A decade of low energy prices?

Written by Benedict De Meulemeester

In March / April of this year, energy prices across the globe hit historical lows. The Brent oil price dropped to 27,88 dollar per barrel, WTI to 26,21. The price of coal for the world markets dropped to 36,55 dollar per ton. Natural gas in the US (Henry Hub 12-month forward strip) traded down to 2,11 dollar per MMBTU, European gas for next year (TTF) dropped to 13,02 euro per MWh. With fuel prices that low, it’s not surprising that power prices hit historical lows as well. The German baseload electricity price for next year dropped to 20,85 euro per MWh. Pricing in the US is very scattered, but the price for Northern Illinois as an example, traded as low as 25,30 dollar per MWh. Since then, prices have rebounded, but they remain at very low levels. Oil is currently trading just below 50 dollar per barrel, less than 11,8 % of the prices seen in the last ten years were better than that.

For buyers of energy this opens up important questions of course. Should you take this historical chance and make long-term fixings? Or are the supply and demand fundamentals supporting this bearishness so strong that we are heading for a decade of low energy prices, so it’s better to stay in the spot market? Some insight into what has been driving prices in the past decade, will teach us that giving a definitive answer to this question is impossible. Hence, the best bet is to prepare for both scenarios.

What on earth happened to peak oil? In the period 2000 – 2008, prices of energy and other commodities increased steadily to reach peaks in the first six months of 2008. An old theory that was popular in the 1970’s was revived. It assumes that production of energy resources follows the path of a bell-shaped curve whereas demand just continues to increase. Once the right-hand side of the bell-shaped curve has been reached, there is an inevitable supply crunch (peak oil). The maker of this theory, M. King Hubbert, was relatively successful in predicting the moment of the crunch in US oil supplies, giving him some credibility. An increasing number of energy market analysts interpreted the energy price bullishness as proof that peaks were occurring (Peak oil! Peak gas! Peak coal!). 8 years later, with prices at these historical lows, the declarations of the peak theorists seem ridiculous. A quick visit to the website of their association http://peak-oil.org/ will make most of us smile, or worse, get annoyed at the lack of empirical backing of what is said, e.g. that the production of oil has been almost flat since 2005, whereas in reality we’ve seen an increase of almost 12%.

Nevertheless, way back in 2008, the peak oil idea had a huge following. Goldman Sachs forecasted an increase of the oil price to 200 dollar per barrel. Many energy buyers fixed prices at the high levels of the first six months of 2008 as they believed the scary stories of ever increasing energy prices. I remember a meeting with the CEO of a big company that said: “we all agree that energy prices can only increase, don’t we”. Why were business people so easily scared into thinking that energy prices could know only one direction: up? First of all, I think that most of us have a hard time not to think in trends. It takes a lot of guts to believe in a decline when for months and months, even years and years, prices have continuously increased. Secondly, when it comes to energy pricing, many of us tend to be pessimist, energy is always too expensive, never cheap. Thirdly, the idea of scarcity was nurtured by environmentalists. When you can’t motivate people to reduce energy consumption for the sake of the environment only, fear of higher prices might be quite helpful. Eight years down the road, and on the other side of the price ranges, it might be tempting to think the other way around, to believe that the decline can only continue. Thinking back about 2008 can be a powerful reminder always to expect the unexpected, to run an energy buying strategy that is ready for the changes in the trends.

If we look at the long term developments in energy markets, we see a pattern of continuously low prices, temporarily interrupted by sharp upticks. This is caused by the way elasticity, the adaptation of supply and demand to price evolutions, works in energy markets. On both sides there is elasticity, but it works slowly, with significant delays. And the delays tend to be longer on the supply than on the demand side.

On the demand side, short term reactions to prices can occur in the shape of fuel switches, e.g. an industrial using fuel oil instead of gas for producing steam. Mid-term, consumers can lower their consumption when prices increase with behavioral efficiency gains, e.g. driving less kilometers with the car or decrease the temperature in one’s house. On the other hand, if prices are low, consumers will become more profligate. Long-term changes in energy demand due to periods of high or low prices can be caused by investments in structural energy efficiency improvements and by the effects of high or low energy prices on the economy. It would be far-fetched to say that the economic crisis that started in 2008 was caused by high energy prices, but it is clear that there was a link. Another example of this can be found in the 1980’s when the high prices of the 1970’s resulted in a sharp economic crisis resulting in much lower energy demand and two decades of low prices.

On the supply side, short term reactions occur in the shape of marginal cost decisions not to produce when prices have dropped below production costs. These reactions cause a continuous rebalancing but no structural price movements, as the capacities come back online as soon as prices increase above the production costs. More structural adaptations can be found on the mid-long term when installations are shut down when prices are too low. However, due to the high stranded costs of energy production installations, this shutdown is often rather temporary (the installation is “moth-balled”) and can be undone as soon as prices increase again. In the same fashion, we often see a supply side correction when prices are very high in the shape of bringing very old installations back online. The real structural adaptations of supply to price occur in the shape of production capacity adaptations by investments or lack of it in new production facilities. And the terms can be very long. The construction of a new power station, an LNG export terminal, ships for transporting coal, the development of an oil or gas field, etc., they can take more than a decade before the first energy is available to the market.

Having these elasticities in mind, we can perfectly understand what has happened in the energy markets in the last two decades. The strong global economic growth of the late 1990’s and early 2000’s with the exponential growth of emerging economies and China caused a voracious growth of demand for energy and other commodities. As of the mid 2000s this started to result in supply shortages causing prices to increase rapidly. Many decisions to invest in new production capacities were taken, but most of them only hit the market as of 2010. In the meantime, mid-term demand adaptations started to occur, we saw e.g. Americans choosing more fuel-efficient cars, causing a slow-down in demand growth. As of the second half of 2008, demand was slashed by the economic crisis which, as I’ve said before, was partly linked to the higher energy prices. This resulted in a sharp reduction of prices. When as of 2010 demand started to pick up again, supply extended more rapidly, resulting in a new supply glut that ended in the historically low prices of the beginning of this year. The recent bullish correction can be explained by higher demand and the mothballing of older production capacities.

It is however too early to say whether this is the definitive turnaround. It is clear that investments in new energy production capacities are slowing down, as we can see in this graph from the IEA with figures until 2013:

Source: Special Report: World Energy Investment Outlook, International Energy Agency, 2014, p. 20.

At some point, this slowdown in investment will result in a supply crunch such as the one that we have seen in 2005 – 2008. Whether that will be next year or whether we will see a decade of low energy prices is impossible to say. A lot will depend on how demand evolves in the meantime. Will we see another period of rapid economic growth or not? Moreover, we are seeing an increasing drive towards higher energy efficiency on a worldwide basis, meaning that more economic growth means less energy demand growth. This efficiency drive in the framework of climate policy started in Europe that has seen its primary energy demand drop by more than 10% since 2006 (although in 2015 it increased again for the first time in nine years). It is now being copied in more and more parts of the world. Will this keep down demand growth sufficiently for prices to remain low?

Slow elasticity sometimes leads some observers to the reasoning that the normal laws of economics (Adam Smith’s invisible hand) don’t work in the energy markets. They are wrong. Trends such as the sharp decrease of energy prices seen in the last five years do end at some point. Whether the recent turnaround is just temporary or the beginning of a longer period is impossible to forecast. Therefore, as an energy buyer you better prepare for all scenarios.

Time’s right to bring sustainable energy procurement to a higher level

Written by Dina Karamarko

According to the latest WWF and Ceres report, 59% of the Fortune 100 and nearly two thirds of the Global 100 have set GHG emissions reduction commitments, renewable energy commitments, or both. Some even go a step further and establish their own energy company, like Apple, which recently made headlines with its Apple Energy – a subsidiary authorized to sell capacity and energy in wholesale energy markets. This supports the fact that large corporations are taking an active approach to energy management. Do you wonder why?

Energy fuels global economic activity. At the same time, volatile energy prices, growing energy demand, and climate change issues are shaping the current global agenda. The industrial sector is particularly exposed to energy, as it accounts for almost one third of total energy consumption. In order to remain productive and competitive, industry needs reliable and affordable energy. Thanks to recent technological developments, sustainable energy increasingly presents commercially viable options to meet industry’s energy requirements. But the challenge remains: How to find the appropriate balance between growing demand for energy and sustainability goals?

For more and more companies, sustainable energy – wind, solar, geothermal, hydroelectric, and biomass –contributes to their strategic goals. More and more large corporations are turning to sustainable energy to power their operations.  Companies are investing in sustainable energy because they believe it makes good business sense: sustainable energy helps to reduce long-term operating costs, diversifies energy supply and hedges against market volatility in traditional fuel markets. It also enables companies to achieve greenhouse gas (GHG) emission reduction goals and demonstrates leadership on broader corporate sustainability and climate commitments. On-site sustainable and distributed energy sources such as solar PV, combined heat and power are contributing to reduced carbon emission output. For some companies, sustainable energy from large-scale, off-site projects has also become attractive for financial sustainability as prices can be locked in for up to 20 years.

On the one hand, the natural disasters which have occurred over the past years have led the private sector to invest in more resilient infrastructure. On the other, rapidly falling battery prices are paving the way for a new and potentially cleaner way of maintaining an uninterrupted supply of power. The issues around baseload concerns and storage levels are widely discussed but it must be noted that reliability is not a function of individual generation technologies, but rather a function of the electricity system as a whole. Grid operators have been dealing with variability since the birth of electricity distribution – therefore the same principle can be applied to sustainable energy sources. Some grid operators are already successfully managing shares of variable energy. Without relying on battery storage, renewables produced 37% of Spain’s electricity last year. In Denmark, 41% of electricity demand was met with renewables, and it is expected that this percentage will increase to over 80% in 2016. Even the world’s 4th largest economy – Germany, was already at 30% last year. It should also be remarked that in these countries grid reliability has grown rather than dropped during this rapid build-up of renewable energy production.

E&C is dedicated to helping its client achieve their sustainability goals. Sustainability will be one of the topics addressed in our workshops during E&C’s Transatlantic Energy Conference, which will take place on Thursday September 22nd in Amsterdam and on Wednesday October 5th in Chicago. The workshop is the perfect introduction to the world of sustainable energy procurement, and is designed to help you find the best path for optimizing your sustainability efforts. Tailor-made sustainability strategies are the backbone of our sustainability services. Renewable energy has become more and more cost effective and companies are setting ever more ambitious goals to buy renewables. Our “technology scan” analysis can map out the most suitable technologies and geographical regions for pursuing your sustainability projects. Our workshop will also feature discussions on the development of environmental commodities trading, as well as monitoring and reporting. Let’s use this workshop as a platform to share knowledge and exchange experiences on both the challenges and vast opportunities of sustainable energy. Leading corporations are scaling up their energy management initiatives, so why would you wait any longer?

Missed our Transatlantic Energy Conference 2016?

La fin de l’ « arenhisation » du marché Français

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

Par Baptiste Desbois.

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

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

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

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

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

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

High time to fix the Spanish energy market

By Jordi Martinez Cuadrado

Please find the Spanish article here.

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

 

 

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

 

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

 

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

 

 

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

 

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

 

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

 

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

 

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

 

2. Get complementary services fixed

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

4. Make flexible contracts available for small consumers

 

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

 

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

 

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

 

 

5. Reduce the costs of grid fees & taxes

 

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

 

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

 

6. Increase interconnection

 

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

 

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

 

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

 

 

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

 

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

 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Does anyone accept the challenge?

Germany’s grand coalition and the ‘Energiewende’

Last week, the SPD, CDU and CSU reached an agreement to set up a new government in Germany. The business world was looking at the program of this new government with fear. The conservative CDU/CSU have traded their pro-business but electorally nullified partner FDP for the socialist party SPD. Many feared that the changes in energy policy, for example, would mean extra costs for German business (see my previous blog article). I therefore read the energy part of the coalition contract with much interest. What happens in Germany is not only important for German business. The rapid transition towards renewable energy (Energiewende) has impacted energy markets all across Europe. So, what will the new government do to Germany’s (and Europe’s) Energiewende?

When the two big German political families make a government together, they call it a ‘Grand Coalition’. Not much than can be dubbed ‘grandiose’ in this coalition contract, however. In such a coalition of parties with very different ideologies, every piece of policy is the result of a carefully crafted compromise. That means that it’s often hard to find a clear line of policy. On the other hand, it also means that policies are often well balanced and don’t produce too much unwanted effects. This is very obvious in the energy policy of this new government. On energy, the coalition contract is often more clear in what it’s not saying, then in what it is saying. Many items seem to be open still for discussion and the text leaves many openings such as ‘we’ll only do that if it’s not producing adverse economic effects’. So anyone saying that he/she has a clear idea of the new German energy policy after reading these ten pages is clearly over-interpreting. Nevertheless, I’ll attempt to summarize what can be read:

1. On the sensitive subject of EEG, the feed-in tariffs paid to renewable power producers that are to be compensated by the EEG tax on consumer’s bills:

• The government wants to move forward quickly on a restructured EEG law, planning to table a proposal by Easter 2014 and then having everything voted by summer.
• The rate of further development will be slowed down, or at least brought under strict control. The share of renewable power production should not grow to more than 40 – 45% by 2025 and 55 – 60% by 2035.
• EEG feed-in tariffs will be made decreasing over time.
• Winners are picked, namely solar, off-shore wind, onshore wind in those locations that have favorable wind conditions and biomass projects using locally produced (waste) material.
• As of 2018 an auctioning model will be introduced. As of 2014, a pilot project for such auctioning will be executed for 400 MW of solar. It will be interesting to see whether this could herald a new way of subsidizing renewable energy.
• As of 2017 electricity from renewables is to be sold directly into the market and not through the grid operators.
• The grid operator and/or the marketer of the electricity should get the possibility of switching off the capacity for up to 5% of the annual production.
• It will be researched whether large producers of renewable electricity can be obliged to always produce a minimum quantity of energy.

The above could boil down to a complete overhaul of the German system of subsidizing renewable energy. But much remains to be researched, so it could still be watered down.

2.    On the reduction on EEG payments for energy-intensive consumers

The important thing is here that the text clearly states that the government wants to keep the reduction, albeit with some changes:

• Companies will have to show that they really are subject to international competitive pressure to get the reduction. Does this mean that the government will make a list of sectors? Will it pick winners and losers?
• It will no longer be sufficient to have an (ISO 500001) energy management system, companies will have to prove that they are effectively reducing their energy consumption.
• Companies producing their own electricity will have to pay EEG. It is unclear how much and how this will be measured. Auto-producers would also have to pay a grid fee. This is clearly in contradiction with another ambition of the government contract, namely to promote production of electricity on-site with cogeneration units. It is the goal to have a 25% cogeneration share by 2020.

3.    On climate change

 

• Germany sets a goal of reducing its carbon dioxide emissions by 40% in 2020 compared to 1990.
• In one of the clearest passages of the coalition contract, it is stated that back-loading of 900 million emission rights should be a one-off operation. And despite paying lip service to emissions trading, the contract states that operations such as the back-loading should not be executed if they create disadvantages for the companies concerned. So, for those that had hoped that the new German government would support stricter allocations and higher prices for carbon, I’m not convinced that’s what the contract says.
• The government wants to increase efforts in energy efficiency and draw up a national action plan for that, although it remains very vague what they mean with that, apart from having free energy audits for residential consumers.
• If renewables produce most of the electricity, electrical heating will be promoted.

4.    Capacity payments

 

The government thinks that as of 2020 there will be a shortage of conventional (coal and gas-fired) power production to deal with the intermittency issues of renewable energy. Therefore it wants to support smart energy applications. But it also wants to give support to owners of fossil fuel-fired power stations to keep them open. I presume this will mean the handing out of capacity payments to keep unused power stations warm. Again, the text is very vague, but it’s important to follow up on this, as such capacity payments would mean the creation of a new cost that is to be passed through to end consumers.

5.    Grid infrastructure

• The construction of new grid infrastructure will be coordinated with the further development of renewable energy production.
• The grid and intermittency issues of large-scale renewable power production will also be countered by supporting the further development of a pan-European power grid. This is a wise decision that could have important impacts for surrounding markets.

6.    Natural gas

 

Is prominently present in the coalition contract by not being present. This means that the German government doesn’t see the necessity of developing the gas market. Oh yes, gas is mentioned once. Fracking for producing the German shale gas reserves will not be permitted as long as chemicals that are toxic for the environment are to be used.

7.    Other topics

 

• The nuclear phase-out will be continued, the last German nuclear power station will shut down in 2022.
• Storage of power, a.o. by power-to-gas conversion, will be studied and/or supported. The text is very vague on this topic.
• The ability to act of the local utilities (the so-called ‘Stadtwerke’) will be a topic. Yes, that’s what the text says. No idea what it means. Will this government be the first one to realize that the disparity of the German energy sector is a cost-increasing problem and not a solution?

The new Merkel government’s energy policy might be anything from a serious transformation of the Energiewende to a continuation with small adaptations of the current policy. Immediately after the publication of the coalition contract, many observers questioned its financial solidity. This is certainly true for the energy policy part. Some of the topics could have severe cost-increasing effects. How does that match with the goal of keeping energy affordable? So it’s important to stay updated as the vague coalition contract text finds its way into legislation in the next months and years.

EU: don’t punish Germany for being best of class in renewable energy

The European Union wants to investigate whether the reductions on renewable energy contributions that Germany awards to its large industrial power consumers are in breach of competition rules. According to Handelsblatt, proceedings could start as early as the 18^th of December. Worst case, the EU could indeed decide that these tax reductions are unpermitted aid for the German industry. But for many German companies, the amount of renewable energy contribution that they have to pay exceeds their EBITDA. Having to pay the full amount would most probably mean the end of steel, non-ferrous metals or paper production in Germany. And I dare not even think of what would happen if companies were obliged to pay back reductions received in the past years. In recent years, the excellent performance of the German industry has been the main economic power factor in Europe. Therefore, I believe (or hope?) that the EU is pragmatic enough not to take any rash decisions that cause the shutdown of German energy intensive industry. It looks like German and European politicians are working towards a compromise. However, inside Germany, politicians are also tabling proposals to curtail reductions on renewable energy contribution. Therefore, I would like to shed some light on this issue from our daily practice of supporting industrial consumers in buying energy in different European countries, including Germany.

The European Union has ambitious targets for the development of renewable energy, such as having 20% of its electricity produced from renewable sources by 2020. But the different Member States have developed their renewable policies at different paces. Germany has been a very enthusiastic renewable energy adept. Way back in 2000, Germany developed a policy of supporting green electricity by obliging its grid companies to buy power produced from renewable sources at legally set feed-in tariffs, the so-called ‘Erneuerbare Energien Gesetz’ or EEG. To spur the development of the renewable technologies, tariffs were set at high levels. Under the first EEG law, some solar panels received more than 500 euro per MWh in feed-in tariffs. Now, there are a lot of critical remarks that can be made about Germany’s green power policy. But one thing cannot be said, and that is, that it would be ineffective. Looking at BP’s data on power production, we can clearly see that Germany has outpaced the rest of Europe and the world in developing green electricity. 48% of Europe’s solar power capacity has been installed in (not particularly shiny) Germany. Runner-up in Europe and globally is Italy, with half as much solar capacity as the Germans. And even on a worldwide scale, 33% of all MW’s of installed panels is to be found in Germany.

Germany is also European champion in the development of wind energy, although its dominance in this sector is less outspoken. 30% of Europe’s windmill capacity is planted in German soil. On a worldwide scale, Germany has 11% (keep in mind that Germany has a little bit more than 1% of the world’s population), with only much larger countries such as the US and China having a larger windmill capacity installed.

Germany is also Europe’s champion in consumption of biomass, another renewable energy that has been heavily subsidized by the EEG laws. It consumes 9,4% of the world’s biofuels.

This rapid move towards more renewable energy production has been dubbed the ‘Energiewende’ in Germany. This word got a particular significance when Germany decided to revamp its nuclear phase-out policy in the wake of the Fukushima disaster. The country seems to be succeeding in replacing low-carbon emitting nuclear power stations by low-carbon renewable energy. It is now producing more than 25% of its power from renewable sources.

The Energiewende is also a policy of industrial reconversion. With their combination of excellent engineering skills and the economies of scales of the rapid expansion of internal demand, German companies specialized in renewable energy have made a sizeable contribution in the development of affordable solar, wind and other technology. Unfortunately for German consumers, these affordable panels or windmills are now ever more often produced in countries with lower labor costs such as China. But if you want to point out any piece of legislation that has contributed to lowering the cost of producing (and installing) renewable technologies, the EEG is a likely candidate.

All these developments haven’t come at zero cost. The grid companies pay the feed-in tariffs to the developers of renewable power projects in Germany. They resell that renewable power to the grid based on wholesale market prices. Because the feed-in tariffs are higher than these wholesale prices, the grid companies are making losses. They are compensated for these losses by funds collected by making end consumers pay a renewable energy contribution (EEG-Umlage). As the renewable power production has grown much more rapidly than anyone could suspect, this contribution has risen unexpectedly high: 62,4 euro per MWh as of the 1^st of January 2014. This has caused the end consumer’s cost of electricity to rise above most other European countries (with Italy being the only exception). The graph below shows the power price in euro per MWh of a client of ours consuming 20 GWh of electricity in sites in four countries. It clearly shows that German power costs are much higher. A detailed analysis of the power bills shows that the high EEG costs are the main contributor to this problem.

The German government has been aware of that problem and has chosen to implement a policy to protect its large energy-intensive consumers, the so-called Härtefallregelung. Large energy-intensive consumers can get heavy rebates on their EEG bill. It is precisely this policy which is now under scrutiny by the EU. However, viewing Härtefall as an unauthorized subsidy for that energy-intensive industry would be outrageous. The reduction is granted to protect the German companies against costs that are higher than in almost any other European country. To just name one thing, the 2014 cost of EEG on itself, is higher than the all-in (regulated) price of electricity in France. If anything, than the Härtefall is leveling out the non-competitiveness of Germany’s energy prices. Anyone that says that it is creating a competitive advantage has clearly never seen electricity bills from large consumers in different countries.

That German companies pay more for (green) electricity is a consequence of a lack harmonization in the European Union of energy and tax policies. If the response of the European Union to that would be a demand for harmonization of the corrective measures, than there is clearly something very wrong with our Europe. How can you claim tax exemption harmonization if there is no tax harmonization?

In this framework, I clearly understand the demand of Peter Altmaier for support and respect for Germany and its attempt to continue its Energiewende without jeopardizing its economic strength. The German minister for the Environment uttered this demand in a German television studio as he was preparing for a trip to Brussels where he discussed this topic with EU officials. Germany has made and continues to make an important contribution to the development of renewable energy, both in terms of capacities installed and of lowering the technology cost. Punishing Germany for that by a ruling on EEG exemptions that puts its large industries in financial difficulties would be a grave error. It wouldn’t be good for European politics, as it would lay bare the deficiencies in European policymaking. It wouldn’t be good for the economy as it would jeopardize the health of Europe’s industrial powerhouse. And it wouldn’t be good for the environment as other governments might be less willing to develop renewable energy if they see they can’t protect their industry from its cost-increasing effects. The discussion regarding the high cost for end consumers of the Energiewende is already leading to reductions of the subsidies granted to new renewable energy projects. Some politicians even call for a (temporary?) stop of further development of green power in Germany.

The exemption from EEG contributions is not just challenged by the European Union. It is also the subject of a vivid social and political discussion inside Germany. This discussion makes clear what the whole EEG exemption ultimately is: a question of how the cost of developing renewable energy is distributed across the different social actors within Germany. As the energy intensive industries are exempted, other actors such as smaller industrial consumers, the service or commercial sector and households, have a larger bill to pay. Handelsblatt, for example, has announced that due to rising EEG costs, 273 utilities across Germany want to increase the cost of power for 8,3 German families by an average 3,4% or 39 euro per family per year. Such cost increases for households could be reduced if the exemption for the large energy-intensive industry was watered down. Germany is now rapidly heading towards a new, more leftish, government, which seems keen on reducing the amount of exemption received. I can only call here for cool-headed politics that realizes the importance of having a competitive heavy industry in Germany (and Europe).

All these remarks don’t mean that I don’t see any failings in Germany’s renewable energy policy and the exemption regulation. There has clearly been over-subsidizing, and scaling back subsidies is a good idea. Germany should indeed ask itself at what tempo it wants to continue its Energiewende. I also want to repeat my criticism that the rules for getting exemption from the EEG-Umlage are too harsh. I’m thinking here specifically about the rule that says that power costs should amount to 14% of the added value of a company. A company that reaches only 13,9% gets no reduction, just a little bit more cost and you enjoy almost full exemption. It would be good to create a more balanced, layered system with different categories that make sure that a larger number of companies enjoys (smaller) reductions. And maybe Germany should consider whether the high stranded costs of subsidies granted in the last ten years cannot be spread out more in time by swapping them for a long term loan granted to the grid companies. Although I understand that spreading costs in time is an ethically sensitive issue, generations to come will enjoy the fruits of Germany’s efforts to build up its renewable energy production apparatus and affordable solar and wind power technologies.