Price transparency, the key to more effective energy price management in the US

Not all large U.S. energy consumers manage their natural gas and power prices in the same way. For natural gas, many have adopted a more advanced approach, buying with contracts that allow for advanced price management techniques such as layered purchasing. For power, most U.S. customers take a different approach – taking either a fixed price or a spot price, and limiting their ability to actively manage their budget through price fixings in the process. Why even opt for this second approach? One major factor is the lower degree of price transparency in U.S. wholesale power markets compared to Henry Hub for gas. That said, there is no logical or economic reason for approaching power price fixing differently. As one client remarked recently: “We’re spending twice as much money on power than on natgas, and 80% of the time we spend on energy pricing, we’re talking about the gas bills”.

How U.S. industrial energy consumers can improve their natural gas price fixing practices

Deregulated natural gas prices in the U.S. are almost always linked to Henry Hub pricing. Those industrials opting for fixed prices contract can simply follow the ups and downs of Henry Hub forward prices on NYMEX. For those gas consumers that want a more managed approach, contracts can be set up whereby prices are layered-in – in other words, consumers can lock-in a certain percentage of their volume – for a certain period – at NYMEX-traded prices for those periods.

Buying natural gas is a tricky business because it involves a double moving target. Not only do you have to deal with the volatility of Henry Hub pricing, but you also have basis pricing to worry about. Your end price depends on the pricing differential between your local hub and Henry Hub. Depending on where your gas is produced or imported, supply / demand dynamics will be more or less favorable compared to the conditions at Henry Hub, resulting in a lower or higher price for the gas. This differential is then reflected in the basis price.

Henry Hub and Basis Prices

front month gas prices - zoom

In recent years, for example, we’ve seen basis pricing for West-Pennsylvania and Ohio drop to negative levels due to the shale gas production. Moreover, gas marketers need to book the physical capacities on the network to bring the gas from the production site and these costs are added to the basis pricing. This gives rise to important differences in regional gas prices that change over time. During the Polar Vortex, for example, the increase in Henry Hub commodity pricing was amplified by huge increases in basis pricing in certain regions.

Polar Vortex 2014

Many US gas consumers are only vaguely aware of the impact of basis pricing on their natural gas spend. All their attention goes to hedging their Henry Hub price and they completely neglect basis pricing. But as you can see from the graph above, basis pricing adds as much volatility risk to your final price as the Henry Hub component.  A sound natural gas price management strategy will therefore take into account basis pricing as well as Henry Hub. It can take some time, but you can often find wholesale market information that gives you a good indication of what basis pricing you should expect. This can help you to select different moments for hedging your basis risk, which often doesn’t coincide with a good moment to layer in hedges on Henry Hub. Moreover, suppliers offer solutions where you can hedge basis in layers, in the same way you spread your commodity buying decision to reduce risk. With some efforts, both of the double moving targets involved in gas pricing can be effectively managed.

How power can be managed in the same way as natgas

Whereas natgas has a pricing system with one reference price for the whole country and basis pricing for different locations, power pricing is based on different wholesale price references. In the State of Texas, for example, there are no less than 4,000 different spot prices. Many of the consumers we speak to have no clue to what specific wholesale price reference their power price is linked to. They are equally unaware of the myriad of forward pricing products suppliers base their fixed price offers on. Many of them are also oblivious to the fact that, just as for natgas, suppliers offer the possibility of layering in power prices, allowing for more active price management.

By managing basis pricing for natural gas and using advanced price management techniques for power, U.S. companies can optimize the way they manage their budgets. While it’s true that floating with the market has often been the better choice given the bearishness of energy markets these past few years, it should always be kept in mind that going on index doesn’t offer any protection when markets turn around. Many customers were reminded of that during the Polar Vortex, when their monthly energy bills exploded. This is especially harmful for so-called ‘budget risk’ clients, businesses that do not have the option of passing on higher energy costs to their customers. For them, it’s a good idea to have contracts with layered forward purchasing features in place for when markets turn bullish. At historically low prices and with the US self-confidently increasing its production year after year, it is tempting to believe that low prices are here to stay. They will not – what comes down must go up. And if they do, many US customers will feel sorry that they didn’t lock-in some of the current low prices for future years.

 

How to deal with the volatility in the oil markets

Written by Frederic Grillet

These last few months we’ve seen oil prices bouncing up and down. Intraday movements between 5 and 10% were not uncommon. Current price levels, which are approximately 70% lower than their peak levels in june 2014 and are the lowest that we have seen in 10 years, seem to cause investors to overreact to every rumour in the market.

Brent front-month prices started January at a price level of 37.28 $/barrel and dropped 34% to 27,88 $/barrel on 20 January, only to rebound 25% by the end of the month. The main causes of the price surge were a vague statement by ECB-President Mario Draghi hinting on potential monetary measures to boost the EU economy and a rumour that OPEC & Russia were discussing a potential production cut.

Despite the fact that oil markets have always been quite susceptible to speculation, which amplifies any trend in financial markets, this volatility seems to edge on irrationality. The oil market has a structural problem of oversupply, with production having exceeded demand with 1 to 2 million barrels per day (depending on the source) over the past years. The US Energy Information Agency has indicated that it expects an average oversupply of 1.75 million barrels/day for the first half of 2016 as well, while crude inventories in the US are at record highs above 500 million barrels. An agreement amongst global oil producers, which is looking very difficult due to a variety of reasons, could of course address the issue from the supply side, but the demand outlook remains weak with major economies, including China, showing signs of a slowdown.

Although the downward trend in oil prices was strong in the past months and has reached historically low levels, the fundamental issues in the markets have not yet been resolved and no solution seems to be in the making for now. The very strong upward and downward movements despite the lack of changing fundamentals shows that price levels have entered a territory in which trends are mainly caused by speculators hedging their long and short positions.

Impact on other commodities

EU gas & electricity markets are generally shaped by a variety of factors, though for January, the trends showed that the main driver for prices were the oil prices. Markets in all countries have therefore seen a very rocky start of the year. The main question here from a procurement point of view is whether this volatility marks the start of a structural trend change after last year’s general downward trend and whether it is necessary to start taking bigger positions.

So when do you hedge?

Volatile times like these prove the value of the combination of market analysis and a strong purchasing strategy. The market analysis allows us to identify the opportunity moments, i.e. when markets start turning around. However, as the last months have shown, it is never a sure bet whether that is only a temporary or a fundamental turn of the trend. Hence the importance of spreading your hedging decisions and fix in small incremental amounts. In the end, how much you hedge and how far into the future should depend on your strategy. If your main risk is budget variability over the long term, than you can take large positions for many years into the future, although you should always do that in small incremental amounts. If your main risk is having an uncompetitive energy price, you should be much more prudent and make only small opportunistic fixings.

A long downward trend, as we have seen in the EU energy markets, tends to spark an urge to take bigger bets in the markets, e.g. by opting for fixed energy prices for years ahead, Although a bet can sometimes turn positive afterwards, it remains a bet and should have no place in a professional business. Therefore, although it would be a good idea to check whether the current movements in the markets make it necessary to take a position in your portfolio, it remains very important not to be seduced to overreact to an overreacting market.

Looking for more market information? Order free trials over here.

Czech Republic introduces capacity-based green energy levy

On the 5th of June 2015, the Czech Republic issued a change in its law on green energy levies that might prove to be a watershed piece of legislation. Traditional payments of the levy in Czech Crowns per MWh – now at 495 CZK or 18,31 EUR per MWh – has been replaced with a capacity-based payment. End consumers will no longer contribute to the payment of subsidies to green power production per MWh that they produce. Their contribution will be based on the capacity that they have booked. We believe that the idea of electricity levies based on capacity rather than consumption is interesting for several reasons:

  1. As capacity tends to be more stable than consumption, you reduce the fluctuation in overall income on these levies. If the overall consumption drops, as we’ve seen recently, the overall amount of money that is collected from the energy consumers drops, so the levy per MWh needs to be increased to make sure sufficient money is available to cover for the amounts that are being subsidized. Capacity-based contributions could make the overall amount of money coming in more stable.
  2. One of the consequences of an increased usage of renewable energy is a lower efficiency of the grid usage. This is in the first place due to the low utilization rates of wind and solar power, and that will not be solved. But if the demand size capacity offtake is more stable, with less peaks, you reduce the size of the demand peaks that could coincide with a period of low wind / solar output, thus increasing the efficiency of the grid usage. Capacity payments inspire end consumers to apply peak shaving and stabilize their loads, contributing to a higher grid usage efficiency.
  3. High non-commodity costs have caused many to fret over the impact on the competitiveness of energy-intensive industries. As such energy-intensive users tend to have higher load durations, they will be less impacted by the cost of the green energy levy than less intensive energy users. Levies based on capacity rather than consumption hence create a natural protection for energy-intensive industries against high non-commodity costs.

Because of these clear advantages, it is not unthinkable that more countries will follow the Czech example. Will we see a broader “return of the capacity term”? Will other non-commodity parts of the bill also increase their capacity-based component? In the Netherlands a decision has been taken to have grid fees 100% based on capacity term.

If the importance of capacity increases, end consumers will have an increasing interest in traditional peak shaving, reducing peaks by switching off non-essential equipment when production equipment is causing peaks in capacity offtake. This comes on top of increased interest in capacity management activities such as demand side management and the marketing of interruptible capacity. Finding a good balance between the economics of these different possibilities of cost optimization will be primordial.

 By Ondrej Zicha

Demand Side Management

Grid balancing, meeting the supply of energy to the demand, has become less predictable with more renewable energy being installed and connected to the grid. Until recently, it was mostly generators that adapted their production in case of the risk of unbalance. Nowadays, industrial consumers sometimes implement Demand Side Management (DSM) which is, briefly explained, adapting the demand in exchange for financial benefits.
What exactly is Demand Side Management?
A consumer using Demand Side Management actually switches consumption on and off to improve its energy prices. In a strict sense, DSM means switching your consumption from hours with high spot prices (when the demand is high) to hours with low spot prices. This impacts the balance of the grid because the consumption during the hours in which supply is tight will go down as a lot of consumers are scaling down their consumption in those hours. Recently, some countries, such as Belgium, the UK or Spain have created or renewed incentives for capacity or load management due to the concerns over security of supply. They have installed or renewed interruptibility service packages, meaning that consumers are paid for keeping a certain capacity available for switching off. Grid operators will switch off such interruptible clients in case of capacity tightness on the grid. This has sparked a renewed interest in capacity management.
Are there any other possibilities next to switching your consumption?
Well, first a client can assess whether he could sell his interruptibility, directly to a grid operator or through an aggregator. Aggregators are companies that specialize in bringing together interruptible capacities and marketing them. Increasingly, we see that the traditional energy suppliers are playing this role aggregators. However, a client shouldn’t forget that traditional peak shaving is still an option. Grid fees still contain large capacity terms, meaning that keeping your capacity continuously below a certain peak pays off. Also, in some countries a careful management of the load can help a client to drop below certain thresholds for getting certain tax exemptions.  These different possibilities necessitate an integrated, holistic approach with clients avoiding that a saving on the left side causes a cost increase on the right side. Moreover, clients should be careful that their actions to manage their capacity don’t jeopardize their energy efficiency attempts at managing consumption.
Could Demand Side Management result in serious cost savings?
There is definitely a cost-saving potential although we must say that, contrary to popular belief, the difference between the expensive and the inexpensive hours on the spot markets has gone down during the last years , making demand side management less rather than more rewarding.

switchingload

This is due to the fact that many energy systems have a lot more flexibility on the production side these days. Client should also always keep in mind that is an arbitrage activity – meaning that inevitably you will see markets get more balanced out if lots of clients apply it, reducing the benefits that you can gain from applying it. It is therefore good to have a very critical look at load management proposals and to carefully weigh its benefits against the extra costs that it could cause.
If I want to start implementing DSM, what should I do or which parties should I involve?
What mostly happens is that people get approached by somebody offering interruptibility services, an aggregator for example, and they spontaneously go down this road. We advise clients to first make a step back and make a holistic study of the different possibilities for your company. How much interruptibility can I offer in terms of megawatts and duration? In this context, companies should have a look at their internal utilities. After having done that you can select the options which are feasible for you and based on that, you can go into the market and see who can give you the best conditions. E&C recommends a market based approach and a holistic approach where you look at all the possibilities of making money with load management. But, of course, not every company can just easily switch their loads. High labor intensity or the necessity of a high utilization rate of the production apparatus can seriously hamper the possibilities of load management. People do not consume electricity just because they love consuming electricity but because they need it. You have to really look into the details and see where you can find flexibility.
Do you think the implementation could have an impact on the electricity prices?
Yes, on two levels. The introduction of incentive programs for DSM could push up the non-commodity price. The transport grid operator in Belgium for example has recently launched a new program for interruptibility services. It is clear that the cost of the grid operator paying money to companies for having interruptibility available needs to be collected somewhere, for example in the prices for the transport grid usage. As far as the commodity price is concerned, like I’ve already point out, DSM is an arbitraging activity, which can reduce the difference between expensive and less expensive hours.

By Benedict De Meulemeester

Poland’s dangerous coal addiction

Electricity prices all over Europe extended their downtrends in the last months. Since the first of September, German year ahead baseload prices dropped by -2,95%, France -6,61% and the UK by a hefty -10,24%. This bearishness didn’t spread to Poland. It’s year ahead baseload price increased by +4,52% in euro and +5,09% in the local currency, Zloty.

No European country produces as much electricity with coal as Poland. According to Eurostat a staggering 83% of all electricity produced in Poland in 2014 required the burning of coal. Moreover, 70% of Polish households still use coal as a heating fuel. Considering the high percentage of coal-fired power production, you would expect Polish power prices to have dropped in the last month. The price paid for coal in the international markets dropped by -12,72% since September. Unfortunately, the dynamics of energy pricing in Poland are determined by politics rather than economics.

Underground tunnel in the coal mine

Illuminated, Underground Tunnel in the Minery (iStockphoto)

Due to the falling price of coal on the international markets, the Polish coal producers are in deep trouble. According to Paulina Pacula in an article published on euobserver.com on the 23rd of October, Polish coal mines have a deep efficiency problem, as they produce 648 tonnes of coal per worker per year, compared to 2.000 tonnes in the worst performing mines in the US. With 50% of its operating costs being labour costs, this low efficiency pushes the Polish coal mines deep into the red figures. Again according to Ms. Pacula, Poland’s Kompania Weglowa, Europe’s largest coal producer has negative cash reserves and it still operates with a cost of production below the international coal price. In the troubled coal mine in Brzeszce production costs exceed the market price by 265 Zloty per ton.

Using normal economic reason, everyone would call for a restructuring of this coal sector. Not so in Poland. Some 500.000 Polish voters are estimated to depend on  coal production for their income. Their trade unions fiercely resist any attempts of reform. And Polish political parties – afraid of protesting miners – cater to their needs. Instead of pushing Polish coal mines to become more cost-efficient, they oblige power producers to merge with coal companies. Blending the loss-making coal with the revenues from its electrification should make up for the losses seems to be the reasoning. The previous more liberal-minded government back-tracked on its attempt at splitting off the least efficient coal mines. And the new government, dominated by the conservative Law and Justice party, seems even less willing to let economic laws determine its coal mine policy.

Poland pays a heavy price for its addiction to coal. The year ahead electricity price (on the 24th of November) stands at 39,09 euro per MWh, compared to Germany’s 29,29, Czech Republic’s 29,63 and Slovakia’s 32,93. These higher coal prices and the contrarian increasing trend of the last months is based on the market’s fears that obligations to buy coal at prices higher than the international market price will push up the cost of producing electricity in Poland. And there is obviously the environmental cost, Poland is one of Europe’s worst performers in terms of air quality. But here again, coal-addicted Poland is isolating itself within the EU by continuing to oppose climate policy ambitions.

Worst case, pushing power producers to acquire troubled coal producers could be the energy market equivalent of swallowing poison pills, bringing power producing companies on their knees. It could also stall the liberalization process. As one of Europe’s countries with the most rapid economic development, a development largely based on the growth of an energy-intensive industry, Poland should think about this. It is financial nonsense to pour money into a coal industry that, according to Ms. Pacula, contributes nothing at all to Poland’s GDP growth. It is even larger insanity to risk wrecking your all-important power production sector in an attempt to prop it up.

energymix

By Bartosz Palusinski

Groningen looks for balance between citizens safety and gas production

Last February, the gas market was startled by another episode of the debate on gas production in the Netherlands. The gas production in the Northern part of the Netherlands has brought the country wealth through annual gas revenues and the opportunity to develop itself as ‘the gas roundabout of Europe’. This production, which takes place since the 60’s, is accompanied by small earthquakes. For a long time, this geological activity was seen as an unpleasant side effect. But as a consequence of the diminishing amount of gas that is left in the Groningen gas field, the surface starts to move more and more. The increasing number of earthquakes and the earthquake in August 2012 near Loppersum seemed to be a turning point in the public attitude towards gas production. In 2013, when the production increased to a level of 53,9 billion cubic meters (bcm), the number of earthquakes peaked at a level of around 120. Some of them between 3 and 3,5 on the Richter scale.

number of earthquakes
After the 2012 Loppersum earthquake, the NAM (Dutch Oil Company), KNMI (Royal Dutch Meteorological Institute) and the SodM (State supervision of the Mines) carried out additional tests. These showed, inter alia, that future earthquakes in Groningen could be much more intense than previously expected. Ever since, the government in The Hague is looking for a new equilibrium between economic and environmental and between national and regional interests.  The Dutch government decided in January 2014 to limit the production of the Groningen gas field to 42,5 (bcm) per year for 2014-2015 and 40 bcm for 2016. Later that year, the maximum production cap was lowered again. For 2015-2016, no more than 39,4 bcm can be produced. In the beginning of February 2015, the Dutch government intervened again in the Groningen production limits and installed a production cap of 16,5 bcm for the first 6 months of 2015. The total amount for 2015 remained unchanged. In the days that followed this decision and in the run-up to provincial elections, the Dutch Green party ‘Groenlinks’ and some politicians from the Groningen area asked for a limit of 30 and 35 bcm for the whole of 2015. The responsible Minister, Henk Kamp, did not give in and kept to his decision. On the 18th of March, Provincial elections were held in the Netherlands. These elections were important for two reasons. Firstly, voters in the northern part of the Netherlands expressed their aversion of the gas policy of The Hague. The Groningen region has been plagued economically in the past years and it is a thorn in their side that the revenues of the gas production are transferred to The Hague while they suffer the disadvantages. The regional party ‘Groninger Belang’, with their quest for structural solutions for the gas production in Groningen, panned out 3 seats and became the biggest regional winner. This sent a clear signal to The Hague but the question remains whether this will have sufficient impact. Secondly, it was a test for the government of Prime Minister Rutte. The results were not in their favour. The labour party PvdA, the governmental partner of the Liberal VVD party, lost the elections. This has put pressure on the ruling majority. It is important to know that the provincial assemblies choose the country’s senate.  Ever since the beginning of this government, the VVD-PdvA coalition had no majority in the senate and therefore had to ally with different parties to get their program passed.

The vulnerable position of the government deteriorated even more with these provincial elections. Will they remain strong enough to maintain their position on the Groningen production cap or will they have to make a trade-off with other focal points in their governmental program?

On the 1st of June 2015, Hans Alders was appointed as the National Coordinator for Groningen. In this function he goes on a tour around the Groningen area and is providing a platform to the people of Groningen to discuss the current situation. The feedback on his visits of the last months clearly point at a different interest between The Hague (gas and incomes) and Groningen (safety and restoration of the damage).

On June 22nd, minister Kamp published the 4th decree in a timeframe of 18 months. The production was limited to 30 bcm for 2015. This was less than the expectations because the last calculations at that time had pointed out that 33 bcm/year was the required amount of gas to foresee the Dutch households and to comply with the long-term export contracts. But apparently there was another 3 bcm left at the Drentse Norg which could be used in a case of shortage.

production cap

That production cap meant a loss of 2 billion euro per year for the Dutch treasury which is hard to handle in times of low economic activities and European calls to keep the budgets in balance. Moreover, the current gas revenues are already lower than expected due to the current low gas price.

Not even considering this loss in income, it is technically questionable whether the NAM can decrease the production further. The gas that is produced in the Groningen gas field is low caloric value gas (so-called L-gas), whereas gas that is produced in the rest of the Netherlands and Europe is high caloric value gas (H-gas). This L-gas is used in the Netherlands and parts of Belgium, Germany and France and supplied by Gasterra.  The exported volumes are traded under long-term contracts that contain volume conditions. Internal research of Gasterra pointed out that for 2015 they have to be able to deliver 34,6 bcm of L-gas for export  (which can increase further with 1,8 bcm in case of cold weather). For the consumption of natural gas in the Netherlands, no distinction is made between L-gas and H-gas. Therefore we have no clear view on the Dutch demand for L-gas.

tabel1groningen.png

Not all of this L-gas has to come from the Groningen gas field since there is also the option to have the grid operator GTS convert H-gas to L-gas. This of course means a loss in caloric value and a cost increase but might provide a way out for a lower production in Groningen. The maximum amount of gas that can be converted depends on the maximum conversion capacity, the amount of additional H-gas available in the market, the temperatures and the quality of the H-gas. GTS executed some simulations based on this variables. The results of this show there is a need for 21 – 35 bcm of Groningen gas in the period 2014-2019 if the conversion capacity can be used in an optimal way. After this period, the need for Groningen gas reduces due to an increase of installed conversion capacity.

tabel2groningen.png
If the utilization rate of the conversion capacity is sub-optimal (due to seasonality in the Groningen gas production), the need for Groningen gas will be much higher.

tabel3groningen.png

But both the research of Gasterra on its export obligations and GTS on its conversion capacity show that the Groningen production cap can’t be put at any level.

Recently another episode was added to the saga. After more than 40 complaints were filed against the decision of Minister Kamp in June, the Dutch Court of State has to rule on this complaints. On the 18th of November the Court finally published its ruling: a rejection of the current amending acts of Minister Kamp and a new production cap of 27 bcm, with the exception of 33 bcm in case of a cold gas year 2015-2016. This new production cap was set in place to avoid that there was no more cap, which would have been very contradictory to the purpose of the ruling.

All this means that Minister Kamp has to come up with a new amending act which takes into account the ruling of the Court of States. So there is no light at the end of the tunnel yet…In a letter to the House of Representatives, Minister Kamp pointed out that more information can be expected on the 18th of December. So, save the date!

By Bart Verest

Nueva ley de Hidrocarburos: ¿España finalmente en camino hacia la fijación de precios del gas basada en el modelo Hub?

Prefer English? Read the article here.

Uno de los eventos más remarcables de la última década en los mercados de la energía en Europa fue el cambio de la indexación del precio del gas al petróleo hacia el tan nombrado modelo Hub. La indexación del precio del gas al del petróleo es hoy ya una reliquia del pasado. Promocionado por sus gobiernos, las compañías del monopolio gasista establecieron contratos de larga duración con productores de gas natural con duraciones de hasta treinta años. Debido a una falta de precios de referencia de gas natural, se decidió fijar el precio al combustible competidor más importante en aquel momento: el petróleo.

Incluso si la indexación al petróleo fue una inteligente estrategia de marketing en aquellos días de cambio de combustibles de fuel a gas natural, cuando los mercados fueron liberalizados, esto causó varias cuestiones serias a tener en cuenta:

  • Los acuerdos a largo plazo aportan una importante ventaja competitiva a los proveedores que ostentan el control, ya que es difícil para un proveedor alternativo poder conseguir un contrato con un productor de gas. Por lo tanto, para obtener los suministros, estos proveedores alternativos a menudo tienen que comprar el gas de los proveedores titulares con los que se supone deben competir. En los primeros días de la liberalización del mercado del gas, frecuentemente vimos que los proveedores alternativos no eran más que los vendedores del gas que fue originalmente adquirido a un gran competidor en virtud de un acuerdo a largo plazo. Esto era obviamente una base pobre para que los proveedores alternativos ejercieran el tipo de presión competitiva que hace bajar los precios,
  • Por otra parte, este tipo de acuerdos a largo plazo a menudo contenían los derechos exclusivos para el uso de la capacidad en la infraestructura clave, como las conexiones transfronterizas para la importación de gas, terminales de GNL o de los sitios de almacenamiento. Esto hace que sea aún más difícil para los proveedores alternativos desarrollar su negocio.
  • Los precios indexados al petróleo tienen un cierto grado de complejidad matemática. Los consumidores finales a menudo no alcanzan a comprenderlo, por lo que es imposible para ellos hacer una evaluación correcta de las propuestas que les ponen en la mesa.
  • En algunos mercados (por ejemplo, Alemania) el mercado tiene una gran variedad de diferentes fórmulas de indexación al petróleo, por lo que es muy difícil conseguir una idea correcta del nivel de precios del gas en ese país.
  • En los mercados a largo plazo, los contratos indexados al petróleo no son un instrumento con mayor claridad. Los consumidores finales sólo pueden preguntarse que es lo que pagan sus proveedores por el gas a sus proveedores. Por lo tanto, no hay transparencia en absoluto respecto a los márgenes, poniendo de esta manera a los consumidores finales en desventaja en las negociaciones de contratos.
  • Esta falta general de transparencia también se ve claramente cuando se ofrecen servicios de gestión de precios. En muchos países, los proveedores tienen una larga tradición de ofrecer contratos indexados al petróleo con servicios que permiten a sus clientes hacer swaps de precios flotantes a fijo, fijo por flotante e incluso cambiar entre diferentes fórmulas. Los proveedores realizan las operaciones necesarias de fijación en el mercado de petróleo para ejecutar este tipo de swaps. Sin embargo, el cliente final a menudo carece de los conocimientos matemáticos de las formulas y de las operaciones en el mercado del petróleo para juzgar si el precio fijo por ejemplo, era la opción correcta o si su proveedor estaba abusando de la operación de fijación para obtener márgenes extra.
  • Desde el punto de vista de la teoría económica, la indexación al petróleo es también una solución peligrosa. Esto significa que el precio de un producto (gas natural) está determinado por la dinámica de oferta y demanda de otro producto (petróleo). Por lo tanto, el precio no está dando una señal correcta a productores y consumidores. Pudiendo ser que la oferta del gas natural sea baja, pero su precio sea bajo debido a una gran oferta de petróleo. En ese momento, el consumidor no está recibiendo la señal de reducir su consumo y el productor no está recibiendo la señal para aumentar su producción, por lo tanto, el mercado no está restaurando en equilibrio entre la oferta y la demanda. Estoy bastante seguro de que a Adam Smith le habría disgustado la idea de la indexación del gas al petróleo.
  • Por otra parte, hay más gas natural en el planeta que petróleo. Por lo tanto, las posibilidades de sobre-valoración de gas natural son bastante altas cuando se indexa al petróleo. Eso, obviamente, explica porqué los productores, como la rusa Gazprom, han sido feroces defensores de esta indexación del gas natural, y esto no es sólo una teoría económica. En efecto, hemos visto que en todos los países que se cambió la indexación al petróleo hacia un modelo Hub, el precio del gas natural se redujo significativamente para el consumidor final.

El modelo Hub comenzó su andadura por primera vez en los EE.UU. con el Henry Hub y en el Reino Unido. Con la creación del NBP, el Reino Unido hizo algo sumamente interesante, la creación de un Hub virtual, a lo cual volveré más tarde. A continuación, este modelo fue copiado en Bélgica (Zeebrugge), Países Bajos (TTF), Francia (PEG), Alemania (NCG y GPL), Italia (PSV) y otros países. Hoy en día, en la mayoría de los países de Europa, el gas se compra basándose en la fijación de precios en un Hub. Incluso hemos sido testigos de la integración del mercado, con los precios de esos mercados mayoristas convergiendo y el TTF convertirse en precio de referencia al cual están vinculados los precios en los contratos de los consumidores finales. Para la mayoría de los grandes consumidores industriales de gas en Europa, las desventajas de tener precios de gas indexados al petróleo se han convertido en un tema del pasado. Actualmente disfrutan de precios de gas más transparentes, acompañados de mejores servicios de gestión de precios. Por otra parte, como se mencionó anteriormente, el cambio hacia el precio Hub se acompaña de precios más bajos y ahorros importantes. Aún así algunos países se han quedado atrás y no han hecho el cambio hacia un modelo tipo Hub. Uno de ellos es España. (Portugal también, y al igual que en los mercados de gas en España y Portugal, los mercados de la electricidad están muy ligados.)

Después de años de abandono, el gobierno español ahora parece tomarse en serio la realización de las adaptaciones necesarias para reformar su mercado de gas e introducir el modelo de mercado Hub que ha sido un gran avance para los consumidores de gas en otros países europeos. El 22 de mayo se publicó la nueva Ley de Hidrocarburos tan esperada. Tras la primera lectura, parece contener algunos elementos que podrían despertar el desarrollo de un mercado Hub real en la Península Ibérica.

No cabe duda de que el elemento más importante es la introducción del Hub virtual. La primera virtualización de un Hub fue llevada a cabo en el NBP dando muy buenos resultados. Posteriormente, se repitió este proceso en diferentes países, siendo TTF el ejemplo mas espectacular. Desde el punto de vista legal, un ‘Hub’ es el lugar físico donde el gas cambia de titular. Tradicionalmente en Hubs físicos como el Henry Hub o el Baumgarten en Austria, es un lugar físico concreto. Antes del punto físico (normalmente una válvula en un gaseoducto), el gas pertenece al vendedor y pasado ese punto, el gas pasa a pertenecer al comprador. Cuando se crea un Hub virtual, éste está formado por toda la red de transporte. De esta manera, toda un área geográfica como por ejemplo Gran Bretaña o Holanda, se convierte en una gran zona de Entrada-Salida (Entry-Exit zone). Esto quiere decir que el vendedor puede inyectar el gas en cualquier punto ya que se considera que éste es inyectado en el Hub, y el comprador puede extraerlo desde cualquier punto de la red, ya que se considera que lo ha extraído del Hub.

Los Hubs físicos no son tan beneficiosos para la competitividad del mercado minorista y el trading como los hubs virtuales. Los vendedores de gas necesitan pedir acceso a un lugar geográfico específico y la capacidad que quieren extraer puede ser restringida ya que, si otros comercializadores han firmado contratos de gas a largo plazo, los derechos de capacidad se les asignan a éstos últimos. Por tanto, un comercializador necesitará transportar el gas hasta el cliente final. Durante el transporte, puede que tengan lugar restricciones de capacidad que dificultan enormemente el transporte de gas hasta las zonas de entrada en las que sí tienen derechos de capacidad para inyectar el gas. Esto está claro en el caso de España, donde las distancias entre los puntos de inyección y los clientes son grandes. Un comercializador que obtenga su gas en Huelva, puede tener dificultades para suministrar el gas a clientes industriales en el norte. Sin embargo, hemos observado el desarrollo de un mercado de swaps en el que unos comercializadores intercambian cantidades de gas que pueden suministrar en ciertas áreas con otros comercializadores que no pueden suministrar gas en esas áreas. En conjunto, no podemos decir que el mercado español sufra la falta de ofertas. Cuando lanzamos una licitación de gas, obtenemos fácilmente hasta diez ofertas de comercializadores diferentes. Lo que realmente nos produce frustración es que los precios que ofertan son altos comparados con otros países de Europa, continúan indexados al Brent y al tipo de cambio y en muchos casos no permiten a nuestros clientes gestionar su riesgo.

La nueva Ley de Hidrocarburos introduce un Hub virtual que cubre todo el territorio español. Es una idea muy interesante ya que opino que la Península Ibérica, contrariamente a lo que dicen los comercializadores, posee un sistema gasístico idóneo para el desarrollo de un Hub virtual. La red de transporte se asemeja a la rueda de una gran bicicleta con gaseoductos que recorren la costa y atraviesan el centro (Madrid). El gas puede ser inyectado en la rueda al menos en diez puntos diferentes: gaseoductos que conectan Francia en el norte y la costa Norafricana por el sur y ocho terminales de GNL. Si se conecta todo esto en un Hub virtual, se liberará a los comercializadores de las dificultades que tienen para acceder a los puntos de inyección cercanos a sus clientes . También se les liberará de obtener derechos de capacidad (o de hacer swaps) para transportar el gas desde las zonas de entrada hasta las zonas de salida. De esta manera, cabría esperar que España desarrollase el tipo de competición entre comercializadores existentes y nuevos que existe en otros países. Esto podría dar lugar a importantes beneficios para los consumidores españoles, tales como:

  • Ahorro de los costes. Actualmente, estamos viendo precios del gas indexado al petróleo en un rango de 24-25 €/MWh. Los precios en los Hubs del noroeste de Europa rondan los 22-23 €/MWh. Si, debido al desarrollo del hub, los precios en España convergiesen con los precios del resto de Europa, seríamos testigos de una gran oportunidad de ahorro. Cabe señalar que, debido a la bajada del precio del petróleo, la diferencia entre los precios del gas en España y otros Hubs europeos es históricamente baja. En 2014 por ejemplo, la diferencia era de hasta 10 €/MWh.
  • La posibilidad de comprar energía de una manera diferente, con productos indexados al mercado spot y al mercado a futuro.

Todavía no esta claro si la nueva ley va a provocar un desarrollo rápido del modelo Hub en la Península Ibérica o no. La nueva ley de Hidrocarburos es una ley generalista en la que se define el marco legal para el desarrollo de un Hub en España. Que finalmente este modelo funcione o no va a depender de la resolución en futuros reales decretos y otros textos regulatorios de conceptos más específicos tales como el código de red necesario para equilibrar el sistema. La Ley anuncia que se está trabajando en la preparación de textos importantes en materia de regulación. La dificultad surgirá a la hora de entrar en los detalles. El gobierno español ha estado trabajando en la creación del Hub durante varios años. Tal y como he remarcado en otras ocasiones, las autoridades parecen estar centrándose demasiado en aspectos financieros del mercado como la creación de la plataforma de intercambio de productos spot y a largo plazo. Sin embargo, el éxito del Hub va a depender primordialmente de poner en orden aspectos físicos en los que se defina una gran zona de entrada/salida que permita que el acceso a la red se haga en condiciones no discriminatorias. Por tanto, tendremos que estar muy atentos a estos textos regulatorios pendientes de publicarse y ver si contienen los elementos necesarios para establecer realmente un Hub en España.

La nueva Ley de Hidrocarburos asigna la figura del operador del mercado organizado de gas a corto plazo a la compañía MIBGAS. Ésta estará formada por la compañía transportista Enagás y el operador del mercado OMIE/OMIP. La ley determina también que MIBGAS establecerá la plataforma de intercambio a la que deberá acudir Enagás para balancear el gas (compraventas de gas de corto plazo con entrega en el punto virtual de balance).

El hecho de involucrar tanto al organizador de la plataforma de intercambio en el sistema de balance, resalta la visión española de confundir el modelo Hub con una plataforma de intercambio. La política energética española normalmente falla en establecer beneficios para los consumidores finales y las autoridades se empeñan en detallar todo al milímetro, aumentando así la complejidad del sistema. Pero deberíamos dar a España el beneficio de la duda y esperar que, en los próximos meses, la formación de un Hub se convierta en una realidad para los consumidores españoles tal y como hemos atestiguado en otro países.

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

Prefer Spanish? Read the article here.

One of the most remarkable events of the last decade in Europe’s energy markets has been the switch away from oil-indexed gas pricing towards the so-called Hub-model. Oil-indexed pricing for natural gas is a relic from the past, when no open markets for the trading of gas existed. Sponsored by their national governments, monopolist gas companies set up long term agreements with producers of natural gas with durations of up to thirty years. Lacking a price reference for natural gas, it was decided to peg the price to that of the most important competing fuel at that moment: oil.

Even if oil-indexation was a clever marketing strategy in the days of the fuel-switch from oil products to natural gas, when markets are liberalized, it causes some serious issues:

  • The long term agreements give important competitive edge to incumbent suppliers, it’s difficult for an alternative supplier to get a contract with a gas producer. Therefore, for getting supplies, these alternative suppliers often have to buy the gas from the very incumbent suppliers that they are supposed to compete with. In the early days of gas market liberalization, we saw that alternative suppliers were often nothing more than resellers of gas that was originally purchased by a large competitor under a long-term agreement. This was obviously a poor basis for alternative suppliers to exercise the sort of competitive pressure that brings down prices,
  • Moreover, such long term agreements often contained exclusive rights to the usage of capacity on key infrastructure, such as cross-border connections for the import of gas, LNG terminals or storage sites. This makes it even more difficult for alternative suppliers to develop their business,
  • Oil-indexed pricing has a certain degree of mathematical complexity. End consumers often fail to grasp it, making it impossible for them to make a correct assessment of the proposals that they get on their table,
  • In some markets (e.g. Germany) the market came with a huge variety of different oil-indexed formulas, making it very difficult to get a correct idea of ‘the’ price level for gas in that country,
  • The market of long-term, oil-indexed contracts is not a market with a clear wholesale – retail segmentation. End consumers can only guess what their suppliers pay for the gas to their suppliers. Hence, there is no transparency at all regarding margins, putting the end consumers at a disadvantage in the contract negotiation,
  • This overall lack of transparency is also clear when price management services are offered. In many countries, suppliers have a long tradition of offering oil-indexed contracts with services that allow their clients to swap floating prices for fixed, fixed for floating and even swap between different formulas. The suppliers perform the oil market hedging operations necessary to execute such swaps. However, the end client often lacks the knowledge of the formula’s mathematics and the oil market operations to give a correct judgement of whether a fix price e.g. was correct or whether his supplier was abusing the fixing operation to make some extra margin,
  • From a point of view of theoretical economics, the oil-indexation is also an ugly beast. It means that the price of one product (natural gas) is determined by the supply and demand dynamics of another product (oil). Hence, the price is not giving a correct signal to producers and consumers. It could be that natural gas is short in supply, but its price is low because of a large supply of oil. At that moment, the consumer is not getting the signal to reduce its consumption and the producer is not getting the signal to increase his production, hence, the market is not restoring the supply and demand balance. I’m pretty sure that Adam Smith would have disliked the idea of oil-indexation of gas,
  • Moreover, there’s more natural gas left on the planet than oil. Hence, the chances of over-valuation of natural gas are quite high when you index it to oil. That obviously explains why producers, such as Russia’s Gazprom, have been such fierce defenders of oil-indexation of natural gas. And this is not just economic theory. We have indeed seen that in every country that switched away from oil-indexation towards a hub model, the price of natural gas for the end consumers declined significantly.

The Hub model was first rolled out in the US with its Henry Hub and in the UK. With the creation of NBP, the UK did something enormously interesting, namely the creation of a virtual Hub, on which I will come back. This model was then copied in Belgium (Zeebrugge), the Netherlands (TTF), France (PEG’s), Germany (NCG and GPL), Italy (PSV) and other countries. Today, in most of the countries in Europe, gas is bought based on the pricing on a Hub. We even witnessed market integration, with pricing in those wholesale markets converging and TTF becoming thé benchmark to which prices in end consumer contracts are pegged. For most large industrial gas consumers in Europe, the disadvantages of oil-indexed gas pricing described above have become a thing of the past. They enjoy more transparent gas pricing, and it comes with a better price management service. Moreover, as mentioned above, the switch towards Hub-pricing came with lower prices and important savings. However, some countries have been left behind and haven’t made the switch towards Hub-pricing. One of them is Spain. (Portugal as well, as the Spanish and Portuguese gas markets, like the electricity markets are well linked.)

After years of neglect, the Spanish government now seems to get serious about making the adaptations necessary to reform its gas market and introduce the Hub market model that has been such a boon for gas consumers in other European countries. On the 22nd of May, the long awaited new Hydrocarbons law was published. Upon first lecture, it seems to contain some elements that could spark the development of a real Hub market on the Iberian Peninsula.

The most important element – no doubt – is the introduction of a virtual Hub. This virtualization of the gas Hub has been first tried out in the NBP with great results and then repeated in many countries, with TTF being the most spectacular example. From a contractual / legal point of view, the “Hub” is the place where the gas changes in ownership. In traditional physical Hubs such as Henry Hub or Baumgarten in Austria, this place is an actual physical location. Before that spot (often a valve on a pipeline), the gas belongs to the seller, after it, it belongs to the buyer. When a virtual Hub is created, the whole transportation grid is defined as being the Hub. Doing so, a whole geographical area, e.g. the whole of the UK or the whole of the Netherlands, becomes one big Hub or Entry-Exit Zone. This means that the seller can inject his gas at any point and it is considered to be delivered at the Hub, and the buyer can extract the gas at any point from the transportation grid, and it is considered to have been taken from the Hub.

Physical Hubs are not as beneficial to trading and retail market competition as virtual Hubs. Sellers of gas need to find access to that specific geographical location where the physical Hub is located and capacities to get there might be restricted, especially if capacity rights have historically been allocated to incumbent suppliers in the framework of long-term gas contracts. And a supplier needs to “route” his gas from that Hub to his end client. Capacity restraints can occur on that route, making it impossible for him to develop clients far away from the entry points at which he has sufficient capacity rights to get gas in. This is clear in the case of Spain, where the distances that are to be covered from injection in the Spanish system to an end client can be large. A supplier that gets his gas delivered in Huelva, on the Southern, Andalusian shore, might have difficulties routing this gas towards clients in the industrial heartland in the North and North-East of Spain. Nevertheless, we have seen the development of a market for locational swaps in Spain, where suppliers swap gas quantities that they can deliver in certain areas with quantities of other suppliers in areas where they can’t deliver. All in all, we can’t say that the Spanish market is suffering from a lack of diversity in offers. When we do gas tenders in Spain, we can easily collect up to ten different offers. What frustrates us, is that they all come with high prices (compared to other countries in Europe), oil-indexation and poor price management services.

The new Hydrocarbons Law talks about the introduction of a virtual Hub for the whole of the Spanish territory. That is a very interesting idea, as I believe that Spain or rather the Iberian Peninsula – contrary to what some suppliers say – has an almost ideal gas system for the introduction of a virtual Hub. The transportation grid is looking a bit like a giant bicycle’s wheel, with pipelines running along the coastlines and through the center (Madrid). Gas can be injected into the wheel at no less than ten places, the pipeline connections with France in the North and North-Africa in the South and eight LNG terminals. Connect all of that in one virtual Hub and you liberate suppliers from the difficulties of getting access to injection points near their clients and getting the capacity rights (or locational swaps) to go from entry to exit. You would expect that this will finally make Spanish gas suppliers and new suppliers develop the sort of competition that we’ve seen in other countries. This could bring important benefits for Spanish gas consumers, such as:

  • A cost saving. Currently, we are seeing (oil-indexed) gas prices in Spain in the range of 24 – 25 euro per MWh. Prices on the North-West-European Hubs are in the 22 – 23 euro per MWh range. If due to the Hub development the prices in Spain converge with prices in the rest of Europe we could see a two euro per MWh saving opportunity. And it should be remarked that due to the drop in oil prices, the spread between prices in Spain and Hub prices elsewhere in Europe is historically low. In 2014 the spread was rather in the 10 euro per MWh range.
  • Possibilities of buying energy in a different way, with spot indexation and forward products for securing future price levels.

Whether the new law will lead to a rapid development of such a more competitive Hub-based market on the Iberian Peninsula or not is unclear at this moment. The hydrocarbons Law is a general text, setting up the legal framework for developing the Spanish Hub. Whether it will function or not depends on how it will be worked out in decrees and other regulatory texts such as the code for the usage of the grid that is to determine the crucial balancing system. The Law announces the preparation of these important extra pieces of regulation. The devil will indeed be in that detail. The Spanish government has been working on the creation of a Spanish gas market Hub for a long time. As we have remarked here before, the officials seemed to be focusing too much on the financial aspects of the market, the creation of a platform to trade in spot and forward contracts for natural gas. Whereas the success of a Hub depends primarily on getting the physical aspects right, defining a large entry / exit zone and making sure that there are non-discriminatory access rights and balancing services in that zone. So we’ll have to watch carefully for the extra regulatory texts and see if they have the right elements for setting of the Hub market development in Spain.

What is a bit bizarre in the new Hydrocarbons Law is the definition of the entity that would be responsible for managing the balancing system. This is to be a company in which the transport grid company (Enagas) and the organizer of the exchange platform (OMIE/OMIP) would come together. In most other countries, the balancing system is simply run by the transport grid operator. Spain seems to aim at the introduction of some sort of independent system operator. Having the organizer of the exchange platform so tightly involved in the balancing is a reminder of Spain’s confusion of the Hub model with the organization of an exchange. And the preoccupation of the Law with getting involved in the financial aspects of the gas market is reminiscent of the dirigisme of Spanish lawmakers. Spanish energy policy, also in the electricity market, often fails to produce the best and cheapest results for the end consumers because of officials trying to arrange everything in too much detail. But we should give Spain the benefit of the doubt and hope that in the next months, a Hub market for natural gas becomes a reality for Spanish gas consumers, just as we have seen in other countries.

Buying energy in the land of the free

Prefer video? Have a look at the end of this blog article.

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

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

Transatlantic Energy Conference

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

  • Lack of a clear federal competence for energy market regulation

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

  • Bottom-up versus top-down market development

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

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

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

  • No development of entry-exit zones

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

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

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

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

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

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

  • More complex, less transparent pricing

With a larger diversity of price references referring to the wholesale supply of natural gas and electricity, it is harder to get a good idea in the US of what energy costs. When we talk to European clients, they almost always have an idea of what the underlying price level is of the energy that they have to buy. That’s because European consumers can go and have a look at the websites where the wholesale energy for their market is traded and the price is published, wide and open for everyone to consult. That is impossible for the US. You can find information free of charge for Henry Hub in the natural gas markets, see Side 2 of this document: http://www.cmegroup.com/daily_bulletin/current/Section61_Energy_Futures_Products.pdf. But there is no source where you can find all the information necessary to make an estimation of the cost of routing the gas towards your facility free of charge. And for electricity, daily pricing data on the 41 price references can only be obtained if you’re willing to pay for it. Therefore, we observe that compared to their European counterparties, most US energy buyers have much less insight into the daily movements of wholesale energy prices. Many of them only get an idea of how high or low the energy markets are by asking offers to suppliers.

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

  • More market mechanisms for setting non-commodity price component

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

  • Less usage of advanced price management techniques

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

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

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

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La fin de l’ « arenhisation » du marché Français

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

Par Baptiste Desbois.

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

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

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

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

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

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

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