Calculating procurement savings when buying energy

Procurement savings are often the measure of the performance of procurement professionals. In an earlier blog we commented on the risks inherent to this narrow view on procurement. But reporting procurement savings is an inevitable part of a buyers’ job, and why should it be avoided? There is nothing dishonorable about saving money for your employer.

However, when procurement savings are used to measure a buyer’s (or a consultant’s) performance, you better get the metrics right. And in a complex knowledge environment like energy markets, it’s not always easy to be sure that the cost reduction is indeed the result of an individual’s good work. In the past few years, wholesale prices for natural gas and electricity have dropped dramatically. Many buyers have enthusiastically reported the resulting cost reduction compared to the previous year as a cost saving. Now that markets have stopped falling, many are feeling cold sweat about how to report the year-to-year evolutions. Here’s our vision on how purchasing cost savings due to energy buying should be reported (and how not).

It starts with an analysis of what an energy buyer is doing and what procurement savings he can generate with those activities:

  1. Energy contracting,
  2. Energy trading activities (forward fixing or not fixing & unfixing activities),
  3. Energy controlling,
  4. Special projects.
  1. Energy contracting

Generating savings by negotiating better contractual conditions is a traditional activity of professional buyers. It is important to get a clear view on what improvements have actually been made thanks to the buyers’ activities. The energy price consists of three components:

  1. The wholesale value of the gas or electricity, or the price at which the energy is secured by your price fixing actions,
  2. The retail add-on, which is the add-on cost added by the supplier to go from the wholesale products, which are flat capacity blocks, to the specific load profile consumed by you as a client with its ups and downs,
  3. The grid fees and taxes.

What your wholesale value will be is not decided by your negotiation skills, but purely by the moment at which you are closing it. And grid fees and taxes are in most cases charged on a pass-through basis, meaning that you pay the amount at which they have been set by the regulator and not what you negotiated. Therefore, the only part of the energy bill that you can influence during the contract negotiations is the retail add-on.

Now, if we look at the kind of simple TTF or other Hubs plus add-on contracts that are often negotiated in today’s gas markets, we can easily explain how a saving can be reported. Let’s say that you currently have a contract with a formula TTF + 0,7 euro per MWh and that you negotiate a new contract for 2017 with a formula TTF + 0,4. Then it becomes clear that thanks to your negotiation, your company will save 0,3 euro with every MWh that it consumes in 2017.

However, the calculation isn’t always that simple. In a country like Belgium, suppliers are not charging transportation costs on a pass-through basis but apply reductions to the official tariff. In that case the reduction on transportation should be part of the savings calculation. And for electricity, the retail cost is often based on a complicated formula to go from wholesale to retail price. However, by plugging the same wholesale values in the different formulas, the implied add-on costs can be calculated and compared. In the same way, the implied add-on cost of a fix price contract can be calculated by comparing the retail price that was signed to the wholesale value for the relevant period on the day that the fix price contract was signed.

  1. Energy trading

Unfortunately, the performance of buyers regarding their decisions to fix, not fix or unfix forward pricing is often judged based on a year-to-year comparison.  In the past years, with markets going down, that worked out favorably. But what will buyers report in a bull market?

Moreover, if you acknowledge that the savings metrics should reflect the positive results of a buyer’s work, than you should not report every drop in the wholesale value of your energy as a saving. You can be a very good buyer, but you’re not the one that determines whether the market goes up or down. Moreover, if the wholesale price goes down from 40 to 20 and you fix at 35, you might report a saving, but you’re not doing a very good job. In any case, a worse job than someone who fixes at 25 when the market goes up from 20 to 40.

Some organizations might conclude that no added value can be created with energy trading. That is not true. When we look into the performance of companies that we haven’t advised, we see remarkable differences in the quality of the wholesale price management. You’re doing a good job if you:

  • Spread your fixing decisions, so that you don’t fix too much when you’re completely on the wrong side of the market. If you fix a lot in one moment, you might also do this at a very good moment, but that is more due to luck than skill, as markets are unpredictable. Moreover, by fixing too much in one moment you are taking too much risk.
  • Don’t fix in a falling market, don’t unfix in a rising market. It sounds simple but most energy buyers completely ignore this basic rule and end up with having fixed too much too soon in a downtrend.
  • Follow up the market actively, so that you make small fixings every time when a low has been reached and markets start to increase again. Equally, unfix in small portions when markets have reached a peak and start to fall again.
  • Have an efficient decision-making process, so that you don’t lose opportunities because it takes you days to make a fixing or unfixing.

If you apply these principles, your price fixing will have good results. These results can be evaluated by measuring them against a market benchmark. Let’s say for example that you are fixing prices in different moments during the year prior to the year of consumption. You could always choose to just buy the average year ahead price, meaning that if your price is higher than that average, the results of your price fixings are negative. You could have better not done any fixings and take the average year ahead price. On the other hand, a price below the average means that you have added value that can be expressed as a procurement saving of the market average minus the price.

You can fine-tune your market average that serves as a benchmark with your global energy strategy goals. Let’s take the example of a client of ours that is a producer of energy-intensive chemical commodities and the pricing of its products is going up and down with spot natural gas markets. Their strategy is to make fixings and unfixings for small volumes, in an attempt to ‘beat the spot market’. In this case we chose the spot market as a benchmark.

Another example is a client in the automotive sector. As prices for its products are fixed for several years, e.g. in seven-year contracts with the car manufacturers, the main goal is to achieve cost stability. Running a diverse portfolio of contracts with car manufacturers, we have chosen to run this cost stabilization strategy in a three-year forward timeframe. When markets reach lows, we make larger fixings for those three years into the future at the same moment. Moreover, we have a strict observance of a maximum year-on-year cost increase of ten percent. In this case, we are using the average three-years ahead price as the benchmark for the performance of this client’s energy trading activities.

The choice of the right benchmark is very important. If the automotive company would choose the spot market as a benchmark, its energy buyers would perform less well. They would be “scared” of making forward fixings, as that jeopardizes the chances of beating that spot market benchmark. Which would mean that they have difficulties achieving the primary goal of cost stability.

You can’t expect to fix prices below market average on every contract for every single year. Sometimes you will fix prices for part of the volume in what was just a temporary uptick, with prices diving even deeper afterwards and your price ending up above the market average. Or you have to take a protective price fixing in a rising market.

The solution for this is to spread your price fixing decisions as much as possible, but that diminishes your chances of having a price well below market average. Therefore, skillful price fixing will strike the right balance between spreading enough to avoid prices high above market average and still make opportunistic (un-)fixings that lead to a price below average.

In a more general sense, in its energy trading efforts a company needs to strike the right balance between managing risk (i.e. spreading fixing and unfixing) and making savings (opportunistic fixing and unfixing) to be successful. A company that puts too much pressure on its buyers to make savings, might end up in the disaster of having taken too much risk. A company that puts all the emphasis risk management only, might forego interesting opportunities to lower its costs.

  1. Energy controlling

The involvement of energy buyers in the controlling of energy costs can differ widely. In some companies, the buyer is responsible for setting up budgets, checking cost versus budget and validating bills. In other companies this is done by the financial controlling department. When buyers are involved, management will often want to see results of the energy controlling in terms of savings.

Defining savings through energy controlling is quite simple. For example: the buyer checks the bills of one of his US plants and finds out that the wrong utility rate is applied. He writes a letter, conducts negotiations and in the end a 350.000 dollar refund is granted and paid to the client. This can be reported as a 350.000 dollar saving.

Some companies might have reservations for calling this a saving. It is a rectification of a mistake, a refund of money that the company shouldn’t have paid in the first place. On the other hand, if the energy buyer hadn’t done his job properly, the mistake might have passed undetected and the 350.000 might have never been returned. For the buyer, reporting the 350.000 might be a great success, especially if he has a bonus arrangement based on savings. On the other hand, he needs to realize that such successes depend on being “lucky” that your supplier or utilities send out wrong bills. For the company’s cash flow, receiving a correct bill in the first place and not getting refunds is the better option.

The buyer and his company should also realize that not all mistakes will lead to a refund, they might also lead to an extra bill. From our energy controlling activity, checking thousands of energy bills every month, we can say that 50% of the mistakes in energy bills are to the advantage of the clients. The 350.000 dollar extra bill sent by the utility that has detected its mistake, will obviously never be accepted as a “saving” … However, if the energy buyer detects that mistake, he’s doing a good job, as he can help his company to put aside the money for when the correction comes in.

Putting too much emphasis on savings through the financial controlling activities can also lead to over-opportunistic behavior. This is a particular danger when such controlling services are delivered by a consultant on a no cure – no pay basis. Of the mistakes that we detect in energy bills, some 60% are “differences in interpretation” rather than real “mistakes”. An opportunistic buyer or consultant might hurry into declaring that difference in interpretation a mistake so that she/he can claim the saving. This leads to the reporting of fictitious mistakes and paying of pay for a cure for a problem that wasn’t a problem in the first place. Moreover, aggressive claiming of mistakes can antagonize suppliers without need.

An example will illustrate this. We once took over a client from another consultant that had been working on a no cure – no pay basis. For its French plant, the client had signed a natural gas contract in which it had agreed to pay a fixed amount every month for transportation of the gas. The agreement stated that at the end of the year, the real cost of transportation, based on the official tariff would be calculated and an invoice or credit note to settle the shortage or surplus amount would be sent.

In July, the consultant calculated the amount that was due according to the official tariff, found out that it was lower than the fixed amounts that had been billed, sent a letter to the supplier to claim back the surplus money that had been paid to the supplier and an invoice to the client for the 50% commission on this so-called “saving”. Needless to say that both supplier and client were not very happy with this behavior. However, in a company where the buyer is receiving a bonus when reporting savings by energy controlling, that buyer might be tempted to work together with the consultant in claiming the saving.

  1. Special projects

Energy buyers can be involved in many different projects that lead to cost savings, such as:

  • The implementation of auto-production, e.g., a CHP unit or a PV-installation.
  • Filling in forms to get a reduction of a regulated price component, e.g. the EEG tax in Germany.
  • Setting up a demand-response program to benefit from the highs and lows of spot markets.
  • Marketing of interruptible load to benefit from a capacity program.

Calculation of the savings caused by such special projects is to be determined on a project-by-project basis. Such calculus will always be based on a “before” and “after” situation. It should be taken into account that the world of energy markets is very dynamic with all factors changing continuously.

To give a – at first sight – simple example, a PV project. The saving might be calculated by simply saying: “last year we paid 1,5 million euro, now, we pay 1 million, so we made a 500.000 euro saving thanks to the solar panels on our roof”. However, it could be that in the current year, the wholesale electricity market dropped, causing the cost of the remaining power that you consume from the grid to drop by 300.000 euro. Therefore, the saving thanks to the solar panels is 200.000 euro rather than 500.000. A better measurement of savings could therefore be to take the amount of energy produced by the solar panels and multiply that by the price that you paid for the remaining off-grid electricity.

And even that isn’t correct. Due to installing the solar panels, what you pay for add-on cost and usage of the grid will have increased. If you’re very good at interpreting energy cost components, you might be capable of calculating that this means you paid 25.000 euro more for the electricity than you would have paid without the solar panels. Meaning that the real saving is 175.000 euro. As you can see from this example, savings metrics in energy buying is never a straightforward matter.

The involvement of the energy buyer in such special projects might be anything from having initiated them, to be involved in all steps to just getting called in when the contract has to be signed. Too much focus on making savings, can lead to this ‘being called in at the last moment’ phenomenon. Too many companies still consider their procurement professionals as the people you call in to squeeze out a price concession. That’s a pity, as involvement of procurement from the very first steps in a project will lead to much more added value, as they can help to:

  • Make a better analysis of the needs.
  • Have a broader view of the market in which the project can be bought.
  • Keep potential suppliers and project partners sharp from the very first moment.
  • Tender competitively instead of getting heavily involved with just one potential project partner.
  • Have a better view on the structure of energy costs so that the calculation of the savings and payback of a project is more realistic.

Having procurement professionals involved in special projects can increase the savings that they cause. But again, too much emphasis on those savings can lead to sub-optimal results.

Conclusion: be pragmatic when applying procurement savings metrics in the field of energy buying

From the examples given above, it must be clear that the usage of savings in energy procurement is a delicate subject. It is impossible to set up a system for measuring savings that makes sure that every 1 euro savings reported by the buyer results in 1 euro extra for the company’s financial bottom line. Moreover, a good energy buyer will have many added values that are not measurable. Too much emphasis on reporting savings can cause such intangible added values to be neglected.

On the other hand, saving money for their organizations should always be the fundamental driving force of procurement professionals. In this article we have given some ideas of how pragmatic energy procurement savings metrics can be implemented. Applying them will motivate your energy buyers (and consultants!). However, be aware that such measurable savings are not the only added value that they can deliver.

La ola de frío hace estragos en el mercado energético español

Prefer the English version? Please find it here.

Los mercados energéticos españoles se comportaron de forma inestable la semana pasada. El jueves 19 de enero, el precio de la electricidad para el día siguiente cerró en 88 euros por MWh, este es el nivel más alto alcanzado desde el 6 de febrero de 2006. El nuevo Hub de gas natural, Mibgas, también alcanzó un máximo llegando a los 41,87 euros por MWh los días 12 y 13 de enero.

Hace frío en España y los turistas en busca de un clima agradable en invierno están siendo sorprendidos con tormentas de nieve y heladas. Las circunstancias siberianas son excepcionales y obviamente causan un pico en la demanda de electricidad y gas. El sistema eléctrico ha encontrado dificultades para hacer frente a este pico. En la Comunidad Valenciana 32.000 clientes se quedaron sin electricidad y la eléctrica Iberdrola tuvo que poner en marcha 23 generadores de emergencia.

Álvaro Nadal, nuevo ministro de Energía, advirtió a los ciudadanos españoles en un comunicado de prensa que se fueran acostumbrando a una energía más cara. El ministro cita todo tipo de argumentos para justificar los actuales precios, junto al aumento de la demanda de calefacción, señala también paradas nucleares, mayores exportaciones a Francia, baja producción de energía eólica y solar, mayor precio del crudo y un alto precio del gas natural. La situación actual muestra una tendencia muy alcista, pero los altos precios de la electricidad y el gas natural en España no son sólo un fenómeno de este invierno. Los mercados energéticos españoles son más caros que otros mercados europeos desde hace años.

Respecto a la electricidad, podemos ver que los precios spot españoles se alinearon con los precios spot alemanes hasta 2014, cuando comenzaron a subir estructuralmente. Los analistas señalan a menudo el alto porcentaje de energía renovable en España para explicar los altos precios de electricidad. Según datos de Red Eléctrica, el 49,9% de la capacidad de producción de energía eléctrica en España es renovable. El viento no siempre sopla y, hasta en España, el sol no siempre brilla, haciendo que los precios del mercado de día siguiente se eleven algunos días y los acontecimientos del último día parecen apoyar ese análisis.

Sin embargo, Alemania tiene un porcentaje aún mayor de energía renovables en el mix de capacidad de producción: un 52,43% de acuerdo con los datos de En Alemania, un volumen creciente de energías renovables en la red ha tenido un claro efecto beneficioso sobre los precios de la electricidad al por mayor. ¿Por qué no hemos visto el mismo efecto en España?

La situación actual de altos precios y apagones en algunas regiones parece señalar que en España hay escasez de capacidad de producción de energía. Sin embargo, como podemos ver en la página web de Red Eléctrica, el viernes 20 de enero la demanda alcanzó un máximo de 40.294 MW, esta cifra es muy inferior a la capacidad de producción total de 100.088 MW estando incluso por debajo de la capacidad instalada de producción tradicional de energía térmica (carbón y gas), que se sitúa en 41.154 MW. Además, en el momento de mayor demanda, las centrales nucleares españolas producían 7.100 MW, las centrales hidroeléctricas 6.168 MW, las turbinas eólicas 5.007 MW y las centrales fotovoltaicas 675 MW. Sumando estas cifras, realmente no se entiende el por qué los precios subieron tanto.

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Es cierto que el equilibrio entre la oferta y la demanda en España está cada vez más ajustado. Con una economía en recuperación, España registra un aumento de su demanda de energía de 0,8% en 2016. Al mismo tiempo, la capacidad de producción cayó un 0,9%, debido al cierre de centrales de carbón. A pesar de ello no olvidemos que la situación general sigue siendo muy cómoda en comparación con otros países europeos como Bélgica o Francia cuando tienen centrales nucleares cerradas.

Entonces…¿Por qué los precios españoles son más altos?

Los productores de energía españoles parecen ser incapaces de entregar a la red una electricidad fiable y con un precio razonable. Los 194.530 MW de potencia disponible en Alemania produjeron 648,2 TWh de electricidad en 2016. Esa es una utilización del aparato de producción de 3.322 horas, siendo mucho mejor que las 2.500 horas de los productores españoles, con 100.088 MW de capacidad instalada produciendo sólo 250.266 TWh. Una vez más, el alto porcentaje de energía renovable en España no es una excusa, ya que Alemania tiene un porcentaje aún mayor.

El ministro Álvaro Nadal debería aprovechar la situación actual para hacer un llamamiento a los productores de energía y exigirles que mejoren su rendimiento. Por otra parte, como hemos mencionado antes, los sistemas que organizan la oferta de energía española y la logística de la demanda son bizantinos y disfuncionales. Súbase a un avión señor Nadal y vea cómo otros países europeos lograron organizar mejor sus mercados: una mejor organización que resulte en una mejor utilización del parque de producción de energía y menores precios de los productos básicos para los consumidores finales.

La semana pasada se podía escuchar en las noticias españolas que los altos precios se debían al uso de “costosas” centrales de gas de ciclo combinado. Sin embargo, en el momento de máxima demanda el viernes pasado, sólo había 2.229 MW de ciclo combinado en operación, lo que representa menos del 10% de la capacidad instalada total de 24.948 MW. Es un hecho, sin embargo, que el costo de producir electricidad con una central eléctrica de gas es mucho más caro en España que en otros países. Esto se debe al alto precio del gas en España.

La mayor parte del gas natural en el mercado energético español aún se comercializa a precios indexados a los mercados petroleros. Los recientes aumentos de los precios del petróleo han provocado por tanto un aumento de los precios del gas en España. Si nos fijamos en los precios de los otros mercados europeos, determinados por los hubs como el TTF donde la demanda y la oferta de gas natural fijan el precio, diríamos que el desarrollo del Mibgas en España es una excelente idea. Sin embargo, una idea sólo es buena cuando está bien ejecutada.

El verano pasado, vimos los precios del hub ibérico Mibgas operando a un nivel similar al TTF. En mayo y junio de 2016, incluso vimos un precio de Mibgas más bajo que el TTF algunos días, lo que generó esperanzas de que finalmente veríamos unos precios normales de gas en España. Sin embargo, a partir de agosto, el precio de Mibgas comenzó a subir por encima del TTF. El 13 de enero, el precio de Mibgas fue 21,14 euros por MWh más caro que el TTF u otros precios del norte de Europa.


Los abastecedores españoles de gas (y los analistas que lo apoyan sin argumentos) apuntan dos razones que causan esta situación:

  1. El hecho de que los buques de GNL provenientes de Argelia por ejemplo, en lugar de llegar a la península Ibérica hayan decidido navegar a otros destinos como Asia, donde los precios del gas son actualmente altos.
  2. La falta de capacidad de interconexión con Francia y los precios del Norte de Europa.

Sí, los precios asiáticos están reduciendo las exportaciones de GNL a Europa. Pero los 41,87 euros por MWh que encontramos en España a principios de este mes, fue el precio más alto de gas natural en todo el planeta en ese momento, así que ¿Por qué los buques no llegaron a España?

Por otra parte, la reducción de gas natural licuado debido a la alta demanda asiática afecta de la misma manera al TTF, así que ¿Por qué el precio en España es más del doble que en el norte de Europa?

La falta de conexión por gaseoducto hacia el Norte es también un hecho, pero no hay ningún país en Europa que tenga tanta capacidad (no utilizada) para importación de GNL como España. Sólo hay 1.305 kilómetros por mar entre los puertos de Zeebrugge y Bilbao.

El 13 de enero, un comerciante podría haber ganado 21,14 euros por MWh al cargar GNL en Zeebrugge y descargarlo en Bilbao, ese habría sido uno de los trayectos de GNL más lucrativos de la historia, pero ningún barco lo hizo.

España estará mal conectada con el resto del mundo mediante gaseoductos, pero está muy bien conectada con terminales de GNL, el problema es que estos no se están utilizando. ¿Por qué? Porque traer el gas a la terminal de GNL es posible, pero sacarlo de la planta de regasificación y venderlo en el mercado interno español parece ser casi imposible.

España ha sido el último de todos los países europeos en establecer un Hub. Preparándose para ese lanzamiento, España se centró más en cómo organizar los aspectos financieros que los aspectos físicos, pero la parte física es clave. Un Hub debería facilitar el acceso de terceros al sistema de gas mediante el establecimiento de una zona de entrada-salida a nivel nacional y la introducción de un sistema de equilibrio eficiente y rentable. Debido a los altos precios actuales y la falta de liquidez, está claro que Mibgas no ha logrado esto. Una vez más, España ha introducido sistemas que son diferentes de lo que vemos en el resto de Europa. Así que, Ministro Nadal, vaya a echar un vistazo al resto de Europa y arregle este desastre de mercado energético español.

A cold snap wreaks havoc on the Spanish energy market

Spanish energy markets were in turmoil last week. On Thursday the 19th of January, the day ahead electricity price averaged 88 euro per MWh. That is the highest level since the 6th of February 2006. The new Hub market for natural gas, Mibgas, went through the roof as well, racing to 41,87 euro per MWh on the 12th and 13th of January.

It’s cold in Spain. Tourists in search of mild winter weather were caught in snowstorms and frost. The Siberian circumstances are exceptional and obviously cause a peak in demand for electricity and gas. The power system struggled to cope with this peak. In the Communidad Valenciana, 32.000 clients were without electricity and utility Iberdrola had to rush in 23 emergency generators. Álvaro Nadal, the new Minister of Energy is all over the press, warning the Spanish citizens to get adapted to more costly energy.

The Minister is citing all kinds of reasons for the current peaks in prices: next to the increased demand for heating purposes he points out: nuclear shutdowns, increased exports to France, low output of wind and solar, the higher price of crude oil and the high price of natural gas. The current cocktail is indeed very bullish. But the high prices for electricity and natural gas in Spain are not just a phenomenon of this winter. Spanish energy markets are more expensive than other European markets for years.

If we look at electricity, than we can see that the Spanish spot prices were at more or less the same level as German spot prices until 2014 and then started to rise structurally higher. Analysts are often pointing at the high percentage of renewable energy in Spain to explain high spot prices: according to Red Electrica’s data, 49,9% of Spain’s power production capacity is renewable. The wind doesn’t always blow and even in Spain, the sun doesn’t always shine, causing spot prices to rise high on some days. The events of the last day seem to support that analysis.

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However, Germany has an even higher percentage of renewable power production capacity: 52,43% according to data of In Germany, increasing amounts of renewables on the grid have clearly had a beneficial effect on the wholesale electricity prices. Why haven’t we seen the same effect in Spain?

The current situation of high prices and blackouts in some regions seems to point out that Spain has a shortage of power production capacity. However, as we can see on the website of Red Electrica, on Friday the 20th demand peaked at 40.294 MW. That is well below the total production capacity of 100.088 MW. It is even below the installed capacity of traditional thermal power production (coal and gas), which stands at 41.154 MW. Moreover, at the moment of peak demand, Spanish nuclear power stations were producing 7.100 MW, hydro power stations 6.168 MW, wind turbines 5.007 MW and photovoltaics 675 MW. Adding up the figures, you really don’t understand why prices were soaring that much.

It is true that the supply and demand balance in Spain is getting more tight. With a recovering economy, Spain is seeing an increase in its power demand, +0,8% in 2016. At the same time, production capacity dropped 0,9%, due to the closure of carbon-fired power stations. However, the overall situation still looks very comfortable compared to other European countries like Belgium or France when it has nuclear power stations shut down. Then why are Spanish prices higher?

The Spanish power producers seem to be incapable of delivering a reliable, reasonably priced electricity to the grid. Germany’s 194.530 MW of available power capacity produced 648,2 TWh of electricity in 2016. That’s a utilization of the production apparatus of 3.322 hours. That’s a lot better than the Spanish power producers’ 2.500 hours with 100.088 MW of installed capacity producing just 250,266 TWh. Again, the high percentage of renewable energy in Spain is not an excuse, as Germany’s having an even higher percentage.

Minister Álvaro Nadal would better use the current situation to call upon the Spanish power production companies to improve their performance. Moreover, as we have mentioned before, the systems that organize Spain’s power supply and demand logistics are byzantine and dysfunctional. Get yourself on a plane, Mr. Nadal, and go and have a look at how other European countries managed to get their markets better organized. A better organization that results in a better utilization of the power production park and lower commodity prices for the end consumers.

Last week you could hear in the Spanish news that the high prices were due to the usage of “expensive” combined cycle gas-fired power stations. However, at the moment of peak demand last Friday, there was just 2.229 MW of such combined cycle power stations at work, which is less than 10% of the total installed capacity of 24.948 MW. It is a fact however, that the cost of producing electricity with a gas-fired power station is much more expensive in Spain than in other countries. This is due to the high price of gas.

Most of the natural gas in the Spanish energy market is still traded at prices indexed to oil markets. The recent increases of oil prices have therefore caused Spanish gas prices to increase. If you look at the pricing in the other European markets, determined by Hubs such as TTF where the demand and supply of natural gas itself is setting the price, you would say that the development of the Mibgas Hub in Spain is an excellent idea. However, an idea is only good when it’s well executed.

Last summer, we saw Mibgas prices trading at a level similar level as TTF. In May and June 2016, we even saw a lower Mibgas price than TTF on some days. This sparked hopes that we would finally see normal gas prices in Spain. However, as of August, the Mibgas price started to rise high above TTF. On the 13th of January, the Mibgas price was 21,14 euro per MWh more expensive than TTF or other Northern-European prices.


Spanish gas suppliers (and analysts paying them lip service) point at two reasons for this:

1. The fact that LNG ships from Algeria for example, rather sail to Asia where gas prices are currently high.
2. The lack of interconnection capacity with France and the Northern European prices.

Yes, Asian prices are reducing LNG exports to Europe. But the 41,87 euro per MWh that you could get in Spain earlier this month, was about the highest price for natural gas on the planet at that moment, so why didn’t the ships come to Spain? Moreover, the “less LNG due to high Asian demand” counts for TTF just as well, so why is that price in Spain so much higher than in the North of Europe?

Lack of connection by pipeline to the North is also a fact. However, there is no country in Europe that has so much (unused) LNG import capacity as Spain. There is only 1.305 kilometer by sea between the ports of Zeebrugge and Bilbao. On the 13th of January, a trader could make 21,14 euro per MWh by loading LNG in Zeebrugge and sailing to Bilbao. That must be one of the most lucrative LNG trips in history. But no ships did it.

Spain might be badly connected to the rest of the world with gas pipelines, but it is well connected with LNG terminals. But these are not being used. Why? Because getting the gas into the LNG terminal is possible, getting it out and sell it in the internal Spanish market seems to be all but impossible.

Spain has been the last of all European countries to launch a Hub market. Preparing for that launch, Spain was more focused on how to organize the financial aspects than the physical aspects. Whereas the physical side is key. A Hub should facilitate third party access to the gas system by the establishment of a nation-wide entry-exit zone and the introduction of an efficient, cost-effective balancing system. From the current high prices and lack of liquidity, it is clear that Mibgas has failed to achieve this. Again, Spain has introduced systems that are different from what we see in the rest of Europe. So, Minister Nadal, go and have a look in the rest of Europe and get this mess of a Spanish energy market fixed.

Energy procurement: the bureaucratic versus the entrepreneurial approach

Recently I held a meeting with a customer to define a new strategy for buying energy. The company is a family-owned food producer that has recently witnessed strong growth under the leadership of a new generation of enthusiastic entrepreneurs. In terms of energy procurement we took many excellent decisions in the decade of our collaboration, such as leaving open an increasing part of the pricing to spot indexation in the recent period of price declines. Such decisions were based on the strong risk / opportunity optimization instincts that characterize strong entrepreneurs. However, as the company and its energy spend has grown, the owners feel the necessity of a more formal approach to eliminating risk due to energy market volatility.

During the meeting, we were surrounded by a management team of people trained in larger corporations. Confronted with the question of how much of the volume we leave open to spot price indexation, these professional managers quickly opted for the zero risk solution, meaning in their case that for all production for which sales prices have been agreed with clients the energy price would be hedged, leading to a freezing of the margins. The entrepreneur-owner protested against this, saying that he would feel sorry about the loss of opportunity if markets would go down. This was an excellent example of the tension between entrepreneurialism and a more managerial approach to business and the way it can manifest itself when buying energy.

As companies grow, it becomes impossible to run them based on the enthusiasm and strong instincts of their entrepreneurs. The necessity for more managerial skills grows. In the buying function of a company, procurement professionals are hired and they introduce more structured approaches to buying. Systems are introduced that can track an invoice back to a procurement decision (purchase orders). Decision power is attributed and the authority to purchase is taken away from the users of the goods and services that are bought and delegated to the professional buyers. Formal contract negotiation procedures such as RFQ’s (request for quotations) and RFI’s are introduced. In commodity buying, risk management or other approaches to fixing volatile forward prices are set up. Often, the success of this introduction of professional procurement is measured in terms of savings, which can lead to the introduction of complicated systems for savings calculations.

In many cases, energy is one of the last categories to be brought under formal control. Many companies consider it to be a highly technical category and leave it for a long time with the maintenance or facility management professionals. There is no reason for doing this. Buying energy in an open market is much more challenging from an economic-commercial point of view than technically. I’ve never witnessed a company doing an awful job at energy procurement because its staff members failed to grasp the subtleties of MWh’s versus MW’s. But I’ve seen many companies failing at buying energy because of a lack of understanding of how commodity markets work. Therefore, introducing professional procurement management methodologies can be a blessing for a company’s energy buying practices.

However, too much management techniques can easily derail in a too formalistic approach. Entrepreneurialism, that usage of passion and strong instincts to take the right decisions, disappears and gives way to corporate bureaucracy. I recently had a discussion with the energy buyers of a client of ours, one of Europe’s largest corporations. In this company, a strong procedure for running tenders has been developed that should ensure that the company is always making the best out of the market. However, running this procedure is so demanding that the buyers prefer running bi-annual rather than annual tenders, which would give them better protection in terms of wholesale price hedging. In its worst form, the procurement division becomes a corporate bureaucracy where the instrument of running formal procedures becomes a goal in itself, rather than making the best out of the markets. The system for savings calculations, for example, can easily start to live a life of its own. One client once told us that the first thing their new CEO said in a meeting with the procurement division was: “I want you to stop reporting savings. Why? Well, if all the savings that you guys and girls reported in the last five years had materialized, we would now be paid by our suppliers”.

It’s logic that entrepreneurs that are introducing formal management in their companies revolt against such a bureaucratic approach to procurement. Corporate excellence isn’t founded on “just following the procedures”. A good energy procurement practice will strike a good balance between the professionalism of good procedures and leaving room for talented individuals to take good decisions:

  • Good data management is an indispensable starting point for professional procurement. You can’t be successful at buying energy if your information is stuck in the heads or on the local hard disks of hard-working staff members. However, you should consider efficiency when setting it up. One client once told me that he spends about 70% of his time on internal reporting. Imagine what it would mean for his company if he could bring this down to 40% and actually double the amount of time he has for being informed about the market.
  • Giving some structure to your contract negotiations will make them more effective. However, take into account that energy companies have to produce a lot of offers. If your RFQ procedure becomes too demanding, the account managers might lose their enthusiasm for doing the deal because they have to deviate too far from their standard procedures for making offers. Also, leave some room for good old negotiation. I see many large corporations that go into the market with RFQ’s that are already asking for all the concessions that they want to get. They will get them, but at what price? Negotiating concessions is a much better methodology than writing lengthy, demanding RFQ’s.
  • As a larger corporation, you can’t have the fate of your energy spend determined by the gut feeling of your energy buyer(s). Setting up a good risk management strategy can make sure that nobody will take decisions (or not take decisions) that damage the company. However, within the framework of such a risk management strategy, you should leave room for some opportunistic decision making.

Savings reporting can be a good tool for measuring the success of your energy buyers’ entrepreneurialism when buying energy. However, it isn’t always easy in energy to determine which savings are due to an action by an individual and which are just due to changing market circumstances. But that’s a topic for a new blog article.

Mibgas and its failure to fix the Spanish gas market

On this blog and in conferences, we have repeatedly complained about Spain’s reluctance to fix its gas market. For years now, Spanish end consumers of gas are paying more than consumers in other countries. And we can’t see any good reason for that. Spain’s gas import and transportation infrastructure was drastically expanded in the booming early 2000’s, anticipating a never-ending period of growth of the economy and gas consumption. Instead of that, Spain slumped into a deep recession and in 2015, Spain’s gas consumption was 29% lower than in 2008. As a result, wherever you look in Spain’s gas system, you will find excess capacities. So why on earth doesn’t this result in lower prices?

Many Spanish gas suppliers will point at the limited capacity on the French-Spanish cross-border pipeline. Yes, this means that only small quantities of gas can float directly, through a pipeline, from the cheaper markets in the North to Spain. However, only looking at this pipeline is a very shallow look, especially if you consider that most of Spain (and Portugal’s) gas comes in through LNG ships. As a matter of fact, no other European country has such a large LNG import capacity. Most of the terminals are used at very low percentages of their capacities. And still, lots of LNG ships are sailing past Spain without unloading the gas, taking it to terminals further North to sell it at a price far below what they could get in Spain. They are sailing hundreds of extra, expensive miles to unload at a lower price. In September, the average spot price of gas in Spain was 4,6 euro per MWh higher than in Zeebrugge in Belgium. Why didn’t anyone cash in on that spread by loading gas in Zeebrugge and unloading it in Bilbao? Why isn’t the market with the highest end-consumer price in Europe and the highest amount of unused import capacity flooded with LNG?

Traders answer us: we can get the gas into the Spanish ports, but we can’t get it out. The Spanish government has failed to implement gas market policies that guarantee third party access to the Spanish gas grid. The system makes it possible for incumbent suppliers to sit on unused capacities on key infrastructure just to keep newcomers out. And it creates a lot of risk for traders that don’t have access to huge physical quantities of gas within the country. For a little while we were hopeful that things might change with the introduction of the Hydrocarbon Law in May 2015. It resulted in the launch of Mibgas, a Hub market for gas in Spain. In the middle of this year, we saw prices on this Mibgas drop towards the levels in the North of Europe (TTF). But in the last month, the gap has widened again. Mibgas prices are now trading well above TTF level. In October, the gap was reduced a bit, but that was because of TTF rising, and not Mibgas falling. And, despite the obligation for suppliers to balance their portfolios using the Mibgas spot market since October, volume has picked up only slightly. 

Spain is currently without a government that can fix this mess. On behalf of all gas consumers in the Iberian peninsula, we hope that the first thing a new energy administration will do, is book a flight to the North and see what simple but effective measures are necessary to make a gas market work. It is really very simple:

  • Make the whole country one entry – exit zone and give the responsibility for managing congestions to the transport grid operator (Enagas),
  • Create an hourly day-ahead market (Mibgas) that is adequately aligned with a balancing system (run by Enagas) that is as simple as possible,
  • Implement the use-it-or-lose-it principles that oblige owners of unused capacities to sell it to others.

And while they are there, they might look at power market regulations as well.

In the meantime, the Spanish gas buyers face difficult choices regarding their gas contracts:

  • In April / May / June, when Mibgas and TTF were close to each other, we saw some offers in the retail market that were very attractive, will such periods return? It’s more important than ever for buyers in Spain to follow up intensively what suppliers can offer.
  • When should you switch to Hub-indexed gas buying instead of oil-indexation? With the low liquidity and lack of forward products, financially swapping an oil-indexed formula to TTF is a better choice than Mibgas. Budget risk customers that need long term price stability can focus on the possibilities for savings and more agile price fixing of the new market realities. Market risk customers for whom energy pricing matters in terms of competitiveness should consider whether their competition is in Spain or in countries that have already switched to Hub-indexation. If you face foreign competition, you better consider a quick switch to Hubs. If you’re competing with Spanish companies, you have to decide whether you want to be a first mover or not.
  • Switches to Hub-indexation can come at different add-on costs, depending on the difference between oil-indexed gas and the Hub (TTF) at the moment that you make your contract. From that perspective, you should consider switching an oil-indexed formula in gradual steps towards TTF, which is a complicated hedging operation.

Natural gas is an important input to the economy. It is intensively used by base industries that are the cornerstone of many supply chains. Moreover, it has a lot of impact on electricity pricing. In Spain’s fuel mix, natural gas-fired power stations have the potential of being the marginal power stations, meaning that lower gas prices should result in lower electricity prices. Getting Mibgas fixed should therefore be an important priority for the next Spanish energy minister.


Sytuacja na światowym rynku węgla

By Ondrej ZichaEnglish version

W 2016 nastąpiła znacząca zmiana trendu w poziomie cen węgla. Po latach systematycznych spadków ceny węgla odbiły się w marcu tego roku, aby ustabilizować się na poziomie 60 dolarów za tonę (indeks API2, lipiec 2016). Ceny na takim poziomie widzieliśmy ostatnio ponad rok temu.


Źródło: opracowanie własne

Ceny węgla spadły o 70% od 2011 roku. Węgiel dostał łatkę ‘brudnego’ paliwa i zgodnie z popularną polityką dekarbonizacji został wyparty przez inne źródła energii. W sytuacji, gdy popyt spadał szybciej niż podaż, ceny systematycznie szybowały w dół do poziomu poniżej 40 dolarów za tonę w lutym i marcu br., dochodząc do progu rentowności wydobycia. Cały sektor dopadł poważny kryzys, gorącego okresu nie przetrwało kilka dużych firm amerykański Peabody Energy.

Co jednak przyczyniło się do odwrócenia trendu i wzrostu cen od marca tego Roku?

Chiny siłą napędową światowych cen węgla

Główną przyczyną odwrócenia trendu są zmiany w polityce gospodarczej Chin, które odpowiadają za ok. 50% światowej produkcji i zużycia węgla. W lutym br Chińczycy zapowiedzieli zamknięcie ponad 1000 kopalni do końca roku. Do likwidacji wyznaczono głównie małe kopalnie, które nie zapewniały odpowiednich warunków pracy. Dodatkowo w kwietniu ograniczono czas pracy w lokalnych zakładach o 16%.

Ograniczenie produkcji węgla powinno iść w parze ze zmniejszeniem zużycia surowca, ze względu na ekstremalnie wysokie zanieczyszczenie powietrza. Jednakże przestawienie się na inne bardziej ekologiczne paliwa to powolny i żmudny proces. Chiny mocno angażują się w rozwój odnawialnych źródeł energii, jednak chińska sieć przesyłowa wymaga dalszych inwestycji, żeby poradzić sobie z transportem niestabilnej energii odnawialnej.

Należy również ostrożnie podchodzić do tego co Chiny mówią i obiecują. Z jednej strony rząd zapowiada ograniczenie wydobycia paliw kopalnianych, z drugiej Greenpeace informuje o budowie kolejnej kopalni o mocy 400 GW, podczas gdy plan redukcji zakłada tylko 70 GW.

W krótkim okresie Chiny będą musiały importować więcej węgla (rokroczny wzrost w sierpniu wyniósł 52%), co z pewnością ucieszy wydobywców na całym świecie i ustabilizuje ceny węgla z powrotem na poziomie opłacalności.

Węgiel a sprawa polska

Rosnące ceny węgla to dobra informacja dla Polski, gdzie rodzimi producenci walczą o przetrwanie. W ramach ratowania sektora górniczego Kompania Węglowa, największy producent w UE, została przekształcona w Polską Grupę Górniczą. Wyższe ceny pomogą PGG w podtrzymaniu rentowności.

Z drugiej strony, nową spółkę dalej czekają problemy które obniżają jej konkurencyjność. Przede wszystkim, benchmarkem dla węgla wytwarzanego przez PGG jest polski indeks PSCMI1 (a nie API2 jak w przypadku rynków światowych). I jak możemy zobaczyć na poniższym wykresie, ceny węgla w Polsce jeszcze się nie odbiły, i od czerwca są one poniżej indeksu API2.

afb2Źródło: opracowanie własne

Kolejnym problemem są zbyt wysokie koszty wydobycia. Silna pozycja związków zawodowych nie pozwala kopalniom na redukcję szerokiego pakietu benefitów pracowniczych. Do uzyskania długoterminowej rentowności potrzebne będą bardziej radykalne zmiany niż czasowa likwidacja tzw. czternastek.

Perspektywy na przyszłość

Ograniczenia wydobycia węgla w Chinach doprowadziły do usztywnienia podaży w niektórych regionach co skłoniło rząd w Pekinie do rozluźnienia regulacji. W przypadku niewystarczającej podaży węgla lokalne kopalnie mają pozwolenie na zwiększenie produkcji. Jest jeszcze za wcześnie, aby stwierdzić czy ogólny trend cenowy znów odbije w dół po tej decyzji, jednocześnie mała korekta była widoczna w ostatnich dniach.

Nie ulega wątpliwości, że Chiny są główną siłą napędowa światowych cen węgla i jedną decyzją polityczna potrafią zmienić sytuację na rynku globalnym.

What is moving the coal market?

By Ondrej Zicha – Polish version

2016 could be a year marked by the trend reversal of world coal prices. After years of steady decline, coal prices rebounded in March. In October, API2-prices event hit the level of 65 dollar per tonne, a level last seen one and a half years ago.


Source: Own study

Since 2011, coal prices lost more than 70%. Coal was marked as a “dirty” fuel and in line with the wide spread policy of decarbonisation, other energy sources were preferred. This made demand decrease faster than supply, so prices continuously went down to reach levels below 40 dollars per tonne in February and March this year. These prices made it difficult for miners to be profitable, endangered the entire sector and even caused bankruptcy of some big players like Peabody.

China drives world coal prices

Changes of the Chinese policy are the main reason for the price rebound. China takes about 50% of both worldwide production and consumption. In February, Chinese officials announced the country will close more than 1000 coal mines before the end of year. The mines on the list were mostly rather small ones and had to be closed because of inadequate working conditions. In April, this decision was followed by another one limiting the number of working days in local mines by 16%.

Limiting the coal production should go hand in hand with decreasing coal consumption, as China is pushed to do so because of extremely high air pollution. However, changing to other more ecologically friendly fuels will take some time while mines will already be closed at the end of this year. China is now investing a lot in renewable sources but these investments need some time to be realised. Additionally, some analysts remark that the current grid system is not prepared for more and potentially unstable renewable sources and therefore requires further investments.

On top, we should take into account that China has proven its statements to not always be 100% correct. China claims it’s abandoning fossil fuels, but according to Greenpeace’s report published in July, the country is currently building another 400 GW of installed coal capacity while the shutdown is only 70 GW.

This means China mainly needs to import more coal in the short term (year-on-year increase in August was 52%), which brought coal prices back at profitable levels and is good news for coal miners all around the world.

Situation in Poland

The rising coal prices are great news for Polish miners as they are struggling with serious problems. Kompania Węglowa, the biggest coal producer in the EU was restructured to Polska Grupa Górnicza (PGG) in order to save the Polish coal sector from bankruptcy. The higher coal prices could help the company to stay alive in a tough market.

On the other hand, the new company is still facing many difficulties which decreases its competitiveness. First of all, the benchmark price index for coal mined by PGG unfortunately is the Polish Coal Index PSCMI1 (not the API2 like on other European markets). However, the Polish index usually follows the European benchmark but this hasn’t happened (yet). As we can see on the graph below, the polish coal prices are even below the API2 index since June.


Additionally, PGG is still struggling with too high mining costs. The unions have a very strong position in the Polish coal sector and generally are not willing to reduce the non-standard benefits of workers in the mining sector. Despite some positive changes in the last months like a temporary suspension of 14th month salaries, further and more radical changes are necessary to make PGG fully competitive.

Outlook for the future

Mining restrictions in China led to tight supply in certain regions. As a consequence, the Chinese government last month decided to ease the mining restrictions. In case of problems with supply, local mines would be allowed to increase production to meet demand. On top, the limited working days in the most efficient Chinese mines could be eased as well. However, this was not confirmed by the Chinese officials and for the time being, the market isn’t taking this into consideration.

Seeing the above, we can only be sure about one thing – China is the main driver of coal prices at this moment and any political decision there can impact the market situation.

Payment day for nuclear addiction in France

French year ahead baseload power ended the day yesterday at 39,9 euro per MWh, backing off from the 42,5 euro per MWh peak that it reached one week ago. The price increases came amid worries over next year’s power supply. Today (12th of October), 37% of France’s nuclear production capacity is shut down due to safety probes. With 76,9% of France’s electricity in 2015 produced with nuclear power stations, it is normal that markets worry when a supply crisis looms. Moreover, the fears are exacerbated by shortages of hydropower stocks due to dry weather. With 9,48% of all power production in 2015, hydro is France’s second source of power production. Stocks currently stand at 68,3%, the lowest level for the time of the year since 2010.

France is addicted to nuclear power. Only the US produces more energy from atoms and no country comes anywhere near the high percentage of power production through nuclear. This addiction has been a deliberate choice. It was France’s answer to the oil crisis of the 1970’s. Ever conscious about its role in this world, the French prime minister Messmer estimated that nuclear was the safest option to reduce resource-poor France’s dependence on energy imports. This was summarized in the slogan: “France is poor in oil but rich in ideas”. The nuclear ideas were sold to the population by offering them cheap prices, hiding the real costs of nuclear through massive subsidies to state-held nuclear champions EdF, the producer of the energy, and Areva, the builder of the power stations.

Recently, public opinion and politicians, mainly from the currently governing socialist party, have turned somewhat against nuclear power. After the Fukushima disaster, it is clear that nuclear energy isn’t as safe as promised. The exact harm caused to man and nature by Fukushima is a source of intense debate. But if you take into account the 196 billion dollar clean-up bill estimated by the Japan Center for Economic Research in March 2012, it is clear that the risks should not be underestimated. Moreover, it is a myth that nuclear power is cheap. France is currently building a new nuclear power station in Flamanville. On top of massive delays, the project is suffering a threefold overrun of its original budget to 10,5 billion euro. The French government, hoping to build similar EPR-reactors all over the world, is swallowing that bill. But even EdF admits that nuclear power is far from cheap, as it negotiated a 92,5 pound per MWh guaranteed price with the British government to build a new nuclear power station at Hinkley Point. That is more than twice as high as the price paid for year ahead baseload power in the UK at this moment. And three times more than the price paid for year ahead power at its lowest point earlier this year.

Maybe one day we will name Flamanville as the project that killed the nuclear industry. For not only have its overruns of budget and project time proven the flawed economics of nuclear. It also sparked the safety concerns that put serious questions regarding a third pro-nuclear argument: its reliability. Carbon concentrations were discovered in the steel used to build its pressure vessel, and it is feared that these could cause integrity issues that result in nuclear disaster. Alarmed by this, the French nuclear safety authority has ordered probes in 18 reactors causing the shutdowns that currently rattle the markets. This safety issue is a worrying reminder of the situation in the Belgian nuclear power stations in the last years, where similar worries about vessel integrity caused on and off shutdowns resulting in sharp price spikes during 2014 & 2015. Prices were not just higher but also more volatile and unpredictable, causing many Belgian energy buyers to make “mistakes” by panic buying on the peaks. Recently, the French power price has risen high above the German and Belgian prices in similar sharp spiking activity.


The comparison of German and French power prices is also showing that Germany has become structurally cheaper in the last four years. Anyone that had predicted this in 2011 would have been called a nutcase. Germany announced its plans for a quick shutdown of nuclear power plants. Everyone expected this to result in higher pricing. The contrary happened. Now, I do acknowledge the role of lower coal prices in this. But even now, when coal prices have recently increased by more than 50%, German power is still much cheaper than French. Germany has heartily embraced the renewable energy revolution. This has caused high add-on costs for paying back the subsidies granted to the many windmills and solar panels that were built. But it also resulted in structurally low commodity prices.

The new energy market reality shown in Germany is one of decentralized production spread over a multitude of technologies in small power stations. That contrasts sharply with France’s addiction to large, centralized power production with the one nuclear power technology. Today’s situation is confronting France with the vulnerability and reliability issues of this old market model. Market situations are always changing, so the current situation could reverse in the future, near or distant. But in any case, what happens now in France’s power market should cause politicians in France and other countries to rethink energy policies that bet on nuclear. For consumers of energy in France, difficult times lie ahead. We don’t want to think about what would happen if the carbon concentration issue would turn out to be a genuine safety risk and the current situation becomes permanent. But even if this issue is just the proverbial storm in a teacup, the Belgian situation has proven that due to the scientific complexity surrounding nuclear power, such storms can last a very long time. And as France is an important powerhouse, producing 17,3% of all EU electricity in 2015, surrounding markets will continue to be affected as well.


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!

Will the Polish capacity market stimulate new investments?

Read the Polish blog here. Written by Wojciech Nowotnik.

The last couple of weeks there’s been a debate on whether a capacity market needs to be created in Poland. At the beginning of July, the Ministry of Energy published a few suggestions to implement this capacity market. The main question is whether the capacity market as it’s outlined by the Ministry of Energy will stimulate new investments in stable production capacity to increase the energy security in Poland.

Let’s start with a brief recap. Support for investments in conventional power plants in Poland is nothing new. Do you remember how in the early nineties the Polish energy was in need of intensive modernization to reduce greenhouse gas emissions? A relatively simple mechanism was introduced: the long-term contract, called KDT (Kontrakt DługoTerminowy – Long Term Contract). This kind of support was simple and beneficial for the investor. After Poland entered the European Union, the KDT had to be changed because it was seen as unlawful state aid. The KDT became a transition fee as of 2008, a part of the distribution costs.

In August last year, the so-called power stages were introduced to significantly relieve the power system in Poland. This revived the discussion on the promotion of investment in conventional generation sources.


As you can see on the image above, the available capacity and demand are almost at the same level. This is a clear sign that similar problems might occur in the future. Therefore, other solutions need to be introduced in order to have a more stable national power system. Some other European countries are in a similar situation but the risk of supply constraints isn’t that significant as it is in Poland at the moment.

This is exactly why the Ministry of Energy worked on functional solutions for a capacity market in cooperation with experts from PSE SA. The document says they want to ensure the continuity and stability of electricity supplies to all end-users in the country on a long term. The project is largely based on the concept of the capacity market in the UK.

The proposed system assigns one party that is obliged to determine the size of the power demand and needs to organize the purchase of this amount of power based on . The asking price will be gradually lowered and the winner will be the one who offers the lowest rate.

Below you can find the schedule of processes on the capacity market.


Source: Ministry of Energy

Unfortunately, the example of Great Britain shows us that this solution does not guarantee investment in new blocks. According to the blog of Professor Świrski only 5% of the funds will be invested in new gas-fired units and the vast majority will support the old coal-fired plants to continue to be maintained.

In my opinion, it’s a pity that the solutions were only based on the national system without having a look at the opportunities of cross-border trading. As well, solutions providing Demand Side Response are only marginally treated. I also share the opinion of different commentators that point out that the capacity market as currently proposed might be considered as unlawful state aid. My last and most important remark concerns the cost for introducing the capacity market. ClientEarth’s analysis says that the capacity market based on the current proposal would mean an additional cost of 80 to 90 billion polish zloty (20 to 22 billion euro) between 2021 and 2030. The average energy bill would increase by 30%. The project only shows settlement mechanisms without providing any cost simulations. It seems like the Ministry of energy tries to solve the problems of the Polish energy sector by duplicating the mistakes of other EU countries.

In 2014 Benedict De Meulemeester, founder and owner of E&C Consultants, published an article about the capacity market: Capacity payments: expensive solution for a non-existing problem. At the end of the blog article, a more fair, cost-efficient way without unnecessary increases of energy prices for consumers is proposed:

  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.
  4. Support demand side management where it is realistic.

If you analyse both the project above and other legislation on the energy market in Poland (such as the law on the construction of wind farms) it seems like the actions of Minister Tchórzewski are exclusively focussed on supporting the Polish coal industry.

Prior to signing the “Windmills Act”, the Energy Minister said “there is a need for less of this renewable demagogy”. I would say there’s a need of less of this coal and bureaucratic demagogy.