zijn we voorlopig nog niet.

In z’n Memorandum 2014-2019 trekt de VREG aan de alarmbel. Zo roept het op tot de ontwikkeling van een “stabiel decretaal kader”: “Als op Vlaams niveau geen decretale initiatieven terzake ondernomen worden blijft de federale wetgeving inzake distributienettarieven van toepassing. Dit is problematisch want het is een wetgevend kader dat nog niet is toegepast door de CREG en er bestaat ook nog geen tariefmethodologie die in overeenstemming is met dit kader.”.

De Vlaamse regulator pleit voor een vereenvoudigde procedure om de tariefmethodologie op te maken. Geen verrassing aangezien het de taak is van de regulator (in deze de gewestelijke regulator) om de tariefmethodologie op te stellen. Zonder methodologie is het immers moeilijk een tarief vast te leggen. Wat als die methodologie er nog niet is op het moment van de bevoegdheidsoverdracht? Laten we vooral dat juridisch vacuüm vermijden.

Voorlopig bevinden de distributietarieven zich in een stand-still fase aangezien ze vanaf 2012 tot en met 2014 geblokkeerd werden. Eerder gaf Eandis al aan dat we vanaf 2015 een tariefverhoging mogen verwachten. In het Vlaams Parlement maakte minister Van den Bossche duidelijk dat dit pas tegen 1 januari 2016 voorzien is. Krijgen we in 2015, na de bevriezing, dan nieuwe tarieven die (retroactief?) herzien worden in 2016? U merkt dat ook dit ruimte geeft voor juridisch getouwtrek.

Vanwaar deze verhoging? In 2012 waarschuwde de SERV in een advies aan de ministerraad al voor grote overschotten aan groenestroom- en warmtekrachtcertificaten. Hierdoor zagen we de afgelopen periode de marktprijs van deze certificaten sterk dalen. De Vlaamse regering trok in juli 2013 dan ook aan de noodrem. Door een tijdelijke maatregel kregen netbeheerders 170 miljoen euro om zo de minimumsteun verder te kunnen garanderen.

Daarnaast werden 1,5 miljoen groenestroomcertificaten en 1 miljoen warmtekrachtcertificaten bevroren om zo te voorkomen dat netbeheerders die doorrekenen in hun tarieven. Helaas zal wat bevroren wordt ook ooit ontdooien. Omwille van de lage marktprijs doen veel aanbieders beroep op de distributienetbeheerders. Zij zijn verplicht om de certificaten aan een gegarandeerde minimumprijs op te kopen. Hierdoor krijgen ze een berg certificaten in hun schoot geworpen met een financiële kater tot gevolg.

In december 2013 onthulde de Tijd al een stukje van een nieuwe SERV studie waar momenteel aan gewerkt wordt. In de studie wordt de kost die de eindverbruiker boven het hoofd hangt geraamd op ongeveer 2 miljard euro. De vraag is dan ook niet of deze kost zal doorgerekend worden aan de eindverbruiker maar wanneer. De BTW verlaging van 21 naar 6 procent is hierdoor snel vergeten.

Het is duidelijk dat de noodmaatregel van de Vlaamse Regering de druk even van de ketel haalde maar zeker geen structurele oplossing biedt. De bubbel die ons op dit moment boven het hoofd hangt zijn kosten die reeds zijn gemaakt. Wie zijn gat verbrand moet op de blaren zitten maar bij een ongewijzigd beleid zal deze kost verder toenemen.

Indien de tarieven ook voor 2015 worden bevroren omwille van de bevoegdheidsoverdracht betekent dit niet dat men op andere vlakken ondertussen niets kan doen. Er is nood aan structurele maatregelen. Een oplossing kan het verlagen van de minimum steun zijn, het optrekken van de quota om zo extra vraag te creëren of het hervormen van het ondersteuningsmechanisme voor de hernieuwbare installaties van de early adopters.

Het eerste gebeurde vorig jaar gedeeltelijk waardoor de steun voor de meest recente installaties zich op aanvaardbare niveaus bevindt, ver onder de steun die werd vastgelegd voor installaties uit de beginperiode. Een gelijklopende steunverlaging voor de oudere installaties is voor sommigen even erg als vloeken in de kerk, maar wie van hen die in 2010 reeds investeerden in een zonne-energie installatie waarbij hij/zij 450 euro per certificaat ontvangt, heeft die investering nog niet terugverdiend? Het systeem van de onrendabele top zou een betere oplossing zijn voor zij die de investering nog niet terugverdiend hebben. Anderzijds zorgt dit wel voor een instabiel investeringsklimaat en kan zo’n beslissing ervoor zorgen dat de verdere uitbouw van hernieuwbare energie wordt gehypothekeerd en het vertrouwen in de politiek als investeringspartner verder wordt ondermijnt.

Een andere mogelijke oplossing is het spreiden in de tijd. Hierdoor wordt een deel van deze kost betaald door toekomstige energieverbruikers. Vraag is of zij moeten voorzien in de genereuze subsidie voor early adopters? Terzelfdertijd kunnen ook toekomstige afnemers genieten van de hernieuwbare bronnen die nu zijn gezet en zijn het deze vroege vogels die een vraag hebben gecreëerd en er zo voor hebben gezorgd dat we nu zonnepanelen hebben aan betaalbare prijzen.

Het is duidelijk dat geen enkele politieke partij er baat bij heeft om deze koe de bel aan te binden in de aanloop naar de ‘moeder aller verkiezingen’. De vraag is wie de politieke moed heeft om het wel te doen en in staat is om verder te kijken dan 25 mei 2014? Sire zijn er nog staatsmannen? Misschien nog wel. Eerder deze week gaf Groen voorzitter Van Besien in zijn boek ‘Beter’ een eerste aanzet met het voorstel om groenestroomcertificaten te betalen met ‘algemene middelen’.

De bevoegdheidsoverdracht en prijsontdooiing vallen in grote mate samen met de Vlaamse zoektocht naar een eengemaakt distributietarief. De impact hiervan mag niet onderschat worden aangezien de distributietarieven een aanzienlijk deel uitmaken van ieders elektriciteitsfactuur. Hoeveel dit percentage nu reeds bedraagt is niet eenduidig te omschrijven aangezien deze tarieven sterk verschillen tussen de distributienetbeheerders onderling en afhankelijk zijn van ieders specifieke aansluitingssituatie.

Een belangrijk onderdeel van het eenmakingsvoorstel dat Eandis in de afgelopen maanden op tafel legde draait om het uitvoeren van een meerjarentarifering en het solidariseren van de kosten van de openbare dienstverplichting. Laat dit nu net twee aspecten zijn die op dit moment nood hebben aan krachtdadige besluitvorming en geen onderdeel mogen worden van politieke spelletjes tussen intercommunales.

Vijf minuten politieke moed volstaan hier niet. Er is nood aan een grondig politiek debat om beide problemen aan te pakken.

Bart Verest
Energieconsultant
E&C Consultant

On buying and selling of forwards as an energy price hedging technique

Watch the interview with Benedict on this whitepaper
https://vimeo.com/85727090

In many countries, energy markets seem to have reached a new level of maturity with buyers looking for new products that allow them to deploy more sophisticated price hedging techniques. One of those is the selling back to the market of forward positions that have been fixed before. This buying and selling of forwards is sometimes presented as a miracle solution that inevitably brings ultra-low energy prices. It is true that adding the selling of the forwards to the hedging toolbox opens up new possibilities. If well applied, it can produce good results. But we don’t see that every client that sells positions as well as buying them pays much better prices than clients that don’t do it. It is not a miracle solution. Moreover, we sometimes see it being deployed without appropriate risk management. And that sometimes leads to disaster rather than miracle. Before considering the selling of forward positions, it is key that a buyer understands the ins and outs of this sophisticated hedging technique to the last details. It’s not something that you can explain in a few simple sales slogans.

This hedging technique of buying ánd selling is often confused with portfolio management. If you enter a portfolio management agreement, it means that you mandate somebody outside your organization to take the price hedging decisions for you. That portfolio manager will probably want to use the full scale of hedging tools, including the selling of previously bought forwards. But portfolio management is possible without the selling technique. And you can deploy buying ánd selling without the help of a portfolio manager.

When I talk about this hedging technique of buying ánd selling, many clients debunk it as being too risky, too speculative. On the other hand, most traders find the fact that traditional multi-click or tranche model contracts don’t have the selling option too risky. Both are right. By having the possibility of selling a forward contract if markets start to fall after you’ve fixed your price, you can reduce the price risk. But because it is a more sophisticated hedging technique, the risk of something going wrong is higher. This means that buying ánd selling adds system risk to your energy procurement.

To deal with this higher risk of something going wrong when applying buying ánd selling of forwards, it is essential that you have a good understanding of how it works. The basic principle looks simple. You buy e.g. at 40, you sell that position at 60 and then buy it back at 50. Your ultimate price will be: +40 -50 +60 = 30. You have optimized your original position by the 10 (euro per MWh, e.g.) drop in the market. This is the simple + – + logic of applying buying ánd hedging. From it, you can derive two very simple rules for applying it successfully:

  1. Buy in a rising market
  2. Sell in a falling market

In theory, it looks dead simple, but in practice I see that even clients that have applied buying ánd selling for years make mistakes against this simple logic. For example, they get sloppy about their original buying positions, forgetting that the better your original price, the better your ultimate price. Or: they don’t want to sell at a price below the original buying price, losing valuable possibilities of improving the price in a downtrend. A third example of a misconception occurs when clients sell as soon as the price has risen above the original buying price, being too eager to cash in the ‘profits’ on the original position, but forgetting that they will have to buy back. To avoid such pitfalls, it is essential that everybody involved in the decision-making understand the basic + – + logic of this hedging tool.

Another misconception that I often hear is that people think that buying ánd selling is an energy procurement strategy in itself. It’s not a strategy, it’s a hedging tool. And how you apply that tool depends on your broader strategy that should be based on a thorough analysis of the type of risk that you’re exposed to in the volatile energy markets. Buying ánd selling can be used to optimize price results within the broader strategic goal of stabilizing energy budgets. But it can also be used by clients that have the opposite strategic goal of wanting to safeguard that they have competitive energy prices. Defining your risk limits and applying risk monitoring tools such as value-at-risk should help you in deploying buying ánd selling without excessive risk-taking.

If markets would move in straight lines, it would be very simple to be successful in buying ánd selling forwards. You would just buy everything if the straight line up starts and sell everything if the straight line down starts. But that’s not the reality of the markets. The price goes down for two days, then increases again, down again, etc. It’s this unpredictability of the markets that makes the application of hedging techniques so difficult. Some clients try to get around this by applying machine gun tactics, buying and selling at every first sign of an up-, resp. downtrend. That often results in big losses. I believe that it’s much safer to apply the piecemeal tactics, building up and down your positions in small steps, using your value-at-risk calculations to avoid excessive losses. I also recommend buyers to have patience. The real big gains are made in the big up- and downtrends. These don’t occur every year. If you trade too frantically in and out of every small intermediary trend, you’ll start piling up losses.

Operationally, the most important recommendation I can make is: apply the four eyes principle. Make sure there is at least one other person in your organization that completely understands the hedging technique to avoid disaster. Consultants such as E&C can also have an important role in deploying this sophisticated manner of hedging prices. I recommend to avoid black box solutions and to only use consultants that share all their information with you. Consultants should act as risk management consultants in the first place. The same is true with portfolio managers. Make sure that they are not taking excessive amounts of risk on your behalf by putting the necessary risk management practices in place.

Buying ánd selling of forwards is a powerful energy price hedging technique. It reduces the energy price risk by giving you the chance to reverse buying decisions. And it optimizes your chances of making really good prices as it allows you to benefit from downtrends in the market, and not only uptrends. However, it also adds a next level of complexity to your energy price hedging. And because of this complexity, things can go wrong. If you want to adopt this hedging technique, I recommend the following steps:

  • Make sure that all the people in your organization involved in the energy price decision-making process understand how it works. Don’t use an instrument that you don’t understand. Don’t outsource because you don’t understand.
  • Hire a consultant to help you understand the technique completely and at least check that you have no misconceptions.
  • If you hire a portfolio manager, make sure you are capable of checking his operations as a risk manager should do.
  • Set up a good energy procurement strategy based on a good qualification of your energy market risk exposure.
  • Develop good monitoring tools that everybody involved in the energy procurement understands.
  • Be patient. Go for the long term trends and not for the short term gains.
  • Develop your buying or selling positions piecemeal.
  • Use value-at-risk calculations to manage the risk.

Good consultancy is based on an open and free exchange of knowledge. In this perspective, I have written a whitepaper on this topic of buying ánd selling of forwards as an energy price hedging technique. This blog article is a summary of that whitepaper. Send an e-mail to Joke at joke@eecc.eu to get the full version.

Whitepapersample

My best wishes for 2014 (wishes, not forecasts!)

Want a short resume? Watch our video here: https://www.youtube.com/watch?v=h1JkWacc8QA&feature=youtu.be  

In my home country Belgium, we have the nice tradition of ‘New Years letters’. Children write letters full of semi-philosophic observations and wishes which they read to their parents and grand-parents on New Year’s Day. In this tradition, I also want to write a few words in which I look back on trends observed in the past months and try to look forward on what could happen in the new year. As I have remarked before, I am not in the forecasting business. So don’t expect any forecasts on prices or events. I will try to think about what might happen to guide the reader as to what she/he should look out for in the next months in the news on energy markets.

1. Will the European gas prices move? Up? Down?

The gas markets in Europe have traded flat in the past two and a half years. Impossibly flat. The main concern of analysts in this market was trying not to fall asleep. Prices traded towards a level of 26 – 28 euro per MWh in the wake of the Fukushima disaster. Upward pressure continued as Asian demand remained high. And this was / is not just more demand in Japan due to nuclear shutdowns. New LNG import terminals in China, South-Korea and other Asian countries have also put pressure on the demand side. At the same time, expected LNG export projects in Australia were delayed. Without further delays, the first of the Aussie new LNG will start flowing in 2014. As of 2015, they are expected to hit the market in full strength and US LNG export projects add extra volumes. Can this (anticipated) increase in supply cause a downtrend in 2014? Or will, on the contrary, prices increase as supply projects suffer further delays, Asian demand continues to soar and European demand picks up in the wake of an economic recovery?

A downtrend in gas markets would be a welcome relief to Europe’s energy markets. In the last three years, consumers haven’t had any chances of securing some good prices for future gas budgets. The same would be true for power consumers in the UK, where power prices are closely linked to gas prices. A dip in the gas price would be even more welcome for the power production sector. With relatively high gas prices, low coal prices and large amounts of renewable power on the grid, the owners of gas-fired power stations have been butchered in the last two years. This became clear in the last days as Germany had to announce that its lignite consumption peaked in 2013. A drop in gas prices that improves gas power plant economics would therefore also be good news for our climate policy.

2. Will low wholesale prices for electricity persist?

 

Certainly in Germany and Central Europe, the wholesale electricity prices hit historically low levels in 2013. Causes have been: low coal prices, increasing renewable energy production, low prices for emission rights and declining power demand. This has obviously enabled end consumers to fix some really low budgets for power (commodity) for the next years. But we might see some dark clouds on the horizon:

  • The low prices have slashed the profitability of power production. Therefore, we should expect a normal economic reaction: i.e. shutdowns of power plants that lead to a decline in supply and increasing prices. This trend has started already, certainly as far as the unprofitable gas power stations are concerned. Governments are trying to stop this by denying plants the right to shut down or by considering capacity payments to gas-fired power plants (see below). Moreover, it is highly likely that other than economic reasons will also influence our power supply situation.
  • Seeing that their climate and other environmental policy efforts are undone by increasing coal and lignite consumption, governments might decide to shut down coal and lignite-fired power stations, a phenomenon we have seen already in the UK.
  • In many countries, governments are also turning back or rather reducing their programs for supporting renewable energy. They might take that a step too far and slow down the development of renewables too much.
  • And what if in 2014 measures are taken regarding the emission trading system (ETS) that go further than the cosmetics of the back-loading proposal? What if a real shortage of emission rights prices is created? Buyers (and policymakers) have to take into account that theoretically every 1 euro per ton increase in emission rights prices leads to a 0,5 euro per MWh increase in wholesale electricity prices. This theory was empirically proven in 2005 – 2006. And the impact might even be larger this time as more marginal MWh’s are produced from coal, which has higher emissions per MWh factors.
  • Many economists are quite upbeat about Europe’s economy in 2014. It would be very interesting to find ourselves in that situation, not just from a socio-economic point of view. A period of economic growth would show us whether the decline in power (and natural gas) demand observed in the last years can be purely attributed to the economic crisis or whether it was also caused by a more fundamental trend: the effect of climate policy. But a recovering power demand could have a price increasing effect.

As you can see, there are many reasons to observe power markets carefully this year and watch out for signs of a reversal of the current downtrend. However, in the first week of the year, the market was rather pointing in the other direction. It could therefore very well be that the combined forces of low coal prices, unstoppable renewable energy development and declining demand continue to push down prices. And – who knows – if we would see a downtrend in gas prices (see above), we might find even lower prices. If the past years have learned us anything about energy markets, it is ‘Never say never’.

3. Will the non-commodity part of the power bill continue to increase?

Even if commodity prices for electricity have reached historical lows, for many consumers across Europe the total price of electricity has increased sharply. This is due to the increase of the non-commodity part, the grid fees and taxes. Europe’s power supply system is being rapidly transformed from a centralized system with large-scale power stations to a locally distributed system with many small-scale power stations. It is logic that such a systemic transformation causes cost increases. Also, we have to consider that the market system in itself has been redesigned. In the past, markets were regulated and its operators were state-held and/or heavily politicized monopolists. Systemic transformations such as the construction of nuclear power plants or the continuing use of coal when it was no longer economic to produce it, have been and continue to be heavily subsidized. However, these subsidies were often paid from other sources than the power consumers’ bills. Therefore, they were less visible. In today’s liberal markets, every cost of the power market transformation is passed through in the bills of end consumers. This makes the cost of the transformation much more visible than what we have seen in the past.

This obviously doesn’t mean that the cost increases should be neglected. In those countries that have pushed for more renewables hardest, we now see impressive add-ons for renewable energy on the electricity bills. Germany is the most obvious example, with the contribution to support renewables now almost twice as high as the wholesale value of the electricity. In other countries such as Spain, Italy, Belgium (especially the Southern part) or (increasingly) the UK, we see a similarly high renewable energy bill for the end consumers. Even if price increases were perfectly predictable when politicians introduced the renewable support schemes, politicians have reacted to them with surprise and have announced reforms of the renewable support schemes. They might take this too far and stop the further development of renewables. I personally think that this would be a sorry thing. The efforts of the past decade have brought down the cost of renewable energy technology. It’s never been cheaper to invest in more renewables than at this moment. It would therefore be very disappointing if we stop the efforts right now. It would be like stopping while the finishing line is in sight. However, maybe countries that have so far been laggards, such as the Netherlands or many Central European countries, should take over the efforts. That would also be a good thing for the balance of both the grids and the internal market for electricity in itself.

The high add-ons for renewable in countries such as Germany, are largely caused by ‘stranded costs’, compensation for high subsidies that were guaranteed to investors in renewable energy when the technology cost was still much higher than it currently is. It should therefore be carefully considered how this cost is distributed in time and across the different actors. Protection of Europe’s electro-intensive industry should be an important consideration. And should we really pay back these costs in the next five to fifteen years or shouldn’t we rather finance them from a long term credit? The next generations will profit (from an environmental but also from an economic point of view) from our current efforts to develop renewable energy. Is it therefore a case of inter-generational injustice when we pass on part of the renewable energy bills to these future generations? In the North of Belgium (Flanders) reforms of the renewable energy support mechanisms seem to have succeeded in keeping the costs at bay without completely stopping the development of renewable energy. Germany has also started its reforms and is discussing the distribution questions actively at this moment. This week, we saw a rather disappointing ‘stopping in the bud’ of the intergenerational discussion by the President of Bayern and of government party CSU Ernst Seehofer. But I would be surprised if this ‘spreading the cost in time’ isn’t discussed again in Berlin.

I am not entirely confident that politicians will manage to make these reforms of Europe’s renewable energy policy a success. I have seen too many cases that prove that politicians’ interventions in the energy market always cause unwanted side effects and price increases. This lack of economic prudence shows itself again as the effects of more renewable are being discussed. Policymakers are loudly protesting the current cost increases caused by renewable energy development. However, at the same time they want to hand out money (capacity payments) to gas-fired power stations to solve a problem (power plant shortage) that hasn’t manifested itself yet, against all forecasts. Who will pay for such capacity payments? Yes, the end consumers in the shape of another add-on on the electricity bill. Worst case, we will see reforms that stop the development of renewable energy but because of the stranded costs issue that doesn’t lead to any cost improvements and capacity payments to gas-fired power stations continue to increase the power bill.

As in every ‘New Year’s letter’, I want to end this blog article with some good-hearted- if slightly naïve wishes. I wish all of you energy buyers out there for 2014:

-        A good dip in the gas markets,

-        Continuing low wholesale power prices (and, if possible, a little bit lower still?),

-        Politicians that manage to reform renewable energy support mechanisms in a cost-efficient and rationally distributed manner.

Servicios Complementarios – ¿Podemos gestionar el riesgo?

Durante todo 2013 nos hemos encontrado con una subida sustancial de las formulas indexadas a OMIP o Multiclick. El motivo de dicho incremento es debido al incremento del coste de los llamados Servicios Complementarios (SSCC).

Los Servicios complementarios son operaciones que lleva a cabo el operador del sistema (Red Eléctrica) para asegurar la entrega de la energía con los niveles de seguridad y calidad establecidos. En esencia son reservas operacionales de potencia activa y reactiva necesarias para el equilibrio técnico entre oferta y demanda durante la operación normal y ante ciertas perturbaciones.

El siguiente gráfico muestra la evolución de estos costes desde principios de 2011.

Image

Durante el 2011 el precio de los SSCC se situaba alrededor de los 3 euros por MWh. Ahora bien a partir de 2012 los valores de estos costes empezaron a tomar valores muy por encima de la media, hasta llegar a los 13 euros por MWh. El problema no proviene de anomalías puntuales sino que se deriva del incremento del valor medio como muestra la media móvil de los últimos 12 meses; y por el aumento de la volatilidad de estos valores, es decir, el incremento del banda de fluctuación. Actualmente nos encontramos en una media entre 5 y 6 euros por MWh con un rango entre 1 y 13 euros por MWh.

Pero, ¿cómo nos afecta a la hora de comprar energía? Las comercializadoras deben estimar el coste de estos servicios para todos los contratos a precio fijo o indexado a OMIP con formulas cerradas. Como no existe un mercado organizado de estos servicios, ningún agente se puede cubrir el riesgo y por lo tanto la estimación se basa en los valores pasados, previsiones futuras más una prima de riesgo por volatilidad.

Ante una situación como la descrita, no parece extraño que alguien se pueda “pillar los dedos”. ¿Podía alguien imaginarse que el coste de los servicios complementarios se doblaría? ¿Pueden las comercializadoras soportar una reducción del margen comercial de 3 euros por MWh? La inevitable consecuencia fue el traslado de este incremento a los precios ofertados.

¿Por qué subieron los servicios complementarios?¿Qué variables afectan a su evolución?

Hay dos drivers principales. En primer lugar, el porcentaje del mix energético de tecnologías no gestionables. Se entiende como tecnologías no gestionables las renovables y la nuclear. Para el operador del mercado resulta más dificultoso y por ende más caro gestionar el equilibrio oferta-demanda en el mercado intradiario con tecnologías que por naturaleza no son gestionables.

Este año sucedió que Red Eléctrico tuvo que dar la orden de desconexión de molinos de viento e incluso de bajar la potencia de las nucleares un 20%. El coste de esta maniobra fue descomunal. En cambio, gestionar los excesos de oferta o de demanda mediante ciclos combinados es mucho más lógico, económico y viable. En definitiva se trata de quemar más o menos gas. Apuntar que a día de hoy estamos utilizando solamente un 10% de la capacidad instalada de ciclos combinados.

En segundo lugar, también influye la demanda ya que finalmente los costes de estos servicios se pagan entre todos los consumidores y por lo tanto el coste total se divide entre los MWh consumidos en esa hora. En otras palabras, a menos demanda el precio sube.

Desde el punto de vista de un comprador lo importante es entender el riesgo al que estamos expuestos y las alternativas de gestión que ofrece el mercado actualmente.

La primera pregunta que un comprador debe realizarse es, sin tener en cuenta las oscilaciones del propio mercado, ¿puedo además tener una fluctuación en mi coste energético de entre 3-4 euros por MWh que no puedo controlar? Sí la respuesta es negativa, la opción más prudente es aceptar el incremento de estos costes por la coyuntura española y pagar el Premium asociado.

Si por lo contrario, la estrategia de compra del cliente permite soportar el riesgo de cierta volatilidad, mantener estos costes en modalidad “pass through” puede ser una opción interesante. Y no lo digo porqué crea que van a bajar, porqué nunca puedes predecir nada a futuro sino por el hecho de evitar el Premium implícito. Esto se puede conseguir mediante un contrato indexado al Pool o bien con los contratos indexados a OMIP pidiendo a las comercializadoras que las SSCC estén abiertos.

Ahora bien, ¿se puede ir un paso más allá? ¿hay alguna alternativa extra? En el mercado está surgiendo el debate sobre la posible gestión de este riesgo. Teniendo en cuenta como hemos dicho anteriormente que la estimación de costes se basa en las cotizaciones pasadas más una prima de riesgo, abrimos el debate de poder disponer de una cláusula donde se nos permita cerrar los SSCC durante el contrato antes de la entrega de la energía con la media de los SSCC durante los X meses anteriores más una prima.

Si las comercializadoras dieran esta posibilidad, sería posible medir el riesgo, monitorizarlo y en consecuencia tener una gestión activa.

¿Alguien se anima?

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

By Albert Puell Prat

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

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

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

grafiek albert blog

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

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

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

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

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

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

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

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

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

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

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

Does anyone accept the challenge?