Why you should continue to negotiate your energy contracts

Way back in 2000, when Europe’s continental energy markets were deregulated, I remember how many business clients were thrilled by the prospect of negotiating their energy contracts. After decades of nerve-wrecking non-talks with arrogant monopoly utilities, they would finally get the chance to unleash the power of their contract negotiation skills on the important energy budget. A decade and a half later, we see more and more clients questioning whether negotiating energy contracts makes sense and if it’s not better to ‘just expand your running contract’. Reasons for that disillusion? First of all, in mature energy markets the part of the energy bill that you are negotiating, what we call the retail add-on, is just a tiny part of the overall energy bill. And as it is small, the amount of “savings” you can make by negotiating it is small as well. Moreover, energy companies often run highly standardized contracting procedures, making the room for improvements small. Nevertheless, with every contract negotiation that we as E&C do, we see that improvements can be made. And even if they look like small steps (dots and commas), they often lead to important improvements in the energy procurement practice.

Natural gas and electricity have become highly commoditized products. A product becomes a commodity when standard quality and service characteristics have been defined or developed for it, meaning that it can be bought with “price” as the primary focus. As far as energy is concerned, the quality is standardized. Whether you buy from supplier A, B or C, the natural gas or electricity as a physical product will not be different. Regarding the service, we have to remark that most of the traditional service aspects of a delivery of a product have also been standardized as far as energy is concerned. I’m talking here about aspects such as timing of the delivery, security of supply, responsiveness of the supplier in case of a supply interruption, etc. In the case of electricity and natural gas, it’s not the supplier but the grid operator that is responsible for the delivery at the gate of the client. And this is a regulated company delivering a legally regulated, standardized, one-size fits all service.

The standardization of quality and service level is an important step in the development of a wholesale commodity market. Wholesale markets, whether they are exchange traded or OTC, always face the liquidity dilemma. For them to become successful, they need to have sufficient volume traded. If there is a large diversity of products traded, the total volume traded (or the amount of money flowing into that market) will have to be spread out over all these different products, reducing the liquidity per product. With insufficient liquidity, bid-ask spreads will run up, price changes become erratic and it becomes difficult to find counterparties. As far as energy is concerned, it has proven to be possible to sufficiently commoditize energy products for successful wholesale markets, even exchange-traded, to develop. We have first seen this in the oil markets and in the US Henry Hub gas market, the UK’s NBP and Scandinavia’s Nordpool, and recently also in continental Europe’s natural gas and electricity markets with TTF and EEX being the best-of-class examples, but for example Poland’s Polpx recently developing very rapidly as well.

When products become commoditized, a phenomenon called ‘margin erosion’ occurs. The suppliers become retailers in the sense that they buy the product in the wholesale market and then sell it on to end consumers. The basic price reference becomes the wholesale price, which is the same for every supplier – retailer. They have to make their living from the add-on that they charge on top of that wholesale price. As suppliers can no longer distinguish themselves with better quality or service levels, it becomes increasingly difficult for them to charge a price premium for that add-on cost compared to other suppliers. That’s why we observe that as markets mature, the price differences between the suppliers become marginal. This is clear in a very transparent manner in the TTF-based gas markets, where suppliers offer energy at a very simple TTF + add-on in euro per MWh price formula. For consumers above 20.000 MWh per year, we often see at the end of a negotiation that there are three – four suppliers that are offering at TTF + 0,2 or 0,3 with differences of less than 5 eurocent per MWh among them. If you consider that the total value of the natural gas (commodity + other costs) is around 18 euro per MWh, you can clearly see how marginal a phenomenon retail price distinction has become.

Having observed this commoditization of the product, you could easily conclude that the energy supply business is commoditized as well. Hence, comparing energy supply offers is a simple matter of putting prices next to each other. “Negotiation” is even a hyperbole when we speak about commodities, as it’s just a matter of picking the best price, which in the case of many gas markets in Europe has become childishly simple. However, even if their product has become commoditized, the energy supply business hasn’t, on the contrary. As markets mature, energy suppliers have become suppliers of a set of services regarding the delivery of energy commodities that we can subdivide in the following categories:

  1. Profiling services. In the wholesale markets, energy can only be bought on a forward basis in rudimentary blocks. And the physical delivery of the electricity and natural gas goes through a complicated process of balancing. A supplier will buy the blocks for you and perform the complicated day-ahead, intraday and end-of-day financial settlement operations to make sure that you get delivered exactly what you consume. This profiling service constitutes the main economic rationale for buying energy through a supplier – retailer and not directly in the wholesale market. Due to his portfolio effect (he can go through the balancing mechanism on a portfolio-wide basis), the supplier can deliver the profiling at a very reasonable cost.
  2. Volume services. The blocks that you can secure on a forward basis in the wholesale markets come with no or very limited volume flexibility. Energy suppliers can increase the amount of volume flexibility offered to an end-client by using their portfolio effect again.
  3. Price hedging services. As the links between the end-consumer and the wholesale market, the energy suppliers have developed services to perform price hedges. Again, because of their portfolio effects, they can deliver these at a price and with a level of flexibility that is often unachievable for the individual client.
  4. Payment services. Suppliers offer payment terms which are longer than the terms they themselves have to pay to the counterparties in the wholesale markets or the grid companies and authorities in case they offer a single utility bill service. This means that they actually become a credit provider. The amount of credit that they provide and the conditions at which it comes can be more or less strict.
  5. Other services. Suppliers can develop other services in terms of invoicing services, advanced meter reading services, cost monitoring services, energy efficiency services, etc.

Remarkably enough, having a good level of the services described above doesn’t necessarily come at a price premium. It depends mostly on the operational and commercial practices that the different companies have developed. However, the differences in the level of these services makes contract negotiation important. And makes it necessary for clients to have the necessary experience to make a good assessment of the different contractual possibilities. Having a good insight into how suppliers work, e.g. when they perform a price hedge, can be very helpful in getting a better result negotiated. As a consultant, I’m obviously biased, but believing that the suppliers themselves will help you getting the necessary insights into their complicated worlds is somewhat naïve. Not just because of their ill will, but also because the account managers that you talk to often don’t have those insights themselves. As markets mature, we see that energy suppliers’ services in themselves become more standardized, as all the suppliers have to gradually adapt to the best-of-class service standard to stay competitive. However, even then a small difference in wording of e.g. a volume or a price fixing condition can make a very big difference in operational outcome, making it important to carefully check every offer received and negotiate conditions.

But not only such service aspects make it important for a client to have good contract negotiation. Even if the price differences are small, there is still one offer out there in the market that is the cheapest. It’s the responsibility of a professional procurement organization to go out and find that cheapest contract. This importance obviously grows as the consumption grows. 10 eurocents multiplied by 500.000 makes for more money to be made by contract negotiation than for a client consuming just 10.000 MWh. But then the price differences can be larger when the consumption is lower. So it is still worthwhile to go out in the market and negotiate the price conditions. With almost every RFQ we see that we can create value with contract negotiation, that the contract that the client ultimately signs is a better contract than what he would have signed without the negotiation, not just in the conditions but often also in price. The market has come to this stage of low retail add-ons and good service levels thanks to the negotiation efforts of many buyers and consultants. And it’s worthwhile to keep up the effort!

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.

Why spot contracts are not immune to volume risk

Readers of my previous blog article (in Dutch) will have remarked that I was quite agitated by misleading sales of spot contracts to end consumers. I would want to come back on a specific issue, the volume risk, and write a separate blog article in English on.


“No volume risk” is often cited as one of the advantages of a spot energy contract. And indeed, these contracts don’t have “volume conditions” in the sense of minimum or maximum volumes that have to be / can be consumed. Many buyers of energy have gone through agonizing experiences when they ran into the threshold levels of such traditional volume conditions. This was particularly a problem in 2009. Many industrial consumers of energy saw their consumption drop below levels that they hadn’t anticipated even in their worst nightmares. Moreover, many continental European energy contracts at that moment still had minimum volume conditions of a type that we call ‘hard take-or-pay’. It means that any energy that isn’t consumed needs to be paid for anyway at the contract price. But even those consumers that already had ‘soft take-or-pay’ conditions suffered. In a soft take-or-pay settlement, which has become very common, you pay the contract price and get back the spot price. As the reduction of consumption in 2009 struck many consumers, the overall demand for energy was going down. This caused spot prices to drop sharply. Therefore there often was a very big difference between contract prices that had been fixed in the bull markets of 2007 and the first half of 2008 and bearish spot prices for unconsumed levels of 2009. So, even with such soft take-or-pay arrangements, clients still had to pay a lot of money for unconsumed energy.


Of course, for anyone that has had to report to his management the payment of a few hundreds of thousands of euros for not consuming energy, the proposal of a contract without any such volume obligations sounds very tempting. And indeed, a spot contract is a ‘you only pay what you consume’ type of contract. Some such contracts really look at what you consume on an hourly basis and multiply that with the spot price for that hour. Most spot contracts look at the monthly consumption and multiply that with the average spot price for that month. So, even if your consumption drops to zero, no problem, no energy will be billed. If your consumption doubles, you’ll pay the spot price for that extra energy. No more thresholds to keep an eye on, just simply pay for what you consume. I can understand why some people call that ‘no volume risk’. But I don’t agree with them. Not at all.


First of all, it should be remarked that the zero volume risk proposition only holds as long as you keep everything open for the spot market. Many such spot contracts also have clauses that allow you to forward fix your prices. Such fixings are then always made for capacity blocks. Let’s say you are a client with such a spot contract and you expect you will consume 60.000 MWh next year and you want to fix your price 100%. Your supplier will come back to you with something like ‘OK, your load duration is 6.000 hours on an annual basis, so I’m going to fix a 10 MW Calendar year block for you’. If your contract is then regulated based on monthly consumption times the average spot price for that month, every month that you consume less than 5.000 MWh, you will pay the fix price and get back the spot price for the unconsumed volumes. If your consumption is higher than 5.000 MWh, you will pay the spot price for those extra volumes. If at the end of the year the aggregated volume of the months is 60.000 MWh, the volumes you haven’t consumed and for which you got back the spot price (in certain months) will equal the extra volumes bought at spot price (in certain months). If you’re lucky, you might have consumed less in exactly those months when the spot prices were high and more in the months with low prices. You could actually make some extra money that way. But it could also be the other way around.  The opportunity and risk are even higher when you have a contract that settles on an hourly basis. It should be remarked that in that case, an extra problem occurs of checking such bills based on hourly consumptions, fixed levels and rates.


The volume risk of forward fixing a capacity block can be reduced by buying ‘structured blocks’, meaning that you will use calendar, quarter and month products to fix capacities that correspond with your expected monthly volumes. For electricity, such structuring is further complicated by the fact that you have to construct a structure of base and peak-load blocks. However, unless you have a 100% accuracy regarding your volumes forecast, you will never be capable of making a fixing that exactly corresponds with your actual volumes consumed. And it certainly means that you find yourself in real big risk of having a big extra cost due to volume issues when you’ve fixed 100% of your expected volume and your consumption turns out to be structurally lower. If this coincides with a period of low spot prices (like we’ve seen in 2009), you will find your energy costs exceed the fixed price level (at which you probably budgeted) very rapidly. Same thing when a period of larger than expected consumption coincides with high spot prices. In those cases, you will experience that the old contract with its volume conditions wasn’t such a bad idea after all. In such contracts, the volume issue only starts to bite once you’ve hit the threshold volumes. For this reason we recommend any clients that want to have a high degree of certainty over what their future energy prices will be to sign traditional forward fixing contracts, even if they come with volume conditions (nowadays some suppliers offer consumers of smaller volumes forward fixing contracts without volume conditions).  If you want to sign a spot contract, only do it when you are willing to keep the price of at least 20% of your volume unfixed and open for the spot market. And if you have a high volume uncertainty, you should keep the price open for the spot market for even higher parts of the volume.


But even if you keep 100% open for the spot markets, this still doesn’t mean that you don’t have volume risk. High prices in the spot market often coincide with high overall consumption of energy, that’s very obvious economic logic. That means that consumers that have typical consumption patterns, e.g. consuming natural gas for heating in the winter or consuming electricity for cooling in the summer, have an increased risk of seeing periods of increased consumption coincide with periods of high prices and vice versa. Moreover, in the electricity markets you should take into account the large differences in hourly pricing. If you have a typical peak-load pattern, for example because you consume the electricity in an office setting, the probability of a large consumption in a particularly expensive hour increases. In a cold winter or a heat-wave summer, the combination of increased consumption and higher spot prices can cause serious derailing of budgets.


If you look at it in this perspective, the claim that spot contracts are free of volume risk, actually is true only if you look at it from the suppliers’ perspective. The supplier is sure that he will always get paid for what his clients consume at the exact same price at which he has to buy the energy in the spot market. (Or, if it is a contract settled on a monthly basis, a price very close to it.) No risk of having bought  too much for a client and having to sell it in a bearish spot market. No risk of having to buy more in a bull market. Actually, the volume flexibility conditions of traditional (forward) fix price or tranche model contracts are just that: flexibility, a way of reducing the volume risk. They mean that inside the tunnel or bandwith, you are sure of the price you will pay, regardless of what your exact consumption is. An 80% – 120% volume condition protects you against the negative effects on your prices of unfavorable spot market movements. Forward fixing your prices and accepting volume flexibility on that fixing, protects you against budgetary catastrophe in times of high consumption. In many cases, spot contracts are less expensive than forward fixings with volume flexibility. This clearly illustrates that with a forward fixing contract with volume flexibility, risk is shifted from the client to the supplier and not the other way around. And that makes the claim that spot contracts are less risky absurd.


This example clearly shows that as a buyer of energy, you need to be extremely on alert when somebody is proposing you something that has no risk. If I have learned anything in thirteen years in the energy markets, it’s that it is very hard to find ‘no risk at no extra price’. The closest thing to it could be the forward fixing contracts with unlimited volume flexibility that some suppliers currently offer to smaller consumers. But spot contracts aren’t a ‘no volume risk’ solution. Every energy contract negotiation is an act of carefully balancing risks and opportunities between supplier and client. A spot contract means a shift of volume risk from supplier to client. That explains why it often comes at a lower price.

On the success of Hub gas pricing across the globe

This week, I was invited to speak at a C5 conference in Berlin on long term gas contracts. My presentation (or speech rather) was on recent developments in gas production and the impact that they might have on developments in gas contracting in Asia. It gave me the chance of reflecting upon the transformations that we have recently seen in Europe’s gas market and their possible impact across the globe. I’d like to share those thoughts with you.


Several other speakers, among them Patrick Heather of the Oxford Institute of Energy Studies and Brian Little of Nexant, confirmed that in 2013 more than 50% of Europe’s gas will be brought to market based on Hub pricing instead of oil-indexed pricing. The word ‘tipping point’ was shortly discussed, but most speakers were rather prudent  as to using it. Whether this ‘more than half the gas’-moment symbolizes the point at which an inevitable evolution towards 100% Hub-based has been started, I leave up to energy market historians to decide in a year or five. It’s not important, the important thing is that we are there already. If anyone would have said at a similar gas industry conference in 2008: “in five years, more than half of Europe’s gas will be traded at Hub conditions”, he would have been ridiculed. But it has happened, which once again shows how unexpectedly dynamic markets can be.


To assess whether this rapid evolution towards gas-to-gas pricing can be repeated in other parts of the world such as Asia, let us look more deeply at the phenomena that explain it. I am explicitly not talking about causal relationships, as I believe that it’s difficult to assign what exactly has been a cause and what has been an effect in these gas market dynamics. I see four phenomena:


  1. As Emir Hamad bin-Khalifa Al-Thani has ceded power to his son, it is befitting to praise his role in the development of Qatar’s gas industry and his significance for the world’s gas markets. The extra volumes of (liquefied) natural gas brought to the world’s markets by the Qatari’s have caused a supply glut that certainly in the years 2009 – 2011 contributed to low prices on Europe’s Hub markets. It caused the decoupling of Hub and oil-indexed prices that, even if Hub prices have risen in the last two years, is still a reality. I’m not sure if their contribution to the development of the Hub pricing model was a conscious choice, but the Qatari’s did even more than just bringing extra MWh’s into the market. They were also the first major supplier that signed long term contracts with Hub-indexation rather than oil-indexation.


  1. In the last five years, there has been a ten percent decline in the demand for natural gas in Europe. I was pleasantly surprised to see on the conference that now even a large gas supplier such as VNG stated that this decline in demand might be structural and not just linked to the economic crisis in Europe. The gas industry has long been quite delusional in thinking that the demand will come back as soon as the crisis is over. VNG was giving examples of how the broader climate policy is causing a structural decline in gas demand in Europe.


These first two phenomena have caused a temporary surplus of supply in the European market. I think this is a quite essential feature of energy markets. In energy markets, lead times for supply expansion are quite long. Therefore, supply elasticity is slower than demand elasticity. If prices of energy are high, producers start up projects to produce, pipe and/or liquefy extra volumes, projects that take five to ten years to start delivering. This is the boom phase. By the time the extra energy hits the markets, demand has often started to decline in a reaction to the high prices. The result is a supply glut. Prices crash and investment comes to a standstill, the bust phase. As demand increases again in a reaction to the higher prices, supply crunches start to occur, causing prices to rise again and the whole cycle to start up again. I know it’s a simplified scheme, but there are too many examples of it to ignore it. One of the interesting features of the shale gas development in the US, is that the lead times for supply adaptations seem to be much shorter than in conventional gas development.


In the glut phase, we have a clear example of a buyer’s market. The consumers have the bargaining power. This is clearly what we have seen in the last five years in Europe. End consumers could put pressure on traditional suppliers: mid-stream players that buy in the framework of long term contracts from producers to resell to end clients. Clients pushed the mid-stream companies to make Hub-based deals instead of the more expensive traditional oil-indexed contracts. The mid-stream companies were squeezed between the Hub conditions they had to offer their clients and the Oil-indexed prices enforced on them by the producers. This has caused a spate of contract renegotiations. Some of those came to a commercial solution. Others ended up in legal action. Last week, news broke out that RWE has won such a dispute against Gazprom. All this fighting over pricing between suppliers and producers (which is what this whole conference was about), clearly supports my vision that in the last five years the European gas market has been a buyers’ market. Of course, the lower price level has been the main reason why these buyers opted for Hub pricing. But I’m seriously convinced that in the long term the greater transparency, fairness and economic logic of Hub pricing will continue to support it. Moreover, two more phenomena have contributed to the success of Hub pricing in Europe.


  1. In many corners of Europe, some decisive steps have been taken to finalize the liberalization process that was started in the late nineties. Germany’s opening up of the gas market since 2007 has been crucial. In 2012 we saw a similar process in Italy, where government decisions to free up transit capacities to competitors of incumbent suppliers has caused the PSV Hub market to develop rapidly. Poland has announced a similar policy for this year, it will be interesting to observe if it succeeds. And how about Spain, which wants to launch a Hub, will that be supported by measures facilitating access to the Iberian market? It has become much easier to develop a gas supply business in many European countries. This has been the playing field of smaller (second tier) mid-stream players, that have developed supply businesses based on sourcing gas at the Hubs. They were the competitive nail in the coffin of the first tier mid-stream companies and their long-term oil-indexed contracts.


  1. This was made possible by the rapid development of Europe’s wholesale Hub markets themselves. Here it becomes very difficult to assign causes and effects, but the higher liquidity of many of these markets have developed and facilitated the development towards Hub-based gas retail markets. Especially TTF has played and increasingly plays a pivotal role in this.


However, in the last three years, some disturbing factors have occurred. Hub prices have started to increase. This is due to two reasons. The first one is the well-known increased demand from Asia. The second one is the delays of gas production projects that we have seen. I wouldn’t exactly say that this has caused a supply crunch, and it should be remarked that Hub prices are still well below oil-indexed prices at this moment. Still, the glut is getting thinner, causing nervousness in the markets. As a landmark of this development, we can point out the decline in LNG production witnessed in 2012. This decline was mainly caused by the reduction of production in traditional LNG production countries such as Egypt and Yemen.


Could better times be ahead? We have recently made another tour of the websites giving information on today’s projects for developing new LNG production. If all goes according to plan, we might see an increase of 30% in LNG production by the end of 2015, most of it coming from Australia, but it also contains the first cargoes of American shale gas brought to the world’s markets through the Sabine Pass terminal. Treat this information with care, as the Australian projects have been plagued massively by cost overruns and delays. But several industry experts that I spoke with at the conference confirmed our information. We are not talking here about planned LNG production, we are talking about facilities that are being built, so the chances of the projects being abolished are rather slim. Will Australia become the next Qatar in the coming two years?


That brings me to the Asian market, which is where most of this Australian gas will go (which would make more gas from places closer to us available to the European market). If these extra LNG volumes hit the market, one of the four phenomena that contributed to European Hub market development, more supply, would materialize in the next three years. But as far as the other four are concerned, it’s looking rather bleak. Gas demand in Asia is still increasing. And there are no steps taken towards liberalization of the gas markets or development of Asian gas Hubs. Therefore, the development of a full-fledged Hub market like we have seen in Europe seems improbable in Asia. What we might see though, is continuing and increasing pressure of Asian midstream gas companies to index their gas contracts to a Hub price (European or American) rather than to oil prices. This illustrates an important point about the main topic of the conference. The question is not whether long-term contracts will prevail or not. The question is which pricing model will be used in future long term contracts.

Le marché de l’énergie français en Décembre: une fin d’année mouvementée pour EDF et GDF!

Les différents événements observés à la fin de l’année 2012 témoignent de la mutation constante des marchés. EDF s’est montré très offensif sur le marché du gaz pour asseoir davantage sa position et tenter de faire face aux tensions croissantes. En revanche, les déconvenues liées à l’EPR et le souhait de Hollande de fermer Fessenheim jettent un froid sur la scène nucléaire française. Même bras de fer avec GDF en Belgique, qui cherche à redémarrer ses centrales nucléaire à Doel et Tihange. Par ailleurs, dès Janvier, GDF va pouvoir appliquer en France une hausse des tarifs réglementés pour le gaz, mais en augmentant heureusement la part d’indexation sur le marché hub dans sa formule d’approvisionnement.


Un nouveau dérapage des coûts de construction du premier EPR en France a été annoncé début décembre. La facture avoisinerait désormais les 8.5 milliards d’euros, au lieu de 3.3 milliards d’euros prévus au début du projet. Suite à cette annonce, l’italien ENEL a décidé de se retirer du projet, laissant EDF faire cavalier seul et lui rembourser au passage les 613 millions d’euros investis. Enel se justifie également  au travers de la « forte baisse de la demande d’électricité et un calendrier incertain pour les autres investissements dans le nucléaire en France». La question de la rentabilité de l’EPR est alors ouverte. Tout dépend de la suite qui est donnée: s’agira t-il d’un modèle unique ou est-ce le premier d’une construction en série? Le président du directoire d’Areva (Luc Oursel) a lancé quelques chiffres: selon lui, le prix de l’électricité produite sur ce site coûtera entre 70 et 80 euros par MWh, à comparer aux prix de marché inférieurs à 50 euros par MWh actuellement, et au prix de l’ARENH de 42 euros par MWh en vigueur. Même si la construction en Finlande souffre également de problèmes, le chantier des deux EPR en Chine obéit encore au planning fixé et se maintient dans le budget prévu. Toujours selon Areva, le coût de l’électricité fournie par un EPR standard devrait à terme tomber à 60 euros par MWh en Europe. En effet, M. Oursel a confirmé son objectif ambitieux de commercialiser au moins 10 EPR de 3ème génération d’ici la fin de l’année 2016 et se doit donc de rassurer la clientèle! Parmi ces 10 EPR, 2 seraient très probablement construits en Grande Bretagne et exploités par EDF Energy, mais il y a encore quelques incertitudes à l’heure actuelle.

Poursuivre l’exploitation d’une centrale existante est donc bien moins risqué en termes économiques. Cependant, le débat a encore été ravivé quant au souhait de François Hollande de fermer Fessenheim d’ici 2016. Il s’agirait d’une bien mauvaise affaire pour EDF au vu des investissements en cours. Le montage du dossier de démantèlement prendrait environ cinq ans, mais EDF serait contraint de réaliser entre temps les nouveaux investissements imposés par l’expérience post-Fukushima, soit environ 350 millions d’euros. Cela s’ajoute aux travaux récemment effectués pour prolonger l’exploitation de la centrale jusqu’en 2021. Ceux-ci avaient déjà couté 300 millions d’euros. Ces travaux en font par conséquent une centrale à l’avant-garde des normes de sureté les plus exigeantes! Par ailleurs, dernier bémol, EDF se doit fournir de l’électricité à ses homologues allemands et suisses qui ont participé au financement de la centrale, et cela au coût de production actuel estimé à 25 euros par MWh, bien inférieur au prix de marché (centrale déjà amortie). Une perte de plusieurs centaines de millions d’euros est là aussi à attendre. Pour orchestrer cette fermeture, Francis Rol-Tanguy, surnommé M. Fessenheim, a été nommé en Conseil des ministres mercredi 12 décembre. Il devra garantir que les emplois liés à la centrale soient préservés. Il n’est cependant pas parvenu à entrer sur le site lors de sa visite le vendredi suivant, refoulé par des salariés mécontents, qui n’ont « pas besoin de liquidateur ». De nouvelles actions sont prévues.

En Belgique, Electrabel (filiale de GDF) tente d’obtenir le feu vert pour redémarrer Doel 3 et Tihange 2, les deux centrales stoppées  suite à la découverte de fissures dans les cuves qui abritent les cœurs des réacteurs. L’entreprise a remis début décembre un rapport à l’Agence Fédérale de Contrôle Nucléaire (AFCN) avec ses conclusions et son plan d’action pour le redémarrage des deux unités, estimant qu’un redémarrage est possible : “Toutes les normes et standards internationaux ont entièrement été respectés lors de la construction des centrales” et  “le constat initial selon lequel il s’agirait de défauts dus à l’hydrogène non évolutifs et formés lors de la phase de forgeage est confirmé” et indique que « les résultats confirment l’intégrité des cuves des réacteurs considérés, ce qui permet le redémarrage immédiat et l’exploitation sûre de Doel 3 et Tihange 2 ». L’évaluation finale de l’AFCN est attendue pour la mi-janvier 2013. Une telle annonce a redonné de l’optimisme au marché de l’électricité en Belgique, avec des prix atteignant des niveaux intéressants.

Il y a quelques années, il était fait mention d’une renaissance nucléaire à travers le monde. La France avait la volonté ferme de placer son industrie nucléaire à l’avant-garde de cette nouvelle vague d’investissements. Que reste t’il de cet optimisme? La catastrophe de Fukushima et les évènements de 2012 en Belgique ont montré que l’électricité nucléaire semble moins sûre que promis initialement. Tenant compte des conséquences catastrophiques qu’un accident de centrale nucléaire pourrait avoir, on ne peut prendre aucun risque avec un potentiel problème de sécurité/sûreté. De plus, en raison de la taille de ces centrales, un arrêt lors d’un éventuel problème mène à un défaut de capacité disponible considérable. Imaginez-vous que l’on découvre demain un problème nécessitant  de fermer immédiatement toutes les centrales nucléaires en France. L’échec financier de Flamanville démontre que le nucléaire n’est pas une électricité bon marché non plus. Sans aides à l’investissement et avec la prise en compte de ces coûts de sûreté, l’électricité nucléaire se veut plus chère que l’électricité produite à partir des sources fossiles. De plus, elle n’est que légèrement moins chère que l’électricité verte produite à partir d’éoliennes, à travers les panneaux photovoltaïques ou grâce aux centrales biomasse. Les coûts d’investissements de ces énergies vertes suivent par ailleurs une courbe décroissante, ce qui n’est pas tout à fait le cas pour le nucléaire.

Le gouvernement français actuel semble être sensible à ces arguments contre l’expansion de l’industrie nucléaire. Néanmoins, si l’on tient compte de la grande dépendance du nucléaire en France (la plus forte dans le monde), un renversement complet et rapide de la politique énergétique nous semble difficile à réaliser.


Les tarifs règlementés du gaz naturel vont augmenter en 2013. Delphine Batho a confirmé une hausse de 2,4% au 1er janvier, et non pas de 0.8% comme cela aurait du être le cas. En effet, le Conseil d’Etat a  jugé trop faible la hausse de 2% accordée par le gouvernement à GDF Suez en Octobre dernier et réclame une correction (estimant que la limitation de la hausse imposée par l’Etat n’était pas conforme, porte préjudice aux fournisseurs alternatifs et crée un déséquilibre budgétaire pour GDF). Les nouveaux tarifs permettront donc de rattraper le retard accumulé. Cependant, bonne nouvelle, la renégociation des contrats d’approvisionnement demandée par le premier ministre a aboutie positivement : la part d’indexation sur les hubs va augmenter de 26 à 36% dans la formule d’indexation du prix (et donc dans le portfolio de GDF), permettant de contenir cette hausse qui aurait le cas échéant été de 4%. La part des produits pétroliers recule donc. Seconde modification: les prix seront ajustés tous les mois et non plus tous les trimestres pour lisser les évolutions.

La partie d’échec géopolitique qui oppose les deux projets de gazoducs concurrents South Stream et Nabucco, portés respectivement par la Russie et par l’Union Européenne, vient de tourner à l’avantage du premier. Vladimir Poutine a inauguré le démarrage de la construction du gazoduc South Stream. Celui-ci est censé couvrir 2 380 kilomètres dont 925 kilomètres en offshore pour une mise en service fin 2015. Le coût est estimé à 16,5 milliards d’euros. Le tracé évite soigneusement l’Ukraine, et permettrait également de contrôler une grande partie des livraisons du gaz en provenance des gisements de la mer Caspienne et du Kazakhstan, concurrençant directement le gazoduc alternatif Nabucco. Henri Proglio, PDG d’EDF était présent à l’inauguration, dans la mesure où EDF intervient à hauteur de 15 % dans ce consortium. De nombreuses discussions quant à la pertinence de ce projet sont ouvertes. Il est cependant clair que cela va à l’encontre de la politique de L’Union Européenne visant à accroitre la diversification des approvisionnements de gaz!

Preuve du dynamisme et de la volonté de développement d’EDF dans le marché gazier, l’entreprise s’est portée candidate au sien d’un consortium à la reprise de TIGF (filiale transport et stockage de gaz du Sud Ouest mise en vente par Total), estimée entre 2 et 3 milliards d’euros. Annoncé comme un autre possible repreneur probable, GDF n’a pas remis d’offre. Sa filiale GRTGaz gère pour l’instant les réseaux des 2 autres hubs PEG Nord et PEG Sud et aurait pu compléter son tableau de chasse avec la dernière pièce du puzzle, permettant éventuellement un rapprochement plus rapide des 3 hubs.

La France continue à mener une politique à double visage concernant son marché de gaz naturel. D’un côté, la pression mise sur GDF pour évoluer vers une plus forte indexation Hub (plutôt que l’indexation pétrolière) est en phase avec la politique européenne. Mais d’un l’autre côté, des opportunités pour le renforcement des marchés Hub sont ratées. La France souffre du manque d’unité de son marché interne de gaz. Si GDF reprenait le réseau TIGF, une unification pourrait être réalisée, avec comme résultat un meilleur fonctionnement du marché Hub français. En plus, alors que la France pousse GDF à forcer ses fournisseurs à s’indexer sur le Hub, EDF assiste le plus grand ennemi des hubs gaziers, Gazprom, à réaliser son projet South Stream, un projet menaçant la diversification de fourniture nécessaire pour la réussite des marchés Hub en Europe.

Les adaptations récentes de la politique énergétique de la France semblent être inspirées par une acceptation de certaines réalités de marché plutôt que par une volonté d’avancer. Reste à voir si une politique plus visionnaire se réalise.

article by Baptiste Desbois

TIGF sells its gas transportation grid

It has always been an oddity in centralist France, this part of the gas transportation grid called TIGF. It is situated in the South-West of the country and it is owned by Total and not by state-held gas firm GdF. Total has now decided to divest and sell its piece of French gas grid. Four bidders are selected: EdF, Enagas, AXA and CDC. Hold on, you might ask, did you say EdF and not GdF? Well indeed, GdF, owner of the rest of the transportation grid in France is not among the bidders. So the unification of France’s gas transportation grid will not happen.


One of the main flaws in European gas market liberalization is the lack of a North – South gas corridor. There is a pipeline link between the Netherlands and Italy, but so far, no extensive trading activity was seen due to failing capacity rights allocations. And Spain is a gas island, linked to the rest of Europe with just a small pipeline. Also, the lack of good links between France’s regional gas grids (PEG North, PEG South and TIGF) makes North-to-South gas competition difficult. Not unifying France’s gas transportation grid by having GdF at least bid for TIGF therefore looks like a missed chance at first sight. The lack of interconnection with Southern-Europe means that the key-consuming region in the North-West is not plugged directly into the gas fields of Northern-Africa. It also means that Spain’s many LNG import terminals, which due to the crisis have large spare capacities cannot be used to alleviate the broader European market. Organizing a better North-to-South gas market integration looks like a vital step in improving Europe’s diversity (hence: security) of supply.

The necessity of diversifying Europe’s gas supply has been emphasized by the recently announced takeover of Wingas shares by Gazprom. Wingas was a 50/50 joint venture between Wintershall, the oil and gas business of German chemistry giant BASF and Russian gas behemoth Gazprom. BASF has now ceded its shares to its Russian partner, getting access to upstream production assets in Russia in return. The acquisition of Wingas earmarks Gazprom’s continuining efforts to get hold of downstream assets in the European market. And this is not a small step. Wingas is a large gas supplier in Germany and has important positions in the Benelux, French and UK market and in Denmark, Austria and the Czech Republic. Gazprom is now completely owning one of the top ten European mid-stream gas companies. Getting control over Wingas is an important step in Gazprom’s strategy of acquiring a dominant position in the European gas market. Without entering into the geo-political speculations that always surround Gazprom’s business decisions, anyone with a heart for European gas market competition will agree that becoming to reliant on a single source of supply isn’t a good thing. With North-Sea gas production starting to decline and with increasing competition on the world’s LNG markets, extra supplies coming from the South of Europe could bring welcome relief.

(Just another remark on Gazprom’s acquisition of Wingas. Gazprom’s strategy of dominating Europe’s gas market doesn’t seem to be very successful until now. Gazprom seems to be losing rather than winning market share. The Russians’ stubborn resistance to the replacement of expensive oil-indexed gas pricing with the more fair and transparent pricing at Hub conditions is the main cause for this. Shortly after the announcement of the Wingas share deal, BASF announced that it signed a 100% Hub-indexed 4,5 bcm per year gas deal with Statoil. This is an important illustration of how Europe is turning its back on Gazprom and its oil-indexation fetish. But of course, if the Hubs can’t get access to supplies outside of Russia, Gazprom might prevail in the end.)

Returning to the South, it is very interesting to see Enagas, the owner of the Spanish gas grid bid for TIGF. If they would be successful, this could lead to a better interconnection of the Spanish and French gas markets. It could also mean that a cross-border gas grid and balancing zone comes near. We could consider this to be comparable to Gasunie’s attempt as of next year to extend the Dutch gas Hub TTF into Northern-Germany. Such cross-border gas grid operations are a very interesting developments towards an integrated European gas market. However, with so many things that are still to be fixed inside the Spanish market today, this paragraph might sound like day-dreaming, I realize. There remain issues to be solved with different odorization practices in France and Spain for example.

The fact that Electricité de France (EdF) is among the selected bidders confirms that the traditional French electricity producer continues to diversify. EdF wants to become a broader energy group by expanding its gas business. It is unclear to me in how far it can achieve this by going into the grid operation business. This seems to be based on the mistaken belief that owning parts of grids is helpful in extending market share. The experience of the past five years in Europe’s gas markets have shown that independent grids with easy access to their capacities are the best option for developing gas trading. It is also unclear how financial insitutions like AXA and CDC will contribute to solutions for Europe’s gas grid challenges.

Finally, by selling TIGF, Total is following a trend among IOC’s, Independent Oil Companies. These are retreating from downstream energy marketing to have more capital to invest in the increasingly expensive exploration and production activities where they are in fierce competition with NOC’s (National Oil Companies). Last week I was speaking to the country manager of a large IOC and he confirmed to me that his company had no intention at all to go into the retail gas business in Europe. Total is still offering gas to end clients in several European countries, among them obviously France. Could the sale of TIGF mark a broader retreat to the upstream activities?

Why energy suppliers need clients

Last week, we had another episode in an ongoing discussion with energy suppliers. Suppliers of gas and electricity in markets that have reached an advanced state of liberalization have seen the margins in the retail part of the market all but dissapear. On an industrial consumer, a supplier of energy can make just a few thousands of euro of margin per year. German, French or Belgian gas consumers with an excellent consumption profile, for example, pay as low as Zeebrugge or TTF plus 0,5 euro per MWh. Similar clients in the Netherlands or UK might even pay lower add-ons. From that 0,5 euro add-on price (let’s say times 100.000 MWh, which makes 50.000 euro on a yearly basis), the supplier needs to cover his balancing, volume, trade timing, bid-ask spread, credit and other risks. He also needs to pay for his commercial apparatus, account managers and support staff, their offices, computers & cars, etc. That leaves just a very small amount of money in terms of profit margin. And also, if it goes wrong, e.g. with one of those big clients going out of business with unpaid invoices, the margin is quickly gone.

The erosion of retail market margins was to be expected. In mature energy markets, retail prices are completely aligned to wholesale prices. There is no direct selling from producer to end consumer. If the benchmark wholesale market for power is at 50 euro per MWh, then no producer will sell at 45 to an end consumer (which would be very stupid indeed). As a consequence, all retail prices are aligned to the wholesale price. Also, wholesale markets are monolithic country-by-country blocks. In the Dutch market, everybody is buying electricity at Apxendex and gas at TTF conditions, in Germany EEX, NCG & GPL are the market where everybody buys, in Belgium Apxendex and Zeebrugge or TTF. There is no means of beating your competitor by buying the energy in a cheaper wholesale market. Everybody makes a retail price based on the same wholesale price level. That makes the margin, or the add-on on top of that wholesale level very transparent and susceptible to steady erosion towards a level at which competitors “barely survive”.

Some suppliers blame consultants such as us for these low margins. I think that’s shooting at the messenger. True, energy procurement consultants such as E&C add value to their clients by assisting them to negotiate as sharp as possible and to exploit all possibilities in the markets. We are often the first to find out if a certain supplier can offer real low add-on prices and because we service many clients, we speed up the spreading of this information. But if suppliers claim that without us clients would not get access to those suppliers with low add-on prices, I think they are giving us too much credit. The 0,5 euro add-on in the gas markets is there because a supplier was willing to go that low to win new clients. If margins are low, this is due to the laws of competition. Consultants might facilitate this, but they are not the cause.

Suppliers also claim that these low levels of profitability are unsustainable, that retail margins will rise again. Well, they’ve been claiming that for many years now, they claimed it when the add-on price on gas contracts dropped to 2 euro per MWh also. And the prices dropped lower and they are still in business. Other suppliers threaten to retreat from the retail energy market because of the low margins. “Why do we bother making clients for those few thousands of euros per year”, they ask.

Suppliers of energy would better have a look at the banking business to understand why even at these low margins, it makes sense to continue with their retail outfits. If you make a loan with the bank, and you negotiate it well, you might find out that the retail bank’s margin is minimal. However, the bank is willing to do this, because making loans with end consumers is an essential part of its strategy for making money. The same is true for energy companies. Without their retail clients, energy businesses would make less money and be exposed to larger risks. To understand this, we have to go into the details of how energy companies make money.

The large profits of energy companies are first of all made upstream in their production divisions. Money is made with low marginal cost power production plants, such as ageing nuclear plants. And it is made in the gas fields, to which Europe’s energy companies, unfortunately, have limited access. Another moneymaker for energy companies is the trading desk. Through the buying and selling of futures contracts and through portfolio optimisations in spot and within-day markets, the traders maximize an energy company’s profits. Just have a look at Dutch energy companies such as Nuon, Essent or Eneco. They don’t have any high value production assets, as most of their power is produced in Europe’s marginal gas-fired power plants. The Dutch market is very competitive, so retail margins are more than minimal. And still, these companies manage to make reasonable profit margins, year after year. This is thanks to their trading talent. Some will credit the Dutch mentality for this (I once attended a conference where a Dutch speaker claimed, “we are Dutch, we trade the world”). But I think it is mostly due to the fact that lacking valuable production assets, Dutch utilities were obliged to develop their trading floors faster than others.

Now, for an energy company’s trading floor, having retail clients is a very valuable asset. The end clients take positions in the market. They fix their prices because they sign fix price contracts or “click” in the framework of multi-click contracts or they keep their positions open for the spot market. In any case, the combined position of the clients is something against which the trader can trade. To put it very simply, if the clients have fixed at an average price of 55, and the trading floor manages to fix at 50, than 5 euro’s per MWh have been made for the company. The end client’s position will also serve as a risk limit for the traders. Let’s say that the trading floor has that 50 euro per MWh position, the clients have 55 and the market starts to fall. The trading floor might start unwinding some of its positions, in the hope of fixing them again at a lower level. However, in that unwinding operation, the 55 euro per MWh of the client position will serve as a risk limit. I know that I am oversimplifying, but I’m quite sure that in any energy company, the high-profit trading desk would protest if the low-profit retail business was left out of the profit-making equation.

If you look at the profitability of the sales departments of energy companies in isolation, you could indeed come to the conclusion that the low margins are killing the energy business. But you have to look at the broader picture. Having retail clients is an interesting risk limiting asset for energy companies. Therefore, I don’t believe that sales to end clients will easily be abandoned. And to get hold of that asset, there will always be companies willing to offer at lower add-on prices. And energy companies will continue to complain about low retail business profitability. And blame consultants for it.

Forward fixing capacities or percentages of volumes?

More and more large and medium-sized consumers in mature markets, are being approached by suppliers offering them full flexible power contracts. The main characteristic of these contracts is that the forward fixing of prices is done on capacity blocks instead of on percentages of volumes. The risk and opportunities of such contracts are very different from more traditional supply contracts. Let me start this blog article with an explanation of this new contract type with a short history of open market energy contracts offered to medium- and large-sized consumers of natural gas and electricity in Europe:

  1. In regulated markets, these consumers were paying tariffs that had multiple variables. The structures were linked in multiple ways to consumption patterns with capacity and consumption terms, peak, off-peak, weekend or even more periods and seasonal differences. The prices were linked to parameters reflecting underlying cost changes of the utilities, e.g the oil-indexations of the utilities’ long term gas contracts. As a result the energy pricing process was complicated and non-transparent. Especially for buyers that needed budget stability, this caused issues.
  2. Therefore, the practice of forward fixing prices became very popular rapidly after the markets were opened up. This spurred the development of exchange-traded and OTC futures and forward markets where the suppliers hedged the fixed prices they offered their clients. As these hedging procedures were streamlined, suppliers passed on the full volatility risk of these markets to their clients. If the wholesale price rose from 30 to 40 euro’s per MWh, e.g., the fix prices that consumers were offered rose by equal amounts, regardless of which supplier was contracted. Large consumers started to realize that the moment of closing the contract was the most important price-setting factor. And more and more of them started to grasp that fixing everything in one moment that you sign the fix price contract, is the win all – loose all option.
  3. This gave birth to a new contract type, which is now very widespread among medium-sized and large consumers of energy, certainly in North-Western Europe: the clicking contract. This is still essentially a fix price contract. The client will have a price fixed for all the MWh’s that he consumes before the period of consumption starts. How does that work? Let’s say that you have such a clicking contract for 2014. Your contract has a formula that tells you how your price will be calculated based on the Cal 14 contracts, base and peak (if available). You can keep track of the Cal 14 contracts every day on the exchange. When you think there is a good moment, you can “click”, meaning that you fix that day’s Cal 14 price for a certain percentage of your annual consumption. If you have, for example, 6 clicks of equal portions, the price you will pay in 2014 will be a fix price that is based on the calculation of your price formula using the average of the Cal 14 prices on each of the six days that you chose to do your clicks. This gives you the opportunity of spreading the risk of your price-fixing decisions.
  4. As the clients’ needs to hedge their wholesale energy market price risk grew more sophisticated, suppliers started to offer varieties on the basic clicking theme:
    1. Very early on, vertical clicks were introduced. Instead of fixing on Cal-products for percentages of annual volumes (i.e. horizontal), clients were offered to fix on quarterly products and for the volumes per quarter.
    2. Combinations of vertical and horizontal appeared. In such contracts, clients can for example fix the price for 50% of the consumption with four clicks on the Cal-product and the remaining 50% with one click on each of the quarters.
    3. Clients with many clicks, found out how hard it gets to ‘beat the market average’. In some organizations, “making the click” entails a responsibility nobody is eager to take. Therefore, suppliers started to offer contracts where the price is based on the average of a Cal, Quarter, and/or Month product during a certain period. An example could be that your 2014 price will be based on the average of the Cal 14 price for each trading day from the 15th of January 2013 to the 15th of December 2013.
    4. In recent years, spot markets have quite consistently beaten the forward markets. Therefore many consumers want (part of) their energy price indexed to spot markets. Some of them go all the way to a 100% spot-indexed natural gas or electricity contract. Many stick with the clicking contracts, but build in the possibility of indexing a percentage of the consumption to the spot market. This percentage can be defined at the moment of signature of the contract, but often, contracts allow the possibility of swapping a click for a spot indexation. E.g. a contract with 10 clicks on the Cal-product, if the client doesn’t execute all 10 clicks by the 15th of December, the remaining clicks are transposed into spot-indexation.

As you can see, the hedging possibilities of the clicking contracts have reached a high level of sophistication, certainly in North-Western Europe. In less mature markets, like Spain and Italy, the products are still rudimentary, as many large consumers are still in the process of making the switch to clicking contracts. But in countries like the Netherlands, Belgium or Germany, most consumers now have highly individualized approaches to how their prices are being fixed (or spot-indexed). It is sometimes questionable whether the level of complexity is still serving risk-mitigating purposes, but that is a topic for another blog article.

For all their sophistication and complexity, the clicking contracts are still creating hedging risk for the energy suppliers. They still create the risk for the supplier that the revenue he generates on his client is not completely matching with his costs in the wholesale market. This is due to the fact that the clients fix percentages of volumes with every price fixing. The supplier commits to apply that price for any volumes consumed between the volume flexibility margins of the contract and regardless of the moment that the volume has been consumed.

Let’s say for example that a client has a contract to fix his 87,6 GWh of 2014 gas consumption in 10 clicks on the TTF Cal 14, a contract with 80% to 120% volume flexibility on the annual volume. Every time that the client clicks, the supplier can buy a 1 MW block of TTF Cal 14. He will get 87.600 MWh delivered at the price that he fixed at the TTF during 2014 (a year has 8.760 hours). If the client consumes 90.000 MWh, he will have to buy the extra volume in the spot market. If the spot price is higher than the forward price, he will loose money. If the client consumes only 80.000 MWh and the spot market is lower than the forward price, he will loose money again, as he pays the forward price for the 7.600 MWh of forward bought but unconsumed gas and he can sell them back at the lower spot price only. This is why more volume flexibility will cost more money in terms of the add-on on top of the TTF wholesale price. On top of that, the supplier has hedged capacity blocks, 10 MW in total. But the client will not consume his 87.600 MWh (or 80.000, or 90.000, or anything in between the volume limits) in equal 10 MW per hour chunks. One hour, he will consume 12 MW, and the supplier will have to buy an extra 2 MW, the next hour he will consume only 8 MW and the supplier will have to sell 2 MW’s. For capacities per hour that can be forecasted, the supplier can do his buying and selling in the day ahead market, for unexpected diversions of the consumption pattern, he will have to use the within-day market or get balancing system payments or invoices.

This is basically the issue here. The fixed price for the annual volume cannot be perfectly hedged by the supplier in the wholesale market where only capacity blocks are for sale. This creates volume, spot market regulation and balancing risks for the supplier. The supplier will have to add risk premiums to his add-on on top of the wholesale price to mitigate that risk. If a client chooses to have part (i.e. a percentage) of his price indexed to the spot market, the risk is lowered but not eliminated.

The North-West European markets for supplying energy to industrial consumers have become very competitive. In most tenders, the difference between the three best offers are less than 1%. It is therefore not surprising that suppliers search for possibilities to lower  their wholesale market add-ons and offer new, innovative products. Hence, the emergence of the full-scale flexible energy contract. In such contracts, hedges are no longer on percentages of annual, quarterly, or monthly volumes, but on capacity blocks. The capacity block is than regulated over the spot and/or balancing market. If we go back to our 87,6 GWh example, with a full-flexible contract, the supplier will basically do the same hedges, i.e. buy 10 1 MW capacity blocks. But instead of just charging a fix price for every MWh consumed between the flexibility margins, he will also charge or pay back to his client the costs of extra MW’s or lacking MW’s that were consumed, resp. not consumed on an hour by hour basis. If during one hour, a client is consuming 12 MW, he will pay 10 MW at the forward price and 2 MW at the spot price for that hour. If he is consuming only 8 MW, he will pay 10 MW at the forward price and get back the spot price for the 2 MW. If at the end of the year, he has consumed more than 87,6 GWh, this will mean that the overall quantity of energy that was to be bought in the spot market will be larger than the overall quantity that could be cold back. With such a contract, the supplier is passing through his volume and capacity regulation risks to the client. Therefore, such contracts will often have an add-on price that is markedly better than traditional clicking contract with volume flexibility.

Reactions of clients to such full-flexible contracts are mixed. Some clients are blinded by the lower add-on and sign a full-flexible contract without apprehension of the extra risks. Others are scared by the extra risk and shy away from signing them without fully understanding the opportunities. One thing is sure. If you put two clicking contracts next to each other, you can say with 100% certainty: “whatever happens to the markets or our consumption, contract A will always be better than contract B”. With these full-scale flexible contracts, this is no longer possible. You will always have to say, if this and that happens, the full-scale flexible contract will be the better option, if this and that happens, the multi-click contract will be better. Therefore, we have developed a statistical approach at E&C for judging the risk / opportunity balance of this new contract type. The choice of such contracts should also be based on the broader strategic approach of buying energy.

A few more observations for all of those that have this new option in front of them right now:

  1. Don’t underestimate portfolio-effect. Suppliers can keep the risk premiums of clicking contracts at reasonably low levels because they have several clients. If one client consumes less than the capacity block that has been fixed, another might consume more. Therefore, a full-flexible energy supply contract cannot be that much cheaper than a traditional clicking contract.
  2. If you systematically buy part of your energy on the spot market, the risk of a full-scale flexible contract is substantially lowered (but then the risk of a multi-click contract for the supplier also). Especially these clients should really consider lowering their add-on cost by switchting to a full-scale flexible contract.
  3. Keep a good eye on correlations of factors determining your consumption and the level of the spot market versus the forward market. If your consume gas for heating buildings, this means that you will see an increasing consumption when it gets really cold. In such cold winter months, there is also an increasing chance of peaks in (spot) gas prices.

Full-flexible energy supply contracts offer important advantages to some consumers of energy. However, careful analysis is necessary before signing them.

Deutsche Börse – NYSE merger and the German energy market

“Erfolgsgeschichte”, that’s the beautiful German word for success story. And that is clearly what the recent German economic history reads like. The German economy has recovered more rapidly from the 2008 crisis than any other traditional economy. The whole country seems to be vibrating with a newly found self-confident entrepreneurial spirit. This economic success is not without political consequences. At the latest EU Summit, statesmen from other European countries saw an unprecedented German assertiveness. Miss Merkel’s argument seemed to be: “since Germany is the best-performing economy of Europe, all other countries should adopt our economic policy”.

Today, a next chapter in the success story of the German economy is written. The Belgian business newspaper ran as its headline today “Deutsche Börse takes over the New York Stock Exchange”. The headline is exaggerated as headlines should be. Deutsche Börse is not taking over, it is merging with the world’s most famous trading place on Wall Street. But as 10 of the 17 top jobs in the new company will be held by Germans, it is clear that Frankfurt is the leading dancing partner. So, to continue in hyperbolic language, who would have thought that Germans would once run Wall Street?

I guess that in the next years we will be able to buy many books that explain in detail for what reason the German economy recovered at such a rapid pace. I don’t have the arrogance to share more than an observation with you on this topic. In recent years, I have done a lot of business in Germany. What I have come to appreciate especially in the way Germans do business is their ability to balance discipline and creativity. This can also be observed in the policy adopted by the German government to recover from the crisis, a policy which they would like other European countries to copy. It is a cocktail of budgetary discipline and increased entrepreneurial flexibility, e.g. by relaxing rigid employment conditions.

The question is of course, whether we can see a similar positive, vibrating development in the German energy market. Many would argue that this is not the case. In my opinion, the German energy market is still facing two major issues:

  1. The non-commodity part of the energy bill is higher in Germany than in any other country. As I have written earlier in this blog, Germany has developed its green power production remarkably fast. But it comes at a massive cost of now 35 euro per MWh. On top of that, grid fees are the highest of any Western-European country. The reason for that is very simple. There are more than a thousand different grid companies, all of which have fixed costs. Michèle Bellon, the CEO of ERDF, the French electricity distribution grid operator, probably has a decent salary. But the French pay just one CEO salary for having electricity distributed in 95% of their country. The Germans pay a thousand CEO salaries for that same service.
  2. To some extent the German energy market remains stuck in archaic structures. There are not only a multitude of local grid companies, the Stadtwerke, most of them also continued to run a supply business after liberalization. What is the future of such companies? If they don’t develop a commercial approach to attract customers outside their traditional supply area, they are sitting ducks, waiting for new suppliers to steal away clients from them. As the Stadtwerke are run by local politicians, they often lack the willingness to expand the business beyond their locality.

In many cases we observe negative consequences of the archaic market structure with buyers of energy. I have already praised the unique German cocktail of discipline and creativity. However, sometimes the discipline takes over and becomes conservatism. This is nurtured by the local supply companies that rely heavily on the decades long relationship that they have with a client to convince him to continue working with him. But when these local companies are small, they often lack the ability or willingness to develop the new energy buying solutions to face today’s energy market challenges and grasp the opportunities. German energy buyers then continue to sign fix price contracts for electricity and oil-indexed gas contracts, out of habit, and not based on a genuine analysis of their risk exposure in the energy markets.

I am not too negative about the German energy market however. We do see the discipline – creativity cocktail manifest itself in many – surprisingly rapid – evolutions:

  1. The German gas market is developing at light speed. We now find gas contracts based on Hub prices available for almost every client. Prices can be spot based with good possibilities for forward hedging. We can see most suppliers still struggling to develop the right approach, but such contracts are almost as good as anything you can find in for example the UK or the Netherlands.
  2. Especially as I come from Belgium, I’m surprised to find in Germany a country with a government that takes decisions and implements them relatively efficiently. This is probably why German politics succeeded in coming out of the crisis the way they did. We also observe it in the energy markets. One of the main issues with deregulating the German market is having free access to grids arranged in a country with such a massive amount of grid companies. Even the transportation grid is split up in a multitude of different grids. In the past four years, the German authorities have worked very hard on assuring free third party access and with great success. In the electricity market, any supplier can now supply to any client anywhere in the country if he wants. For gas, some restrictions remain, but they are removed at an extremely rapid pace.
  3. Thanks to the multitude of energy companies in the country, the supply market is very vivid and competitive. The German power market, for example, is not dominated by a single large supplier such as EdF in France or Electrabel in Belgium, there are four big players in the power market: E-On, RWE, Vattenfall and EnBW. Next to that there are several local suppliers or conglomerates of local suppliers that have developed a nation-wide business, players such as EWE, MVV, Trianel, N-Ergie, etc. And then there are new players, newly created companies such as Natgas or Gasag in the gas market. One of the consequences of this vivid competition is that new products such as a tranche model contract for buying gas on the TTF or NCG have been developed very rapidly.
  4. Leipzig-based EEX is the most liquid of all continental European energy exchanges. I remain skeptical whether the energy markets will develop as exchange-traded or as OTC markets. But if the exchange-traded model prevails, the EEX will be the big name in Europe. A little bit like Deutsche Börse in the stock markets?

The German energy market is full of opportunities. And I am confident that the newly-found economic self-confidence will inspire the creativity in German companies to grasp these opportunities.

German Court deals a (small?) blow to oil-indexed gas pricing

It was a long ride yesterday from Berlin back to Frankfurt, and my German colleague Arne and I threatened to run out of conversation topics. But then the radio news gave us a topic that kept us busy for the remaining two hours. A courthouse in Karlsruhe has decided against oil-indexed gas pricing practices by two German suppliers, Rheinergie from Cologne and Stadtwerke Dreieich from Hessen. I’ve heard about this court case in Karlsruhe a month ago and was watching anxiously for its results. The court ruling isn’t the definitive blow to oil-indexed gas pricing that some had hoped for. The judge hasn’t outright forbidden oil-price indexation for gas. That’s probably for the better. Where do we go when judges decide upon micro-economic realities such as gas price indexation? The ruling, to my opinion, will not be without consequences, like some German papers imply this morning.

Before we go into the details of the ruling some background. When we started consuming natural gas in large quantities in the 1960’s, two different market models developed:

1. In the United States and the United Kingdom, pricing systems were created that we call ‘Hub markets’ or gas-to-gas pricing today. The principle is simple and economically wise. Supply and demand of the natural gas itself determine the price. Such pricing obviously calls for a competitive gas market on the supply side to avoid misuse of market power to push up prices. It is therefore not surprising that the first liberalized gas markets developed in the US and the UK. Such a market model demands a fundamental (Anglo-Saxon?) believe in the powerful force of markets. Security of supply is guaranteed by open access to markets in this model and not by political protection of energy rights. (Although the role of the UK and the US in the Iraq war shows that they are not always such firm believers of this principle either.)

2. In continental Europe, belief in the power of open markets has always been much less. Therefore, a different model was developed, that of the long-term oil-indexed pipeline gas deals (what a mouthful). European politicians of the consuming countries, such as Germany, France, Belgium, Austria, Spain, Italy, etc., negotiated long term supply contracts with the producing countries such as Russia, Norway, the Netherlands or Algeria in the South. Large pipelines were constructed to which only the companies that had invested in them had access rights. Long term contracts were made, guaranteeing the off-take of certain minimum (take-or-pay) quantities of natural gas for up to 30 – 40 years. If you make such long term contracts, you obviously don’t want to go for a fixed price. And as no liquid market with gas prices was available, the habit grew of linking the price of gas to the ‘first nearby’ energy product: oil. There was even some economic logic for doing this. At that time, natural gas was still fighting for its place as a substitute for heating oil. By linking the gas price to heating oil prices, the producers and resellers in the countries of consumption could ensure that the gas price was developing unfavorably compared to the competing heating oil.

In the then regulated markets, the official tariffs reflected the underlying costs of the monopolistic suppliers, i.e. of the prices going up and down with the oil prices. So we have all grown accustomed to the fact that our gas prices rise, not because of supply and demand dynamics of the gas itself, but because of what is happening in the oil markets. But if you think about it, it isn’t exactly logic. It’s a little bit like selling potatoes for the price of tomatoes. They are both vegetables, but if the growing season for tomatoes goes wrong, this doesn’t necessarily mean that the growing season for potatoes was also a failure. So if you have linked your potato price to the tomato price, you will inevitably find yourself sooner or later in a situation where you find yourself paying a high price for a product that is in abundant supply (i.e. when the tomato and not the potato growing season went wrong).

Since the middle of 2008, we find ourselves in exactly that situation in the gas markets, which brings oil-indexed gas pricing in an increasingly difficult situation. Whereas the oil prices have doubled after hitting their lowest point in February 2008, the gas prices on the Hubs have fallen since the middle of 2009. The gaspool Hub price for German gas published by http://www.eex.de has fallen by 63% compared to June 2009. This falling gas-to-gas price reflects fundamentals, namely the increasing inflow of LNG into the UK and the increasing supply of gas to the world markets due to the shale gas developments in the US. Many observers cite decreasing demand due to the economic crisis as a main reason, although that isn’t completely correct. We come out of a winter with record high demand due to the cold weather, and in that winter the spot price for gas never was much higher than 17 euro per MWh. This clearly shows that increased supply is an important gas price driver at the moment.

Now let’s go back to the Karlsruhe court case. This is a clear case of consumers complaining that they get potatoes sold at the price of tomatoes. And of course, a judge cannot outright forbid the practice. But the ruling does say that oil-indexation cannot be used as a justification of price rises if the underlying costs for the suppliers haven’t risen equally as much. This could have some important ramifications. Gas suppliers currently win a lot of money on oil-indexed vs Hub-indexed gas arbitrage. For example. If the Hub price is low, as it currently is, they only buy their minimum obligation (take-or-pay volume) from the gas producer. If the total sum of consumption of their clients is larger than that take-or-pay level, they buy the extra gas on the Hub and sell it against oil-indexed prices to their clients. The Karlsruhe court ruling puts such money spinning based on oil-indexed end contracts in question.

Moreover, the big German gas suppliers seem to have understood that the current decoupling of gas and oil prices could continue. They have therefore renegotiated their Gazprom contracts and the Russian gas giant is now indexing part of its gas prices to the Hub prices. However, in the retail market, the big suppliers continue to encourage clients to buy gas at oil-indexed prices. Isn’t that another example of what the Karlsruhe court ruling calls a price rise based on oil-indexation that is not supported by the real cost structure of the suppliers?

It remains to be seen whether the court ruling could have any short term practical consequences for industrial consumers that are frustrated with their oil-indexed gas contracts.  But I am convinced however that it could have some longer term consequences:

1/ As large European gas resellers try to renegotiate terms with Russians and Norwegians to include Hub components in the gas price indexations, the court ruling will help them in stating their case,

2/ It draws consumers attention to the ambiguity of oil-indexed gas pricing, which many large industrial consumers, especially in Germany, take for granted. They are easily convinced by suppliers’ arguments that oil-indexation is ‘safer’. Many think that the Hub market is a spot market. IT IS NOT ! You can buy gas for 2013 today based on Hub pricing. That’s not exactly my idea of a spot market. Still, today, in almost every German newspaper I read, I find that the Hub markets are described as spot markets and spot markets are more risky. The raw facts, however, are there. If you have chosen an oil-indexed gas contract 12 months ago, you pay a lot more than if you have chosen that ‘risky’ Hub price. Moreover, if you had chosen a Hub contract five years ago, you would have suffered spikes that never went much higher than oil-indexed price spikes and your average gas price over those five years would have been substantially lower. The Karlsruhe court ruling might help consumers to have a fairer assessment of hub prices. I found out at least one German client today where the articles on the court ruling were being mailed around.

3/ It will draw politicians attention to the problems of continuing with oil-indexed gas prices if Hub gas prices stay where they are. The papers cited several German politicians that pleaded for ending the oil indexation, the long term contracts along with it and go for a fully liberalized gas market. That is very remarkable in a country where a former chancellor hammered out the North Stream pipeline deal (all very long term and very oil-indexed contracts) and was rewarded with a top job at the company constructing it.

The decoupling of gas and oil prices is an extremely interesting event. We are not predicting that it will continue. However, if you look at reserves of natural gas and oil, you cannot deny the potential of it continuing. If it doesn’t, it is because somebody blocked the import of extra quantities of gas into Europe. Long term oil-indexed pipeline gas deals are an excellent instrument for doing so. The Karlsruhe court ruling could be an important milestone in fighting such blocking of the markets by oligopolies. Let’s hope it will turn out to be so.