Dealing with unpredictability in energy trading

When buying energy, you inevitably have to take energy trading decisions. In deregulated electricity and natural gas markets, the commodity value of the energy is linked to the underlying wholesale markets. On these over-the-counter (OTC) and exchange traded markets, the price of energy moves up and down. Buying energy means taking decisions on whether to fix the price or not and if you fix, whether to do it today or tomorrow. In volatile markets, these decisions can cause large variations in your energy costs.

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Most buyers of large volumes of energy have clearly understood that the timing of your price fixings is the most important factor determining how much you will pay. They have put in place contracts with suppliers that offer them flexibility for the fixing of the wholesale value, contracts that allow you to fix in different moments on the different forward products and/or leave volumes open for spot indexation.

In most mature deregulated energy markets, the users are well accustomed to working with such products. But in countries where the deregulation is more recent, we still find that many industrial consumers have resistance towards this energy trading activity. They call it “speculative”, confusing trading with speculation. Energy trading is an inevitable component of buying energy in a deregulated market. You have to take decisions on whether you fix your prices or not in a market that moves up and down. That’s trading, whether you like it or not.

As trading is not a natural environment for industrials, we see many of them struggling to find the right approach to it. This struggle has a lot to do with people’s attitude to unpredictability.  Energy markets are unpredictable. 95% of the energy buyers that we talk with acknowledge that.

5% of the buyers: you can predict energy prices

5% don’t. They think that you can ‘crack the code’, that there are mathematical laws determining the movements of energy markets. That you can unveil these laws and use that mathematical information to take decisions on whether to fix or not.

The popular argument for debunking that illusion of predictability is simple. If you would have cracked the code for predicting energy prices, why would you be an energy buyer? You would much better become a real trader, buy and sell speculative volumes and earn yourself a villa in the Bahamas. And any consultant or portfolio manager that has a forecasting that actually works would be very stupid if he or she sells it to an industrial client for a few thousand euros or dollars.

Energy markets are unpredictable. The supply and demand equation is extremely complex. The number of variables is very high and the interactions between them are not simple causal relationships. Most forecasting models are based on mathematic wizardry that unveils correlations. However, analysis shows that these correlations change over time, so a current correlation cannot be used to predict the future. Moreover, even if a correlation would be constant, e.g. between the price of electricity and natural gas, this knowledge doesn’t help you very much. It just tells you that one unknown factor (the future electricity price) is correlated to another unknown factor (the future gas price).

On top of this, energy markets can be shaken by unexpected events. Some of those noticed in the recent past: the shutdown of nuclear power stations in France due to security issues, the impact on worldwide energy markets of the Fukushima nuclear disaster or the shale gas revolution in the US. Anyone claiming that she/he can predict energy markets, is claiming that she/he can predict such events.

Best case, forecasts are right 50% of the time. Therefore, they are not a solid basis for taking your energy trading decisions. And if your energy buyer believes in forecasting, she or he is a danger to the financial health of your company. One day, she or he will take a decision based on a wrong forecast that makes your company buy energy on the wrong side of the market.

10% of the buyers: you can’t predict energy prices, so you shouldn’t trade energy

10% of the energy consumers accept the full consequences of this unpredictability. They choose to delete deliberate trading decisions from their energy procurement practices. They link their energy prices to the spot price, to an average forward price or buy at randomly chosen moments to produce an average price. We have a client, for example, that fixes the price for 1/24th of the expected consumption in each of the next twelve months on every 10th and every 21st of the month.

You will find this hands-off approach most often with very large consumers. If you are consuming Terrawatthours of electricity and/or gas, every decision to fix or not is a matter of millions of dollars or euros. Many companies decide that the energy buyer is not the appropriate person to do that. So they either set up a real trading desk, or they go for automated buying. We also observe that hands-off is much more popular among US companies.

E&C supports clients that want to set up a system for price averaging or automated buying decisions. The main challenge for them is to find an average that is in line with their risk exposure. Are they a budget risk customer that is mainly affected by large year-on-year cost increases? Then they should set up a system of automated buying for three or even more years in the future. Are they a company that can see its competitiveness affected by having a higher energy cost than competitors? Then they should find out how rapidly the prices of their products adapt to energy price changes and set up automated buying in line with it.

Nevertheless, giving up the taking of deliberate decisions to fix or not, is a bit of a pity. The large majority of E&C’s customers have a hands-on approach in which they take decisions based on energy risk management instead of forecasting. We see a lot of business value in that approach.

10% of the buyers: you can’t predict energy prices, but you can create business value by actively managing your prices

Active energy price management means that you adopt the following approach:

  1. You analyze the impact of energy market volatility on your business and implement a strategy that mitigates the risks. This strategy will not determine when you buy, but it will determine how much you buy how far into the future. If your main risk is a large increase of energy costs (i.e. budget risk), you buy larger volumes for many years into the future. If your main risk is a loss of competitiveness by having fixed at a higher level than the market (i.e. market risk), you buy very regularly and buy only small extra portions in opportunity moments. How far you buy in the future is determined by the pace at which prices for your products adapt to changes in energy costs. This approach can be further finetuned with budget-at-risk calculations and price fixing tables with minimum and maximum levels up to which you should / can fix before certain dates.
  1. To determine when you buy, you follow the markets. This market analysis is not aimed at forecasting. You don’t look at fundamental and technical information to try and forecast what the price will do in the future, you are only interested in what it is doing now. When the markets are falling, you don’t do anything. You only buy when the market has turned around after a period of falling prices. We call this “buying the dips”.
  1. But of course, markets don’t fall and rise in straight lines, they go down a few days, have a little uptick, than fall again, rise again, etc. This means you are constantly confronted with a dilemma: is this the definitive turnaround of the market or just a temporary uptick? Most buyers are solving this dilemma with forecasting. They look for information that predicts whether the market will continue to rise or whether it will fall again. Sometimes (best case: 50% of the time), they will get it right. But in all other cases, they will either buy too much on a temporary uptick or miss the definitive turnaround.

An energy risk management approach to buying energy means a totally different approach to the uptick versus turnaround dilemma. When making a price fixing decision, you should adopt a 50/50 approach. The chances that markets fall again the next day are exactly as high as the chances that they will continue to increase. This will inspire you to fix prices prudently, step by step. Let’s say that your energy risk management policy allows you to fix up to 50% of an annual volume in a certain moment. You could carve this up in four 12,5% tranches. When the market turns around, you fix a first 12,5% tranche. If it continues to go up, you fix another 12,5% tranche, and so on until 50%. If it drops again, you don’t fix anything and you have only 12,5% fixed on a temporary uptick.

This active energy price management approach produces excellent results. It allows a company to achieve pre-defined energy risk management goals. And because you make your fixings when markets turn around and not in the middle of downtrends, you’ll produce good results versus the market. A disciplined application of energy risk management, always spreading decisions and never make too large fixings because you think you know where the market is heading, will avoid energy trading disasters.

Hands-on active energy price management is definitely a great solution for budget risk customers. They can visualize their commodity costs for energy in the next years and then take the price fixing decisions based on goals, e.g. in a rising market: don’t let your cost increase by more than 10%. Or in an opportunity moment: cement a budget reduction by buying forward. For a budget risk client, this is a better approach than hands-off as you take your future costs in your own hands rather than let them randomly depend on how the market average prices you are buying are moving.

You can take your energy trading to a next level by adding an extra tool to your active energy price management toolbox: the selling of previously bought forward positions. If well-executed, this can definitely lead to great results, but it’s not the miracle solution that many consultants and portfolio managers try to sell you. Moreover, if you adopt the buying and selling approach with forecasting, you are doubling the financial impact of the 50% cases in which the forecasts are wrong (best case).

For market risk customers, the hands-off approach is excellent for achieving the main energy risk management goal, i.e. never have a price high above the market average. Active energy price management for them means the buying and selling of small extra volumes in opportunity moments in an attempt to do better than those market averages. It’s up to every company to decide whether to go that extra mile or not.

75% of the buyers: you can’t predict energy prices, but I want a forecast when I take an energy trading decision

 Like we’ve said, there is only a very small fraction of the energy buyers that we talk to that believes you can predict future energy prices. However, a large majority of them cannot imagine that they take decisions to fix, not fix or unfix without some kind of forecast. This makes no sense. Why would you base your decision-making on a technique of which you acknowledge yourself that it doesn’t work?

The use of forecasts is deeply embedded in the business world. It has its roots in deterministic economics. Economists try to upgrade their science by making it look as exact as physics or mathematics with laws that produce correct predictions again and again. This branch of economics is often taught in business schools. And it is sold to businesses by consultants in the shape of forecasting services. They are either based on the guru status of the consultant or on a sophisticated-looking mathematical model.

Albert Einstein taught us that even in physics forecasting will not always work (I’m not going into the details of quantum physics to explain this). And in mathematics, we have chaos theory. It still believes in a deterministic physical reality, there is a set of initial conditions that determines the outcome. But this reality is so complex that it is impossible to trace that chain of causal effects. The butterfly effect describes how a small change that is impossible to trace can have large consequences. A butterfly flapping its wings in the forest in Brazil can cause a tornado in Texas.

The butterfly is an excellent metaphor to illustrate the complex, chaotic environment of energy markets. Forecasting systems will invariably over-simplify this, leading to wrong forecasts. But as human beings, we are so allergic to the uncertainty of unpredictable chaotic environments like energy markets that we keep buying the false certainty of forecasting.

I think about a recent meeting with the energy buyer of an international food company. He told how every month their board had a presentation by a professor that gave his vision on the world economy and how it would affect pricing of diverse commodities. Decisions to hedge were then based on that vision. So, we commented: “if the professor gets it wrong, the economic health of a company with thousands of employees will be affected”. “He is very clever, he gets it right most of the time”, was the energy buyers’ answer …

I also think about other meetings during which energy buyers’ acknowledge that forecasting doesn’t work. However, they buy forecasting services and base their energy trading decisions on it, because then they know why they took wrong decisions … Some even said: “we then have a consultant to whom we can transfer the blame” … I’m sorry, I’m a consultant that respects his job and I will never sell myself as a scapegoat.

It’s all the more sad that so many energy buyers keep holding on to forecasting even if they know that it doesn’t work, because they don’t need it. The active energy price management approach described above produces excellent energy trading results. It is simply a much more rational approach to buying energy than holding on to the false certainty of forecasting. It’s E&C’s mission to convince large energy consumers of that and help them to implement an energy trading practice that is not based on false forecasting.

More information on how to deploy buying and selling can be found here or contact benedict@eecc.eu for receiving our whitepaper on this topic.

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 https://www.energy-charts.de/power_inst_de.htm. 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.

omie vs eex.png

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.

ttf-mibgas

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.

omie vs eex.png

However, Germany has an even higher percentage of renewable power production capacity: 52,43% according to data of https://www.energy-charts.de/power_inst_de.htm. 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.

ttf-mibgas

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.

Is the world ready to grow its economy without increasing energy demand?

It is a strongly imbedded belief in the world of energy analysis that demand for energy can only grow. In terms of energy procurement, this leads many buyers to bullish biases, making them buy too soon or at high price levels, as they believe increasing demand will make prices rise. However, as commented earlier on this blog, we have recently seen a slowdown of the growth of worldwide energy demand. It’s true of course that the last decade hasn’t excelled in terms of economic growth. However, in many parts of the world now, an extra percentage of GDP doesn’t necessarily mean an extra percentage of energy use. In 2015, the world’s primary energy consumption grew by just 1%, whereas GDP, according to the World Bank, grew by 2,47%. Have we cracked the code and can we – as of now – increase our economies without using ever larger quantities of energy? Or will a next phase of strong economic growth come with an acceleration in energy consumption growth again?

afb1

Fig. 1: Primary energy consumption in the world (Source: BP Statistical Review)

The graph on the world’s primary energy consumption is showing us how during 2000 – 2007 strong economic growth came with large extra quantities of energy. The economic crisis of 2008 & 2009 brought that down sharply, only to be followed by a record year-on-year increase in 2010 as particularly China – the world’s largest energy consumer – revived quickly. But then the energy growth started to slow down. Last year, worldwide primary energy consumption grew by just 1%.

It should be clear that not all parts of the world are equally contributing to this reduction in energy voraciousness. As can be seen from the graphs below, the traditional economies in Europe and Northern-America have been in the lead. In the European Union, we even see a clearly declining trend that started in 2006, which is before the striking of the economic crisis. This is the moment that many energy efficiency programs devised in the framework of Europe’s climate policy have come into effect and I believe that there is a clear causal relationship here. In North-America, energy consumption in 2015 was at the same level as in 2000. US primary energy consumption in 2015 dropped 0,9% compared to 2014, despite a 2,4% increase in GDP.

(Regarding Europe, critical observers might remark that there has been an increase in EU consumption in 2015 – to which I would respond that this was a year with cold winter weather.)

afb2

Fig. 2: Primary energy consumption in different parts of the world (Source: BP Statistical Review)

The lines on the right hand side don’t show much slowing-down of the hunger for more energy in the emerging economies. However, in China e.g., energy consumption grew by just 1,5% last year, which is far below the 16,6% and 17% that we saw in 2003 and 2004. On the one hand, this slowdown in hunger for ever more energy can be explained by the mechanics of economic development itself. In the first phase of its economic development, growth in a country like China came from the growth of basic, energy-intensive industries such as steel production, causing energy demand to go up quickly. On top of that, the growing middle classes started to enjoy energy-consuming luxuries such as cars, a larger house, air-conditioning, frozen foods, etc. However, once a certain level is reached, further economic growth comes from less energy-intensive industries and services and the middle class stops to grow, causing the growth of energy consumption to slow down. But could it be a deeper trend, and is the world starting to copy Europe’s example of consciously improving its energy efficiency?

When I talk to people around me, I observe that most of them don’t realize at all what a revolution they’ve gone through in their daily lives in terms of energy efficiency. To just name a few examples:

  • Cars have drastically improved their fuel efficiencies,
  • In lighting, we’ve moved from the lighting bulb to energy-saving lighting bulbs to LED-lighting, meaning that we now have the same amount of light using less than 10% of the energy that we used 15 years ago,
  • Insulation regulation has reduced the amount of energy that we use to cool or heat our houses,
  • Walking into electro shops, we are now looking at the energy efficiency labels, inspiring us to buy new fridges, microwaves, vacuum cleaners, etc. that use much less than the ones we throw away,
  • The boilers that we use to heat our houses are now super-efficient top technology,

And not just households have reduced their energy consumption. If I look at our clients, mostly large industrial users, all of them are running energy efficiency programs, inspired by government regulations, demands by clients and other stakeholders or just environmental consciousness. Implementing more efficient technology and practices, they have all reduced the energy-intensity of their production. And many of them are not only reducing energy consumption in relative (MWh per ton) terms, but also in absolute MWh per year terms.

It is true that the effects of more efficient technology, appliances using less energy every time we use them, has partly been undone by the fact that we use them a lot more. We drive our cars more often, take more flights, light up every building with LED’s, etc. This leads pessimists to disbelieve that technological improvements are not a solution to our energy problems. What has happened in the EU in the last decade, has proven them wrong. We can grow our economies and enjoy the luxury of a well-lit building or smoothly-driving car without increasing the overall amount of energy that we use. The next years should show whether this can be imitated and turn the slow-down of energy demand growth in other parts of the world into a decline as well.

You can still subscribe for the second leg of our Transatlantic Energy Conference 2016 in Chicago over here: http://bit.ly/TEC2_US 

Czy Polska potrzebuje rynku mocy?

Written by Wojciech Nowotnik. The English version will be published later today.

W ostatnich tygodniach toczy się dyskusja nt. konieczności utworzenia rynku mocy w Polsce.

Ministerstwo Energii zgodnie z wcześniejszymi zapowiedziami opublikowało na początku lipca Projekt Rozwiązań Funkcjonalnych Rynku Mocy.

Czy wprowadzenie rynku mocy w kształcie zarysowanym przez Ministerstwo Energii faktycznie sprawi, iż pojawią się nowe inwestycje w stabilne moce wytwórcze zwiększające bezpieczeństwo energetyczne w Polsce?

Zacznijmy jednak od krótkiej genezy. Wsparcie dla inwestycji w konwencjonalne elektrownie nie jest w Polsce niczym nowym. Wielu z nas pamięta jak na początku lat 90-tych polska energetyka wymagała dużych nakładów modernizacyjnych zmierzających do ograniczenia emisji szkodliwych gazów. Wprowadzono wówczas stosunkowo prosty mechanizm tzw. Kontraktu Długoterminowego potocznie nazywanego KDT. Taka forma wsparcia była przede wszystkim prosta i korzystna dla inwestora. Polska musiała jednak po wejściu do Unii Europejskiej rozwiązać KDT-y, gdyż stanowiły one niedozwoloną pomoc publiczną. Ich pozostałością od 2008 roku jest opłata przejściowa umiejscowiona w kosztach dystrybucji energii elektrycznej.

Dlaczego dyskusja nt. wspierania inwestycji w konwencjonalne źródła wytwarzania odżyła?

Wielu z nas z pewnością pamięta sierpień zeszłego roku, kiedy to po raz pierwszy od kilkudziesięciu lat wprowadzono w Polsce stopnie zasilania, które miały na celu znaczne odciążenie systemu elektroenergetycznego w Polsce.

 

1Źródło : Opracowanie własne na podstawie danych z PSE

Jak widzimy na powyższym wykresie moc dyspozycyjna względem zapotrzebowania niemal się pokrywa. Jest to istotna przesłanka do występowania podobnych problemów w kolejnych latach.

Nieuchronne jest wprowadzenie rozwiązań, które doprowadzą do zwiększenia stabilności w krajowym systemie elektroenergetycznym. Podobna sytuacja dotyczy również innych krajów europejskich, jednak znaczne ryzyko ograniczeń dostaw występuje obecnie tylko w Polsce.

W ten oto sposób dochodzimy do Projektu Rozwiązań Funkcjonalnych Rynku Mocy opracowanego przez Ministerstwo Energii przy współudziale ekspertów z PSE S.A.

„Celem Ministra Energii jest zapewnienie ciągłości i stabilności dostaw energii elektrycznej do wszystkich odbiorców końcowych na terenie kraju w horyzoncie długoterminowym” – możemy przeczytać we wspomnianym dokumencie.

Projekt w dużej mierze bazuje na założeniach rynku mocy w Wielkiej Brytanii.

Minister Energii proponuje system zcentralizowany, w którym jeden podmiot ma obowiązek określenia wielkości zapotrzebowania na moc i zorganizowania zakupu mocy w trybie aukcji holenderskiej, gdzie cena wywoławcza stopniowo jest obniżana i wygrywa ten, kto zaoferuje najniższą stawkę.

Harmonogram procesów rynku mocy:

3Źródło: Ministerstwo Energii, Projekt rozwiązań funkcjonalnych rynku mocy, wersja 1.0, Warszawa, 4.07.2016, http://www.mg.gov.pl/node/26170.

 

Przykład Wielkiej Brytanii pokazuje nam jednak, że wprowadzenie takiego rozwiązania nie gwarantuje inwestycji w nowe bloki. Jak możemy przeczytać na blogu Profesora Świrskiego tylko 5% środków zostanie zainwestowanych w nowe bloki gazowe a zdecydowana większość będzie stanowiła wsparcie dla starych bloków węglowych, aby nadal były utrzymywane w ruchu.

Jedną z zasadniczych wad projektu ME w moim odczuciu jest bazowanie wyłącznie na krajowym systemie z pominięciem możliwości związanych z połączeniami transgranicznymi.

Ponadto marginalnie potraktowano jednostki zapewniające DSR (Demand Side Response), czyli potencjał odpowiedzi popytu.

Podzielam również opinię niektórych komentatorów, którzy uważają, że założenia projektu ME mogą być niezgodne z unijnym prawem. Rynek mocy w zaproponowanej formie może być uznany za niedozwoloną pomoc publiczną państwa.

I wreszcie ostatnia i dla wszystkich z pewnością najważniejsza kwestia dotycząca kosztów wprowadzenie rynku mocy. W analizie prawnej i ekonomicznej przygotowanej przez organizację Client Earth Prawnicy dla Ziemi czytamy, że rynek mocy w obecnej propozycji oznaczałby nałożenie na odbiorców końcowych kosztów rzędu 80-90 mld zł w latach 2021-2030. Według Client Earth przeciętny rachunek za energię wzrośnie o około 20%.

Niestety projekt ME pokazuje jedynie mechanizmy rozliczeń bez podawania jakichkolwiek symulacji kosztowych. Dlatego też trudno się do tego odnieść.

Konkludując wygląda na to, że ME zamierza rozwiązać problemy polskiej energetyki powielając błędy innych państw unijnych.

Samo wprowadzenie podobnych rozwiązań w innych krajach unijnych nie jest dla mnie wystarczającą argumentacją.

W 2014 roku Benedict De Meulemeester – założyciel i właściciel E&C – opublikował artykuł nt. rynku mocy: Opłaty za moc: drogie rozwiązanie dla nieistniejącego problemu (tytuł oryginału: Capacity payments: expensive solution for a non-existing problem).

W końcowej części tego artykułu możemy przeczytać 4 punktową receptę rozwiązania problemów związanych z opłatami mocowymi osiągając wydajniejszy kosztowo i bardziej transparentny sposób zmniejszania niedoborów mocy przy jednoczesnym unikaniu podnoszenia cen energii dla odbiorców końcowych:

  1. Kontynuacja polityki klimatycznej w celu zmniejszenia zużycia energii.
  2. Rozwój transgranicznego handlu energią i wspieranie takich inicjatyw jak market coupling.
  3. Kontynuacja wsparcia dla OZE, zwłaszcza w obecnej sytuacji, gdy spadły koszty inwestycyjne (…)
  4. Wspieranie zarządzania popytem tam, gdzie jest to realne.

 

Czytając Projekt rozwiązań funkcjonalnych rynku mocy Ministerstwa Energii jak również analizując nowe akty prawne dotyczące rynku energii w Polsce (np. Ustawa o budowie farm wiatrowych) mam nieodparte wrażenie, że działania Ministra Tchórzewskiego skupione są wyłącznie na wsparciu polskiego sektora wydobycia węgla.

Parafrazując słowa ministra, który przed podpisaniem „ustawy wiatrakowej” przez prezydenta stwierdził, iż „trzeba mniej tej demagogii odnawialnej” chciałoby się powiedzieć: mniej tej demagogii węglowej i biurokratycznej…

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.

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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