End-consumers: beware of capacity payments

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

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

 

Why have capacity payments disappeared from energy pricing after liberalization?

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

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

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

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

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

Marginal cost pricing

Figure 1: Marginal cost pricing for power supply

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

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

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

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

 

Why are governments thinking about introducing the capacity payments again?

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

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

price reduction

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

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

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

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

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

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

 

What will capacity payments mean for the end consumers?

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

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

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

 

What are the alternatives?

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

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

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

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

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

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

Please find the English version below.

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

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


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

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

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

 

The gap between Belgian and German electricity prices

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

 

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

 

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

 

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

 

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

 

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

 

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

Dernier appel pour une politique gazière efficace

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

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

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

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

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

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

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

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

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

 

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