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.

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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.

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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.

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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.

 

 

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?

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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.)

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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 

A decade of low energy prices?

Written by Benedict De Meulemeester

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

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

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

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

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

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

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

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

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

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

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

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

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Go long or go short?

Written by Bart Verest

“I think we should buy all of our electricity and gas needs for next year’s delivery because I’m risk averse and don’t want to miss this opportunity”. It’s a statement I’ve heard quite often in the past few years. Sometimes, it’s followed by the reaction of another stakeholder who, on his end, wants to “take some risk and leave volumes open on the spot market”.
This example brings two important risks to the surface when buying energy.
Sometimes the personal appetite for risk is projected on the company the buyer is working for. In itself this is a natural reflex – people use their personal experiences and vision to perform their job. Nevertheless, it is important to keep a clear line between your personal preference and the interest of the business. Only then will you be able to set up a successful procurement strategy that aligns with the risks and interests of your company. If due diligence matters to you, then you should focus on the interests of your company rather than on your own personal beliefs or risk appetite. Putting your agenda ahead of that of your company can harm both you and the business in a personal and financial way.

We often see that the personal definition of risk is equated with the definition of risk for the company. On one hand, you will have people who see volumes floating on the spot market as a risk because of the unpredictability of spot pricing. On the other hand, you will have people who argue that hedging forward volumes is a speculation on the future price evolution and that a buyer shouldn’t speculate on this. In themselves, both statements are incorrect. Whether or not hedging volumes / leaving volumes open on the spot market constitutes a risk depends on the business model of the company. To explain this a bit further, I can take extremes on both sides of the spectrum as an example. On one side you have company A that makes long-term pricing arrangements with its clients. In order to do this, they look some three years ahead and estimate all costs to determine the final product price they will agree on. Their energy cost is naturally included as part of their calculations and therefore has to remain stable for the next years. If they end up with a price that is higher than the one they agreed upon, they lose margin. In this case, leaving (too much) volumes open on the spot market is rightfully considered a risk because it represents a mismatch between their pricing model and their business model. On the other side you have company B that meets every quarter with their clients to agree on a product price for the next quarter. In these quarterly agreements they have clauses where they pass-through the energy cost. If they fix prices for the next three years and the energy markets drop, they will lose margin as their clients force them to lower the prices they charge for their products. In this case, it’s buying (too much) volumes on the forward market that represents a mismatch between their business and pricing model.

Therefore, answering the question “go long or short” should have nothing to do with the personal convictions of the energy buyer regarding future prices or his/her appetite for risk. It should be based on a long-term energy buying strategy that aims to reduce the impact of energy market volatility on a company’s bottom line. In my presentation at this year’s “Transatlantic Energy Conference”, I will give practical examples of how companies from many different industries managed to take control over their energy costs by setting up such a strategy.

Click here to register for Amsterdam: https://www.eventbrite.com/e/transatlantic-energy-conference
Click here to register for Chicago: https://www.eventbrite.com/e/transatlantic-energy-conference-2-united-states-tickets-21030478728

 

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…

Managing data on a global energy portfolio

By Magdalena Stępniak

According to Experian’s 2016 Global Data Management Benchmark Report, 84% of businesses believe that data is an integral part of forming a business strategy. This is a far cry from the reality of a few decades ago, when data management only contributed to operational efficiency. Today, data management has become the basis for strategic decisions involving millions of euro, dollars, and pounds.
But what kind of challenges lie ahead for all the big companies that need to work with data? Almost a quarter of the data gathered around the world is believed to be inaccurate. In big organizations, data is often scattered around, with no central point of management. When there is a central point, the data is usually concentrated in the hands of IT people. This presents a clear challenge: how do you manage data if your facilities are located in different countries around the world? How do you follow and comply with all the different energy specific regulations and tariffs across the globe?
Let the figures speak for themselves – if your company has just one plant in one country, buying two commodities – how does that translate into data? For this site alone, you are looking at 2 contracts, with a minimum of 4 price fixing confirmations and 24 invoices from two suppliers over a 12-month period -which each include with a minimum of 10 line items per invoice. That brings us to a minimum of 246 data entries per year – not to mention the thousands of measurements for natural gas and electricity. Multiply 246 by 10 sites and 20 connections points and you already have 4,920 data entries. If you add country-specific price structures, wholesale markets, different suppliers and local regulations for grid fees and taxes, you can end up with a mass of incompatible and unmanageable data. What’s more, your UK site buys natural gas in pence per therm, Belgium in euro per MWh and the US in dekatherms, Hungary in forints, Poland in zlotys. All of sudden, answering your CEO’s question: “how much energy do we consume, how much do we spend and how do we buy it?”, is not so easy.
The key to effective and time-to-value data management on a global portfolio is to focus on data capturing, validation, standardization and presentation. A good solution requires dedicated resources, relevant technical skills and the newest technology. The best energy data management solutions are developed solely for that purpose, providing flexible and tailor-made data quality tools.
E&C Consultants has developed an excellent solution for managing energy data on a global scale. Our data management platform is highly accessible, flexible, and large enough in terms of geographic footprint to support your current and future data management needs. We can provide our clients with ongoing access to all contracts, price fixations, invoices, calculations, reports, budgets, risk analyses, historical data, market prices, consumption figures, management resumes and any other desired tools – per site, per country, per commodity, per month, per year, per legal entity, in any configuration needed – all 100% shared and downloadable from their own tailor made website. Our constantly updated market intelligence and highly customized reporting are a big help when having reliable data is indispensable to taking important business decision across sites and across countries.
With E&C’s global energy data management tools you can rest assured that your strategic decisions are based on reliable information.
You are probably among the 79% of organizations that believe it is difficult to predict when and where the next data challenge will arise – would you like to be prepared? Then register to our Transatlantic Energy Conference! The first leg of our event is being held in Amsterdam on Thursday, September 22nd and the second will take place in Chicago on Wednesday, October 5th: http://www.eecc.eu/TEC

 

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

Written by Dina Karamarko

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


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

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

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

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

Missed our Transatlantic Energy Conference 2016?

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Nowelizacja ustawy o odnawialnych źródłach energii – konsekwencje dla odbiorców końcowych

Prefer the English version? You can find it here.

W dniu 28 czerwca Prezydent RP podpisał nowelizację ustawy OZE, która wejdzie w życie już 1 lipca 2016 r. i już z tym dniem wprowadzone zostaną zmiany które mogą mieć konsekwencje dla odbiorców końcowych.

Nowy obowiązek – niebieskie certyfikaty – od 1 lipca 2016 r.

Już od 1 lipca 2016 zmianie ulega wymiar obowiązku w zakresie przedstawienie do umorzenia świadectw pochodzenia energii ze źródeł odnawialnych (zielonych certyfikatów). Obecny wymiar obowiązku wynoszący 15% zostaje zmniejszony na całe drugie półrocze 2016 r. do 14,35%. Oznacza, to że sprzedawca energii, za drugie półrocze 2016 r. będzie zobowiązany do przedstawienia do umorzenia mniejszej ilości zielonych certyfikatów w odniesieniu do energii elektrycznej sprzedanej odbiorcy końcowemu.

Jednakże wraz z obniżeniem obowiązku w zakresie zielonych certyfikatów, już od 1 lipca 2016 r. wprowadzony zostanie nowy obowiązek i nowy rodzaj certyfikatów – obowiązek umorzenia świadectw pochodzenia potwierdzający wytworzenie energii z biogazu rolniczego (tzw. niebieskie certyfikaty). Wymiar obowiązku w zakresie niebieskich certyfikatów będzie odnosił się do 0,65% wolumenu zakupionej energii – czyli będzie równy obniżce obowiązku w zakresie zielonych certyfikatów.

Wydaje się, że takie przesunięcie powinno być neutralne dla odbiorców końcowych tym bardziej, że łączny procentowy wymiar obowiązku w zakresie zielonych i niebieskich certyfikatów pozostaje na tym samym poziomie co sprzed nowelizacji ustawy OZE. Jednakże wprowadzenie obowiązku w zakresie niebieskich certyfikatów prawdopodobnie spowoduje wzrost cen energii elektrycznej dla odbiorców końcowych. Wynika to z faktu, że cena niebieskich certyfikatów (ze względu na ich małą podaż) prawdopodobnie będzie zbliżona do opłaty zastępczej (300,03 zł), tym samym będzie ponad czterokrotnie większa niż obecna cena zielonych certyfikatów – czyli odbiorca końcowy zapłaci za niebieskie certyfikaty dużo więcej aniżeli płaci obecnie za zielone certyfikaty.

table1

Tabela 1: Obowiązek praw majątkowych od 2010r. (opracowanie własne)

 Jaki będzie wymiar obowiązku w zakresie zielonych certyfikatów na rok 2017 ?

Zgodnie ze znowelizowanym art. 59 ustawy OZE na 2017 r. ustawodawca ustalił obowiązek w zakresie zielonych certyfikatów na 19.35% a niebieskich certyfikatów na 0,65% energii zakupionej przez odbiorcę końcowego. Jednakże jest to maksymalny wymiar obowiązku i zgodnie z art. 12 ust. 5 nowelizacji „Minister właściwy do spraw energii, w drodze rozporządzenia, zmieni wielkość udziału, o którym mowa w art. 59 ustawy OZE, na 2017 r. w terminie do dnia 30 listopada 2016 r.”

Uprawnienie dla Ministra Energii do zmiany wielkości obowiązku wprowadza dosyć dużą niepewność dla odbiorców końcowych. Po pierwsze w ofertach zakupowych energii elektrycznej na 2017, 2018 i 2019r. spotykamy się z bardzo różnym podejściem sprzedawców co do określenia zasad ustalania ostatecznej ceny energii elektrycznej w oparciu o zmiany legislacyjne (np. pojawienie się nowego „koloru”, brak przedłużenia certyfikatu żółtego i czerwonego na rok 2019 itd.). Po drugie sprzedawcy na wiele sposobów kształtują cenę Praw Majątkowych na następne 3 lata, uwzględniając ryzyka zmienności cen i płynności na TGE. Warto zatem dostosować odpowiednią strategię do tak zmiennego otoczenia rynku biorąc pod uwagę przede wszystkim wpływ zmian cen/kosztu energii na biznes prowadzony przez odbiorcę końcowego.

 table2

Tabela 2: Udział obowiązku praw majątkowych od 2010r. (opracowanie własne)             *Minister Energii zmieni tą wartość do 30/11/2016

Wpływ kolorów na koszt energii odbiorcy końcowego

Bardzo zmienne otoczenie legislacyjne stawia pod znakiem zapytania budżet dla odbiorcy końcowego w następnych latach. W tabeli nr 3 przedstawiono przykładowe szacunkowe ceny za poszczególne kolory w latach 2017 – 2019. Dla odbiorcy zużywającego rocznie ok 100.000 MWh, akceptacja oferty sprzedawcy na rok 2019 uwzględniającej kolor żółty, czerwony i fioletowy, przy braku przedłużenia obowiązku na ten rok powoduje stratę ok 1,4 mln złotych.

 table3

Tabela 3: Ceny kolorów

Opłata OZE – od 1 lipca 2016 r.

Od 1 lipca 2016 r. wraz z wejściem w życie nowelizacji i rozdziału 4 ustawy OZE pojawi się na rachunkach za usługi dystrybucyjne nowa opłata – tzw. opłata OZE. Zgodnie z art. 95 ust. 1 ustawy OZE operator systemu dystrybucyjnego zobowiązany jest pobrać od każdego odbiorcy końcowego opłatę OZE. Na drugie półrocze 2016 r. opłata OZE została ustalona na poziomie 2,51 zł za każdą MWh energii elektrycznej dostarczonej odbiorcy końcowemu. Na rok 2017 Prezes URE ogłosi poziom opłaty OZE do 30 listopada 2016 r. Warto wskazać, że dla przedsiębiorstw posiadających status odbiorcy przemysłowego opłata OZE podlega zmniejszeniu proporcjonalnie do posiadanej ulgi. W tym zakresie warto sprawdzić na pierwszych fakturach czy operator systemu dystrybucyjnego właściwie wyliczył opłatę OZE.

Zwiększenie Opłaty Przejściowej od 1 stycznia 2017 r.

Nowelizacja ustawy OZE przewiduje również zwiększenie opłaty przejściowej dla części odbiorców. Opłata przejściowa doliczana jest do faktury za usługi dystrybucji na podstawie ustawy z dnia 29 czerwca 2007 r. o zasadach pokrywania kosztów powstałych u wytwórców w związku z przedterminowym rozwiązaniem umów długoterminowych sprzedaży mocy i energii elektrycznej.

Zgodnie z Nowelizacją ustawy OZE w odniesieniu do odbiorców końcowych innych niż gospodarstwa domowe, których instalacje są przyłączone do sieci elektroenergetycznej:

  • niskiego napięcia, opłata przejściowa na 2017 r. wzrasta z 0,85 zł do 1,65 zł na miesiąc na kW mocy umownej,
  • średniego napięcia, opłata przejściowa na 2017 r. wzrasta z 2,10 zł na miesiąc na 3,80 zł na kW mocy umownej,
  • wysokich i najwyższych napięć, opłata przejściowa na 2017 r. pozostaje bez zmian
  • wysokich i najwyższych napięć i którzy, zużyli nie mniej niż 400 GWh energii elektrycznej z wykorzystaniem nie mniej niż 60% mocy umownej, dla których koszt energii elektrycznej stanowi nie mniej niż 15% wartości ich produkcji, opłata przejściowa wzrasta z 1,08 zł na miesiąc na 1,10 zł na kW mocy umownej,

Pełen tekst ustawy można znaleźć tutaj: http://dziennikustaw.gov.pl/DU/2016/925