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:

fig1

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?

You can register for our Transatlantic Energy Conference via the following link:
Europe: https://www.eventbrite.com/e/transatlantic-energy-conference-2-europe-tickets-21030454656
US: https://www.eventbrite.com/e/transatlantic-energy-conference-2-united-states-tickets-21030478728

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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

Meet the blue certificate, another certificate of the polish property rights market

Prefer the Polish version? You can find it here:

By Bartosz Palusiński

On June 28th, the polish president signed the amendment to the RES law. The changes will come into force on July 1st, 2016. The first change that will impact the polish end consumer is the reduction of the share of the green certificate obligation from 15% to 14,35% for the second half of 2016. This means the energy seller will need to submit less green certificates for electricity sold to the end consumer.

Unfortunately the reduction will be compensated by the introduction of a new type of certificate: the blue certificate. These certificates confirm that the energy is produced from agricultural biogas. The obligation will be set at 0,65% of the volume of purchased energy, exactly the same amount as the reduction on the obligation of green certificates.

At first sight you’d think this change should have a neutral impact on the end consumers. The price of both certificates is calculated in a different way. The price of green certificates is based on a market mechanism and at the moment these certificates are traded at around 70 zł/MWh.

The price of the blue certificates will probably be aligned with the replacement fee. The replacement fee is a maximum price for certificates set by the regulator to increase liquidity. The current replacement fee is at 300,03 zł/MWh which is more than four times more expensive than the current price of the green certificates!

table1

Table 1: Obligation of the Property Rights (source: Grid Fees & Taxes section of E&C Consultants)

Moreover, the percentual obligation of both certificates will rise to 19,35% for green certificates and 0,65% for blue certificates as of 2017. However, this is a maximum and the legislation mentions the minister in charge of energy is allowed to make adaptation until November 30th, 2016. This ability introduces a fairly large uncertainty on the market.

In the offers of suppliers for 2017, 2018 and 2019 we notice different approaches in establishing the final price for end consumers based on the different legislative changes (introduction of new colours such as the blue certificate and the end of others such as the yellow and red ones in 2019). Next to this, sellers apply different calculations to define the price of property rights for the next three years, keeping in mind risks of changes in price and liquidity on the TGE. This makes it even more important to implement a strategy to handle this unstable market environment and limit its impact on the energy cost of the end consumer’s business.

table2

Table 2: Share of the obligation of the Property Rights (source: Grid Fees & Taxes section of E&C Consultants)                                * Energy Minister change that value by 30/11/2016

Influence on the energy cost of end consumer

This highly unpredictable legislative environment makes it hard to clearly define the energy budget for the next few years. In the table below you can find an estimation of the price of each colour for 2017, 2018 and 2019. An end consumer using 100.000 MWh electricity per year, might lose 1,4 million zloty if there is no prolongation of the existing law to support the yellow, red and violet certificates.

table3

Table 3. Estimated price of particular colour (source: Grid Fees & Taxes section of E&C Consultants)

Other changes to the RES law

As of July 1st, the RES fee will be introduced on the electricity bills. This fee covers distribution services and will be collected by the distribution system operator. For the second half of 2016 this fee is set at 2,51 zł/MWh. The rate for 2017 will be announced before November 30th by the regulatory office. Companies that obtained the status of industrial consumer can be granted a reduction.

As well, transition fees will increase as of January 1st, 2017. This fee is added to the invoice for the distribution services and covers the producers’ cost in case of an early termination of a long-term contract or the sale of capacity and electricity. Below you can find the fees for end-users (other than households) that have installations connected to the grid:

  1. Low voltage transition fee increases from 0,85 to 1,65 zł per month per kW of contracted capacity
  2. Medium voltage transition fee increases from 2,10 to 3,80 zł per month per kW of contracted capacity
  3. High and extra high voltage transition fee for 2017 will stay unchanged
  4. High and highest voltage transition fee increases from 1,08 to 1,10 zł per month per kW per contracted capacity for end-users that consume more than 60% of the contracted capacity and for which the cost of electricity is more than 15% of their production value.

Would you like more information on these regulatory changes in Poland? Feel free to contact us via info@eecc.eu or call Bartosz Palusiński via +48 509 82 00 25.

 

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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How to deal with the volatility in the oil markets

Written by Frederic Grillet

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

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

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

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

Impact on other commodities

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

So when do you hedge?

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

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

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

Czech Republic introduces capacity-based green energy levy

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

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

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

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

 By Ondrej Zicha