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POWER IN EUROPE Issue 726 / May 23, 2016 Sweden nuclear exit ‘in five years’ Vattenfall issues capacity tax warning All of Sweden’s nine operational reactors could be shut in a little over five years if the government does not remove a capacity tax levied on nuclear generation, Mats Ladeborn, vice president, fleet development for Vattenfall, told the Platts European Nuclear Conference in London May 18. “If Swedish politicians do not take away the capacity tax, we will phase out all nuclear reactors in Sweden by the early 2020s,” Ladeborn said. The Swedish nuclear capacity tax is calculated on the amount of electricity reactors could generate, based on installed capacity, rather than actual production. An increase of 17% in the tax was approved by the Riksdag, Sweden’s parliament, in 2015. The tax now stands at SEK 14,770 (€1,580) per megawatt per month. Vattenfall operates seven reactors and OKG two, Oskarshamn 2 having closed last year. The majority of OKG’s shareholders voted in October to close the 492-MW (continued on page 2) Coal exits UK market in May Symbolic decarbonisation milestone Closures, outages and poor economics saw UK coal generation fall to zero May 10, Since when the technology, a mainstay of UK power since Victorian times, has been missing from the system for a total 47.5 hours to May 17. Between midnight and 04:00 May 10 a series of outages on the coal fleet led to generation dropping to zero for the first time in living memory. All units at Aberthaw have been offline since May 6, and on May 7 the only coal unit at Drax not already on maintenance tripped. Then on May 9 Unit 6 at Rugeley tripped. UK QA CLEAN FUEL SPREADS 10.0 (£/MWh) Spark 50% Dark Spark 45% 7.5 5.0 2.5 0.0 -2.5 -5.0 Nov-15 Source: Platts Jan-16 www.platts.com Mar-16 May-16 Following these outages market incentives were enough for West Burton, Fiddler’s Ferry and Ratcliffe to run during May 9 peak evening period but, without the drivers keeping Aberthaw and Rugeley on overnight, all three shut down at the end of EFA Block 6, “bringing to an end what is believed to be more than 100 years of continuous coal-fired generation in the UK,” according to Eclipse Energy, an analytics unit of S&P Global Platts. Meanwhile the near-term competitiveness of gas has continued to improve against coal. The 90-day CIF ARA thermal coal increased from $46.40/mt to $48.70/mt between May 6 and 13. In the same time period, the NBP and UK power front-month contracts remained nearly flat, drifting from 29.30 pence/therm to 29.05 p/th and £32.20/MWh to £32.60/MWh. The month-ahead Coal Switching Price Indicator, assuming 45% efficiency, has been on an upward trajectory in May to-date, gaining from 33.84 p/th to 35.06 p/ th between May 3 and May 13, clocking 34.61 p/th May 6. The CSPI approximates the threshold price for gas, below which it is a cheaper input for power generation than coal. (continued on page 2) www.twitter.com/PlattsPower CONTENTS Analysis Amsterdam part 2: SWOT analysis for wind 3 BNetzA calls for RES slowdown 5 Polish thermal faces price squeeze 8 CEZ: generation, price headache drags on 9 Powervault targets smart tariff future 10 REstore extends Total, Arcelor Mittal deals 11 News Highlights Wind sector laments policy inertia Norther seeks EIB funding IEA recommends phase-out delay CREG proposes DSM improvements Elia seeks black start services Kozloduy extension ‘due next year’ RES amendments favor co-firing Polish GC prices continue to fall Nordic utilities call for ETS reforms Hanhikivi-1 ‘on track for 2024’ HPC FID awaits consultation Total bids for Saft EDF dispels Le Creusot fears Cal reacts to €30/mt floor price news Turbines in at Gode Wind 1 and 2 EU court rules on EEG state aid Gas exceeds lignite as demand dips Edison prepares to repower Wind boost for ERG First round SDE+ bids in Bids in for Borssele offshore Four-day record for RES Sedigas paints upbeat CCGT picture Vartan CHP8 inaugurated SBB grid links approved Gaelectric pursues PV/wind first for NI Dudgeon financed 13 13 13 13 14 14 14 15 15 16 16 17 17 18 18 18 20 21 22 23 23 24 24 25 25 26 26 News Austria 13 / Belgium 13 / Central and East Europe 14 / Europe 15 / Finland 16 / France 16 / Germany 18 / Greece 20 / Italy 21 / Netherlands 23 / Portugal 24 / Spain 24 / Sweden 25 / Switzerland 25 / UK 26 Data Biomass27 Power Market Commentary 28 Bilateral Market Assessments 29 CEE Power Market Assessment 30 Feedstock Comparisons 31 European Exchange and Pool Prices 32 ELECTRIC POWER POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 Sweden nuclear exit ‘in five years’ Coal exits UK market in May ...from page 1 ...from page 1 Oskarshamn-1 due to financial reasons and the company said February 16 that the unit would be shut permanently in the middle of 2017. Shareholders also voted to shut the 661-MW Oskarshamn-2 ahead of schedule, also due to financial reasons. It is planned to be closed before 2020. Ladeborn also said that Vattenfall’s closure plans for the 916-MW Ringhals-1 and the 910-MW Ringhals-2 would not change even if the capacity tax was removed. Vattenfall has previously said that all investment in Ringhals-1 and -2 will stop in 2017 as the company does not plan to make new safety improvements to the two units that are required under Swedish law for all nuclear power plants operating in the country after 2020. Nuclear production of 64 TWh in 2013 represented 43% of total Swedish generation of 149 TWh. Hydro accounted for 41% and wind power 7%. Meanwhile the month-ahead clean spark spread assuming 45% efficiency climbed from £0.90/MWh May 3 up to £1.67/MWh May 13. Gas-for-power demand in the UK has increased by more than 50% year on year so far in 2016. A total of 7.644 Bcm (56 million cu m/d) has been used by gas-fired power stations during the January 1-May 16 period, 56% higher when compared to the same period in 2015. April 2016 saw CCGT generation at its highest since September 2011, with output up by 7 GW year on year. In both September 2011 and April 2016 CCGTs accounted for 45% of the market, but the nature of plant running has changed in that time, Eclipse noted May 19. “Plants such as Rocksavage, Severn Power and Staythorpe are optimising intraday shape by running through the day but varying output between Stable Export Limit and Maximum Export Limit during the overnight and Block 4 dip,” the analytics group said. “Others such as Didcot B continue to run a two shift schedule – turning off overnight and ramping up daily for the Block 5/6 peak – as overnight fuel spreads are too low to offset costs associated with shutting the plant down.” As summer rolls on, Eclipse forecasts a further rise in Block 4 solar output working to widen the within-day price shape. “During these periods downside flexibility on the fleet may be a problem for National Grid, perhaps leading to an increased number of negative bids accepted (as seen on 16th May) for CCGTs to reduce output,” it said in its May UK Power Pilot report. SWEDEN’S REACTORS Unit OwnerMW Commercial Intended operation decom Oskarshamn 1 OKG 473 1972 2017 Oskarshamn 2 OKG 638 1974 Closed in 2015 Oskarshamn 3 OKG 1400 1985 2035 or 2045 Vattenfall 878 1976 2020 Ringhals 1 Ringhals 2 Vattenfall 807 1975 2019 Ringhals 3 Vattenfall 1062 1981 2041 Ringhals 4 Vattenfall 938 1983 2043 Forsmark 1 Vattenfall 984 1980 2040 Vattenfall 1120 1981 2041 Forsmark 2 Forsmark 3 Vattenfall 1187 1985 2045 Source: World Nuclear Association Power in Europe is published twice monthly by Platts, a division of S&P Global, registered office: 20 Canada Square, Canary Wharf, London, UK, E14 5LH. POWER IN EUROPE Issue 726 / May 23, 2016 ISSN: 0955-6079 Editor Henry Edwardes-Evans [email protected] +44 (0)20 7176 6207 Design and Production Martina Klancisar Global Editorial Director, Gas and Power Simon Thorne Chief Content Officer Martin Fraenkel Platts President Imogen Dillon Hatcher Officers of the Corporation: Harold McGraw III, Chairman; Doug Peterson, President and Chief Executive Officer; David Goldenberg, Acting General Counsel; Jack F. Callahan, Jr., Executive Vice President and Chief Financial Officer; Elizabeth O’Melia, Senior Vice President, Treasury Operations. Restrictions on Use: You may use the prices, indexes, assessments and other related information (collectively, “Data”) in this publication only for your personal use or, if your company has a license from Platts and you are an “Authorized User,” for your company’s internal business. 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Text-only archives available on Dialog File 624, Data Star, Factiva, LexisNexis, and Westlaw. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 Amsterdam part 2: SWOT analysis for wind Platts’ European power conference in Amsterdam had a good, hard look at wind power – strengths and weaknesses, opportunities and threats. The technology is facing a significant setback if repowering falters – but could profit from a new RES Directive and entry to ancillary markets. First, the looming threat. Repowering of wind farms must be supported by the European Union’s new renewable energy directive or Europe risks losing up to 6 GW of green capacity a year, delegates heard in late April. the guild of lawyers and dentists in Germany,” said Hans Schweickardt, chairman of Polenergia, Poland’s leading independent wind develop. These investors may not be willing or able to support the cost of repowering, or have factored this into their original decisions. During a panel on wind power, chief executive of WindEurope Giles Dickson said there had to be a “provision that supports repowering of existing wind and other renewables in the directive,” which is due to be revised by the European Commission in November this year. “What cannot happen is that these repowered wind farms once again rely on subsidies, because the EC is targeting harmonized market rules and these wind farms will have the same role and duties of residual power stations,” Schweickardt said. “For example if a wind farm has got a permit for 20 years and financial underpinning for that time and the developer after 15 years decides to take smaller turbines down and put some bigger, more modern turbines up, that wind farm should still be able to benefit from subsidies for those last five years,” he said. Holger Gassner, head of energy policy and political affairs at RWE Innogy, said that on the solar side “the repowering problem could be just as serious because for many people the investment was for the financial return, not for electricity system reasons. Those with money to invest were advised the returns were better on the roof than in the bank. So the question is, if this power is going out of the system and at the same time new lines are being built to transmit the electricity, how do you replace it?” In addition, permitting should be easier for repowering than for completely new wind sites, he said. Repowering is taking place in Germany and the Netherlands, Dickson said, “but we’re only at the first stage in what is becoming a real issue for us.” Many of the private investors “had no interest in managing a wind farm or providing balancing power,” he said, “so there will be scope for providing services by utilities or other companies in the wind area, as well as managing the repowering at these sites. New business models and new cooperations will emerge to ensure the best wind sites are not given up.” Wind contributes 11.5% of Europe’s electricity generation today, renewables overall supply 29% of Europe’s power and the EU has a target of 50% by 2030, he noted. Some 13 GW were added last year, this year a slightly lower figure is forecast, perhaps 10 GW, he said. “It is tempting to think that we go up in a straight line from 29% to 50%, we’ve already got a lot of renewables, we just build some more. No. We lose over half of Europe’s wind before we get to 2030.” Opportunity knocks While the threat of a failure to repower was real, so was the opportunity to boost existing capacity and improve efficiency at sites considered to be poor. “We have 142 GW of installed wind capacity today. In the 2020s alone, 75 GW of that – over half – will come to the end of its life,” he said. “Repowering doesn’t involve upgrading existing turbines, it involves taking everything down, including the tower, foundations – full replacement,” said Dickson. “In a lot of cases that means replacing 500 kW machines with, say, 3 MW machines of greater efficiency. It is hard to generalize, but often you have poor technology on very good sites, so I think most sites could be repowered.” “If it is not repowered -if existing, usually fairly small, low capacity turbines and not taken down and replaced by the much larger turbines – you’ve lost 75 GW and gone backwards, installed renewables capacity actually starts to fall, at 6 GW-7 GW a year.” Gassner had one concern: restrictions on tower height in some areas of Germany, with an 80-100 meter limit on poor wind sites that would become very good sites if tip height were allowed up to 120 meters. Investor appetite Others agreed. “This could be quite a remarkable problem because so many wind farms were set up by what we call © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 3 POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 Then there was the visual impact and public acceptance problem. “The UK is very tough on this and that is a big challenge for repowering,” Gassner said. “Don’t take it for granted that you can remove the old wind farm and replace it for good economic reasons.” “I was in Q1 and I wanted to take a Q2 position, and we were looking at whether lignite would be in or out of the stack. I realized it did not really matter – if it was windy and sunny, the price would be down here, and if it was not, it would be up here,” he said. He quit and moved into weather risk management. Balancing markets Renner had started his career at Centrica, where the first big multi-year weather deal was done in 2002, so he understood the desire of generator utilities to remove weather-driven volatility to their earnings. Another area of opportunity for wind was in balancing capability, the conference heard. Today renewables are generally excluded from balancing and other ancillary service markets, despite the fact that wind has the technology to play in all these arenas, and despite the fact that wind farm operators are now paying balancing costs in most countries in Europe, normally of around €2-€3/MWh, Dickson said. “Weather risk management is pretty straight forward because you’ve got a ton of data, 50 years of historic temperature data, rain data, wind speed data,” Renner said. There are trends, such as the last three warm winters, that do pose challenges to modelling and pricing of weather products, “but essentially you’ve got excellent data and pure weather deals are relatively simple to do,” he said. “A number of pilot projects have shown wind can successfully contribute to automatic secondary reserve, and to primary reserve,” he said. “We are developing fast frequency response to enable us to change frequency at two-second intervals. Wind is generating reactive power to support voltage control, and if there were a market for inertia that we could enter, then we would develop a product for that too – the technology is there for wind to play in the balancing markets, which will only grow in future, and the key point is this: wind can provide the services cheaper than other forms of power generation.” Global book As a seller of weather products, the trick was to have a globally diverse book. “If you just write European risk, you’re only going to be writing warm side [ie all European utilities want to hedge the risk of warm winters], meaning that after this year you are no longer in business as we’ve just had the warmest December on record,” he said. “The problem with weather, and this is what makes it different from a commodity, is that nobody knows anything about it until everybody knows it,” he said. “You can build a position around the view that oil will be at $40, $50 in six a months’ time, but with weather nobody knows anything until maybe a few weeks or months before, and then everybody knows.” Wind should be able and encouraged to provide both upward and downward balancing capability, Dickson concluded. That meant separating procurement of upward and downward balancing power. “Not many operators can offer both, so if you procure the two together you are limiting the market. Second, if you procure the two together it is always going to be more attractive for a wind farm to offer downward than upward balancing capability. To offer upward you have to be operating 10% below capability, which you are not going to want to do. So you need separate procurement and a higher price paid for upward balancing,” he said. Endurance’s weather business is 30% US/Americas, 30% Europe, 30% Australia. The largest single weather risk category in the world is European warm winters, Renner said, with about €1 billion transferred from utilities to insurers per year. “It has been dominated in recent years by E.ON, RWE, EDF, with trade essentially around the risk that if it is warm, you don’t sell any gas,” he said. While RWE Innogy’s Gassner agreed that “there can be no argument against wind’s participation” in ancillary markets, he offered a note of caution. “An uncontrolled opening for these markets will drive prices down and affect participants. We must keep sight of the strengths of wind, solar, hydro, biomass – but also be realistic about their limitations.” Utilities either buy a temperature structure, hedging every month, or they trade this as an option or a swap – “if it’s warm I have to pay them, if cold they pay me, over a month, season, even a year,” he said. “You can make it more fun and bring price into it, so if it’s warm and prices are low, that is bad for the utility.” Weather insurance So while risk is largely uniform across Europe, every energy company manages it differently. Meanwhile renewables have opened a new world of opportunity for weather-driven risk management, Ralph Renner of Endurance Global Weather told the conference. Big shift to wind Renner was working as a German power trader in 2010 when he had a moment of clarity. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. “Over the last two years we’ve seen a big shift,” Renner said. “Energy assets are now called energy liabilities, all the 4 POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 95% bespoke value that used to be extracted from trading around dark and spark spreads and optimization, that’s gone. So rather than writing pure temperature options, we’re looking a lot more at wind.” For now the market is 95% bespoke, he said. These are hedges, not trades, and very specific. In Germany, Endurance is managing Rhine river level concerns, insuring against levels not being high enough to allow coal deliveries, while in the Netherlands there is a Dutch client buying warm winter cover augmented by a low wind scenario, and in the UK there are retail suppliers hedging against high wind and solar tariff obligations, Renner said. This has been exemplified by the launching of wind futures by EEX and Nasdaq. “We’ve worked with the exchanges to make sure that the way they are launching these products makes sense not just for a trading house but also for insurers to write very solid data methodology behind these futures,” Renner said. “The Armageddon in Germany is beginning to happen elsewhere – the volatility induced by solar and wind in Spain is just as severe, they just have not had the familiarity with weather risk to manage that, but it is changing rapidly,” Renner concluded. “We’re seeing our first deals in the Nordics, East Europe, southern Europe. This is specific to a company and how they want to manage their risk. I think insurers and traders will eventually find a point of convergence where we meet in the market, I hope that will happen with the wind futures.” Interest in the exchange products has been modest in these early days, but Renner is taking a five-year view. “It is going to grow gradually into a completely normal product as in Australia, where they are comfortable with hedges in pre-defined weather positions, hydro, wind, temperature combined,” he said. BNetzA calls for RES slowdown Germany needs €35 billion of internal network expansion investment involving 7,000 kilometers of new lines in order to cope with the system consequences of the Energiewende transformation to renewables. Meanwhile regulator BNetzA is recognizing the possibility of price zone splitting in its latest forecasts. Grid expansion investment Germany’s network regulator has called for a slowdown in renewables’ growth while expansion of the electricity grid catches up, BNetzA president Jochen Homann said May 13. The cost of grid expansion to deal with this phenomenon has risen in recent years, with the latest draft of the annual grid expansion plan (NEP 2025) estimating the cost of over 7,000 km of new power line needed at €35 billion, BNetzA said. “We need to synchronize the expansion of the grid with new renewable power plants, otherwise the costs will explode,” Homann said while presenting BNetzA’s annual report. Late last year the government introduced legislation prioritizing the burial of high-voltage grid links in order to overcome local resistance, potentially adding up to €8 billion in costs. Germany has installed almost 49 GW of wind and solar capacity since 2010, but grid strengthening and expansion investment has failed to keep pace, increasing regional imbalances and boosting the annual cost of redispatch to over €1 billion in 2015. The bill aims to ensure realization of three major new North-South transmission projects (SuedLink, SuedOstLink, Ultranet) by the time Germany’s last nuclear power station is switched-off at the end of 2022. According to Germany’s four transmission system operators (Tennet, 50Hertz, Amprion, Transnet BW), redispatch costs could rise to €4 billion by 2020, a sum the grid regulator said was not unrealistic. There are serious doubts, however, that deadlines are deliverable following the volte face on undergrounding last year. “Priority for underground cabling means the last three years spent in planning, from 2012, is turned into waste paper,” said Tennet spokesman Markus Lieberknecht back in March. Tennet is responsible for Suedlink. “We have to start all over again. The whole process of planning, permitting and construction will take around 10 years. The HVDC cables due to be ready by the end of 2022 can hardly be ready by then,” he said. Redispatch costs arise in Germany when priorityaccess, must-run renewables cause transmission congestion. TSOs then have to pay conventional power stations to ramp down in order to balance the network. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 5 POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 GERMAN GRID EXPANSION LAGS BEHIND RENEWABLES Nuclear phase-out will add to North/South imbalance CURRENT GRID BOTTLENECKS WITH LOOP FLOWS CURRENT SCENARIO NEW HVDC LINKS TO BOOST TRANSMISSION CAPACITY BEYOND 2022 SCENARIO D E NM AR K DENMARK 2021 P OL AND 2022 POL AND 2021 N E T H E R L AND S NETH ERL ANDS GE R M ANY B E LG I U M F R A N CE k ttlenec Grid bo 2019 Nuclear reactor 2022 Decomissioning date Wind (45GW) Solar (40GW) 2021 UK p flows Loo UK 1 BELG IUM 2 G ERMANY 3 2015 CZECH R EP UBLIC 2017 2021 2022 CZECH REP UB L IC F RANCE AUSTRIA 1 Ultranet 2 SuedLink 3 SuedOstLink AUSTR IA Wind S W I TZE R L AND Solar SWITZERL AND Source: S&P Global Platts analysis of BNetzA, TSO data Speaking at the E-World event in Essen February 15, secretary of state at the federal economy ministry Rainer Baake expressed hope that the setback in planning would be made good by an easier planning process. To create a clear framework, the BNA issued a position paper on underground cabling planning on February 22. Once a planning method is defined, new preliminary planning for Suedlink and Corridor D can begin. Discussions with landowners on underground cable routes, however, indicate that assumptions of reduced public opposition may be optimistic, according to Peter Ahmels, head of energy and climate protection at environment NGO Deutsche Umwelthilfe. Meanwhile Corridor A (Ultranet) is being built by TransnetBW and Amprion. It uses mainly existing overhead line infrastructure. No undergound cable is required. In a December 2015 presentation Transnet BW foresaw commissioning in 2020, the year after the Philippsburg 2 reactor closes. This is not yet a firm date due to uncertainties in the planning process being carried out for the first time by the BNA. The problems do not go away, they are just different, he said March 8. For instance, where before overhead cable planning involved deciding routes passing near villages, underground planning involved deciding whether a route circumnavigated woodland or not. Detailed planning for the northern part of corridor A, since January the sole responsibility of Amprion, has not yet begun. Commissioning of this section is now slated for 2025, Amprion said in March. Before the change of priority to undergrounding, NEP 2024 had forecast TSOs’ targeted completion dates for Corridor A projects (known collectively as Ultranet, with 2 GW capacity) as 2022 for Emden Ost-Osterath, and 2019 for Osterath-Philipsburg. Last year’s annual grid development plan (NEP 2024) outlined almost 100 grid projects needed in order to boost capacity along major north-south connections by up to 12 GW. For Corridor C projects Brünsbuttel-Grossartach and Wilster-Grafenrheinfeld (the two routes running north-south through the center of Germany, together known as Suedlink with a total 4 GW) a 2022 completion date was foreseen. Based on NEP 2024, some 43 high priority projects were put forward by TSOs to the BNetzA, to be subject to accelerated planning procedures (see map). These projects, listed in the the BBPlG 2015 federal transmission act, involve 2,550 km of new cable routes and 3,100 km of optimizing and strengthening measures. For Corridor D (2 GW) running from mid-eastern Germany to Bavaria (Wolmstedt–Isar) completion was 2024. Renewables reform Two of the three HVDC corridors, however, will be heavily affected by the changed priority to underground cabling – the two lines for the Suedlink Corridor C, and Corridor D. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. Meanwhile Germany’s energy ministry (BMWi) is consulting on the next reform of its renewable energy law (EEG 2016), 6 POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 aimed at transforming support from feed-in-tariffs to a tender process for most new renewable energy projects from 2017. SNAPSHOT VIDEO The target is to achieve a share of renewables in the German power mix of 40% to 45% by 2025, from just below 33% in 2015. EU wholesale power prices: facing structural collapse or cyclical recovery? The idea is to ensure that annual growth corridors or ranges for wind and solar are followed more closely than in recent years, when a boom in solar (2010 to 2012) was followed by a boom in wind (2013 to 2015). We explore a key question that emerged from Platts’ recent European power conference: is Europe’s wholesale power price collapse structural, or could central plant closures prompt a post 2020 recovery? The details are contentious, with a variety of vested interests from industry, regional states as well as the different technologies blurring traditional party lines. Watch video at: http://plts.co/SISS300ij3U A first summit between the leaders of Germany’s 16 states with Chancellor Angela Merkel earlier in May brought no solution. Another meeting is set for May 31. Last year, European energy regulatory body ACER at the request of Polish regulator URE called for the introduction of capacity allocations on the German-Austrian border, which in effect would split the common German-Austrian price zone, by far Europe’s most liquid power market. A leaked position paper by Merkel’s CDU/CSU faction proposes a sharp reduction in capacity, especially for onshore wind, introducing an upper limit of 51 GW, above which no further subsidies will be payable. Germany’s Eastern neighbors have complained for many years about loop flows of excess wind power from Germany’s oversupplied North and East, surging through Polish and Czech grids and on to Germany’s South and Austria. For solar, an upper limit of 52 GW was introduced back in 2012 amid a number of other measures to stop the boom, which saw 22 GW installed over three years. Price zone split Earlier this month, Nordic neighbors added their concern about Germany’s grid bottleneck, which prompted a report in German financial daily Handelsblatt May 5 saying the European Commission is considering requiring Germany to split its internal power grid into two zones, based on sources inside the EC. The growing disconnect between Germany’s wind and solar boom and the slow expansion of its internal transmission grid has reignited the debate about a possible price zone split. There is a precedent for the EC taking similar action. In November 2011 Sweden split into four price zones north to south, following a complaint from Denmark. A bottleneck in the Swedish network was limiting flows of cheap power from the north and from Norway to the south of Sweden. €4K E-CAR INCENTIVE CLEARED Germany has approved a cash incentive of €4,000 per electric vehicle that it hopes will help achieve the government’s target of 1 million electric cars on the road by 2020, the economy and energy ministry said May 18. Together with other measures boosting electro-mobility, the government has given the green light to €1 billion of public subsidy, primarily sourced from the energy and climate funds managed by the ministry. The automobile industry will also contribute to the cash incentives. Now BNetzA itself is assuming the introduction of capacity allocation on the German-Austrian border from 2018, basing its winter 2018 outlook on this hypothetical scenario, with another issue the planned use of phase-shifters on the German-Polish border. Utility association BDEW welcomed the measures, but warned that there needed to be more focus on building the necessary charging infrastructure in the short term. Last year the BDEW called for some €100 million to back its initiative to install 10,000 new charging stations by 2017. In its May 2 statement for various winter outlook scenarios, BNetzA said that a change to flow-based market-coupling between the regions would help optimize cross-border power trading between the Central Eastern Europe (CEE) region and the Central Western Europe (CWE) region, as well as helping to balance power grids. Government, the auto industry and the utility sector all agree that the charging infrastructure is key for the mass roll-out of electric vehicles over the next couple of years. Research into power demand of electric cars varies, but according to some experts, 1 million electric cars may have an annual consumption of around 6 TWh. This is just over 1% of current German consumption. — Andreas Franke © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 7 POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 Polish thermal faces price squeeze Poland’s four state-controlled utilities all saw their distribution volumes rise in the first quarter of 2016 thanks to a 2.1% year-on-year growth in electricity consumption. Generation volumes, however, were mixed with the country’s largest generator, PGE, suffering from higher maintenance on its lignite-fired units and warning of a price squeeze ahead for conventional units. Annualized GDP growth of 3.9% in January-March boosted power consumption among business customers which allowed both PGE and Energa to increase their distribution volumes by 3% year-on-year to 8.64 TWh and 5.64 TWh respectively. Tauron and Enea saw growth of 2% or just under to 12.7 TWh and 4.73 TWh respectively. have fallen from a high of Zloty 249/MWh in February 2014 and since March last year have been below Zloty 140/MWh thanks to an oversupply on the market, which is currently estimated at the equivalent of 18 TWh. PGE saw its RES generation fall 9% to 0.64 TWh, with co-firing accounting for just 0.09 TWh. Tauron saw a 24% fall to 0.41 TWh on co-firing and lower hydro production. Energa and Enea saw falls of 32% and 44% respectively to 0.36 TWh and 0.15 TWh. PGE and Energa saw their generation volumes fall 9% and 16% respectively to 13.16 TWh and 1,005 GWh thanks to a higher maintenance load and lower demand from the transmission system operator, PSE, for Energa’s must-run hard coal-fired 647 MWe Ostroleka B plant. Tauron’s generation was flat but Enea saw 13% growth on lower maintenance. Policy highlights In terms of policy there were two issues dominating this year’s first quarter, the unveiling of new capacity market mechanisms by the Ministry of Energy, which is scheduled next month, and amendments to the country’s renewable energy law. Lignite-fired generation, which accounted for 65% of PGE’s total production in January-March, fell 16% year-on-year to 8.5 TWh due to the maintenance and the removal of unit 1 at the 5.3 GW Belchatow plant to peak-only operation, which saw the company’s total lignite unit availability fall eight percentage points. PGE, Enea and Tauron are in the process of building major conventional generation projects and Energa is seriously considering relaunching a project to build a 1 GW unit C at Ostroleka. Tauron’s management said it cannot afford to keep its investment to build a 910 MW unit at its hard coal-fired Jaworzno III plant on its balance sheet without state support. PGE said its outlook for conventional generation is substantially lower this year than in 2015 thanks to a lower wholesale blended electricity price, which it now forecasts in the range of Zloty 165-167/MWh (around €37.75/MWh), compared to Zloty 173/MWh (€39.234/MWh) last year. The ministry has stated its policy is to support conventional generation in Poland to ensure energy security but it is yet to release any details about its capacity market plans, save that it will be similar to the UK’s solutions. Poland currently has two temporary capacity mechanisms, an operational reserve capacity and an intervention cold reserve. The company said lower lignite and hard coal-fired generation, with two units at its hard coal-fired Dolna Odra plant shifting to cold reserve, would also depress the company’s performance. “The only positive trend in the sector we could see in this quarter was in distribution. The negative trends were generation, a decline in power prices and renewable energy production, which is being hit by declining black electricity prices, falling green certificate prices and reduced subsidies for co-firing and large hydro,” said Pawel Puchalski, head of equity research at BZ WBK. Deputy energy minister Andrzej Piotrowski said May 10 the government is proposing to use funds already collected from end users to fund long-term contract payments and money to be collected to fund upcoming RES auctions to create a pool of cash that could be used to fund a new capacity market and direct investments in new, mostly coal-fired projects. However Puchalski said the capacity market proposals may be disappointing for some utility bosses. “I don’t believe it will be as beneficial as management hopes it will be. Why would the government create a capacity market scheme that would make utilities extremely profitable? Then the companies have to pay higher dividends and profits out of the group and the government wants them give money to the ailing coal mining sector,” he said. Co-firing hit for all Renewable energy generation from all of the utilities fell significantly in the quarter due mainly to the reduction of 50% of subsidies for co-firing from January 1, as well as declining green certificate prices that rendered the practice unprofitable. Average green certificate prices in April continued their year-long slide reaching Zloty 108.71/MWh, down 5% monthon-month and 14% year-on-year. Green certificate prices © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. — Adam Easton 8 POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 CEZ: generation, price headache drags on An improved trading performance on a volatile first quarter and a healthy step up in net profits for CEZ were balanced by reduced output, falling achieved prices and problems in generation. Generation problems Dominant Czech electricity producer CEZ’s Q1 2016 results May 10 were deemed by analysts to be ahead of expectations. In spite of a 5% drop to 17 TWh in generation compared with Q1 2015, the company announced net profits around a third higher year on year at Koruna 10 billion (€37 million). As well as the impact of electricity prices, CEZ appears to be suffering some internal problems on the generation front. Last week’s predictions for increased electricity production for 2016 were pared back to 66.2 TWh from 67.8 TWh in a previous forecast made mid-March. The biggest factor is lower expected output of 28.7 TWh from nuclear power plants, its lowest cost baseload production.A day after that prediction, CEZ announced extended outages this year at two of its four units at the Dukovany nuclear power plant for checks on piping welds, the problem that plagued it through the second half of 2015. The impact of those shutdowns has not been estimated yet. Part of the good news was a sizeable Koruna 1.1 billion profit from proprietary trading of electricity. Head of Commercial Operations Pavel Cyrani said these profits equaled those for a whole year in the past. Volatility on the market had created profitable trading opportunities but these would not necessarily endure through the rest of 2016, he warned. Another one-off Q1 bonus was a Koruna 1.3 billion windfall profit from Turkish currency operations. Nevertheless, in the light of managers’ complaints that it is still unclear how electricity prices will evolve over the next nine months, CEZ stuck to its conservative financial prediction for the full year. And CEZ is also facing teething problems with some of its new and retrofit coal-fired power plants due to begin full operation this year.The 660 MW Ledvice power plant is currently operating at around two-thirds of capacity and is not expected to be at full capacity until the third quarter of the year at the earliest. This seemed prudent, given the Koruna 1.5 billion decline in Q1 earnings from electricity produced from conventional power plants. CEZ says there are problems still being resolved with turbines and boilers when operating at full capacity, with the generator in discussions with boiler supplier Alstom over who should pay for the repairs.Meanwhile at the three 250 MW retro-fit units at Prunerov, CEZ says teething problems should be solved within the next few weeks. Going forward, according to a presentation from April, CEZ is still expecting to take a Koruna 5.7 billion hit on its 2016 overall earnings because of lower realized electricity prices, and earn Koruna 900 million less from CO2 credits due to a lower annual free allocation in 2016. The size of the expected overall drop in earnings was confirmed in May. German wind talks CEZ has moved to diversify and boost its revenue streams by moving into energy services for companies, solar panels and smart solutions for firms and households, and by increasing its steadily earning distribution assets. Achieved price decline CEZ forward-sells a large portion of its expected electricity output, usually averaging 55 TWh-57 TWh a year, with the move insulating it against some of the damage from falling wholesale spot prices. At the April presentation it said 85% of 2016 production had been sold by the end of February at an average price of €35 MWh. Finance director Martin Novak said talks on acquiring wind projects in Germany were “intense,” conceding, however, that competition for assets was fierce. CEZ had to seek out projects which, for various reasons, investment funds and others were unable to buy into, he said. These included projects in various stages of development. That path also increased potential returns, he said. It announced May 10 that 72% of earmarked production for 2017 was sold by April 30 at an average price of €31 MWh. And all of the latest average prices in the most recent figures to 2020 (see table) are lower or at best the same as those given during the April presentation, meaning that prices had weakened in the latest deals. The overall target is to boost revenue to around Koruna 6 billion by 2020 from renewables in Germany, Poland, and other “stable countries”. CEZ: FORWARD SALES OF ELECTRICITY CEZ was also interested in EDF’s heating plant assets being offered for sale in Poland. Here, Novak said developments remained at a very early stage. 2017 2018201920202021 % of pre-sold power as of April 30, 2016 72.0 41.0 18.0 10.0 2.0 Average price of forward sales (€/MWh) 31.0 30.5 32.5 38.0 36.5 % of pre-sold power as of February 30 67.0 35.0 15.0 10.0 2.0 Average price of forward sales (€/MWh) 31.5 31.5 34.5 38.5 36.5 — Chris Johnstone Source: CEZ © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 9 POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 Powervault targets smart tariff future UK energy storage developer Powervault is getting on with fitting affordable domestic batteries ahead of a smart power revolution that will blow the UK market wide open, the company says. Early adopters are being found amongst the UK’s 850,000 solar PV householders. But the installation of 20 million smart meters offers a much bigger opportunity, according to Powervault’s chief executive Joe Warren. The more exciting market opportunity for Powervault, however, was via smart tariffs and smart grid services.There are a million smart meters in UK homes at present, with an ambitious rollout program targeting 20 million by 2020. The government has asked regulator Ofgem to remove barriers to smart tariffs and, once they are introduced, “anybody in the country will be able to benefit from Powervault,” Warren said, “and we can achieve our vision of Powervault becoming as common place as dishwashers or washing machines.” “We’re a practical company focused on getting things done in anticipation of huge change ahead,” Warren told S&P Global Platts May 17, noting that Powervault was “battery technology agnostic. Lithium-ion has become extremely fashionable but I’m sure there’ll be other technologies coming along in the next few years.” Powervault launched two years ago using lead acid batteries because they were the cheapest option in the market. “That remains the case today,” Warren said. Stacking benefits “We’re open with our customers that they are going to have to replace lead acid batteries every five years during the lifetime of the product [15-20 years],” he said. In addition, Powervault has just signed an agreement with demand response aggregator Open Energi to develop dynamic frequency response in its units, aggregating them and bidding the service into the grid. Because Powervault’s unit can house different battery types, and Lithium-ion costs are forecast to fall by 50%-75% over the next five years, “people can buy lead acid today and upgrade to Lithium-ion, although we’re already seeing demand for our Lithium-ion products today, and we expect to sell both technologies going forward,” Warren said. “We’ll be able to stack some additional benefits on top of the time of use tariff benefits. With storage at any level – domestic or grid-scale – you have to work out how to stack multiple benefits to maximize the value. That’s what we looking at over the next 12 months.” The company is just getting off the ground. It is on target to install 500 units by the end of this year and aims to hit 50,000 by 2020. The machines are already connected to Powervault’s ‘cloud’, allowing the company to view data and potentially control them remotely. “We also have a product for those with the Economy 7 tariff and solar panels, where we can tell the product to start charging at night,” Warren said. “There are some simple changes to be made to the hardware in the product to make it fully compatible with frequency response.” “We started in the solar market [850,000 households have solar panels in the UK], where we found willing installers and early adopters. Customers like the savings, the feeling of independence from the grid, the environmental angle and the ability to plug directly in to the unit in the event of a blackout,” Warren said. Open Energi already has thousands of sites with frequency devices on them “and we think it would be relatively easy to integrate our cloud with theirs to provide that service to the grid,” he said. SMART TARIFF CONTROL kW How would the user benefit from this? 1.0 Cloud shifts low cost electricity to day-time Charge off low cost daytime electricity Actively controls storage to avoid evening peak “There are lots of different ways and we’re looking at that,” Warren said. “If you look at the last five years, we’ve seen business models where the value of feed-in tariffs is used to help finance cost reductions in solar panels. People could be offered the Powervault at lower cost, or get a payment. We’re confident we can roll this technology out with a proposition that works best for the user. 0.8 0.6 0.4 0.2 0.0 00:00 06:00 12:00 Import Low cost energy stored 18:00 Data protection is an issue, Warren acknowledged. “We take it very seriously. Customers today are fully aware that data from the Powervault are going into our portal and a lot of consumers are savvy about that – it has become normal, they are happy to allow the process if it makes their lives 00:00 Peak avoidance Energy discharged Source: Powervault © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 10 POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 SOLAR SHIFTING WITH ACTIVE DAYNIGHT CONTROL kW easier. One advantage over smart meters is that people have chosen to buy our products.” 1.0 4 kWh sweetspot Cloud shifts low cost electricity to day-time Actively controls storage to avoid evening peak 0.5 Powervault’s 4 kWh lead acid battery unit is the company’s most popular product, with a typical installed price of £2,900. Daytime import covered 0.0 It’s 4 kWh Lithium-ion unit has a typical installed price of £3,900. Other products range between 2 kWh and 6 kWh, with the largest units costing around £5,000 installed. Solar shifted to evening -0.5 -1.0 In terms of return on investment, solar PV feed-in tariffs deliver around 4.5% RoI. Powervault “improves on this, giving 5%-7% return, rising to around 10% when twinned with solar and an Economy 7 tariff. Smart tariffs would see this increase further,” Warren said. 00:00 06:00 12:00 Energy discharged Import Low cost energy stored 18:00 00:00 Peak avoidance Export Solar PV energy stored Source: Powervault throughout the evening peak. “We’re not in the business of blasting all the power out of the battery really quickly,” Warren said. “By doing that we keep the cost of the product low – the costs of inverters and chargers are based on size.” “We’ve gathered data to understand what would happen if we change battery size or the size of the inverter,” Warren said. “Based on this, 4 kWh is right for most people. People with solar panels can typically save around 40%-50% on their electricity bills. Powervault increases that by an additional 20%. With Economy 7 and solar PV, the unit saves you an additional 30%.” Half-hourly metering Turning finally to regulation, Warren called for the introduction of half-hourly settlement to unlock significant value in the domestic energy sector. When smart tariffs arrive, household bill savings are put in the 40%-50% range just for Powervault, independent of solar PV. “This would lead to the introduction of smart tariffs and blow the market wide open,” Warren said. “The National Infrastructure Commission believes that removing barriers to smart power could unlock £8 billion/yr of value to 2030. Today, home owners are responsible for a large proportion of peak energy consumption, but there is no incentive to avoid consumption at that time. If there was, we’d spend less on capacity mechanisms and transmission networks.” A few units have been sold to small commercial buildings, “but the great advantage of the domestic market is that people tend to be out during the day, so there is a big opportunity to shift the energy,” Warren said. The unit’s battery, inverter and charger (rated at around 800 Watts) are designed to shave off a portion of consumption REstore extends Total, Arcelor Mittal deals Having doubled aggregated demand response capacity under its management to 500 MW last year, REstore is now seeking to extend existing relationships with large consumers who are starting to see the benefits of participating in Europe’s ancillary power markets. balancing reserves – tertiary reserve and Short Term Operating Reserve-like services, primary reserve and dynamic Firm Frequency Response-type services,” said REstore co-founder Pieter-Jan Mermans. This implied a material expansion in the number of machines involved within Total’s industrial processes, that in future will be controlled to elicit earnings from electricity services without interrupting industrial production, he said. REstore has signed a new demand response framework agreement with French petrochemicals giant Total, the European demand response aggregator said May 11. Since 2014 REstore has had multiple Total manufacturing sites under contract in Belgium and the UK, seeking capacity market-like earnings. Under a new multi-year contract, the scope of the collaboration has been expanded to cover “all types of DR monetizing opportunities, including capacity markets and © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. A specific example would be new demand turn-up services, Mermans said. 11 POWER IN EUROPE ANALYSIS ISSUE 726 / MAY 23, 2016 Building trust “With penetration of RES increasing, we are seeing Transmission System Operators contracting for demand increase to deal with situations of oversupply of intermittent renewables on the grid,” he said. “Specifically in the UK, National Grid has introduced a new reserve called Demand Turn-Up, which is a STOR-like product if you like, but in reverse – it is there to increase consumption as well as decrease generation.” By its nature, DR aggregation involves direct connection to an industrial sites’ processes, sensors and realtime power data on one side, and to transmission system operators on the other. Both parties are, needless to say, highly sensitive to data protection. “Information security has to be a top priority for any player active in the Industry 4.0 or Internet of Things space,” said REstore co-founder Jan-Willem Rombouts. At Total Petrochemicals Feluy, the example is in primary reserve, where the company’s demand would be raised in less than 30 seconds by increasing manufacturing processes and/or decreasing local generation from on-site cogeneration facilities. This explains why an early-stage growth company like REstore has just put itself through an arduous 18-monthplus process of gaining ISO 27001 certification in information security, he said. These capacities would earn around €50,000-€60,000 per MW/year for doing this in the Belgian market. “The service is typically called on around 35 times a year, for a maximum two minutes per instance. So we’re talking about an activation time of around 70 minutes per year. That’s a very valuable 1.1 MWh,” Mermans said. While this was in the Belgian market, “it is applicable elsewhere – primary reserve in continental Europe and the UK is set by Entso-e specifications, which are generic to all countries involved.” Certification requires implementation of a clear security policy; stringent internal processes; and clear choices on the technology side “to make sure that all communications throughout [REstore’s Flexpond platform] are secure. We’re not aware of other aggregators having obtained this but we wanted to be proactive, we have to be trusted, and we are providing leadership in the sector,” Rombouts said. UK auction wins While no industrial consumer has point-blank refused to use automated demand response on data protection grounds, “there have been several occasions when questions of confidentiality and security of data have come up, and this area will become more and more important to industrial players and grid operators as our world becomes more interconnected, more sensors are coupled to process automation systems in factories, and those data are logged to the internet,” Rombouts said. Meanwhile Total’s UK sites contracted to REstore were bid into the UK’s Transitional Arrangements capacity market auction in January, as part of a larger aggregated pool. The auction, restricted to demand response and cogeneration bids, secured over 800 MW for winter 2016/17 at a clearing price of £27,500/MW. “We successfully bid a portfolio of 100 MW into the TA auction, the highest amount of any aggregator for firmlysigned up demand response. Kiwi Power was successful with a 170 MW portfolio of unproven demand side response units, so there is a risk there that not all of them will be signed up by go-live on October 1,” Mermans said. German potential Meanwhile REstore has a team building a DR portfolio targeting primary reserve earnings in the German market, Mermans said, “based on an expression of interest from [TSO] 50Hertz. It’s significant news that there is growing interest in the German market to include demand response as part of the solution. That is complemented by an initiative by German regulator BNetzA to open secondary and tertiary reserve to aggregators.” Incremental growth The new Total deal, and a similar expansion of services agreed with Arcelor Mittal earlier this year, exemplified how client relationships evolved for REstore, Mermans said. “We tend to start off on a specific site and target a specific market area, such as a capacity market or STOR-like services, where industrial consumers have time to react. Once DR services deliver against expectation, the number of sites, processes and reserves involved typically increase as part of a broader DR framework agreement,” he said. With a high penetration of intermittent renewables and a lot of flexible power hidden in manufacturing, the market has obvious potential, Mermans said. In France, meanwhile, REstore late last year signed a framework agreement with transmission system operator RTE to provide primary reserve, and expects to sign up a couple of large French consumers in the next few weeks. Again the potential is significant. RTE buys between 650 MW to 700 MW of primary reserve capacity in monthly auctions. As confidence builds so the consumer moves into primary reserve, “where the earnings are significantly higher, and the value proposition unfolds on a larger scale,” Mermans said. The aggregator’s approach remains the same throughout, Mermans said: “we seek out industrial processes where there is inertia or buffer capacity, such that demand response when activated does not intervene with the core mission of the manufacturing plant.” © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. “EDF is to divest 50% of RTE, that is significant structural news for us,” Mermans concluded. “RTE will become a truly independent TSO, a big step in unbundling the market, and in terms of the company’s capital.” 12 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 AUSTRIA BELGIUM Wind sector laments policy inertia Norther seeks EIB funding Allocations exhausted, backlog growing €450 million sought for 370 MW farm Austria’s wind trade group and leading wind farm operators have called for immediate revision of the country’s fiveyear-old renewables legislation. “Some 230 wind installations totaling 700 MW capacity have been approved but are caught up in a bureaucratic system which has brought a complete halt to the next step essential for construction,” said Stefan Moidl, general manager of the IG Windkraft trade association. Financial approvals are blocked by a bottleneck at the organization (OeMAG) which allocates support subsidies, Moidl said. “With allocations exhausted, that office is dependent on reform of the overall renewable legislation,” he said. OeMAG cannot process applications unless funding is available, but with no revision to the limiting legislation in sight, the outlook is bleak. Windkraft has noted that investors have already put up some €40 million in planning costs with no return in sight. “The projects on hold represent a potential investment of about €2.1 billion,” Moidl said. The current waiting list, extending until 2021, adds a further complication: once the basic approval is granted – site, technical aspects, connectability – OeMAG must agree to the financial side, that is, subsidies and operational/ commercial feasibility. The licensee then has the current year plus three years in which to get the project up and running, but the clock starts with submission of the application to OeMAG, not with OeMAG’s approval. With the backlist awaiting grants, this means that most current applications will not be processed within the waiting period. Current wind operators have rallied support from communities in which they have proposed installations, leading some 34 mayors as a group to urge reform of the current legislation so that facilities can be approved and built. “Our people were always for wind generation,” reports the mayor of a town in Burgenland, the province with the greatest wind density, adding “clean energy should be promoted, not hindered.” Martin Steininger, general manager of Simonsfeld wind farms in Lower Austria, added that “some of our installations are going on ten years and are ready for replacement or upgrading, but approvals are blocked in the system.” Lukas Puespoeck of the private Puespoeck group in Burgenland, which has several projects in the OeMAG backlist, said: “it is high time to deal with this problem and get moving. No other country has Austria’s opportunity to have 100% of its electricity from renewable resources.” Eneco Holding of the Netherlands and Nethys SA of Belgium are seeking a €450 million loan from the European Investment Bank towards the financing cost of Norther Offshore Wind, the 370 MW offshore wind park 22-km off the Belgian coast at Zeebrugge. In a May 18 note the bank says “a full environmental impact assessment was carried out and the environmental permit was granted in 2011” to the project. No full project cost was given. Details of the authorization process and its compliance with EU directives would be assessed by the EIB during appraisal, it said. In April this year, Belgian regulator CREG calculated the 2015 levelized cost of electricity for Norther at €127.04/MWh. In February, project company Norther NV appointed MHI Vestas Offshore Wind as preferred supplier of V164-8.0 MW turbines for the project. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. IEA recommends phase-out delay Closing reactors ‘will challenge supply, costs’ Belgium’s current policy to close all nuclear power plants between 2022 and 2025 should be relaxed to let the plants run as long as the regulator considers them safe, the IEA said in a review of the country’s energy policy May 18. Shutting the reactors would “seriously challenge Belgium’s efforts to ensure electricity security and provide affordable low-carbon electricity,” the IEA said. Belgium has two nuclear power sites, Doel and Tihange, comprising close to 6 GW across seven units built in the 1970s and 1980s. Nuclear accounts for around 47% of Belgium’s electricity generation. the IEA said the country needs to take a long-term approach to developing an energy policy. Given that responsibility for energy policy is divided between the federal and regional governments, the authorities must work decisively together to form a national energy strategy, it said. CREG proposes DSM improvements New flexibility roles defined Belgian regulator the CREG is proposing changes to Belgium’s demand side management regulation and approach in order to make it more user-friendly. Its proposals to date apply only to remote-metered clients, mainly large businesses, it said May 13. It stressed that it is not advocating widespread implementation of smart metering. Its report was drawn up at the request of the Belgian government. 13 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 The key proposal is that these businesses be able to choose a flexibility operator, independent of an electricity supplier. Neither the supplier nor the balancing party will be entitled to dispute their choice. This new market model envisages the creation of two new roles, one of which is the flexibility operator and the other the flexibility data system operator. The end-user sells his flexibility direct to the flexibility operator. Imbalances are corrected through centralized management of the volumes available. The flexibility operator then compensates the supplier on the basis of a negotiated price. If negotiation fails, a regulated price can be envisaged. Flexibility offers cannot be sold on. The CREG also sees a need for auxiliary services more user-oriented whereas it regards them as produceroriented at present. It sees a need for new products on the Belpex dayahead market to deal with constraints it has identified to certain types of demand management. The issue on the Belpex intraday market is a lack of liquidity. Quarter-hourly products on both markets would be beneficial, the CREG suggests, but that means coordinating with Belgium’s neighbors to deliver the full benefits. But if they were just limited to the Belgian market in the short term, that would nevertheless be good for the market as a whole. None of this is likely to happen overnight. New legislation is needed, which will have to be implemented by means of secondary regulation. Once that is in place, the CREG says the process should be progressive starting with balancing services and then intraday and day ahead markets. These generators must provide Elia with forecasts of long-term (one year) and short-term (day ahead) availability. The contracts also form the basic agreement for providing and activating ancillary services – primary, secondary, tertiary reserves, voltage control and black start. CENTRAL AND EAST EUROPE Kozloduy extension ‘due next year’ Investments underway for multiple extensions The first 10-year life extension for the remaining two units of the Kozloduy nuclear power plant in Bulgaria is expected to be agreed next year, Anton Ivanov, an energy adviser to the Bulgarian Parliament, said May 18. Ivanov, who was speaking at the Platts European Nuclear Conference in London, said that the 1,000-MW Kozloduy-5, a VVER-1000 unit, would likely have its 10-year life extension agreed on by the country’s energy regulator in 2017. He noted that an extensive investment and upgrade program for Kozloduy-5 and -6 was already underway, which would likely culminate in a series of life extensions. Ivanov noted that Kozloduy-1,-2, -3 and -4, all VVER-440 units, were already undergoing the decommissioning process. On the fringes of the conference Ivanov noted that demand for Bulgarian exports of electricity were well down in Turkey in Greece. A fall in demand in those markets, stiff competition from Romania and a surge in domestic CCGT output in the home market of Greece and Turkey had all reduced the pull on Bulgarian power, he said. Elia seeks black start services Three yearly contracts on offer to end-2020 Belgian system operator Elia is seeking agreements with one or more companies for the supply of the black start services, it said May 13 in a note in the EU Official Journal. It is looking to contract three power stations for each year of a delivery period beginning November 1, 2017 and running to end-December 2020. Black start services enable the grid to be restored swiftly in the event of a blackout. Production units providing the service are able to power up independently of the external electric grid. The location of production units, the speed of start-up and the availability of trained personnel are the main criteria based on which Elia contracts these services. The plants “must be in the Belgian control area, included in a CIPU contract and in the market during the delivery period,” Elia said. Bids or requests are participate in the tender are due by September 31, 2016. CIPU (Coordination of the Injection of the Production Units) contracts ensure that Elia has sufficient generation at its disposal to balance the grid. All units over 25 MW must have a CIPU contract. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. Poland favors co-firing Wind, solar at behest of minister Proposed amendments to Poland’s renewable energy law will give the country’s PiS government the power to favor stable technologies such as co-firing with biomass over wind or PV farms that only produce power intermittently, Rafal Hajduk, a partner at Norton Rose Fulbright said May 17. A support system for new RES projects, which replaces green certificates with feed-in tariffs or contracts for difference and an auctioning system, was due to take effect on January 1 this year but the government delayed its implementation until July 1 to make amendments to the RES law. The existing law cuts subsidies for co-firing with biomass by a half, which under the current low green certificate prices, has rendered the practice unprofitable. Under the amendments submitted to the Polish parliament on May 5, neither onshore wind nor solar PV 14 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 farms are allocated separate baskets under the auctioning system and secondary legislation gives the energy minister the power to decide which RES technologies are preferred in each new calendar year by choosing how much electricity is allocated between the baskets. In a meeting of the renewable energy parliamentary group on May 10, deputy energy minister Andrzej Piotrowski, said the modified auctioning system reflects the government’s goal to promote more stable renewable energy projects, adding that wind generation is unstable, damaging to the environment and causes additional social costs. PiS lawmakers have tabled a separate draft law regulating wind farms that introduces a minimum distance for turbines from residential buildings and protected areas for new projects. It also introduces new charges for both existing and new projects, that industry participants say will cause most wind farms to become unprofitable. “Taking into account the background, including the draft wind farm law and the declarations from government ministers saying that what Poland needs is stable renewable energy production rather than intermittent production, one can speculate these new rules would be used to promote more stable technologies like biomass, co-firing and waste energy rather than wind or PV,” Hajduk told Platts. Under the amendments the energy minister will also have the power to determine the period of subsidies for RES projects, which the current law fixes at 15 years. In theory the minister could choose to shorten the term for installations, Hajduk said. The amendments also in effect reinstate subsidies for co-firing because the reduction in support brought in by the current law will no longer apply to “dedicated biomass co-firing installations” and the definition for such an installation is “a multi-fuel fired installation, in which the share of electricity or heat produced from biomass, bioliquids, biogas or agricultural biogas is higher than 20% of the total amount of electricity or heat produced”. Unlike the current law, co-firing installations would also be able to take part in future auctions to receive subsidies. The amendments do not change the provision that existing RES projects can choose to remain under the green certificate support system until the amendments are passed by Parliament, which the government hopes to do before July 1. April’s average price was also down 14% year-on-year from Zloty 126.81/MWh, according to figures from the Polish Power Exchange (TGE). The average price of green certificates, which are used in Poland to subsidize renewable energy production, have fallen from a high of Zloty 249/MWh in February 2014 and since March last year have been below Zloty 140/MWh thanks to an oversupply on the market, which is currently estimated at the equivalent of 18 TWh. The oversupply was caused historically by the widespread practice of co-firing with biomass, which in 2012 reached 6.7 TWh, or 42% of the country’s total 16.1 TWh renewable energy generation. In 2011, co-firing accounted for almost 50% of the country’s total RES production. Since 2012, the level of co-firing has declined because it is much less profitable at lower green certificate prices and since the start of this year has almost stopped completely due to lower subsidies. However, the shortfall has been completely covered by increasing wind generation, which has grown more than fifty-fold since 2005 from 135 GWh to 7.27 TWh last year. In 2015, Polish wind generation accounted for 47% of the country’s total RES production. Another reason for the oversupply was that the country’s RES quotas set by the Ministry of Economy did not match the supply of green certificates. Poland’s RES quota has grown in recent years by 1% annually. In 2015, it was 14% and this year it is 16%. The previous Polish government enacted a renewable energy law, with revised subsidies that took force in January, which changes the support system for RES projects to one based on feed-in tariffs and auctioning. Under the law, projects that were completed by the end of last year could choose to stay under the green certificate system or adopt the new system. However the PiS government, which took office last November, is currently reviewing the RES law, and recently published draft amendments that include reinstating support for co-firing with biomass. EUROPE Nordic utilities call for ETS reforms Hike in reduction factor proposed Nordic power utility giants Fortum, Statkraft and Vattenfall want improvements to the EU Emissions Trading System “to better reflect the high ambitions of the Paris Agreement”, they said in a joint statement May 20. The chief executives of the companies have called for three “immediate actions” to be incorporated in the ongoing revision of the EU ETS Directive for Phase 4 of the system, to run from 2021-2030. Polish GC prices continue to fall Certificate values down 14% YoY The average price of Polish green certificates in April fell 4.89% month-on-month to Zloty 108.71/MWh (€24.94/ MWh), continuing the general downward trend over the last 12 months. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 15 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 The actions are: and a group of Finnish shareholders, including industrial companies and municipal power companies, which hold the remaining 66%. Forsstrom said that Fennovoima was expecting a construction license from the government following an assessment from the Finnish nuclear regulator, the Finnish Radiation & Nuclear Safety Authority, in 2018. to increase the linear reduction factor of the system to at least 2.6%/yr from 2021 (this determines the pace of reduction in emissions and is currently set to rise to 2.2%/yr from 2021); to reduce the supply of ETS allowances according to the impact of overlapping national policies; FRANCE and not to sell allowances from the Innovation Fund before 2023 in order to minimize market distortion. HPC FID awaits consultation Further scrutiny as conditions worsen The Paris Agreement on climate change (COP21) established a framework for a global transition to lowcarbon economies, the utilities said, but the EU ETS does not reflect that ambition and needs strengthening. “Fortum, Statkraft and Vattenfall are strongly committed to making EU power generation CO2neutral by 2050 at the latest,” they said. “The earlier the EU ETS is adjusted to reflect the long term EU climate goals, the lower the overall societal costs for reaching the long-term climate target will be, and the more predictability the EU ETS operators and investors will have.” The Nordic utilities’ suggestions look similar to some of those considered by the European Commission during its review process to reform the EU ETS in 2013/2014, investment bank RBC said May 20. “To now suggest that something needs to done – again – to the EU ETS might be met with more resistance than support in our view,” the bank said. A more viable approach seemed to be unilateral carbon price floors, as in place in the UK, being planning in France and observed in Germany and other Member States. National carbon floors still need the European Commission’s approval and are by no means guaranteed, “but at least this mechanism only needs to deal with one entity, not the entire European Parliament and the panel of energy ministers/secretaries of each EU Member State,” RBC said. A final investment decision on the proposed Hinkley Point C nuclear power plant in the UK will be taken only after a consultation with a works council of three French labor unions, Xavier Girre, Chief Financial Officer of EDF, told a financial results conference call in Paris May 10. Girre declined to give a specific date for when this might happen. The final investment decision on the 3.2 GW plant has been repeatedly delayed and triggered EDF board member resignations on concerns about the financial impact of the project on EDF’s balance sheet. The project, estimated to cost £18 billion, has a 115month construction schedule, EDF Energy’s Paul Spence said May 18. Nuclear generation in France was 116.1 TWh in the first quarter of 2016, about 1.8%, or 2.1 TWh, less than the firstquarter 2015 level of 114 TWh, Girre said. EDF said it had adjusted down its nuclear output target for 2016 to between 408 TWh and 412 TWh due to an extended maintenance outage at the 1,382 MW Paluel-2. First quarter sales were down 6.7% to €21.4 billion, with all divisions reporting lower revenue on mild weather, historically low prices and intensifying competition, Girre said. Total French output and sales of 147 TWh were stable on the year. French hydro output of 12.3 TWh was down 0.8% year on year. UK nuclear output, meanwhile, was stable at 15.7 TWh. Group generation of 168.5 TWh for the quarter was down from 177 TWh for Q1 2015. Coal/fuel oil generation was responsible for much of the decline, itself down 46% from 13.5 TWh to 7.3 TWh. The company noted negative wholesale prices trends and low volatility due to mild weather in Europe, with EDF Trading sales down over 35% on the year to €173 million. A project update on the Flamanville 3 EPR nuclear plant noted finalisation in late March of the main primary circuit and installation of all four steam generators, reactor vessel, pressurizer and reactor coolant pumps. Next steps include ramp up of the electromechanical build; a start of plant system testing; and system performance testing in Q1 2017. Overall project costs remains at €10.5 billion, with first fuel loading at the 1.65 GW plant set for Q4 2018. FINLAND Hanhikivi-1 ‘on track for 2024’ First concrete pour could be in 2018 The Hanhikivi-1 nuclear power project in Pyhajoki is on track to start commercial operation during 2024, Fennovoima project director Minna Forsstrom said May 19. First concrete could be poured at the new nuclear site in 2018, Forsstrom said on the sidelines of Platts’ European Nuclear Power Conference in London. Hanhikivi-1 is a planned 1,200-MW AES 2600 model VVER nuclear reactor. Fennovoima is a consortium between Russian state nuclear company Rosatom, which owns 34%, © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 16 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 EDF SALES IN FRANCE (TWh) Finally, EDF’s renewables unit, EDF Energies Nouvelles, announced that Enbridge Inc of the US is to take a 50% share in Eolien Maritime France (EMF), the company building three offshore wind farms totaling 1.4 GW in French waters. EMF was awarded the three projects in 2012. They are Eoliennes Offshore des Hautes Falaises (498 MW) off the coast of Fecamp in the English Channel; Parc du Banc de Guerande (480 MW) off the coast of SaintNazaire, Atlantic coast); and Eoliennes Offshore du Calvados (450 MW) off the coast of Courseulles-surMer, English Channel. Construction is expected to start gradually from 2017, EDF said. No financial details on the deal were given. Q1 2014 Local authorities, companies and 14.2 professionals (not at historical tariffs) Local authorities, companies and 47.5 professionals (at historical tariffs) Residential customers 44.8 Total 106.5 Q1 2015 15.2 Q1 2016 39.5 45.6 12.2 51.2 112.0 47.0 98.7 Source: EDF EDF GROUP: NET ELECTRICITY OUTPUT Q1 2016 (TWh) Nuclear Coal/Fuel oil CCGT Hydro Other renewables Group Total bids for Saft Q1 2015 Share Q1 2016 Share 135.3 76%132.7 79% 13.5 8% 7.3 4% 11.1 6%11.4 7% 13.48% 138% 3.7 2% 4.1 2% 177.0100%168.5100% Source: EDF Storage play follows solar acquisition review processes, about 50 were currently in use in the French nuclear fleet. EDF later said that 60 parts could be affected. Miniere said ASN would carry out its own analysis “in the weeks to come,” but that EDF would not shut any reactors as a consequence of the discrepancies since they do not have an impact on the parts’ mechanical integrity. Areva said April 29 the discrepancies had been revealed in some of the manufacturing records that are part of the so-called fabrication files of certain components. During the meetings, EDF’s head of new nuclear projects Xavier Ursat said the first results on the anomalies on the head and bottom of the Flamnville-3 EPR were “very encouraging.” Areva, EDF and nuclear safety authority ASN reported in April that chemical tests Areva performed in 2012 on steel similar to that used in the reactor vessel top and bottom heads at Flamanville-3 showed a carbon content of 0.30%, compared with the 0.22% maximum limit set by French regulation. High carbon content in the vessel heads can reduce fracture toughness, which is the ability to withstand crack propagation. EDF and Areva said April 13 that they would extend testing of the vessel parts to the end of 2016 to strengthen the robustness of the demonstration of the quality of the parts. The final tests will be submitted in November to ASN, Ursat said. He said that construction work on the Flamanville-3 reactor was going according to schedule. The startup and loading of the first fuel of the EPR in northwest France has been delayed to Q4 2018 with costs to complete the unit estimated at €10.5 billion, EDF said September 2015. The re-organization of the project’s management structure, notably the clarification of the schedule with suppliers to the project, is allowing the company to stick to its new schedule announced in September, Ursat said. The next project milestones will be the end of construction and start of the pre-operational testing phases scheduled for early 2017, he said. French petrochemical giant Total has offered to buy French battery manufacturer Saft for €950 million, the companies said May 9. The proposed acquisition, unanimously approved by Saft’s Supervisory Board, is subject to review by French Financial Markets Authority, the companies said. “The acquisition of Saft is part of Total’s ambition to accelerate its development in the fields of renewable energy and electricity, initiated in 2011 with the acquisition of [solar energy company] SunPower,” Total CEO Patrick Pouyanne said. “It will notably allow us to complement our portfolio with electricity storage solutions a key component of the future growth of renewable energy,” he said. In November Saft launched its Power 2020 plan, focused on higher-value grid-level applications of its battery technology rather than the low-cost, high-volume domestic storage market. “Saft will concentrate its development activity in technology bricks customized to specific requirements where mass production products cannot meet customers’ needs in terms of battery performance,” it said. By the end of 2019, Saft said it would seek to reduce the cost of purchased material by 4% to 5%, lower total manufacturing costs by 5% to 6% “and improve supply chain management to reduce Operating Working Capital by 2% as a percentage of annual sales.” EDF dispels Le Creusot fears No reactor to shut due to discrepancies No reactor will shut due to discrepancies found in 60 fabrication files at Areva’s Le Creusot forging subsidiary, EDF’s director in charge of nuclear and thermal assets Dominique Miniere said during the company’s shareholder meeting in Paris May 12. French nuclear safety authority ASN said May 3 that 400 parts with discrepancies detected in the quality © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 17 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 GERMANY Palm Papier GmbH is seeking a €37 million loan from the European Investment Bank towards the €76 million cost of two combined heat and power plants to be built in existing paper mills based on recycled paper in France and the UK, EIB records showed May 17. Turbines in at Gode Wind 1 and 2 On schedule for summer operation Dong Energy has completed installation of all 97 turbines at the Gode Wind 1 and 2 offshore wind project in the German North Sea, the Danish company said May 19. The 582 MW project 45 km offshore will go into operation this summer after offshore construction started in April 2015, it said. Dong, which plans to go public this summer, has a 50% share in the project having sold the other half to a group of Danish pension funds for €600 million in 2014. It will operate and maintain the wind farms. It has a target of 6.5 GW of offshore wind capacity by 2020 and reached the 3 GW milestone last year with its Borkum Riffgrund 1 project in the German North Sea. Cal reacts to €30/mt floor price news Impact likely to be marginal Calendar 2017 baseload power prices in France ticked up May 17 on news that a national carbon floor price would be set at €30/mt. Speaking on the fringes of a meeting with EU ambassadors in Paris, environment minister Segolene Royal said France would “fix a carbon price in the next finance law of about €30/mt.” Details of the mechanism were not yet available from the ministry. French Cal 17 base was seen trading at €30.40/MWh May 17, up 85 euro cent on the day, while Cal 18 baseload was heard trading up by the same amount at €31.05/MWh. Details of a carbon floor price are due to be presented September in the country’s budget for 2017, Royal said, with earlier reports citing January 2017 as the roll-out date. In late April Engie chief operating officer Isabelle Kocher said the wholesale power price impact of a French scheme would be lower than that of an EU-wide scheme. “The marginal price is not set by coal in France, but by gas,” Kocher said. “Nevertheless, even with a pure French scheme we consider that there would be an outright power price increase, not massive, and probably . . . a slight price increase in Belgium because these mechanisms are contagious.” Cosma Panzacchi, analyst at research and brokerage company Bernstein, said that “even a €30/t French-only carbon price floor” would not impact power prices by more than around €2/MWh. At the end of March, Royal asked former development minister Pascal Canfin, economist Alain Grandjean and Engie CEO Gerard Mestrallet to present by July 1 a list of proposals for the introduction of an EU-wide carbon price floor or “corridor.” This news was followed one month later by President Francois Hollande’s announcement that France will introduce a national carbon price floor unilaterally by January 2017. Nordex doubles Q1 installations Germany, Pakistan, France main markets Nordex installed 490.5 MW across nine wind markets in first quarter of 2016, more than double the 240.2 MW installed in Q1 2015, the German wind turbine manufacturer and installer said May 10. Its main markets in Q1 2016 were Germany with 147 MW, Pakistan with 95 MW and France with 72 MW. At 573.9 MW, meanwhile, turbine production was 24% up on first quarter 2015’s 462.1 MW. Rotor blade production climbed by 141%, or 66 units, to 159 rotor blades, driven by improved processes at Nordex’ Rostock facility. During the quarter the group received firmly-financed orders worth €541 million, down from Q1 2015’s €644.1 million. The 16% decline was due to a single large-scale contract last year that is still being executed, Nordex said. The company’s firm order backlog was stable at €1,638 million as of 31 March 2016. The figures do not include Spain’s Acciona Windpower, which merged with Nordex April 1. The new subsidiary will be consolidated from the second quarter of 2016. Nordex has installed wind power capacity of 18 GW in over 25 markets. In 2015, Nordex and Acciona Windpower recorded combined sales of €3.4 billion. Its product range is focused on onshore turbines in the 1.5 MW-3 MW class. FRENCH CAL REACTS TO CARBON NEWS 34 (€/MWh) (€/mt) French year-ahead base (left) 9 EU court rules on EEG state aid EUAs nearest December (right) 32 8 30 7 28 6 26 5 Some RES levy relief illegal 24 Jan-16 Feb-16 Mar-16 Apr-16 May-16 The European Commission was right to categorize some of Germany’s reductions in renewable surcharges for heavy industry under its 2012 EEG law as illegal state aid, the EU General Court ruled May 10. The EC decided in 2014 that all the renewables support under the 2012 EEG law was state aid, but that 4 Source: S&P Global Platts © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 18 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 GERMAN OFFSHORE WIND SNAPSHOT Name Alpha Ventus Baltic 1 Bard I Riffgat Baltic 2 Dan Tysk Meerwind Butendiek Borkum Phase 1 Global Tech I Nordsee Ost Amrumbank West Borkum Riffgrund I Owner EWE, Vattenfall, E.ON EnBW Ocean Breeze Energy EWE EnBW Vattenfall, SWM Blackstone Various Trianel SWM, ENTEGA, Axpo RWE E.ON Dong Capacity (MW) Status 60 Operating 48 Operating 400 Operating 108Operating 288 Operating 288 Operating 288Operating 288Operating 200 Operating 400 Operating 295 Operating 288 Operating 312 Operating Total in operation Nordergründe WPD AG Gode Wind I Dong, pension funds Gode Wind II Dong, pension funds Sandbank Vattenfall, SWM Veja Mate Laidlaw Capital Borkum Phase 2 Trianel Borkum Riffgrund II Dong Nordsee 1 Northland, RWE Deutsche Bucht Laidlaw Capital Hohe See EnBW Albatros EnBW Iberdrola Wikinger Arkona E.ON, Statoil Capacity in development 3263 111 330 252 288 400 200 312 332 210 450 395 350 385 4015 Under construction Under construction Under construction Under construction Advanced development Advanced development Advanced development Advanced development Advanced development Advanced development Advanced development Advanced development Advanced development Online Year 2009 2011 2013 2014 2015 2015 2015 2015 2015 2015 2015 2015 2015 2016 2016 2016 2017 2017 2018 2018 2018 2019 2018 2018 2019 2019 Source: S&P Global Platts PowerVision The EC put together a list of 68 sectors eligible for such reductions, based on how much they spend on electricity compared with their contribution to the economy – known as electro-intensity – plus how exposed they are to global trade, known as trade intensity. The list includes sectors with an electro-intensity above 10% plus a trade intensity above 10%, sectors with an electro-intensity above 20% plus a trade intensity above 4% and sectors with an electro-intensity above 7% and a trade intensity above 80%. Governments can also add companies outside these sectors that have a special problem with electro-intensity. Governments can grant reductions to all eligible companies so they only have to pay up to 15% of their full contribution to renewables support costs, or 4% of their gross value added, whichever is lower. The cap on how much very highly energy intensive companies have to pay is set lower, at 0.5% of their gross value added. Energy law expert and Bird & Bird LLP partner Matthias Lang said that current work on Germany’s 2017 EEG law, moving from FiTs to auctions, “is due to the fact that the Commission only cleared the renewables support regime EEG 2014 for a limited time, using its state aid law powers. If the General Court had said that the EEG 2012 did not constitute state aid, this would have meant that Germany (and other Member States) would be much more free in shaping their national renewable energy support schemes. The revision of the EEG for 2017 would perhaps look quite different,” he said. most of it was compatible with EU state aid rules, and therefore allowed. Some energy-intensive companies, however, had benefited from reductions to the surcharge levied to support renewables to an extent that gave them an undue advantage over their competitors, and therefore broke EU state aid rules, the EC said. This illegal aid given in 2013 and 2014 had to be paid back, it said. The EC did not specify at the time how much illegal aid was involved, but local media reported the German government estimated it would have to recover about €30 million in total from 350 companies. Germany had argued that none of the support was state aid and had challenged the EC’s decision in court. The court said that it rejected all of Germany’s arguments to have the EC decision annulled. The ruling can be appealed on points of law only within two months. Any appeal would be heard by the EU’s higher Court of Justice. Germany updated its EEG law in 2014, and the EC approved this new version as being entirely in line in with its own new EU state aid guidelines for energy and environmental protection, which were also adopted in 2014. These 2014 guidelines set out the rules EU governments must follow when considering aid to renewables or other energy sectors, except nuclear. The rules allow governments to limit how much energyintensive users such as steel, aluminum and chemicals producers pay in renewable levies and taxes under certain conditions. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 19 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 E.ON Q1 generation falls 7% Hard landing for coal, hydro E.ON Group’s first quarter 2016 owned generation fell 7% year-on-year to 50.5 TWh, the German utility said May 11. Total power procurement of 192.9 TWh was down 2.67% on Q1 2015. The decline originated in reduced dispatch of coal-fired power stations in France, Germany, and the UK, and from the sale of generation operations in Italy and Spain in 2015, E.ON said. By source, natural gas was the largest contributor to E.ON’s owned generation Q1 2016 mix, at 18.8 TWh (up from 18 TWh in Q1 2015). Nuclear output of 13.3 TWh was down from 14.4 TWh. Lignite generation was stable at 3.6 TWh. Hard coal generation was down 34%, from 11.8 TWh to 7.8 TWh, while hydro was down from 7.1 TWh to 3.3 TWh. Wind was up from 2.6 TWh to 3.4 TWh. E.ON’s Q1 2016 electricity sales of 188.9 TWh fell 3% year-on-year, while gas sales climbed 16% to 503.9 TWh. Lower wholesale prices and the decommissioning of Grafenrheinfeld nuclear power station in June 2015, plus worsening market conditions in Sweden were behind a stark decline in nuclear earnings, down over 34% to €332 million ($378 million). Conventional fossil-fired generation earnings fell 14%, meanwhile, to €190 million, E.ON noting that front-year wholesale prices in the German market hit a 12-year low during the period. Meanwhile gross earnings from renewables also declined, by 10% to €345 million, with lower wholesale prices and the sale of assets in Spain and Italy more than offsetting strong growth in wind, following commissioning of Amrumbank West and Humber Gateway offshore wind farms. Group investment of €697 million was up 4% while underlying net income of €1.314 billion was up 30% on Q1 2015. Operation has begun at a new 60 MWe, 100 MWth combined-cycle gas turbine cogeneration plant at the Marl chemical park, Nordrhein-Westfalen, E.ON and Evonik Industries said May 12. The unit, which replaces a coal-fired plant, is to be operated by Evonik and was developed, financed and built by E.ON Connecting Energies. Fuel efficiency is put at 89%. The plant would contribute to the political objective of increasing the share of combined heat and power in Germany’s power generation mix from 16% to 25% in 2020, Evonik said. TWh, the German utility reported May 12. Gas sales volumes fell 9.3% to 97.1 TWh. Impairments of €204 million were recognized for gas storage facilities, “primarily due to changes in price expectations,” RWE said. “We are still confronted with burdens in the gas midstream business because the cost of managing and marketing gas storage capacity contracted over the long term cannot be recovered,” it said. Conventional generation earnings continued to decline on weak wholesale prices, with the division’s operating result down 20% year on year to €354 million. “This was contrasted by lower fuel purchase prices, which caused the market conditions for our gas-fired power plants to be slightly more favourable and their utilisation to improve accordingly, primarily in the UK,” RWE said. Supply’s operating result, meanwhile, was down 2.2% to €543 million, with increases in network fees, taxes and levies in German retail only partly offset by price increases. Further, the UK retail business lost a significant number of domestic customers last year, with only some enticed back by cheaper tariffs, while the pound weakened against the euro, the utility said. Nevertheless, the quarterly results showed RWE in a much healthier light than in recent times, with a headline 7% increase in Group operating result to €1.7 billion. This was partly attributable, RWE said, to energy trading, which made “an unusually high earnings contribution” of €166 million, up from €7 million for Q1 2015. “Our three future-oriented divisions, Renewables, Grids and Retail, are developing well,” said RWE finance officer Bernhard Gunther. The commissioning of offshore wind farms Nordsee Ost and Gwynt y Mor, in particular, had a positive effect on the results, he said. Renewables’ operating result of €154 million was stable on Q1 2015, with the significant drop in wholesale prices weighing on earnings, “as some of our renewable assets do not receive fixed feed-in fees from government and are therefore exposed to this market risk,” RWE said. Investment in the quarter of €373 million was down 10% year on year. Conventional generation spend has virtually dried up after UK gas-fired power stations at Pembroke and Staythorpe were completed last year. Capital spent on renewables was also down due to completion of Nordsee Ost and Gwynt y Mor. Grid infrastructure investment, however, was up. GREECE RWE rises from the depths Gas exceeds lignite as demand dips Offshore, trading bright spots Gas-fired output up 137% in April RWE’s first quarter 2016 power generation increased 1.6% to 57.4 TWh while electricity sales volumes rose 4.8% to 70.1 Greek electricity demand in April fell 3.3% year-on-year to 3.6 TWh, data from system operator Lagie showed May 16. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 20 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 GREECE ENERGY BALANCE STATISTICS, APRIL 2016 (GWh) Apr-16 Production Lignite Oil Gas Hydro Renewables Total production Imports Exports Import/export balance Demand Low voltage customers Medium voltage customers High voltage customers Pumping Total demand Peak load (MW) YoY change (%) 727 0 843 393 771 2,734 970 99 871 2,212 860 531 1.2 3,605 6,451 (21:00, 01/04/16) YTD 2016 YoY change (%) -37.00 4,501.0-27.00 N/A 0.0N/A 137.00 3,888.094.10 -16.60 1,302.0-39.50 -3.20 2,823.02.70 -1.50 12,513.0 -4.20 -5.30 3,902.0-11.40 36.30 362.023.80 -8.50 3,541.0 -14.00 -10.10 10,240.0 -11.60 4.70 3,760.0 -2.10 21.20 2,044.0 18.90 -84.30 9.8-72.10 -3.32 16,054.0 -6.57 -9.00 8,390 (20:00, 19.1.16) -4.70 Source: LAGIE SA ITALY MWh, market operator Gestore Mercati Energetici (GME) said May 16. The April average was 33% lower in a year on year comparison, GME said. Record lows were achieved across all of Italy’s price regions, with the North at €30.83/MWh and Sicily at €36.70/MWh. The average April peakload price on the platform was €32.69/MWh, also down 33% year on year. Offpeak dayahead prices averaged €31.64/MWh, again down 33% YoY. The hourly minimum in the month was €17.20/MWh while the hourly maximum was €66.36/MWh. Average hourly baseload volume on the day-ahead market during the month, comprising both bourse and over the counter trade, rose 2% year on year to 31.4 GWh, with average hourly baseload volume on the bourse up 4% YoY to 22.7 GWh. Total offered volume on the system (bourse and OTC) was 40.1 TWh in the month, unchanged YoY, while total demand volume was 23.9 TWh, up 3.9% YoY. Wholesale sales by generation type saw gas-fired generation cover 36.3% of supply in the month, up from 30.9% in April last year, while renewables, including hydro, covered 43.8% of supply from 45.7% in the same month last year, GME said. Coal covered 8%, down from 9.5%, while other traditional thermal sources supplied 9.9%, down from 12.9% the previous April, GME said. On the country’s international links, the market coupling mechanism saw 78% of the 2.6 GWh total hourly capacity allocated to the French border, with 98% of that amount being import volume. IPEX DA plumbs new low Edison prepares to repower 33% decrease on April 2015 Potential to double Abruzzo sites Average baseload day-ahead power prices on the IPEX power exchange in April dropped to a record low of €31.99/ MWh, well down on March’s previous record low of €35.22/ E2i Energie Speciali Srl (Edison) is preparing to repower three wind farms in Abruzzo, potentially boosting capacity across sites from 49 MW to 95.7 MW. Demand has now fallen over 6.5% year to date to 16 TWh, driven by much lower domestic consumption (down over 10% in April, and 12% YTD) and despite an 18.9% recovery in high voltage industrial consumption (in total, however, HV customers consumption equates to less than 20% of low voltage volumes). In production, lignite-fired power generation fell 37% year-on-year in April to 727 GWh, while gas-fired production increased by 137% to 843 GWh. Year to date, gas-fired production (3.9 TWh) is closing in on traditional lignite (4.5 TWh), a remarkable situation for Greece and one that underlines how much cheaper gas has become. Meanwhile hydro production had a seventh weak month in a row, down 17% at 393 GWh for April. Year-to-date hydro production was down 39% at 1.3 TWh. Total production for the month of 2.212 TWh was down 10% on April 2015. Reduced imports of power in April saw the import/export balance decline 8.5% to 871 GWh in a year-on-year comparison. Italy exported most to Greece in April, moving ahead of Bulgaria and FYROM. Finally, the decline in Greek wholesale power prices seen throughout 2015 has continued into 2016. Average ex-ante system marginal day-ahead electricity prices (set ahead of actual delivery) were €38.97/MWh in April, down 18.51% on April 2015’s average of €47.83/MWh. Average ex-post system marginal day-ahead prices (including balancing costs) were €41.23/MWh, down 23.67% on April 2015’s €54/MWh. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 21 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 In a May 3 noted in the EU Official Journal the company calls for bids to supply, install and commission 3.3 MW (maximum) wind turbines at Castiglione Messer Marino, Roccaspinalveti and Schiavi d’Abruzzo. At the 26.4 MW Castiglione Messer Marino wind farm, in operation since 2002, Edison seeks to install 12 and up to 16 new turbines. At the 13.8 MW Roccaspinalveti wind farm, in operation since 2001, Edison seeks to install nine new turbines, and at Schiavi d’Abruzzo (9 MW, operational 2001), Edison seeks four new turbines. Multi-year maintenance contracts are an additional option. The contract is set to run for 36 months from award. Bids are due by May 13. The wind sites in question entered operation around 2000-2004 under Italy’s old green certificate mechanism, now expired, according to Italian energy consultancy Nomisma Energia. The existing support mechanism (decree of July 6, 2012) foresees a register for repowering projects, but these Edison projects are not included. This means that Edison is probably hoping to be included in a new register, to be approved within a few months. “The new decree gives an incentive of €110/MWh for plants over 5 MW with a reduction according to actual costs compared to benchmarks, that could be up to 30%,” said Davide Tabarelli of Nomisma. Up to 40 MW in repowering schemes can be subsidized under the new decree. In detail, Italian wind generation rose 14% year-on-year to 774 GWh due to greater wind resources, while production outside Italy jumped 151% on the year to 452 GWh due to more generating capacity in France, Poland and Germany. In the thermal sector, where the company owns and operates a 480 MW combined cycle gas plant at Priolo, Sicily, as well as hydro assets, the company said it generated 1.1 TWh in the quarter. Of that, 695 GWh was from the gas plant and 384 GWh from the hydro assets. The company bought 527 MW of hydro production units in Italy from Germany’s E.ON in November last year. Its strategy for the rest of the year was to grow its international wind fleet from a position where it holds 626 MW outside Italy in an overall fleet of 1.72 GW including Italy. In the thermal sector, the company said it expects production at the Priolo unit to be affected negatively once a new interconnection linking Sicily to the mainland of Italy is concluded. The link, due online at the end of June would mean that more cheaper power could be transferred to Sicily from the mainland, potentially displacing output from Priolo from the local energy mix. In the renewable sector, the company reported an average price of Green Certificates of €100.10/MWh in the quarter, down slightly from €101.60/MWh in the same period last year. Feed-in tariff rates were also lower in Germany and France but slightly higher in Bulgaria over the same period, ERG said. Wind boost for ERG Demand drops 2.2% in April Wind output up 43% to 1.23 TWh Wind prospers, solar weakens Stronger wind resources coupled with increased generating capacity saw Italy’s ERG push up first quarter power sales by 20% to 3.3 TWh, it said May 13. Of that total, the company generated 2.3 TWh from its own asset base. ERG said it generated 1.9 TWh from its plants in Italy, equivalent to a 2.4% share of total domestic demand, as well as 0.5 TWh outside of Italy. The main boost in overall generation came from its wind fleet, which produced 1.23 TWh in the quarter, up 43% on the year. Italian power demand dropped 2.2% year on year in April, despite the Easter effect meaning more working days and warmer temperatures in the month, data from grid operator Terna showed May 13. In January-April cumulative demand was down 1.7% on the year at 101.2 TWh. Demand in the month was 23.5 TWh, down from 24.1 TWh in the same month last year, the data showed. The company said there were more working days in the month than April last year, due to the move in the date of Easter, ITALIAN ELECTRICITY BALANCE, APRIL 2016 (GWh) Apr-16 Apr-15 % change YTD end-Apr-16 YTD end-Apr-15 % change Hydro 3,760 3,709 1.411,667 13,301 -12.3 Thermal 12,30112,485 -1.558,476 57,543 1.6 of which biomass 1,230 1,249 -1.5 5,848 5,754 1.6 Geothermal 485 482 0.61,974 1,920 2.8 Wind 1,5661,460 7.37,338 6,655 10.3 Solar PV 2,2022,672 -17.66,168 7,145 -13.7 Total net production 20,314 20,808 -2.4 85,623 86,564 -1.1 Imports 4,103 3,897 5.318,562 18,533 0.2 Exports 611 443 37.92,141 1,580 35.5 Import/export balance 3,492 3,454 1.1 16,421 16,953 -3.1 Pumping demand 257187 37863 63736.0 Total demand 23,549 24,075 -2.2 101,181 102,880 -1.7 Source: Terna © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 22 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 while mean temperatures were 1.5 degrees Celsius warmer this year, in what is usually a shoulder month between winter and summer demand profiles. Peak hourly demand in April was 4.5% lower than a year earlier, reaching 44.6 GW on Friday April 1 in hour 11. Production fell on the year in April, mainly from thermal and solar photovoltaic, when compared to the same month last year. At the same time, the country boosted imports from neighboring countries by 5.3% year on year and its overall net import balance by 1.1% to a net inflow of 3.5 TWh, the data showed. Hydro production showed a first year-on-year increase in six months of 1.4% to 3.8 TWh. By the end of April, hydro resources were higher than the start of the month, with 2.9 TWh available, or 42.5% from 2.8 TWh available or 41.5% of maximum available at the start of the month. The figure was also higher on the year, with Italian reservoirs 41.2% full at the same point last year. conversion of animal waste; in the third, small-scale solar predominated. There were very few applications in the fourth phase. Overall, there were 3,352 applications for 3,126 MW. The average was 0.36 MW for the photovoltaic projects, for example. The averages in other categories were below 10 MW, except for 19.6 MW for 13 geothermal projects and 209 MW for four biomass projects. There will be a second round in the autumn, for which another €4 million is available. Minister Kamp welcomed these signs of strong interest in renewables as putting the Netherlands on the right path to meet its targets, notably 14% of energy from renewables by 2020. A review published May 17 of the cross-sectoral energy accord concluded that this is feasible, whereas other recent reports have suggested it will be touch and go. The energy accord review said that energy savings targets are more problematic. Kamp conceded that achieving those is “very ambitious” and will need everyone to commit fully to it. NETHERLANDS Bids in for Borssele offshore First round SDE+ bids in Eneco, Vattenfall, RWE lead bids Biomass applications swamp budget A consortium of Eneco, Shell and Van Oord announced May 12 that they had bid to participate in the Dutch government tender to build two windfarms off the Dutch coast. The consortium has selected MHI Vestas as the preferred wind turbine supplier. The wind power tender comprises of two permits to build and operate two windfarms of 350 MW maximum installed capacity each. The two windfarm sites, called Borssele I and II, are located 22 km off the coast of Zeeland. Vattenfall has also bid (without any partners) and RWE announced last November that it planned to bid with EDP Renewables and Macquarie. The Borssele wind farm sites I and II are the first of five 700 MW zones off the Dutch coast designated for development. A second tranche is scheduled for tender later this year (also for the Borssele zone), followed by two in the Hollandse Kust Zuid zone (in 2017 and 2018) and one in the Hollandse Kust Noord zone (2019). This first Borssele tender was originally meant to be held in 2015, but legal issues related to the unbundling of networks held up enabling legislation for the offshore wind program. The program aims to boost the country’s offshore wind capacity from 1 GW to 4.5 GW by 2023. A precondition of the awards is that offshore wind costs fall by 40% over the coming years. Dutch transmission system operator Tennet said March 8 it would invest to enable fulfillment of the Netherlands’ 2015 Wind Energy Act, installing an offshore AC grid in the Dutch North Sea connecting 3.45 GW wind capacity to 2023. Applications in the first round of SDE+ tenders this year for subsidy of all renewables except offshore wind requested a total of €8.2 billion – more than twice the €4 billion available, minister of energy Henk Kamp said May 9. The first round in April was in four phases. The level of the subsidy rises with each phase with a maximum of €0.09/kWh, €0.11/kWh, €0.13/kWh and 0.15/kWh per phase. The €4 billion total was reached half way through the second phase, although this does not mean later applications necessarily stand no chance. Not all project applications survive the screening process. It can also depend on the category into which they fall. In the first phase, the bulk of applications were for geothermal and liquid biomass projects; in the second, they were mainly for co-firing of biomass in coal-fired plants and SDE+ SPRING 2016 APPLICATIONS Category Applications Maximum applied Maximum requested power (in MW) budget (€ million) Wind 2129 Solar PV 3,104 1 Hydro 38 Total renewable power 3,128 1,478 Biomass – heat and CHP 137 569 Biomass – co-firing 4 836 Geothermal 13255 Solarthermal 4771 Total renewable heat, CHP 201 5,472 Biogas 25236 Total renewable gas 25 1,200 Total SDE+ Spring 2016 3,354 8,150 Source: Ministry of Economy © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 23 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 PORTUGAL Four-day record for RES Renewables outstrip demand, thermal vanishes Portugal chalked up a new green energy record between May 7-11 as renewable power met 100% of national demand for 107 consecutive hours, according to sector association Associacao Portuguesa de Energias Renovaveis (APREN). Using data from grid operator REN, APREN and green group Zero concluded that renewables covered 100% or more of national demand between 6.45 am CET (4.45 am GMT) on May 7 and 5.45 pm on May 11, APREN said May 16. Earlier in May Germany came close to the 100% renewable milestone on a combination of hydro, wind and solar output, while there are instances of other countries hitting the 100% RES target, notably Costa Rica, which last year racked up 75 days on non-stop renewable coverage, mostly from hydro. REN data showed conventional thermal generation between May 7 and May 10 of just 9.4 GWh from a total demand of around 500 GWh. In the first 16 days of the month, thermal generation was down naerly 60% year on year (see table). Total renewable production was around 630 GWh, outstripping national demand in the period by about one quarter. The excess production was exported to neighboring Spain, according to REN. Increased hydro resources have allowed Portugal to cut back on its thermal production. At the end of April, hydro reservoirs in Portugal were 88.6% full with 2.8 TWh held, the highest level since February 2014. The country has an installed capacity of 12.3 GW in terms of renewables, led by 6.0 GW of hydro and 5.0 GW of wind, according to the national Energy Department, DGEG. CONVENTIONAL THERMAL BLOWN AWAY IN MAY May 1-16, 2016 (GWh) YoY variation (%) Hydro 1,152.2155.0 Conventional thermal 254.3 -59.5 Ordinary Regime total production 1,406.5 30.2 Imports 39.9-70.1 Exports 352.4324.5 Import/export balance -311.2 -731.3 Pumping 85.239.9 Small hydro 112.7 89.4 Small thermal 299.0 -8.9 Wind 560.36.6 Solar PV 31.6 -21.8 Special Regime total production 1,003.6 5.3 Consumption 2,013.7-0.4 Adjusted consumption 2,016.4 -0.3 * Adjusted for working days and temperature variations Source: Redes Energeticas Nacionais SPAIN Between 5.5 GW and 10 GW of new-build combined cycle gas plants might be necessary if Spain is to conclude the move to a lower carbon future and meet renewable targets at the same time, the group said. Spain has 67 gas plants, all built from 2002-11, with a combined capacity of 25.4 GW. The plants have seen their utilization rate shrink from around 50% in the middle of the last decade to as low as 9%. Sedigas estimated Spain could use 29.3 million mt of oil equivalent by 2030, 3.9 million mtoe higher than EU regulation foresees and up from 23.7 million mtoe in 2014. From this forecast total, 3.5 mtoe would be for residential use, covering 19% of primary energy consumption by the sector, 1.3 mtoe for tertiary use (industry and others) covering 11% of sector demand, 2.0 mtoe for transport covering 5% of sector demand and 10.9 mtoe for power generation covering 34% of primary energy consumption from the sector. Under its projected generation mix, Sedigas said it could see a 49% stake in the mix supplied by renewables, 34% from gas and cogeneration and the remaining 16% from others, most notably nuclear, with coal reduced to zero. By capacity, CCGTs could represent 58% of total installed firm capacity of 62 GW, according to the group. Sedigas paints upbeat CCGT picture Gamesa opens offgrid system prototype Key backup role foreseen to 2030 Targets 1.2 GW market potential Natural gas could increase its share of primary energy supply in Spain to up to 33% by 2030, industry group Asociacion Espanola del Gas (Sedigas) said May 20. With the decarbonisation agenda gathering pace, Sedigas said the future lay in a combination of renewables and flexible, efficient back-up thermal technology. Sedigas, citing a study conducted in conjunction with consulting group KPMG, noted that gas-fired plants can, in many cases, reach full output in less than an hour, while Spain’s seven LNG terminals and three major import pipelines afforded a high level of security of supply. Gamesa has opened a 2-MW prototype offgrid system in La Muela, Aragon, that combines wind, solar and dieselpowered generation with energy storage batteries, the Spanish company said May 10. The system is designed to provide reliable baseload power to areas without access to the grid such as islands, mines and certain rural areas. The prototype includes control software customdeveloped by Gamesa to integrate the four technologies. It combines a G52-850 kW wind turbine with 816 photovoltaic modules (245 kWp) and three 222-kW diesel generators. The plan is to add a battery capable of storing 500 kWh / © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 24 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 500 kW by the summer. It will generate enough power to meet the needs of 400 families. “More than 1.2 billion people lack access to electricity,” Gamesa chairman Ignacio Martin said at the opening. “Rural areas of India, South-east Asia, Africa, islands such as Haiti, Indonesia and the Philippines, and other remote corners of the planet, such as jungles and deserts, stand to benefit from these offgrid solutions.” Development of this class of technology is expected to reach 1,200 MW in the coming years, Gamesa said. In 2007, the company installed a combined wind and diesel generator facility in the Galapagos Islands, Ecuador. SWEDEN Vartan CHP8 inaugurated Naantali to follow in biomass roll out Fortum Värme has inaugurated the 130 MWe, 280 MWth Vartan CHP8 biomass-fired combined heat and power plant in Vartan, Stockholm, joint developer/owners Fortum and the City of Stockholm said May 9. The plant is to start commercial production this autumn, when it will burn forest residues and wood waste to produce district heat and electricity for some 190,000 households. Daily consumption of wood chips will be 12,000 cubic meters. “The current fuel procurement plan is based on 40% of the fuel by rail from Nordic biomass suppliers and another 60% by ship from the Baltic Sea region and Russia,” Fortum said in an information note. A new 200-meter pier was constructed in the harbour area to accommodate vessels up to Panamax size. The pier can hold two vessels at a time, while a new crane has a discharge capacity of 2,000–3,000 tonnes/hour. On average, the plant will need 3–4 shipments per week and five 4,600 cu m trains per week to meets its fuel demand. The project has cost around €500 million to build. It will reduce CO2 emissions in the Stockholm area by 126,000 tonnes per year, Fortum said. During the next few years Fortum’s annual use of biomass will increase by more than 2 TWh and 1 million cu m as a consequence of the commissioning of Vartan CHP8 in Stockholm in Q4 2016, and the 140 MWe, 250 MWth Naantali CHP4 in Naantali, Finland, in 2017. Fortum is participating in Naantali CHP4 project through its 49.5% holding in Turun Seudun Energiantuotanto Oy (TSE). The multi-fuel power plant can use biomass, coal and high-quality recycled waste. Biomass feeding Naantali will consist of mainly locally sourced wood chips transported from within a 100 km–150 km radius of the site. Annual wood chip consumption will be as much as 1 million solid cubic meters. The plant will produce 900 GWh electricity and 1,700 GWh heat annually. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. SWITZERLAND Swiss RES ranked 25th Project backlog at 37,000 Switzerland ranks 25th out of 29 European countries in the development of solar and wind power, according to a study by the Swiss Energy Foundation (SES), published May 18 by the Swiss Association of Electricity Producers (VSE). The study shows that the Confederation produces just 170 kWh of solar/wind power per inhabitant, enough for the annual consumption of a large refrigerator. More than 37,000 renewables projects are on a Swissgrid waiting list for federal subsidies. The study estimates that if these were cleared Switzerland would climb to 12th place. As of January 1, 2017 the federal subsidy for renewables (KEV) is due to increase from the present 1.3 centimes/kWh to 1.5 centimes/kWh, raising an additional CHF 115 million a year. The Governmental Conference of the Swiss Mountain Cantons has called for replacing KEV subsidies with a quota system as of 2020, requiring subscribers and their utilities to meet a given portion of electricity demand from domestic renewables production, the portion to be increased periodically to reach 100% by the year 2050. SBB grid links approved Advances for Nant de Drance too The Swiss government approved May 4 the planning corridor for the last two sections of Swiss Railways’ 132-kV grid linking the SBB Gotthard power stations of Amsteg, Wassen, Göschenen, Ritom and the Etzelwerk power station at Sihlsee. The two sections are Stalden-Zweite Altmatt and Schlüssel-Nüberg. The Steinen-Etzelwerk grid in canton Schwyz, built in 1927 and uprated from 66-kV in the 1970s is the least able to cope with demand. The work will be supported by the Swiss Federal Office of Energy, which will ensure protection of the nearby Rothenthurm wetlands and investigate the possibility of burying the section supported on wooden poles. Meanwhile the Federal Inspectorate for Heavy Current Installations ESTI gave planning permission May 13 for construction of the last three 380-kV grid sections between Châtelard and La Bâtiaz and replacement of the La Bâtiaz substation, to service the Nant de Drance pumped storage power station. Swissgrid expects to complete the work in the spring of 2017, in time for partial commissioning of Nant de Drance. Finally, the Federal Administrative Tribunal rejected a complaint May 12 against Swissgrid plans 25 POWER IN EUROPE NEWS ISSUE 726 / MAY 23, 2016 for a new 220 kV substation at Chandoline with two 220/125 kV transformers, for connecting the 220 kV grid between Chamoson and Chippis. Swissgrid said it was ready to complete the work as soon as possible to ensure security of supplies for the Grande Dixence pumped storage power station in Arolla and Ferpècle. Liberalization suspended 2018 completion abandoned The Swiss government has decided not to complete liberalization of the electricity sector by 2018, postponing it indefinitely as a result of a public hearing. Of 140 responses at the hearing, 100 were in favor of complete liberalization but 54 of these “only under certain conditions”, while 37 were against opening the market as it might prejudice the government’s energy strategy 2050, or further worsen the competitiveness of the electricity supply industry. A final decision will likely depend on the state of bilateral negotiations with the European Union, the Energy Strategy 2050, conditions in the market and the planned revision of the Energy Supply Act. The ordinance approved by parliament in 2007 called for a two-stage electricity market opening beginning in 2009 with consumers of at least 100 MWh. In a May 4 statement the Swiss Federal Office of Energy said the government remained committed to liberalization, for the benefit of Swiss households and small and medium enterprises. Gaelectric is seeking approval to modify its existing grid connection agreement with Northern Ireland Electricity to co-locate the solar plant. Gaelectric development director Mike Denny said it was important “that the NIE/SONI consultation on grid connections for renewable energy allows the modification of existing and paid for connection agreements, and avoids delays in co-locating solar projects that do not require any increase in the maximum export capacity of existing connections.” The Alternative Connection Application and Offer Process Proposal (March 2016) from NIE/SONI proposes that applications to over-install generation at the maximum export capacity of an existing grid connection would be included in the ‘batching’ process proposed by NIE/SONI. Under this proposal all applications in the ‘batch’ are assessed and awarded connections together. Gaelectric is seeking a derogation from ‘batching’ for co-locating solar projects with wind where the maximum export capacity of the existing grid connection is not being exceeded. “Solar and wind have complementary generation profiles, helping us use limited grid capacity and other essential infrastructure more efficiently,” Denny said. Lightsource Renewable Energy has connected Northern Ireland’s first ever large-scale solar farm, the 4.83 MW Crookedstone facility in Antrim, it said May 20. The solar farm is connected directly via private wire to Belfast International Airport, meeting 27% of the airport’s electricity needs under a 25-year power purchase agreement. Solas Éireann has set up a joint venture with the UK UNITED KINGDOM renewable energy specialist Golden Square Energy to develop Solas Éireann’s 250-MW pipeline of solar PV projects in Ireland, it said May 10. Solas Éireann plans to commit over €100 million to the project. The country’s solar association says Ireland has potential for 3.7 GW of solar PV by 2030. Gaelectric pursues PV/wind first for NI 4.9 MW PV farm to produce 4.4 GWh/yr Modified grid connection required Gaelectric has secured planning approval for a 4.9 MW solar farm at Inishative, near Pomeroy in central Northern Ireland, the developer said May 12. In a first for the region, the solar farm will comprise ground mounted PV panels co-located next to the site of Gaelectric’s Inishative wind farm, currently being built and due to start generation in 2016. The electricity generation capacity of Inishative Solar Farm will meet the equivalent energy needs of approximately 1,175 homes with clean, green electricity. Government statistics for Northern Ireland show average domestic consumption per household in 2013 was 3,727 kWh per annum. Assumed generation of a standard 4.9 MW solar development in Northern Ireland equates to 4,400 MWh per annum, based on average irradiation levels and industry standard efficiency assumptions, the company told Platts. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. Dudgeon financed 402-MW wind farm 50% completed Financing of £1.3 billion has been arranged for the 402-MW Dudgeon offshore wind farm, project owners said May 13. The wind farm off the North Norfolk coast is being co-developed by Masdar, Statoil and Statkraft. It is scheduled to start commercial operation in the second half of 2017. Under the deal Statkraft is to finance its 30% share in the project, while Statoil will finance a share of 17.5%. The project is more than half-completed, with a first turbine monopile installed in early April, and construction of the wind farm’s 1,000 metric tonne offshore substation under way, the developers said. Statoil and Abu Dhabi’s Masdar each have a 35% stake in the project, while Statkraft owns 30% of the wind farm. 26 POWER IN EUROPE DATA ISSUE 726 / MAY 23, 2016 BIOMASS NWE pellet price slides on soft demand Downward pressure has been building in the Northwest European-delivered industrial wood pellet spot market, according to numerous sources, with offers moving lower on limited demand mid-May. Platts on May 20 assessed the weekly price of CIF NW Europe ‘I2’ industrial wood pellets basis 17 GJ/mt for delivery within the next 7-45 days, May 27-July 4, at $120/ mt, a $5 reduction on the week. Several sources said offers, while thin on the ground, had slipped following reports of distressed volumes, with cargoes from Portugal now available around €105/mt delivered into Europe. This appeared to have sparked some trading activity, with one utility buyer heard to have recently transacted for one such cargo for delivery into the ARA region. A source with knowledge of the deal said the same buyer had also recently purchased a cargo from the Baltics, but details around the trade remained sketchy. “The subsidized plants don’t really have any unexpected demand at this time of year,” a trader with a utility outlined, although he added that the delay of a scheduled maintenance could bring UK-buyer Drax into the market for June or July cargoes if inventories were low. Buyers had options, however, according to a trader, who said at least one utility had purchased volumes from existing stock, which were at high levels. Others were looking to swap cargoes where possible, the source said, but added that buyers would have to pay fees INDUSTRIAL WOOD PELLET PRICE ASSESSMENT CIF Northwest Europe (45 day)* May 13 May 20 $/mtChg €/mt Chg 125.000.00110.631.18 120.00-5.00 107.03-3.60 of $5-$8 should they want to execute this option that would see them buy in the short-term and sell back in the long-term. “You always see some interest in doing this, but it’s rarely successful,” a London-based broker said. “It’s basically a pricing exercise to see if storage plays are viable or not. Right now, it doesn’t quite work out.” A US-origin cargo that was heard to have been offered around €100-€110/mt CIF ARA ($112-$123/mt) while it was on the water in previous weeks was widely said to have gone unsold. “The seller was very strong on the price, and they were marketing it while it was on the water, so it definitely sailed,” a trader with a utility said. “I imagine if they didn’t get the price they wanted, they probably just put the cargo into storage in Europe.” UK imports up 29% UK imports of wood pellets in March rose 29% year on year and 25% from February to 634,653 mt, with higher deliveries from the US, Canada and Estonia, customs data released May 10. Shipments during the first quarter of the year totaled 1.82 million mt, up 50% on the year. Wood pellet imports from the US in March increased 60% on the year to 408,061 and jumped 57% from February. Canada rose to the second-largest supplier in March at 123,422 mt, 25% higher on the year and up 60% from February, hitting a three-month high. Latvia slipped to third place, shipping 53,582 mt of material to the country, falling 34% from March 2015 and down 58% from the previous month to a three-month low. UK imports of Estonian pellets totaled 23,390 mt in March, from zero a year ago and 13% higher than February’s volume. Portugal sent 18,252 mt to the UK in March, 65% lower on the year, but up 38% from the previous month. — Stephanie Wilson *Net CV: 17 GJ/t UK WOOD PELLET PROMPT SPREADS, MAY 20, 2016 100% dedicated (ROC x 1.4) 100% conversion (ROC x 1) 85-100% co-fired (ROC x 0.9) 50-85% co-fired (ROC x 0.6) Up to 50% co-fired (ROC x 0.5) Wood Pellet Cost – adjusted Prompt 45-day 30% (£/MWh)Chg 32.66 3.02 15.94 3.02 11.76 3.02 -0.78 3.02 -4.97 3.02 58.37-3.12 35% 40% 30% 35% 40% (£/MWh)Chg (£/MWh)Chg(€/MWh)Chg(€/MWh)Chg(€/MWh)Chg 41.00 2.57 47.26 2.24 42.27 4.64 53.07 4.28 61.17 4.01 24.28 2.57 30.54 2.24 20.63 4.23 31.43 3.87 39.53 3.60 20.10 2.57 26.36 2.24 15.22 4.12 26.02 3.76 34.12 3.50 7.56 2.57 13.82 2.24 -1.01 3.81 9.79 3.45 17.89 3.19 3.38 2.57 9.64 2.24 -6.43 3.71 4.37 3.34 12.48 3.08 50.03-2.67 43.77-2.34 Monthly Average ROC auction price* (£) May 41.810.00 *Provided by NFPA Ltd © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 27 75.55-2.52 64.76-2.15 56.65-1.89 POWER IN EUROPE DATA ISSUE 726 / MAY 23, 2016 POWER MARKET COMMENTARY Volatility buffets German prompt Strong volatility pulled German spot prices hither and thither in May as wind, solar and nuclear unpredictability added spice to the trading day. Day-ahead baseload May 18 was assessed at €32/MWh, the highest since January 22, day-ahead peakload at €36/MWh, the highest since February 15. United Kingdom This contrasted with negative OTC spot prices Sunday May 15, and very low negative prices the previous Sunday. For that day, May 8, peak DA has settled at minus €36.46/MWh, with some hours falling below minus €100/MWh amid record forecasts for wind and solar, peaking just below 45 GW during afternoon hours. Market jitters were evident in auction settlement prices on Sunday for Monday, with block 5 (1500-1900 BST) spiking to £65.44/MWh and block 6 (1900-2300 BST) to £54.90/MWh, N2EX and APX data showed. A trader said the blocks rose on speculation of tighter supply and increased balancing market needs. Prices began to tumble at the start of week 20 after balancing market concerns evaporated. Day-ahead prices continued to fall into week 20, down to £32.90/MWh for base and £37.25/MWh for peak May 19. Nuclear output, meanwhile, bumped down and remained down with longer than expected maintenance outages. Further out, Cal 17 base remained around the €25/MWh mark mid-May, little changed on end-April despite strong volatility in fuel markets. Year-ahead CIF ARA coal closed May 18 at its highest level since November at $47.35/mt. TTF Cal 17 gas, the benchmark contract for Continental gas, having plunged to a 2009-low of €13/MWh April 7, has remained around €15/MWh for much of May amid the general recovery across the energy complex. EUA carbon allowances followed a similar pattern, recovering from below €5/MWh at the start of April to jump above €7/ MWh April 26, before finding support around the €6/MWh mark mid-May. France French spot power prices increased gradually in the second half of May as temperatures fell as low as 5 C below norms. The last week of the month was also set to see colder weather, with prompt baseload prices seen hovering around €30/MWh, up €10/MWh compared to early May. Two strikes by EDF workers had no impact on generation and little or none on price. A fresh strike, to be organized by the FNME-CGT union May 26, is expected to result in capacity cuts, market sources said. On the curve, the spread between the French and German year-ahead baseload contracts narrowed mid-month May 13 and May 16 to €4.7/MWh, but rebounded since then and was last seen May 19 at €5.2/MWh. French Cal 17 base power May 13 fell to its lowest level this month at €29.05/MWh, having gradually retreated from spikes posted after President Francois Hollande’s announcement of the upcoming carbon price floor April 25. However the curve rebounded May 17, after environment minister Segolene Royal said a national carbon price floor would be set at around €30/mt for next year. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. Supply concerns due to reduced nuclear and wind availability drove UK prompt power prices higher at the end of week 19, traders said. On May 13, base and peak prices for May 16 delivery surged to £40.25/MWh and £47.25/MWh respectively. Nuclear power supplies improved to nearly 7 GW in week 20 following the restart of EDF Energy’s 580 MW Heysham 1 nuclear unit 1 and the return of its 525 MW Dungeness B unit 22 on May 19. Contracts on the forward power curve moved in line with the NBP gas prices. The winter 16 base power price remained above the £40/MWh price level for the past two weeks before falling to £39.80/MWh on May 19 due to bearish NBP prices. Spain A changing wind profile kept Spanish prompt power prices volatile in May as strong renewables output pulled dayahead power prices to new lows over the first weekend of the month. Baseload power for delivery on May 8 was assessed at €7.00/MWh, Platts data showed, which was the lowest level seen for day-ahead delivery so far this year, as wind levels tested levels at the 11 GW mark. However, a drop in wind levels in week 20 lifted day-ahead prices as high as €33/MWh on May 16, which was further compounded by an increase in power demand following regional holidays although further gains were capped by healthy hydro levels. Nuclear availability remained at around 5 GW throughout the month with the 1.1-GW Trillo and the 1-GW Asco 2 nuclear reactors offline for planned maintenance, data from Red Electrica de Espana showed, although both reactors are likely to return to the grid at the month. Further forward, year-ahead baseload power prices saw a slight decline over the past fortnight to close at €42.05/MWh on May 19, Platts data showed, as sentiment across the wider energy complex weakened. Platts European Power Team Tel: +44 (0)207 176 6174 E-mail: [email protected] 28 POWER IN EUROPE DATA ISSUE 726 / MAY 23, 2016 BILATERAL MARKET ASSESSMENTS PLATTS BASE POWER ASSESSMENTS (Eur/MWh) 2016 26/1-apr 2/8-apr 9/15-apr 16/22-apr 23/29-apr 30/6-may 7/13-may14/19-may United Kingdom Day ahead Week ahead Month ahead Quarter ahead 2nd Q ahead 42.86 44.44 43.71 41.08 41.28 40.02 41.01 38.83 38.09 45.00 43.21 42.45 38.84 38.25 45.66 44.04 43.16 40.16 39.41 46.87 45.61 43.99 43.71 43.18 50.89 41.69 42.10 40.39 41.19 49.15 46.67 43.52 41.32 42.23 50.00 45.21 42.39 42.01 42.92 50.91 26.60 25.13 24.04 22.95 23.34 24.65 25.38 24.23 21.25 22.63 24.64 24.19 25.20 22.95 21.52 22.93 25.06 24.85 22.86 23.86 22.06 23.71 25.61 25.25 26.56 23.95 23.12 24.97 27.11 27.02 22.33 22.84 23.20 24.35 26.42 26.44 23.27 22.40 23.33 24.44 26.45 26.19 29.95 25.30 24.65 25.34 27.31 27.16 28.94 26.16 25.33 23.61 24.99 27.10 24.51 21.72 22.76 30.35 24.96 23.45 21.73 22.68 30.62 23.68 26.08 22.61 23.62 31.17 29.70 25.94 24.22 25.05 33.20 22.92 23.48 22.76 24.32 32.53 24.91 23.94 23.22 24.47 32.70 30.84 26.38 24.58 25.51 33.31 27.63 25.66 25.48 25.83 25.90 24.27 24.67 27.15 26.57 24.34 24.85 27.39 25.30 24.60 25.46 28.00 28.03 26.28 27.83 30.62 24.55 26.98 26.82 29.64 27.05 27.69 27.14 30.11 30.88 28.05 27.84 30.93 25.04 31.49 38.73 44.05 22.74 37.03 43.39 41.33 25.20 36.38 43.42 41.21 27.96 36.33 43.69 41.40 30.00 35.72 44.89 42.61 28.13 38.85 44.16 42.61 29.48 39.30 43.70 42.39 31.49 39.43 43.88 42.61 Germany Day ahead Week ahead Month ahead Quarter ahead 2nd Q ahead 3rd Q ahead France Day ahead Week ahead Month ahead Quarter ahead 2nd Q ahead Netherlands Day ahead Month ahead Quarter ahead 2nd Q ahead Spain Week ahead Month ahead Quarter ahead 2nd Q ahead 2015 28/3-apr 4/10-apr11/17-apr18/24-apr25/1-may2/8-may9/15-may 16/22-may United Kingdom Day ahead Week ahead Month ahead Quarter ahead 2nd Q ahead 60.53 62.45 61.18 60.30 62.08 60.42 60.61 59.76 59.72 63.83 61.17 59.85 59.12 58.91 63.57 59.74 58.92 58.71 58.54 63.20 58.49 57.39 57.58 57.38 62.25 55.76 55.71 55.78 56.29 61.65 57.79 57.77 57.36 57.59 63.03 56.95 56.81 57.07 57.24 62.74 24.25 31.66 30.20 31.10 33.28 35.05 32.24 29.40 28.86 31.12 34.68 34.88 31.70 28.30 28.36 30.88 34.69 34.95 32.70 25.69 28.12 30.74 34.65 34.99 31.04 28.53 28.33 30.57 34.60 35.03 25.78 24.97 29.76 30.08 34.26 34.72 24.72 28.52 29.79 30.01 34.20 34.58 31.32 26.30 29.15 29.64 33.89 34.29 45.01 44.16 37.38 34.11 39.23 43.85 40.25 32.51 32.84 46.06 37.90 37.06 32.26 33.00 46.01 36.94 33.55 30.55 31.99 45.62 33.99 28.09 28.91 31.05 45.38 25.82 25.75 29.40 30.19 45.02 24.28 28.68 28.93 29.87 45.11 31.37 25.87 28.40 29.43 44.62 42.73 41.33 39.65 41.18 44.25 39.91 38.03 43.29 41.31 39.43 37.33 42.85 40.80 39.08 36.83 41.92 41.65 38.60 36.59 41.15 40.35 36.74 36.03 40.36 41.75 37.17 36.92 41.23 38.31 35.43 35.91 40.39 39.41 42.61 47.25 48.66 44.75 47.01 50.48 48.05 48.35 48.40 51.50 48.33 45.72 47.40 51.71 48.29 49.54 49.18 51.94 48.43 48.10 50.28 51.73 48.28 45.72 48.83 52.31 48.35 43.88 48.20 52.61 48.34 Germany Day ahead Week ahead Month ahead Quarter ahead 2nd Q ahead 3rd Q ahead France Day ahead Week ahead Month ahead Quarter ahead 2nd Q ahead Netherlands Day ahead Month ahead Quarter ahead 2nd Q ahead Spain Week ahead Month ahead Quarter ahead 2nd Q ahead PiE’s base power assessment table shows the last two months’ prices for various products, and compares these with the corresponding two months’ prices from the previous year. Each price is an average of Platts daily assessed prices between the dates shown. For more information, please contact the editor: henry.edwardes-evans@ platts.com Tel: +44 20 7176 6207 © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 29 POWER IN EUROPE DATA ISSUE 726 / MAY 23, 2016 CEE POWER MARKET ASSESSMENT Supply tightness pressures Polish prompt Falling wind generation and transmission outages lifted Polish day-ahead power prices in week 20 ahead of rising temperatures seen likely to add demand. Day-ahead baseload power prices settled above Zloty 150/MWh on the POLPX exchange and were seen nearing Zloty 180/MWh May 17, while day-ahead peakload power prices briefly rose above Zloty 200/MWh for the first time this month in the same session. Week-ahead base gained more than Zloty 2 in the week to close at Zloty 161/MWh May 19, while the near curve saw similar gains with June base rising nearly Zloty 3 over the past fortnight to Zloty 166.25/MWh. Although wind output had climbed to healthy levels of around 3 GW over the weekend of May 14-15, wind then fell away from Monday evening, down to negligible levels throughout the week. Bullish supply outlook lifts Hungarian, Czech prices Transmission outages added pressure, with capacity reduced between Poland and Sweden May 20, and capacity on the 700 MW NordBalt cable between Sweden and Lithuania to be unavailable from May 23 until June 3 likely to reduce flows on the Lithuanian border into Poland. “We’ve had high prices on the balancing market, a lack of wind and more outages for the next week on NordBalt and LitPol,” said a trader, adding that “forecasts for next week are also warmer,” prompting AC demand. CENTRAL & EASTERN EUROPE YEAR-AHEAD BASELOAD 40 (€/MWh) 30 Poland Germany A bullish supply outlook also lifted prompt prices in Hungary and the Czech Republic with both markets maintaining healthy premiums over Germany. Day-ahead baseload prices in Hungary were trading above €32/MWh for most of the week before sliding lower to €29/MWh May 19, Platts data showed. This was despite the expected shutdown of a 500 MW reactor at Hungary’s 2-GW Paks nuclear power plant on May 20 for maintenance until June 18. Water levels in most of the Balkans were expected to rise in week 20 after heavy rain in the previous week, hydrological forecasts showed May 16. Temperatures in Budapest meanwhile were forecast to climb above seasonal norms over the weekend of May 21-22 after hovering below the average earlier in the week, according to CustomWeather data, which may have added pressure on demand. Czech day-ahead base prices also saw gains in week 20 as planned maintenance put pressure on supply levels across the region. This was despite the return of one reactor at CEZ’ Dukovany power plant in the previous week, while reactor 3 is still offline for the rest of the month. 35 Hungary Year-ahead prices meanwhile bucked the bullish trend towards the ends of the week and shed more than Zloty 1 on the day to close at Zloty 160.50/MWh May 19. Czech Republic 25 20 22-Feb 07-Mar 21-Mar 06-Apr 20-Apr 05-May 19-May Source: Platts CENTRAL & EASTERN EUROPE DAY-AHEAD BASELOAD 50 (€/MWh) Hungary Poland Germany Czech Republic In addition, two reactors are offline at Slovakia’s Bohunice nuclear power plant following the ramp-down of unit 3 on May 14. REMIT data showed that both units are scheduled to return to service in the first half of June. A bullish prompt filtered through to the near curve. In Hungary, baseload for June rose to €35/MWh May 18, while its Czech counterpart held steady at around the €26.65/ MWh mark. 40 30 20 10 22-Feb 07-Mar 21-Mar 06-Apr 20-Apr 05-May 19-May Year-ahead power prices meanwhile posted gains at the start of the week but slid lower on May 19 as the rally seen across the wider energy complex came to an end. Hungarian Cal 17 base neared €37.50/MWh but shed €0.65 in the following session, while the Czech Cal 17 base price climbed as high as €25.60/MWh before sliding €0.40 on May 19. Source: Platts © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. — Petra Witowski 30 POWER IN EUROPE DATA ISSUE 726 / MAY 23, 2016 FEEDSTOCK COMPARISONS UK NBP GAS FOR MAY 19 (pence/th) Gas Despite robust Norwegian and Russian imports of gas to NW Europe, prices along the TTF and NetConnect curves have been steadily increasing over the two weeks to May 18. An increase in Brent Front Month oil to its highest level since November last year ($49/bbl), and an increase in the coal curve are likely to have driven this increase. A shortlived cold spell at the prompt has helped to support this steady climb. NW Europe (BE, FR, DE, NL) storage injections decreased 34 mcm/d w-o-w to 166mcm/d (May 11-17), driven by an estimated 22 mcm/d w-o-w increase in distribution network demand to 222 mcm/d. Temperatures across NWE are expected to fall below normal with France impacted the most, from the weekend to May 25 before normalizing out to May 28. In prompt markets, UK within-day gas was seen trading at 29.55 pence/therm May 20, with day-ahead dealt at 30.10 p/th, half of one pence up over a two-week view. TTF day-ahead was trading at €13/MWh, German NetConnect DA at €13.10/MWh, 35 eurocent and 50 eurocent stronger respectively over a two-week view. On the curve, the UK front-month June contract was changing hands at 29.275 p/th May 20 from the previous close of 28.90 p/th, while Q3 16 and Winter 16 seen trading at 29.95 p/th and 35.75 p/th respectively. TTF June was trade at €13.05/MWh May 20, up from €12.85/MWh May 6, while the German GASPOOL equivalent traded midday May 20 at €13.20/MWh (vs €13.05/MWh May 6). 29.25 – 29.45 June July August September Q3 2016 Q4 2016 Q1 2017 Q2 2017 Oct 2016 1 yr 28.80 – 29.00 29.08 – 29.28 29.50 – 29.70 29.85 – 30.05 29.48 – 29.68 34.30 – 34.50 36.55 – 36.75 32.95 – 33.15 34.13 – 34.33 Source: Platts European Gas Daily FUEL OIL FOR MAY 19 ($/mt) Northwest Europe (1% cargoes) Spot (1%) June (1%) July (1%) Q3 16 (1%) 209.75 – 210.25 212.75 – 213.25 215.25 – 215.75 217.75 – 218.25 Source: Platts Global Alert; spot= 5-15 days ahead of publication STEAM COAL PRICES ($/mt) Nation/AreaPrice May 19 CIF ARA FOB Richards Bay FOB Kalimantan FOB Newcastle 48.40 54.00 46.00 51.35 May 13 FOB Colombia FOB Qinhuangdao Russia Pacific CIF Japan CIF Korea West 44.50 64.40 53.80 57.25 54.25 Notes: Price bases: CIF ARA 6,000 kcal/kg NAR; Richards Bay, 6,000 kcal/kg NAR; Bolivar, 6,300 kcal/kg GAR; Newcastle, 6,300 kcal/kg GAR; Qinhuangdao, 6,200 kcal/ kg GAR; Kalimantan, 6,300 kcal/kg, GAR; CIF Japan, 6,300 kcal/kg GAR; CIF Korea West, 6,080 kcal/kg NAR. All 1% Sulfur max. 90-day forward delivery. Coal Source: Platts Coal Trader International It was a game of two halves in May as CIF ARA spot coal prices rose strongly early in the month only to settle back at still high levels given the bearish fundamentals. The material spiked $1/mt May 5, on rising futures prices and reports of dwindling availability, with Platts assessing CIF ARA physical thermal coal for delivery within the next 15-60 day period at $47/mt, up $1 on the day, and up from the $44.20/mt seen early April. CIF ARA spot coal then rose a further $1.15/mt in the week to May 13 to be assessed at $48.50/mt, before trending down in week 20 to May 19, to $47.60/mt. Buying interest remained evident that day, with one large Northwest European utility-trader said to be purchasing numerous cargoes as it reportedly attempted to fill its short position for July. “The premiums [between the derivatives] to the physical market have narrowed quite a lot today,” a second London-based trader noted. “The bids that had been pushing the physical prices higher have come off as a result.” In market news, test cargoes of Mozambican thermal coal have been shipped to a number of end users in Europe for test-burning in power plants, sources said May 13. Since a first cargo left Nacala port in January 2016, the port is understood to have shipped 1.5 million mt of thermal coal up to the end of April. © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. Bal Month May THE BARREL The Platts blog that spans the commodities spectrum Read and respond to posts from Platts editors and analysts on issues affecting a wide range of the world’s energy, petchem, and agriculture resources. Oil, Natural Gas, Electricity and Coal, Steel and Metals, Petrochemicals, Biofuels and Agriculture, Renewables …as well as commentary, analysis and observations on everything from global politics, to market dynamics. The Barrel strives to be the world’s most complete commodities blog, and its comment section is always open for your thoughts. Visit http://blogs.platts.com/ now! 31 POWER IN EUROPE DATA ISSUE 726 / MAY 23, 2016 EUROPEAN EXCHANGE AND POOL PRICES EPEX SPOT GERMANY/AUSTRIA/LUXEMBOURG APRIL 20, 2016 MAY 20, 2016 1000000 (MWh) SPANISH FINAL POOL APRIL 20, 2016 MAY 20, 2016 (€/MWh) (MWh) (€/MWh) 50 500000 800000 30 400000 40 600000 10 300000 30 400000 -10 200000 20 200000 -30 100000 10 Volume Peak price Volume 0 20-Apr 26-Apr 02-May 08-May 14-May 0 20-Apr -50 20-May 26-Apr Weighted average daily price 02-May 08-May 14-May 0 20-May Source: EEX Source: Omel NASDAQ OMX ELSPOT DAILY SYSTEM PRICE APRIL 20, 2016 MAY 20, 2016 APX NETHERLANDS WEIGHTED AVERAGE PRICES APRIL 20, 2016 MAY 20, 2016 1200000 (MWh) (€/MWh) Total volume 120000 30 (MWh) 25 400000 20 02-May 50 100000 40 80000 30 60000 20 40000 10 20000 26-Apr (€/MWh) Average price 800000 0 20-Apr 50 Base price 08-May 14-May 0 20-Apr 15 20-May Source: Nasdaq OMX Commodities Off-peak volume Peak volume 26-Apr 02-May Peak price Off-peak price Average price 08-May 14-May 0 -10 20-May Source: APX EPEX SPOT FRANCE PRICES AND VOLUMES APRIL 20, 2016 MAY 20, 2016 500000 (MWh) (€/MWh) Volume Peak price 50 Weighted average price 400000 300000 30 200000 20 100000 10 0 20-Apr EUROPEAN POWER DAILY 40 26-Apr 02-May 08-May 14-May European Power Daily’s uniquely comprehensive package of news and pricing information, provides you with daily updates on new policies, projects, power deals, acquisitions, regulatory decisions and evolving trading markets in Europe. It also produces market assessments for the UK, Germany, Switzerland, France, The Netherlands, Belgium, Spain, Italy, the Czech Republic, Hungary and Poland. Whether you are an energy executive, trader, broker or investor, European Power Daily will help you make more profitable decisions by delivering only the most pertinent details on market conditions. 0 20-May www.europeanpowerdaily.platts.com Source: EPEX © 2016 S&P Global Platts, a division of S&P Global. All rights reserved. 32
