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Issue 713 / November 9, 2015

POWER IN EUROPE

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CONTENTS

Dutch gas-fired power generator Rijnmond Energie was declared bankrupt October 20. The courts have appointed a receiver to try and find a buyer for the assets.

According to media reports, Crédit Agricole holds a mortgage over the Intergen-owned plant and is owed more than €300 million.

The 810-MW combined cycle plant has been in mothballs and is uncontracted. It was put up for sale in August and attracted bidders, but was withdrawn from sale the day before the bankruptcy was declared by the Rotterdam court.

Law firm Talbot Hughes McKillop LLP had been engaged to sell the plant, which comprises two Siemens V94.3A2 (SGT5 4000F) turbines with 70,000 operating hours per unit, two heat recovery steam generators and one Alstom steam turbine in a 2 GT x 2 HRSG x 1 ST configuration operating at 50% efficiency.

The plant has a nominal 25 year service life and a minimum operating life of 200,000 hours, the law firm said.

Rijnmond CCGT declared bankruptThe plant began commercial

operation in 2004 “and is presently undergoing mothballing preservation measures as a result of the negative spark spread environment for gas fired assets in the Dutch market,” Talbot Hughes McKillop said ahead of a prospective October auction.

The seller had characterized the plant as a potential flexibility play in the Dutch/North West European power market, or “attractive as a relocation play whereby the plant would be dismantled and recommissioned in an alternative country or region.”

The Dutch month-ahead clean spark spread for a 50% efficient gas-fired power plant was hovering just above minus €2/MWh November 4, with December baseload power assessed by Platts at €37/MWh that day. The curve offers no comfort of a recovery, with Cal 16 base assessed that day at €35.60/MWh, and Cal 17 at €34.20/MWh. The year-ahead clean dark spread, meanwhile, was calculated at minus €3.22/MWh.

UK transmission system operator National Grid had to call on demand side balancing reserve November 4 to bolster security of supply on a mild autumnal day.

A Notification of Inadequate System Margin (NISM) was issued by the TSO at 13:30 GMT in the face of multiple plant failures and very low wind production.

Unplanned outages at ScottishPower’s Cruachan pumped storage plant and SSE’s Fiddlers Ferry unit 2 were compounded by reduced power at RWE’s Didcot B gas-fired power unit 6 and on the French interconnector. Wind power, meanwhile, had fallen away to below 400 MW, less than 1% of available generation.

UK’s waning margins laid bareThe events forced National Grid to call

for around 500 MW of additional capacity to be brought online between 16:30 to 18:30 hrs.

This was the first time NISM to be issued since 2012. The market responded, generation came forward, 43 MW of Demand Side Balancing Reserve was ordered for between 18:00-18:30 hrs, and the NISM was withdrawn at 17:40 hrs.

Calming fears stirred by realtime media coverage of the situation, Grid’s Isobel Rowley said the NISM was “one of the routine tools that we use to indicate to the market that we would like more generation to come forward for the evening peak demand period. The issuing of a NISM does

(continued on page 2)

Analysis

11-day call-up for German reserve 3Hinkley liabilities challenged 5Verbund seeks Mellach buyer 6Vattenfall hedging 2017 at €31/MWh 7Turkey: policy contradictions resume 8CSPE ‘needs to rise 11%’ in 2016: CRE 9Belgium, UK buck November slide 10Thermal efficiencies wobble post-2010 12

News Highlights

EVN to close Durnrohr 13Verbund, Solavolta market Powerwall 13Wind reserve potential ‘significant’ 13Hungarian demand up 2.4% 14Seven pre-qualify for Kriegers Flak 14Dong’s wind output up 24% 14EC wants 2030 drafts by mid-2017 15Carbon hits 35-month high 15ACER ‘needs greater data access’ 15Gas burn quadruples in October 16CRE warns of rising DR costs 16Market verdict deflates EDF stock 16Export surplus soars 17Steag targets 90 MW battery portfolio 17SDE+ funds dispersed 17First turbine in at Zuidwester 18Thermal steps up for hydro 18October demand edges up 18Bottlenecks ‘costing €200 million/yr’ 19Conventional hydro support nears 19Small hydro costs denounced 20Beznau ‘won’t generate again’ 20Turkish blackout explained 20UK generation updates 21ROCs slip to £42.75 21FiT deployment exceeds 4 GW 22

News

Austria 13 / Belgium 13 / Central and East Europe 14 / Denmark 14 / Europe 15 / France 16 / Germany 17 / Netherlands 17 /Portugal 18 / Spain 18 / Sweden 19 / Switzerland 19 / Turkey 20 / UK 21

Data

Biomass 23Market Commentary 24Bilateral Market Assessments 25Outages force Polish prompt up 26Feedstock Comparisons 27European Exchange and Pool Prices 28

POWER IN EUROPE ISSUE 713 / NOVEMBER 9, 2015

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Issue 713 / November 9, 2015

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of the year that would see low operational surplus in the week commencing January 11, 2016. Grid will no doubt be hoping that commissioning of ESB’s 880-MW Carrington CCGT will begin as soon as possible next year.

Grid’s 5.1% capacity margin assessment includes Demand Side Balancing Reserve (0.13 GW) and Supplemental Balancing Reserve (2.29 GW). Without these services the margin would be 2.1%.

UK average cold spell (ACS) peak demand this winter is expected to remain fairly flat compared to last year with a narrow range (0.1 GW) between Grid’s four scenarios. The ACS peak demand for the coming winter is expected to be 54.2 GW. On November 4, demand peaked at 47,54 GW at 17:00 hrs.

Tighter next yearKerry Thacker-Smith, Senior Power Analyst at Eclipse Energy, an analytics unit of Platts, said the system would get “significantly tighter from this winter to next, with the the closure of Eggborough, Longannet, Ferrybridge and Wylfa by the end of Winter-15 tightening margins further, meaning that the likelihood of system warnings and the need to call on DSBR/SBR increases.”

Under a cold, low wind, 1.5 GW supply constrained scenario (a ‘realistic’ system tightness stress test) Eclipse would expect prices above £150/MWh for roughly 7% of half hours in Winter-16, up from 5% in Winter-15 – “an almost 50% increase in the risk of £150+ half hourly prices from this winter to next,” Thacker-Smith said.

“We assume that National Grid will increase its requirement for DSBR/SBR for Winter-16 relative to current levels, and under the above scenario would see NG calling on DSBR/SBR capacity for 5% of half hours in December and 7% in January.”

UK’s waning margins laid bare...from page 1

not mean we were at risk of blackouts. It means that we needed the safety cushion of power in reserve to be higher.”

The safety cushion came at some short-term cost, with the system buy price spiking up to £419.50/MWh for half hour period 32 from 15:30 hrs. Grid had also agreed on a cross border balancing transaction with Eirgrid at €390/MWh for 200 MW of power via the East-West interconnector to Ireland from 15:55 to 18:30 hrs.

Meanwhile Grid’s DSBR information showed that an offer price of £12,500/MWh, from a single site holding up to 4 MW of potential load reduction, was accepted.

The resultant peak period supply mix at 18:00 hrs November 4 was dominated by CCGT output (43% of total generation, with over 20 GW online at 18:00 hrs), followed by coal (25%, 11.7 GW), nuclear (16%, 7.5 GW), the French link (3.2%, 1.5 GW), pumped storage (2.9%, 1.3 GW) and the Dutch link (2.1%, 982 MW). Wind was negligible at 0.8% or 375 MW (but by midday November 5 was at 6% of UK generation with 2.65 GW).

Early warningsThe NISM occurred after generating margins of 5.1% were described by National Grid in its October 15 Winter Outlook as “manageable” going into winter 2015/2016.

It had warned, however, that late October was a key period of low operational surplus, with a number of units on planned outages before the main winter peak, some of which had overrun.

Early next year, meanwhile, there were a greater number of units on planned outage plus closures at the end



Germany’s electricity market design act, rubberstamped by the federal cabinet November 4, has revealed further details for the country’s lignite plant reserve – including a leisurely 11-day call-up period during which units are to get up-and-running in case of a last resort emergency.

Although clause 13g of the draft law describes closure of lignite power stations as a contribution to national and European climate protection targets, critics claim that at least some of the plants specified for the reserve, effectively paid to withdraw from the active market, were going to close anyway.

Plant owners RWE, Mibrag and Vattenfall are to be paid a total €1.61 billion, an average of nearly €0.6 million per MW, for placing eight units, or 13% (2.7 GW) of Germany’s overall lignite capacity, in standby cold reserve for four years before final closure.

The reserve is expected to cost €230 million per year for seven years. A €0.0005/kWh increase in network use charges will pay for it. Lignite plant operators will be paid compensation calculated as the sum they would have earned in the electricity markets minus short-term variable generation costs, according to the draft law.

Operators can close plants after just one year in the reserve on condition that this is reported to a transmission system operator at least six months earlier.

They can close plants at any time if effort and expenditure required in holding the plant in the reserve is not reasonable and energy regulator the Bundesnetzagentur (BNA) authorizes closure. The operator is not obliged to put other lignite capacity in the reserve as replacement.

If called up out of the reserve by a transmission system operator, the lignite units will be allowed ten days to become operational, another 11 hours to reach minimum load and a further 13 hours to reach net nominal capacity.

11-day call-up for German reserveOnce a call-up period is over, the units can continue to operate only for the period necessary to empty all the lignite transport conveyor belts and the boiler and power station fuel bunkers, or at the most for 72 hours.

Carbon reckoningIf by June 30, 2018 it is clear that the reserve measures will not result in an additional 12.5 million tonnes/yr reduction in CO2 emissions in 2020, lignite power station operators must set out by end-2018 how additional CO2 reductions totaling a maximum 1.5 million tonnes/yr will be achieved, beginning in 2019.

The 12.5 million tonne target is calculated to take account of rebound effects which occur when domestic or foreign conventional power stations generate more electricity as a result of reserve plants being taken out of the market.

The draft designates RWE’s five lignite units, two Vattenfall units and one Mibrag unit to be placed in the reserve for four years ahead of final closure.

‘Prevents regional upheaval’The units can be called up only as “an ultimate last resort when no other measures are available to cope with an extreme situation,” the draft says.

What use a reserve that needs 11 days to deliver can be to a German transmission system operator in an emergency is not clear – an emergency that needs to be foreseeable 11 days in advance is hard to define.

Possible constellations could conceivably include if gas imports were interrupted for a long period, or if a nuclear incident triggered a round of reactor closures in the short term.

On October 24, the federal economy ministry justified the reserve as “important to achieve climate targets and to prevent structural upheaval in the affected regions – a good and acceptable solution for employees and companies.”

The reserve has nothing to do with security of supply “but rather is a present for the energy companies,” said Green party deputy chairman Oliver Krischer October 28.

“RWE alone cashes in €800-900 million for power stations, most of which the company planned to close anyway,” said chairman of environmental group NGO BUND Hubert Weiger November 4.

RWE’s Niederaussem units C-F (1,184 MW) were included on the BNA’s power station closure list, dated September 25, with 2019 as the “expected closure date according to company planning.” The units were commissioned in 1970, 1969, 1970 and 1971.

GERMAN LIGNITE UNITS DESIGNATED FOR STANDBY RESERVEUnit Net capacity MW Date of entry Date of final to reserve closure

Mibrag

Buschhaus 352 1.10.2016 30.09.2020

RWE

Frimmersdorf P 284 1.10.2017 30.09.2021Frimmersdorf Q 278 1.10.2017 30.09.2021Niederaussem E 295 1.10.2018 30.09.2022Niederaussem F 299 1.10.2018 30.09.2022Neurath C 292 1.10.2019 30.09.2023

Vattenfall

Janschwalde E 465 1.10.2018 30.09.2022Janschwalde F 465 1.10.2019 30.09.2023

Total 2730

Source: German economy ministry, draft electricity market act



Frimmersdorf P and Q (commissioned 1966 and 1970) have since been planned for closure in around 2018, according to a Klima-Allianz research report October 30.

It cited a mid-2013 RWE financial report stating that the Westfalen C coal unit and Frimmersdorf P & Q and Goldenberg J lignite units were under “intense review”. Westfalen C and Goldenberg were included on the BNA’s July 20, 2015 power station closure list, indicating a similar future for the Frimmersdorf units. The other RWE unit, Grevenbroich-Neurath C, was commissioned in 1973.

Clarity for VattenfallDetails on the reserve “creates more clarity over the framework for business remaining in the Lausitz lignire mining area . . . also important for our lignite divestment process in Germany,” company chairman Magnus Hall said October 27.

Janschwalde units E and F were commissioned in 1987 and 1989 respectively, under the former GDR regime shortly before German unification in 1990.

Vattenfall said all its lignite generation and mining assets in Germany would be included in the upcoming sale: the power plants Boxberg, Janschwalde, Schwarze Pumpe and Lippendorf block R as well as corresponding mining activities at the Janschwalde, Nochten, Reichwalde, Welzow-Süd and Cottbus Nord open cast mines.

Vattenfall Europe Mining, with lignite output of 61.8 million tonnes in 2014, made a loss that year due to provisions and, with further provisions expected in 2015 “will again post a significantly negative result”, according to Vattenfall’s 2014 financial report, published October 19. In 2013 the division reported a loss of €147.3 million.

Vattenfall Europe Generation’s Janschwalde, Boxberg, Schwarze Pumpe and Lippendorf generated 56 TWh in 2014 after 57 TWh in 2013.

The division – including the new coal-fired Hamburg Moorburg plant and 3 GW of hydro capacity – made a loss of €708 million in 2014 due to value impairments for Moorburg. It made a loss of €404.3 million in 2013, falling from a

positive €764.2 million in 2012. Placing 930 MW of capacity in the standby reserve would secure the future owner of Vattenfall’s German lignite assets around €559 million.

Mibrag and EPHMibrag’s Buschhaus unit, near Helmstedt and commissioned 1985, was to have operated until 2030, using lignite from its eastern German opencast mining operations after the local Schoningen mine closed in 2017, according to the company. It bought the Helmsted lignite mining assets and power station from E.ON at the end of 2013 for €3.626 million.

Mibrag reported a profit of €82.1 million in 2013 after €83.2 million in 2012. At €0.6 million per MW, placing the 350 MW Buschaus plant in the standby reserve for four years would earn around €211 million.

Closure of the local source of lignite may have been expected to negatively affect Buschhaus’ profitability. But the acquisition was described in Mibrag’s business report for 2013 as securing a strategic sales potential from its Profen and Vereinigte Schleenhain lignite opencast mines of up to 2.5 million tonnes per year.

In 2013, output from the Profen and Vereinigte Schleenhain mines was 19.1 million tonnes, going mainly to Vattenfall’s Lippendorf and Schkopau plants but also to municipal utilities and industrial companies.

Aside from Buschhaus, Mibrag itself has only the small Wahlitz and Deuben lignite-fired generating units in eastern Germany with total capacity of 123 MW, used mainly for electricity supply for the Profen and Vereinigtes Schleenhain mines. Unlike RWE and Vattenfall, it is reliant on external customers for its lignite sales.

Mibrag said in its 2013 report that it was seeking to extend its range of customers with trial deliveries, including to Buschhaus and to power stations in the Czech Republic owned by its parent the EPE Group, the latter under a contract running until end-2016. Mibrag is ultimately owned by large Czech energy holding EPH.

EPE’s interest in acquiring Vattenfall’s eastern German lignite assets can be explained by a desire to keep the Lippendorf and Schkopau power stations running as long as possible to secure the major share of its lignite sales.

Its chances of acquiring Vattenfall’s lignite assets improved after Greenpeace Nordic was excluded from the bidding process by Citibank, which is handling the divestment, “on grounds that it does not plan to participate as a bidder,” according to Greenpeace Deutschland November 2.

— Sara Knight

GERMANY’S PLANNED CAPACITY AND CLIMATE RESERVE

Source: Platts

0

1

2

3

4

5(GW)

2.7 GWlignite

5% ofaverage

peakload

20232022202120202019201820172016

Climate reserve (lignite)Capacity reserve (technology neutral)

mailto:[email protected]



A group of UK MPs has backed a motion calling on the Department of Energy and Climate Change to carry out “a full examination of the nature, extent and consequences” of liabilities relating to Hinkley Point C, the 3.2 GW nuclear power project in Somerset, England being developed by EDF.

As of November 2, 14 MPs had signed an Early Day Motion proposed by Green Party MP Caroline Lucas.

The EDM states that “this House objects to the Departmental Minute from the Department for Energy and Climate Change, dated 21 October 2015, concerning contingent liabilities” relating to the government’s 35-year Contract for Difference for the power station with EDF subsidiary NNB Generation Company.

Early Day Motions are submitted for debate in the House of Commons. Few are actually debated, but they allow MPs to oppose government policy and could, in this case, force examination of objections.

In the Departmental Minute, Secretary of State for Energy Amber Rudd said total state support for HPC through the Contract for Difference “is expected to be in the range of £4 billion to £19 billion (real 2012 prices, discounted to 2012) depending on the level of future wholesale prices.”

The huge range in potential costs reflects DECC’s latest fossil fuel price projections and a range of future carbon prices, Rudd said.

“However, support through the CfD could be higher if wholesale prices were lower than DECC’s low wholesale price scenario or lower if wholesale prices are higher,” she said.

It could also be higher if costs covered by an operational expenditure reopener in the CfD were significantly higher than expected, leading to an increase in the contract’s £92.50/MWh index-linked strike price, the Minute said.

Hinkley liabilities challengedMeanwhile, if the government permanently prevented construction or operation of the plant “or where there is a political shut down of HPC by a UK, EU or international Competent Authority,” liability payments could be up to £22 billion, Rudd said.

Under a Secretary of State Investor Agreement, meanwhile, Rudd refers to a process “for the transfer of the Generator in the circumstance where investors are no longer willing to fund the Generator and no-one else is willing to do so either.”

Waste transfer contractsThe Minute shows that Rudd has also approved a Funded Decommissioning Program for nuclear waste and decommissioning liabilities relating to HPC.

The program requires EDF to provide for waste and decommissioning liabilities, entering into Waste Transfer Contracts with the government, under which the state is to take title to and liability for spent fuel and intermediate level waste from HPC.

While the operator will pay a waste disposal fee to government, the fee is to be capped and contracts could “contain several potential liabilities,” Rudd said.

“I judge the likelihood of these liabilities arising to be very low,” Rudd said. “It should also be noted that the fee to be charged for waste transfer will include a risk premium to provide Government with compenstaion for accepting the risk that costs might subsequently increase.”

Further, in return for setting a price cap at the outset the operator will, on start of generation, pay a ‘risk fee,’ Rudd said.

Objections, final approvalThe Treasury has approved the proposal in principle, Rudd said. If, however, an MP objects within 14 parliamentary sitting days of the Minutes’ publication on October 21, “final approval to proceed with incurring the

WHOLESALE PRICE PROJECTIONS – ELECTRICITY (p/kWh) Electricity (p/kWh) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Reference scenario 5.3 5.6 5.4 5.1 5 5.5 5.8 6.2 6.4 6.7 6.9Low price scenario 4.2 4.4 4.3 4.2 4.2 4.3 4.5 4.7 4.8 4.9 4.9High price scenario 6.5 7 6.9 6.9 7.1 7.4 7.8 8 8.2 8.4 8.5

DECC, December 23, 2014

CARBON PRICE PROJECTIONS* (£/t) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Industry and Services** 4.6 4.7 4.8 5 5.2 5.3 5.5 5.8 6 6.2 6.4Electricity supply sector*** 20.3 22.1 21.9 21.7 21.6 27.3 33 38.7 44.3 50 55.7

*Note the assumption of carbon prices is the same for all scenarios . **This reflects the EU ETS price: there is no Carbon Price Support. ***i.e. with Carbon Price Support

Source: DECC



liability will be withheld pending an examination of the objection,” Rudd said.

The government’s HPC contract provides for an initial strike price of £92.50/MWh (2012 prices), or £89.50/MWh if a similar project at Sizewell C proceeds. Both strike prices are fully indexed to the Consumer Price Index.

A gain-share mechanism in the contract means that, if construction costs are lower than expected, consumers will benefit. The first £1 billion of construction gain is to be shared with consumers on a 50:50 basis. Cost overruns have to be borne entirely by the developer.

There are two forward-looking operational expenditure reopeners in the contract, at 15 and 25 years after the first reactor or two starts production, the Minute shows. These could see the strike price increased or decreased to reflect revised estimates of operating and maintenance costs.

The Secretary of State Investor Agreement includes protection against the developer making excess returns, Rudd said.

If post-tax nominal returns exceed 11.4%, “30% of subsequent distributions go to consumers,” she said. This rises to 60% if the nominal returns rise above 13.5%.

Forecasts, assumptionsAs noted, the £4 billion-£19 billion subsidy forecast is based on DECC’s latest fossil fuel and carbon price forecasts.

DECC’s latest (December 23, 2014) projections for Brent crude oil prices for 2024 (roughly when HPC is expected to come on line) range from a low scenario of $82.5/bbl to a high scenario of $149.4/bbl.

For NBP natural gas, the range is 43.2 pence/therm to 98.4 p/th. For coal imports to North West Europe, the range is $73.3/tonne to 123.8/tonne.

For EU ETS carbon, DECC has just the one projection: £6.2/t CO2 EU ETS, and £50/t EU ETS plus Carbon Price Support. Meanwhile DECC has a low-high forecast range for UK wholesale power prices ranging from £49/MWh to £84/MWh for 2024.

The HPC CfD strike price is index-linked. Office of National Statistics’ Consumer Price Index data show that, since the £92.50/MWh strike price was agreed in September, 2012, the CPI has risen by 3.8% to September, 2015, taking the strike price up to £96/MWh.

Using Bank of England target CPI growth of 2%/year, the strike price will have risen to around £117/MWh by 2015.

On October 21, EDF Energy and Chinese state-owned nuclear company China General Nuclear Corporation signed a strategic investment agreement for the joint development of three UK nuclear plants, including HPC.

Under the agreement, EDF’s share in HPC will be 66.5% and CGN’s will be 33.5%.

Verbund seeks Mellach buyerAll options are on the table for Verbund’s Mellach power plant site, the Austrian utility said November 4, confirming indications in late October that a buyer was being sought for the troubled combined cycle power station.

A September 10 tribunal ruling has relieved the utility of any obligation to maintain an up-to 230-MW thermal block at Mellach power for outage reserve under Verbund’s existing district heat contract with Graz, the company said.

“Verbund is therefore re-evaluating all possible options with respect to the Mellach power plants site,” it said. This included a sale as indicated by the company October 21, and in line with its CO2-free strategy.

The site hosts an 832-MW combined cycle gas-fired power plant opened in 2011 and a 246-MW coal plant opened in 1986. For nine months 2015 Verbund booked a further €58.3 million impairment loss against the CCGT, which was largely offline in 2014 and has been operating only sporadically since.

Verbund noted that its long-term gas supply contract for the CCGT with incumbent Austrian gas trader EconGas GmbH has, since Q3 2012, had to be recognized at fair value in the utility’s accounts. For nine-months 2015, the resulting impact amounted to a €12.9 million loss, it said.

The corresponding derivative instrument in the energy area was recognized in ‘non-current other liabilities’ at €69.6 million, up from €54.2 million as of December 31, 2014, Verbund said.

In ‘current other liabilities’ the instrument was recognized at €6.6 million (December 31, 2014: €9.1 million).

Verbund is challenging the 2008 Mellach gas contract in the Austrian Cartel Court, claiming the contract is not consistent with Austrian and European antitrust law.

For its part, Econgas has begun arbitral proceedings against Verbund claiming payments under the contract,



which is says is valid. Verbund has in return filed a counterclaim for overpayments in the past.

The utility had made no contingent liability disclosures or provisions in relation to the legal proceedings in order not to prejudice its position, it said.

Hydro output downVerbund’s electricity output fell 2.9% to 24.968 TWh in the nine months to end-September 2015 on below-average hydropower resource, the utility said November 4.

Hydro output was down 5.3% over the period to 22.742 TWh from 24 TWh for nine-months 2014. At 0.94, the hydro coefficient of Verbund’s Austrian run-of-river plants was 6% below the long-term average and five percentage points below 2014, Verbund said. Meanwhile its pumped storage power plants produced 4.6% less year-on-year.

A 1% change in hydro plant output adds or subtracts €1.6 million in operating profit, company data showed. In contrast, output from Verbund’s thermal power plants rose 34.7% to 1.563 TWh. Wind and solar output increased 18.7% to 663 GWh.

Thermal plants were being called more ofted for congestion management measures “and the intensified use of coal in order to reduce inventories at the decommissioned Durnrohr plant,” it said.

Verbund sells the majority of its output under year-ahead contracts. Its Calendar 2015 contract sales through 2014 averaged €35.1/MWh, down 10.3% from the prior-year level, it said.

Austrian day-ahead power prices, meanwhile, were down 3% to €31.1/MWh for nine-months 2015 compared to nine-months 2014.

In Verbund’s APG grid business, billable energy volumes transmitted via its 380/220-kV grid increased by 464 GWh year-on-year to 17.733 TWh for the nine months. APG’s control area imported a net amount of 8.65 TWh.

Volume increases in the grid segment “were attributable above all to a greater use of congestion management measures and control power due to increasingly critical grid conditions,” Verbund said.

“Extensive action also had to be taken at Austrian power plants in order to handle congestion outside of the APG grid, particularly in Poland and Germany,” it said.

“Frequent recourse was taken to the contracted reserve power plants in the grid, which were an important component in maintaining the security of supply during the summer period,” it said.

Finally Verbund said it would continue to invest in hydro capacity, with the 430-MW Reisseck II pumped storage power plant due for completion in 2016.

VERBUND: FACTORS AFFECTING OPERATING RESULTS+/–1% generation from hydropower plants €+/–1.6 million+/–1% generation from wind power €+/–0.2 million€+/–1/MWh wholesale electricity prices €+/–0.8 million (hydropower plants and thermal power plants)

Source: Verbund

VERBUND: SALES BY COUNTRY (GWh) Q1–3/2014 Q1–3/2015 ChangeAustria 19,436 20,332 4.60%Germany 16,918 15,685 -7.30%France 1,030 2,219 115.40%Romania 312 366 17.40%Others 356 206 -42.00%Total 38,052 38,809 2.00%

Source: Verbund

Vattenfall hedging 2017 at €31/MWhVattenfall had hedged 77% of its 2017 Nordic electricity production by end-September this year at an average price of €31/MWh, the Swedish power utility indicated October 27.

The utility’s hedging for Year Ahead +1 power is well in advance of previous positions for this contract, indicating that Vattenfall expects curve prices to fall further in the period leading up to delivery.

This time last year, Vattenfall was 69% hedged for Year Ahead +1 power at an average price of €35/MWh. At December, 2013, it was 53% hedged for Year Ahead +1 power at €37/MWh and at December, 2012 the figure was just 50% (at €41/MWh).

Meanwhile Vattenfall had hedged 83% of its Year Ahead Nordic output at an average price of €33/MWh and just 72% of Current Year output at €37/MWh, the data showed.

While its Current Year hedging ratio was in line with previous years, Vattenfall’s Year Ahead hedging was again well in advance of previous years, indicating a growing conservatism in its trading strategy.

A similar if less marked trend is visible in Vattenfall’s Continental European power hedging ratios.

Year Ahead +1 power was 74% hedged as of end-September this year at an average price of €36/MWh, down



from 80% at €39/MWh this time last year but up from 56% at €40/MWh at December, 2013 and 44% at €50/MWh at December, 2012.

A strategy of locking in a greater proportion of future output at lower prices highlights Vattenfall’s current predicament that, “despite having lowered annual controllable costs by 27% since 2010, our cost-cutting efforts must continue.”

CEO Magnus Hall warned that “market conditions remain challenging, with a considerable capacity surplus and low electricity prices, especially in the Nordic countries, which is squeezing our production margins.”

Vattenfall’s Q3 generation rose 12% year on year to 41.2 TWh (36.8 TWh Q3 2014), driven by strong hydro output, stronger fossil-fired power and offset by a decline in nuclear

production on account of extended outages at Ringhals 2 and Forsmark 3.

Nordic reservoir levels were 91% (75.1%) of capacity at end-September 2015, 15 percentage points above the norm.

Vattenfall’s largest wind repowering project in the Nordic countries was completed in September, the company said, with installation of 22 new turbines with combined capacity of 70.4 MW at the Klim wind farm in northwest Jutland, Denmark.

CO2 exposure has increased slightly compared to 2014 as a result of commissioning of Block A at the Moorburg power plant in Germany, Vattenfall said. No new renewable capacity was commissioned during the third quarter, but for nine-months 2015 Vattenfall has added 325 MW of wind capacity at DanTysk in Germany and Clashindarroch in the UK.

VATTENFALL GENERATION (TWh) Q3 2015 Q3 2014 Q1-3 15 Q1-3 14 Full year 2014 Last 12 monthsTotal generation 41.2 36.8 127.2 126.6 172.9 173.5 of which hydro 9.5 6.1 28.9 25.8 34.3 37.4 nuclear 9.1 11.0 31.0 36.5 49.8 44.3 fossil-based 21.4 18.8 62.9 60.7 82.7 84.9 wind 1.1 0.7 3.8 2.8 4.1 5.1 biomass, waste 0.1 0.2 0.6 0.8 2.0 1.8Sales of electricity 46.1 42.5 145.4 145.6 199.0 198.8Sales of heat 2.8 2.5 16.0 16.4 24.1 23.7Sales of gas 5.4 4.8 35.6 30.1 45.5 51.0CO2 emissions (million mt) 20.6 17.5 61.4 58.2 82.3 N/A

Source: Vattenfall

Turkey: policy contradictions resumeThe re-election of Turkey’s Justice and Development Party (AKP) as a single party administration November 1 is expected to herald the re-appointment of long-serving energy minister Taner Yildiz and a continuation of existing policies.

However it remains to be seen how the new administration will deal with inherent inconsistencies and contradictions.

With demand growth expected to continue at or above the 3.7% reported in 2014 and many aging thermal power stations in need of renovation or replacement, development of new plant beyond current installed capacity of 71 GW is a priority.

While new gas supplies from Azerbaijan, Russia, Iran, Kurdistan and possibly Turkmenistan are becoming available and gas prices are falling, Ankara is trying to reduce its dependence on imported gas, promote development of domestic resources, privatize power plant, liberalize energy markets and all this while holding down retail power prices.

Efforts have been made to promote renewables. Flaws in environmental and grid access processes, however, have seen many hydro and wind plant projects frozen indefinitely, with few believing that the stated target of 10 GW of wind capacity by 2019 is achievable.

Similar efforts have been made to promote local lignite, with limited success, however Turkey’s reserves are mostly of low quality and more interest continues to be shown in developing new plant burning imported coal, and natural gas, in opposition to stated policy.

Efforts to liberalize Turkey’s power market this year resulted finally in the launch of the EPIAS energy market. But operators and traders continue to warn that power market liberalization will have limited success without liberalization of Turkey’s gas market, dominated by state gas importer Botas, which imports 80% of Turkey’s gas.

Similarly many warn that the planned development of three nuclear plants, at least two of which will be partly state owned and all three with offtake guarantees, is contrary to



France’s public service electricity tax (the CSPE) needs to rise by 11% next year to €7 billion because of growing renewables capacity and falling wholesale electricity prices, energy regulator CRE said October 27.

Inclusion of some €2.8 billion of back-payments owed to EDF to cover the shortfall in past CSPE revenue took the total bill to €9.8 billion, CRE said, or a 2016 component in end user bills equal to €27.05/MWh.

Changes in the CSPE tax are decided by the government and do not have to reflect CRE’s guidance. If the tax is not amended by ministerial order before December 31, 2015, it would automatically rise by €3/MWh to €22.5/MWh, representing around 16% of residential power bills, CRE said.

If so, the cumulative deficit being carried by EDF by end-2016 “is estimated at €3.4 billion, having amounted to €5.5 billion in 2014,” CRE said.

CSPE ‘needs to rise 11%’ in 2016: CREThe increase in CSPE-related costs from 2014 to 2016 “can be explained by the development of photovoltaic and solar capacity, lower electricity market prices and new production” in non-interconnected zones, CRE said.

The regulator estimates that 39% of the 2016 CSPE charge would be required to cover solar costs and 17% to cover wind costs. Solar power could cost €2.72 billion and wind power €1.18 billion next year, CRE said.

The CSPE covers renewable energy and cogeneration subsidies, the cost of supplying non-interconnected zones and the cost of social tariffs. State-controlled utility EDF pays for all these subsidies and claws back the costs via the CSPE component in end-user bills.

As of end-September, France had 9,923 MW of wind capacity, 6,041 MW of solar capacity and 1,696 MW of other renewables installed, according to RTE data.

This year over 800 MW of wind and 750 MW of solar have been added.

Year-to-end-September renewable energy production in France stood at 26.3 TWh (14.3 TWh wind, 6.3 TWh solar, 5.7 TWh other renewables – mainly waste-to-energy and biogas). This is more than 4 TWh more than in nine-months 2014, when total RES production amounted to 22.1 TWh (12.1 TWh wind, 5 TWh solar, 4.9 TWh other renewables).

EC probe on-goingIn March last year the European Commission opened an in-depth investigation into whether CSPE payment derogations granted to large energy consumers were in line with EU state aid rules. That investigation is on-going, the EC told Platts November 3.

Three exceptions exist as the law stands. No CSPE is due on own-consumption of auto-produced electricity below 240

FRANCE: INSTALLED CAPACITY (MW)Technology 30-Sep-15 30-Sep-14Nuclear 63,130 63,130Conventional fossil-fired thermal 23,462 25,006Hydro 25,416 25,480Wind 9,923 8,636Solar PV 6,041 4,978Other renewables 1,696 1,513

Source: RTE

FRENCH ENERGY BALANCE, SEPTEMBER 2015 (TWh) Sep-15 Nine months Sep-14 Nine months 2015 2014Nuclear 30.633 306.327 31.939 305.130Conventional thermal 1.946 21.670 1.521 16.459Hydro 3.424 47.659 3.779 53.695Total RES 2.982 26.298 1.921 22.107Thermal/combustible RES 0.614 5.685 0.552 4.915Wind 1.653 14.345 0.728 12.176Solar 0.715 6.268 0.640 5.016Total production 38.985 428.252 39.159 397.392

Source: RTE

planned market liberalization and risks dis-incentivizing investment in less profitable forms of generation.

In the short term the AKP’s re-election looks certain to re-start development of the 4.8 GW Akkuyu nuclear project, currently frozen thanks to a spat with Moscow.

Similarly, new efforts can be expected to encourage power plant developers to utilize Turkey’s enormous Afsin Elbistan low grade lignite field. However, as with the planned nuclear plant it remains to be seen whether the enormous investment required will be forthcoming without offtake guarantees.

Ultimately, and despite statements to the contrary, Turkey appears destined to turn back to gas.

Twenty six new CCGT plant projects totaling close to 11 GW are fully licensed, with a further seven totaling 4.3 GW partly licensed, all waiting for new gas supplies.

And with one major gas import pipeline under construction, a second expected to begin construction this year and two more under discussion, that gas is unlikely to be long in arriving.

— David O’Byrne



The value of November cross border capacity fell significantly year-on-year in CASC’s monthly auctions, reflecting this year’s much weaker wholesale price environment and, on certain borders, flow-based market coupling. Only capacity into Belgium and the UK increased in value, as exporters chased higher-priced markets supported by winter supply concerns.

The steepest declines were recorded on sales of capacity from Austria to Switzerland (down €7.27/MWh to €8.61/MWh year on year), Germany to Switzerland (down €7.5/MWh to €8.7/MWh) and Austria to Italy (down €6.42/MWh to €14.23/MWh).

Modest increases in value were seen for France-Belgium (up a euro to €8.51/MWh), Netherland-Belgium (up 32 eurocents to €10.4/MWh despite a more-than-doubling of available capacity).

The biggest hike across west Europe was seen on France-GB capacity in a first auction of 150 MW, up €4.12/MWh year on year to €16.05/MWh. Oddly, a second auction of a further 150 MW saw the price drop to €14.97/MWh from €15.30/MWh for November, 2014.

France turns net importerLooking back at CASC data of power flows in October, meanwhile, shows France becoming a net importer of power via flow-based market coupling (FBMC) for the first time since the system was introduced in May.

France imported a net 165 GWh during October, maintaining a downward trend since August, when the country exported more than 1.7 TWh.

Unseasonably cold weather and reduced nuclear availability last month served to tip France’s supply and demand balance. Its position flipped from a daily export average of 8.4 GWh in September to a daily import average of 5.3 GWh in October. Daily exports had been as high as 47.4 GWh and 55.9 GWh in July and August, respectively.

Germany maintained its position as the dominant provider of power into the FBMC system through October, with 1.42 TWh exported in total to average 45.8 GWh/day.

Belgium, UK buck November slideNet flows into Belgium ticked up in the month, topping 1.2 TWh in October as power flowed in at an average 40 GWh/day, while the Netherlands was balanced during October with a mere net 19 GWh imported, around 600 MWh/day.

Cross-border flows from Germany into France increased close to 50% on the month to 843 GWh, with France now a net importer of German power in four of the five full months since FBMC was introduced, August the only month in which a net flow was seen in the opposite direction.

Tightness in the French grid forced Belgium to lean more heavily on the Netherlands, with October bilateral flows increasing 34% on September to 561 GWh, the data showed.

Flow volumes from France into Belgium. Meanwhile, were 11% lower on the month at 678 GWh, while those from Germany into the Netherlands were largely unchanged on the month at 580 GWh.

Price spreads narrowAverage power price disparities between CWE nations generally decreased on the month, with the spread between Belgium and the Netherlands the only exception.

The average premium for exchange-traded day-ahead baseload power in Belgium compared to France was €10.47/MWh during October, more than €4.50 below the September average.

Dutch power’s premium over Germany meanwhile fell by more than €5/MWh on the month to average €2.06/MWh during October, while the additional the French premium was largely unchanged on the month at €5.58/MWh.

The Belgian spot power premium over the Netherlands was €13.99/MWh for October, continuing a gathering trend since FBMC was introduced. The premium has increased by a factor of 45 since June, when Belgian power carried a mere 31 euro cent premium over that in the Netherlands.

TSOs agree CCRsIn related news, electricity transmission system operators have agreed on coordinated cross border transmission

GWh/yr. No CSPE is due beyond €550,000 (indexed) per consumption site per year; and for industrial companies using 7 GWh or more per year, the CSPE is capped at 0.5% of their annual value added.

“These three reductions appear to give large electricity consumers a selective advantage that could

distort competition in the Single Market,” the EC said at the time.

The EC, however, said it was also considering including provisions in revised Guidelines on Environmental Aid allowing reductions for energy intensive users under certain conditions in order to preserve competitiveness.



Capacity Calculation Regions (CCRs) as part of efforts to integrate the EU’s 28 national power markets, their formal body Entso-e said October 30.

Under the EU’s binding electricity capacity allocation and congestion management network code, which entered into force in August, TSOs in defined regions will have to use the same method for calculating capacity. Entso-e would not give details of the CCRs, as the proposal has yet to be submitted formally to national regulators for approval. But it said the proposal was adapted from the draft published in September after feedback from the consultation.

The draft had 11 regions, including central west, central east, southwest and southeast Europe, as well as the Nordic, Baltic and Hansa regions. Entso-e said the proposal included “a clear commitment” from the central west and central east Europe regions’ TSOs to cooperate on implementing a common flow-based capacity calculation methodology “as soon as possible” and to “ensure a smoother and faster integration” of both regions.

The draft also had Italy split into northern and southern regions, plus a UK-Irish and a UK-French-Dutch “Channel” region.

Entso-e said the draft had been changed to include the borders between Croatia and Slovenia, Croatia and Hungary, and Romania and Hungary in the central east Europe region from the start.

The German-Austrian border will also be in the central east Europe region, it said.

The TSOs have to submit the common proposal to national regulators by November 14 to comply with the EU capacity allocation and congestion management network code.

If any of the regulators do not approve the proposal, the TSOs have two months to resubmit a new proposal and all regulators then have two months to approve it. If there is still no consensus among regulators, the proposal goes to EU energy regulatory agency ACER for a final decision. Entso-e is to publish full details on November 13.

CROSS BORDER CAPACITY AUCTIONS – NOVEMBER 2015 DELIVERY (MW) Offered Requested Allocated Clearing Price Nov 2014 price capacity capacity capacity (€/MWh) (capacity allocated)Austria-Switzerland 215 2001 215 8.61 15.88 (110)Austria-Italy 170 1182 170 14.23 20.65 (184)Belgium-France 5 70 5 0.20 0.06 (325)Belgium-Netherlands 351 3543 350 0.16 0.11 (148)Switzerland-Austria 658 5494 654 0.02 0.01 (371)Switzerland-Germany 2115 18335 2100 0.01 0.01 (1197)Switzerland-Italy (peak) 400 2397 400 5.85 8.49 (300)Switzerland-Italy (base) 1500 6327 1499 5.52 7.43 (800)Denmark 2-Germany 150 1010 148 0.05 0.15 (149)Germany-Switzerland 305 3481 304 8.70 16.2 (190)Germany-Denmark 1 350 1798 349 0.19 1.06 (100)Germany-Denmark 2 120 889 120 0.88 2.19 (120)Germany-France N/A N/A N/A N/A N/AGermany-Netherlands 536 4023 536 5.11 9.81 (252)Spain-France 770 5529 769 0.90 2.28 (360)France-Belgium 212 1696 211 8.51 7.5 (383)France-Switzerland 75 655 75 0.80 0.8 (65)France-Germany 425 3825 425 0.10 0.14 (425)France-Spain 910 5564 909 5.43 6.86 (369)France-Italy (peak) 155 1804 155 6.25 9.09 (150)France-Italy (base) 2005 9118 2004 5.91 6.88 (1600)Greece-Italy N/A N/A N/A N/A N/AItaly-Austria 30 153 30 0.02 0.06 (30)Italy-Switzerland 654 5152 651 0.03 0.06 (550)Italy-France 374 4074 373 0.31 0.53 (294)Italy-Greece N/A N/A N/A N/A N/AItaly-Slovenia 115 699 114 0.06 0.11 (80)Netherlands-Belgium 313 1958 313 10.4 10.08 (148)Netherlands-Germany 584 5955 583 0.35 0.07 (252)Slovenia-Italy (peak) 110 788 110 1.63 9.5 (110)Slovenia-Italy (base) 180 1419 179 2.72 10.1 (220)

GB interconnectors

GB-Ireland (EWIC 1) 50 297 50 2.49 6.06 (75)GB-Ireland (EWIC 2) 75 363 75 2.76 6.21 (75)Ireland-GB (EWIC 1) 50 264 50 0.81 0.01 (49)Ireland-GB (EWIC 2) 108 435 108 0.41 0.02 (100)France-GB (auction 1) 150 973 150 16.05 11.93 (167)France-GB (auction 2) 150 954 150 14.97 15.30 (150)GB-France (auction 1) 150 898 150 0.06 0.35 (190)GB-France (auction 2) 150 724 150 0.07 0.12 (191)

Source: CASC.EU, Eirgrid, National Grid, RTE



The average efficiency of electricity and heat production in public conventional thermal power plants in the EU-28 fell between 2010 and 2012 as generators switched fuels, European Environmental Agency data showed October 20.

Average efficiency peaked in 2010 at 49.2% before falling to 48.5% in 2011 and 47.6% in 2012, the agency said. The latest figure available, for 2013, shows the average recovering modestly to 48%.

The increase in efficiency between 2005 and 2010 is explained by greater use of natural gas and a decline in coal, lignite and nuclear fuel use, the agency said.

The post-2010 dip in efficiency was due to increased use of coal, lignite and biomass, and a fall in gas-firing. About half of the decrease in efficiency between 2010 and 2012 is attributed to the change in fuel mix. Meanwhile increased use of coal and lignite “may have led to the increased use of existing lower efficiency coal plants”, the agency said.

The steepest post-2005 declines in efficiency were registed in Portugal, Latvia, Finland, Turkey, Estonia, the Netherlands and France.

Topping the overall efficiency list for 2013 were thermal plants in Norway, Sweden and Latvia, all 77%-plus. Propping up the league were Greece, Malta and Portugal, all sub-38%.

Thermal efficiencies wobble post-2010“The difference between the countries with the highest and lowest efficiencies was over 40 percentage points,” the EEA noted. “This was mainly caused by differences in the fuel mix used in electricity production,” it said.

The energy efficiency of conventional thermal electricity production is defined by the EEA as the ratio of transformation outputs from conventional thermal power stations (electricity and heat) to transformation inputs to conventional thermal power stations.

It is expressed as a percentage. The output from conventional thermal power stations consists of gross electricity generation plus any heat sold to third parties.

Gross electricity generation is measured at the outlet of the main transformers, with consumption of electricity in plant auxiliaries and transformers included.

Public supply is defined as undertakings that generate electricity (and heat) for sale to third parties as their primary activity. They may be privately or publicly owned.

Fuel inputs include solid fuels (coal, lignite and equivalents), oil and other liquid hydrocarbons, gas, thermal renewables (industrial and municipal waste, wood waste, biogas and geothermal energy) and other non-renewable waste.

EFFICIENCY OF ELECTRICITY AND HEAT PRODUCTION FROM CONVENTIONAL THERMAL PLANTS (%) Member states 2005 2013 Delta 2005-2013Greece 36.9 37.0 0.1Malta 26.4 37.2 10.8Portugal 44.4 37.6 -6.8Estonia 42.0 39.2 -2.8Cyprus 34.9 39.4 4.5Spain 42.5 41.5 -1.0United Kingdom 44.0 43.4 -0.6Bulgaria 40.9 43.5 2.6Turkey 47.1 44.0 -3.1Italy 43.0 44.6 1.6Slovenia 43.5 44.7 1.2Czech Republic 43.7 46.1 2.4Ireland 43.0 46.2 3.2Poland 46.7 46.5 -0.2Germany 47.9 47.4 -0.5EU-28 47.6 48.0 0.4Hungary 50.3 49.3 -1.0France 51.9 50.4 -1.5Belgium 48.4 52.6 4.2Croatia 51.0 54.0 3.0Slovakia 50.9 54.4 3.5Romania 52.2 54.7 2.5Netherlands 60.6 58.2 -2.4Luxembourg 57.9 60.1 2.2Austria 60.4 64.8 4.4Denmark 71.2 72.8 1.6Finland 77.3 72.8 -4.5Lithuania 69.1 75.8 6.7Latvia 84.1 77.4 -6.7Sweden 87.2 86.5 -0.7Norway 87.8 87.5 -0.3

Source: EEA, http://www.eea.europa.eu/data-and-maps/indicators/efficiency-of-conventional-thermal-electricity-generation-4/assessment



AUSTRIA

EVN to close DurnrohrEVN will close its 352 MW coal-fired power station at Durnrohr at latest by 2025, the utility said November 4. The plant has been in operation since 1987.

“This sends a clear signal to the Paris Climate Conference,” said Alexander Egit of Greenpeace, which is lobbying for a nearer-term closure. The plant emits 1 million tonnes CO2 annually, according to Christianne Brunner, environment spokesperson for the Green party.

In May 2014 Verbund closed the 405 MW coal-fired plant located adjacent to the EVN facility. Austria has two other remaining coal burning installations. Verbund’s Mellach coal unit is set for a 2020 shutdown. Energie AG’s Riedersbach block II is set for closure in 2016.

Verbund, Solavolta market PowerwallVerbund and Austrian solar installer Solavolta are to market Tesla’s Powerwall domestic battery to the Austrian market, offering solar prosumers storage “at an affordable price,” Verbund said October 22.

A new customer can buy a complete photovoltaic storage solution from €17,900, Verbund said. Included is a 4 kWp photovoltaic system, Tesla’s Daily Cycle Powerwall, charging management from Fronius plus planning, installation and startup services.

Those already with a solar system can fit the Powerwall retroactively.

For new customers, self-generated power currently attracts a subsidy of 12 eurocents/kWh in Austria. This rate applies for the first 1,000 kWh. The rate decreases as of 1,001 kWh to 5.69 eurocents/kWh, and as of 7,001 kWh to 4 eurocents/kWh. These feed-in rates are guaranteed until end-2019. The average household uses 10 kWh to 15 kWh a day.

Sales of the units have begun, Verbund said, with first deliveries expected in the first half of 2016.

With 7 kWh for daily-cycle operation, the Powerwall battery provides enough capacity to sustain most private households with self-generated electricity, Verbund said. In case of an outage, the battery supplies enough power for

half a day of normal operation. A sunny afternoon fully charges the unit “and is sufficient to supply an A+++ combined refrigerator-freezer with energy for 12 days or to run an A+ television for more than 120 hours,” Verbund said.

BELGIUM

Luminus listing pulledSome 12 days after confirming that the Belgian shareholdings in its subsidiary, EDF Luminus, were to be listed, EDF announced October 26 that the listing would not proceed ahead.

It gave no reason for the change but said it had increased its stake in EDF Luminus to 68.63% from 62.3%, buying out the shares of Publilum and VEH, two public sector finance vehicles linked to Belgian local authorities. It has previously been thought that EDF did not want to increase its stake, whereas the Belgian shareholders, or at least some of them, wanted to realize on their investments – hence the plan for a listing.

Four Belgian shareholders remain. Three have links to local authorities: Publilec (26.4%), Socofe (4.7%) and Nethys (0.1%). The other is Ethias (0.2%), an insurer owned directly or indirectly by the federal or regional authorities. All four benefit from a liquidity mechanism which will enable them to exit the capital of EDF Luminus from the end of 2018, EDF said.

Wind reserve potential ‘significant’There is “a significant potential” for wind farms to participate in the Automatic Frequency Restoration Reserve market, according to the report of a Belgian pilot project released by TSO Elia October 20.

The project has shown that “wind farms are able to provide a significant amount of flexibility to the grid (high ramp rates, low minimum technical power requirements) and can offer these services in a reliable way,” the report said.

Four companies participated in the pilot to assess the technical capability of wind farms to deliver advanced balancing services to the grid. They were Windvision (windfarm owner), Eneco (balancing responsible party), Enercon (wind farm supplier) and Elia (TSO).

The pilot was run at Windvision’s 81-MW Estinnes wind farm, which has 10 E-126 Enercon turbines of 7.5 MW each and one turbine of 6 MW. The wind farm’s systems were modified to allow delivery of Automatic Frequency Restoration Reserve (aFRR, formerly secondary reserve). At present, this are mainly supplied in Belgium by gas-fired power plants.

The focus of the pilot project was mainly on the provision of downward aFRR (secondary reserve) capacity, as the provision of upward aFRR capacity would require continuous de-rating of the wind farm. That would entail a significant loss of green certificates for the producer and a high cost of the service for the system.

DAILY CYCLE POWERWALL SPECIFICATIONSWall-mounted, rechargeable lithium-ion batteryLiquid-based temperature control7 kWh for daily-cycle useGuarantee: 10 yearsCapacity: 3.3 kWVoltage: 350 V – 450 VCurrent: 9.5 AmpCompatible with single-phase and three-phase mains currentOperating temperature: from -20°C to 50°CCasing certified for installation in closed rooms and outdoorsDC/AC inverter not includedWeight: 100 kgDimensions: 1300 mm x 860 mm x 180 mmCertification: The Powerwall will meet all applicable safety standards and guidelines for electrical installations as of its market debut (planned: CE Mark, IEC 62619, 62109-1, IEC/EN 61000, Class B Radiated, Battery Directive 2006/66/EC, UN 38.3)

Source: Verbund



The Available Active Power (AAP) method was found to be is “a very promising mechanism” to ensure efficient delivery of aFRR capacity. There are quality issues, but it is expected that these will be resolved in the near future.

The report also identifies changes which need to be made to the current Belgian aFRR market design. As currently constituted, there are barriers to stand-alone participation of wind farms in the aFRR market.

CENTRAL AND EAST EUROPE

Hungarian demand up 2.4%October gross power consumption in Hungary climbed 2.4% higher year on year at 3.77 TWh, data from power grid operator Mavir showed November 6. As in September, domestic generation increased at the expense of net imports, with domestic production up 10.2% year on year to 2.70 TWh and net imports down 13.1% to 1.07 TWh.

Peak system demand occurred October 28 at 6,238 MW, 1.9% higher than peak demand in October 2014. Growth in demand took place amid a 2.1 degrees Celsius year-on-year drop in average temperatures, and one fewer working days this year.

In ten months 2015, gross power demand rose 3.1% year on year to 36.22 TWh. Domestic generation and net imports have increased at similar rates year to date, by 3.5% to 24.54 TWh and by 2.2% to 11.69 TWh respectively.

DENMARK

Seven pre-qualify for Kriegers FlakSeven companies have prequalified to build Denmark’s 600 MW Kriegers Flak offshore wind farm in the Baltic Sea, the Danish Energy Agency said October 28.

The seven are: Kriegers Flak ApS (owned by Energie Baden Württemberg AG); Wpd HOFOR Stadtwerke München, Kriegers Flak SPV; European Energy Offshore Consortium (owned by European Energy A/S and Boralex Europe S.A.); a yet-to-be established company by Vattenfall Vindkraft A/S; Kriegers Flak Offshore Wind I/S (a not yet established company by Statoil ASA and E.ON Wind Denmark AB); ScottishPower Renewable Energy Limited; and DONG Energy Wind Power A/S.

One application was rejected, the agency said. “I both hope and believe that the great competition for winning the Kriegers Flak tender will lead to the best possible price for the benefit of Danish electricity consumers,” the minister for energy, utilities and climate, Lars Christian Lilleholt, said.

Preliminary tender specifications for Kriegers Flak were scheduled to be published in October. The DEA said it now expects to publish the tender material mid-November. A formal tender would be issued next year, with a winner expected to be announced in December 2016. The winner would be the candidate offering the lowest price in Danish

ore per kWh for the first 50,000 hours at full load.Kriegers Flak, expected to be online before the end of

2021, will be Denmark’s largest offshore wind farm, increasing the contribution of wind energy to the Danish grid by 7%, according to DEA forecasts.

The last large-scale Danish offshore wind farm award (400 MW, Horns Rev 3) was made in February this year, when Vattenfall won the tender with 77 ore per kWh bid, equivalent to €103.1/MWh for the 11-to-12 year support period. This was 32% cheaper than the previous offshore tender award for the Anholt wind farm. Danish consumers would save around €295 million over the 11-12 year support period (50,000 peak load hours) for the project compared to previous Danish offshore wind awards, the DEA said at the time.

Dong’s wind output up 24%Output from Dong Energy’s wind farms in the first nine months of 2015 rose 24% year-on-year to 4.2 TWh, the Danish utility said October 29.

Comprising entirely of offshore capacity, Dong’s renewables fleet produced 800 GWh more than the 3.4 TWh generated in the corresponding period of 2014. Looking at the third quarter in isolation, wind generation was 76% higher on the year, it said.

The increase was driven by new contributions from Westermost Rough, West of Duddon Sands and Borkum Riffgrund 1, and despite the sale of half of Dong’s stake in the 630 MW London Array offshore wind farm to Canadian pension fund Caisse de depot et placement du Quebec.

Output was also hurt by a faulty sea cable at the Anholt offshore wind farm, which resulted in a month-long generation shutdown in February and March. The outage was fully compensated by transmission system operator Energinet.dk, Dong said.

Total power generation in the first nine months of 2015, however, was 18% lower on the year, with a challenging power market in Denmark dragging down output, Dong said, noting low green dark and spark spreads.

The green dark spread in Denmark was minus €2.20/MWh for the nine months, flipping from €5.70/MWh a year earlier on the back of declining power prices. Power sales were slightly higher on the year at 22.3 TWh, up 1.8%, with power distribution just 0.1 TWh lower at 6.1 TWh.

Total investments in the first nine months of the year reached DKK14.6 billion (€2 billion), of which 56% related to wind projects and 5% to thermal projects. Dong said it would pursue an initial public offering within 18 months subject to market conditions, with the Danish state retaining a majority stake.

DONG ENERGY: OPERATIONAL FIGURES (TWh) 9M 2014 9M 2015Gas sales 94.2 87.1Power sales 21.9 22.3Distribution of gas 5.4 5.7Distribution of power 6.2 6.1

Source: Dong Energy



�� Conversion of Skærbæk power station in southern Denmark from gas to biomass is well under way, Dong said October 29. Heavy duty steel elements have just been shipped from India directly to the power station quay, to be used to build new wood chip boilers. Project manager Leif Høgh Sørensen expects commissioning of the plant to start in autumn 2016, allowing the power station to supply district heating based on wood chips in the 2016/2017 heating season. The entire conversion of Skærbæk, including commissioning and service trials, is expected to be completed in April 2017.

EUROPE

EC wants 2030 drafts by mid-2017The European Commission wants the 28 EU national governments to start work on integrated energy and climate plans for 2021 to 2030 next year and finalize them in 2018, according to unofficial draft EC guidance on the plans seen by Platts November 4.

Governments should submit first drafts to the EC by mid-2017, the EC said in its guidance paper, which is due to be published on November 18 with the EC’s first annual state of the EU energy union report. These drafts would be peer reviewed by other national governments and checked by the EC to see, among other things, if collectively they will achieve the EU’s 2030 energy and climate goals.

These goals are to cut EU greenhouse gas emissions by at least 40% on 1990 levels, to source at least 27% of final EU energy demand from renewables and to improve EU energy efficiency by at least 27% compared with energy demand projections.

The EC is to propose legislation next year to set the legal framework for these goals, which EU leaders agreed in principle in October 2014.

The emissions target is to be met partly by reductions achieved through the EU’s emissions trading system, and partly by binding national targets covering non-ETS sectors such as buildings, transport and agriculture.

The renewables target would only be binding at EU level, and the efficiency target is not binding at all, so the national plans are key to monitoring if the EU targets will be achieved.

Governments would have to deliver final plans to the EC in 2018, taking into account any comments from the EC or the peer review. The EC would publish a first aggregate assessment of all the plans in its 2018 state of the EU energy union report.

The EC wants national governments to cooperate and coordinate with their neighbors when preparing the plans, paying “particular attention” when developing new energy resources and infrastructures.

Governments would have to include in their plans assessments of how their national policies will impact their neighbors and how to strengthen regional cooperation. The EC said it would publish detailed guidance for governments on such regional cooperation next year.

Governments would also have to report on their progress in carrying out the plans to the EC every two years from 2020, and the EC would include this in its annual state of the EU energy union reports.

The national plans would be updated once in 2024 to adapt to changing conditions and to keep on track for the 2030 goals, the EC said.

It said it would propose legislation next year to streamline national government’s planning and reporting requirements and also publish a template for the integrated national energy and climate plans.

Governments already provide separate national renewables and energy efficiency plans with regular progress reports, as well as regular reporting of their emissions, as part of efforts to reach the EU’s 2020 energy and climate goals.

Carbon hits 35-month highThe price of carbon dioxide allowances under the EU Emissions Trading System rallied to a 35-month high in October, continuing a long-term trend linked to expected tighter supply in future.

EU Allowance prices for delivery in December 2015 in the over-the-counter market averaged €8.40/mt for the month compared with €8.13/mt in September, a month-on-month increase of 27 eurocent or 3.3%, according to Platts’ daily closing assessments. And on November 6, Germany sold 3.198 million CO2 permits at €8.45/mt at auction.

EU countries sold a total of 60.2 million EUAs at auctions in October. The average cleared price at primary auctions in October was €8.35/mt, compared with €8.06/mt in September, according to data from the European Energy Exchange in Leipzig, Germany, and the ICE Futures Europe exchange in London.

October’s EUA auction volume brought the 2015 total to 540 million mt sold, earning EU governments a total of €4.038 billion. The average cleared price at European carbon auctions this year was €7.50/mt as of October 30, with the low and high at €6.26/mt and €8.63/mt.

ACER ‘needs greater data access’EU energy regulatory energy agency ACER would like the right to access more data to use in its annual EU gas and electricity market monitoring report, its director Alberto Pototschnig said October 29.

“We don’t have any power to require data, and as soon as we go into sensitive areas it becomes very, very difficult to get the data,” Pototschnig told a Eurelectric conference in Brussels.

The European Commission is reviewing ACER’s role and powers as part of work on its “EU energy union package” of legislation expected by the end of 2016. One improvement the EC could propose would be to give ACER more powers to access data, he said.

ACER’s next market monitoring report is due out on November 30. It will include an analysis of the EU’s



wholesale gas and electricity markets and grid access, and look at what is stopping further integration.

Pototschnig said it would also be a good idea to give ACER more powers to supervise formal EU power and gas grid operator bodies Entso-e and Entsog, if the EC decided to strengthen their role.

“We could replicate the national model at EU level,” he said, so ACER would supervise Entso-e and Entsog as national regulators supervise their national grid operators.

Pototschnig also called for ACER to have the right to peer review national regulators’ decisions on its own initiative. “So if we see something wrong in the market we don’t have to wait until the commission or another national regulator asks for it,” he said.

For example, ACER recently reviewed the electricity capacity allocation arrangements that enable Austria and Germany to be a single price zone, at the request of the Polish national energy regulator.

ACER concluded that the unlimited capacity allocation on this border was causing severe physical congestion on other borders.

It urged the German and Austrian regulators and grid operators to introduce capacity allocation mechanisms on this border, which could lead to different prices in the two countries at certain times of the day.

Pototschnig said that ACER could also help more in decisions involving all national energy regulators and grid operators. For example, under the EU’s binding capacity allocation and congestion management network code, all grid operators have to agree a common proposal for capacity allocation regions and submit it for approval to each of their national regulators by November 14.

Each of the national regulators then have six months to approve the proposal – so one slow regulator could hold up the whole process, Pototschnig said. “I think there are better ways [to do this], and probably the agency can play a role with that,” he said.

FRANCE

Gas burn quadruples in OctoberTemperatures in France fell in October to their lowest levels in over a decade, quadrupling gas-for-power burn and pushing average day-ahead power prices up 6% year-on-year to €43.97/MWh.

Chilly conditions pushed electricity demand up 8.5% year on year to 38.9 TWh according to grid operator data compiled by Platts PowerVision.

A 5.6% rise in nuclear output this October to 34.3 TWh versus October 2014 was not enough to match the higher demand.

Gas-fired generation stepped up, increasing 1.8 TWh on year to 2.41 TWh, four times levels seen in October 2014.

In all, France recorded a 37% hike year-on-year in gas demand this October to 3.5 Bcm, mainly due to CCGT demand. Cheaper gas prices provided an additional

incentive to gas plant owners to ramp up output, with PEG Nord day-ahead down 15.14% year on year at €18.491/MWh, while the TRS day-ahead plunged 25.61% at €18.606/MWh.

Some 17 gas-fired power units were operating (out of 18 available) compared to 12 gas plants last year (of 21 available), RTE data showed.

Meanwhile French coal-fired generation this October was down 7.6% at 980 GWh on sharply reduced coal plant availability. Only four coal units were operating this October, compared to eight last year.

Increased gas burn made up for a dip in renewables output. Wind output fell slightly to 1.21 TWh from 1.26 TWh in October 2014, and hydro output was down 7.8% at 3.51 TWh, while solar output was up by 8% at 520 GWh albeit from a small base.

CRE warns of rising DR costsThe cost of paying for more demand response to manage peak demand in 2016 could significantly reduce the resultant benefits in terms of security of supply and balancing expenses, regulator CRE said October 27.

By increasing the amount that transmission system operator RTE will tender for later this year, the government has created a situation in which RTE will have to accept bids at unit costs that will “probably” be higher than in the past, CRE said.

Under the energy transition law passed in August, it is the government that now sets the requisite level of load curtailment. This it has set at 2,000 MW for large users over any one month, and at 300 MW for retail users (36 kVA or less). Last year’s total was 1,500 MW, which was supplied by six operators (suppliers and aggregators).

The terms on which companies can obtain remuneration from RTE for demand response will remain substantially unchanged according to CRE. The changes RTE is proposing compared to last year are a higher penalty for cancelling a contract as a disincentive to bid without any certainty of being able to deliver, and lowering the ceiling on bids from 10 MW to 1 MW. This is in line with a reduction in the balance threshold introduced earlier this year. CRE has approved both changes.

Market verdict deflates EDF stockEDF’s share price fell 8% November 5 with fears for the future prevailing over solid nine month 2015 results, BNP Paribas credit analyst James Sparrow said November 6.

The decline was due “to a combination of concern about earnings dilution following the French State’s decision to take the scrip dividend as well as EDF’s potential exit from the CAC40 [Euronext index],” Sparrow said.

The analyst had expected the equity markets to react more positively to EDF’s plan to sell a stake in transmission network subsidiary RTE, a key element in the utility’s CAP 2030 strategic program.

“The simple takeaway from this seems to be that equity as well as credit markets are highly sceptical about EDF’s future strategic direction,” Sparrow said.



The reaction was despite solid volume and sales news from the utility. Nine month 2015 French nuclear output was up 1.2 TWh year on year to 306.3 TWh, with full year 2015 French nuclear output now seen at the upper end of EDF’s 410-415 TWh target.

The increase in nuclear output partially offset a 3.8 TWh decline in hydro output, which stood at 26.4 TWh for nine months 2015.

Total French electricity sales of €28.7 billion were down 0.9% in organic terms year-on-year, “penalized by the decrease in market prices, which led to a drop in ARENH volumes sold (-39.5 TWh), and an equivalent increase in market sales (+39.3 TWh). Sales were also affected by the end of some long-term contracts,” EDF said.

In the UK, meanwhile, EDF sales fell 5.2% in organic terms to €7.7 billion. Nuclear output was stable at 44.5 TWh, with good operational performance of the nuclear fleet offset by reduced load at Hartlepool and Heysham 1.

In Italy, sales stood at €8.6 billion, down 6.6% in organic terms “due to a drop in average sales prices and the decrease in volumes sold on wholesale markets and to end customers,” EDF said. Hydro output for the period fell 31% or by 1.2 TWh, offset by stronger thermal and wind generation.

GERMANY

Export surplus soarsGermany’s electricity export surplus soared 67% (14.3 TWh) to 35.7 TWh in the first nine months of 2015, energy and water federation BDEW data showed November 4.

Gross generation in the period reached 479 TWh, up 4.4% on the 459 TWh generated in 9m 2014. For whole year 2015, BDEW forecasts gross generation of 645 TWh, up 3% or 19 TWh on 2014’s 626 TWh.

German electricity consumption in the first eight months of 2015 also showed an upward trend to 364.3 TWh, 2.6 TWh or 0.7% higher than the 361.8 TWh consumed in the same period of 2014, according to the BDEW.

Renewables accounted for the largest share in generation at 145.5 TWh, leaving the next largest fuel contribution, lignite, well behind, at 115 TWh (114.4 TWh for 9m 2014).

Renewables generation was up 20% (24 TWh) for 9m 2015 to 145.5 TWh, from 121.6 TWh in the equivalent 2014 period, taking a 30% share of gross electricity generation.

Of RES technologies, wind (onshore plus offshore) provided the biggest increase, up 52% to 59 TWh from 38.8 TWh in 9m 2014.

Next in the pecking order was solar, up 5% to 33.2 TWh (31.5 TWh 9m 2014), followed by biogas/biomethane at 22.3 TWh (21.5 TWh) and hydro (16 TWh, up from 14.7 TWh).

Coal generation fell to 84.8 TWh and nuclear to 68.8 TWh in 9m 2015 (86 TWh and 69.7 TWh respectively for 9m 2014) according to coal federation GVSt and BDEW.

Gas-fired generation accounted for just 9% of German gross electricity generation, albeit showing a 1.8 TWh increase to 43.1 TWh in 9m 2015 from 41.31 TWh for 9m 2014.

Steag targets 90 MW battery portfolioIndependent power producer Steag is to invest €100 million on six unsubsidized battery systems totaling 90 MW, the company said November 4.

The 15-MW lithium-ion systems are to be commissioned between mid-2016 and the beginning of 2017 at Steag coal power station sites in Herne, Luenen and Duisburg-Walsum in the state of North Rhine Westfalia and in Bexbach, Fenne and Weiher in the Saarland.

The batteries will be used for primary reserve and marketed by Steag’s Trading and Optimization division. Primary reserve is procured in weekly auctions by the transmission system operators. It must have a response time of under 30 seconds and a minimum supply time capability of 30 minutes.

Steag already operates a 1 MW battery storage system at its Volkingen-Fenne coal power station site, commissioned in February 2014. This project was supported by the federal economy ministry.

NETHERLANDS

SDE+ funds dispersedDutch renewable energy developers holding out for the highest subsidy rates under the SDE+’s final auction round November 9 have been disappointed. The €3.5 billion budget for 2015 is all spent up across previous, lower subsidy level rounds. This was not unexpected, as the take-up rate was high from early in the year.

The money has gone to 194 projects. Of these 145 were for renewable electricity and will receive a total of €1.59 billion. There were 590 applications in this category in all, so only one in four were successful. However, the unsuccessful projects were mainly small-scale photovoltaics – 437 of the 445 unsuccessful projects applying for a total of €404 million.

The picture was different for renewable heat and cogeneration, as many larger projects were unsuccessful. There were 153 applications seeking €5 billion, of which 49 were successful and received €1.9 billion. A further €0.6 billion went to 12 green gas projects. No green gas projects were rejected.

The good news for unsuccessful bidders is that there will be significantly more money available in 2016. Energy Minister Henk Kamp announced October 9 that he is making €8 billion available in 2016. He wants to make sure there is enough for several large onshore wind projects, which will be mature enough to apply next year. He is also expecting applications for co-firing of biomass.

Kamp is not just reacting to demand for subsidies, but to the fact that the Netherlands is falling behind in reaching its renewables targets. The latest figures suggest it can still reach its 16% target by 2023, but that the 14% target for 2020 is not achievable. The government’s current projection is 12.4%.



Using the methodology applied by the European Commission, the figure is only 11.9%, but the Dutch government is to press the EC to change this. It believes that current methodology does not take innovative technologies into account, which increase the number of operating hours.

Next year’s budget is to be available in two tranches of €4 billion. There will be phased increases in the subsidy level as in previous years.

Cable EIAs proceedTennet has appointed Witteveen+Bos and Mott MacDonald to prepare environmental impact assessment and license applications for interconnection of the Hollandse Kust Zuid offshore windfarm area, the TSO said October 22.

This is one of three offshore windfarm zones designated by the Dutch government and will be the second to be developed. Tennet said in November 2014 that Arcadis and Pondera would be preparing the EIA and license applications for the Borssele zone.

The government’s intention is to have 3,500 MW installed in the three zones by 2023. Before it can tender for this capacity it needs to obtain an EIA for a ‘cable decision’ on the interconnectors.

The Environmental Assessment Commission said October 13 that it was happy with most of the draft EIA for the Borssele 1 and 2 cables, and in particular the provisions on the protection of marine and wildlife. It asked, however, for provisions on the safety of shipping to be made clearer.

First turbine in at ZuidwesterConstruction of the 90-MW Zuidwester wind farm “is in full swing” on the dyke along the shore of the Ijsselmeer, RWE reported November 4. The first of 12 Enercon 7.5-MW wind turbines was put into operation a day earlier. Fifty turbines installed during the late 1980s and early 1990s are being replaced by the larger machines. “Each of the new Zuidwester turbines can generate as much electricity as all 50 turbines of the old wind farm combined,” REW said. The Enercon turbines are the largest in the world with a hub height of 135 metres. Total investment is put at over €150 million.

Nine industry associations and 17 companies have aligned to form a umbrella organization for sustainable energy in the Netherlands, project partners said October 26. The Dutch Association for Renewable Energy (NVDE) has been formed to serve as a partner for energy companies and the Dutch government to aim for a fully renewable energy supply by 2050. The NVDE has set out guidelines for renewable energy targets by 2050, the introduction of a “polluter pays” principle, flexibility in the energy market and maximum accessibility in the market for newcomers, among others, it said. Partners include Eneco and Delta, TSO Tennet and several financial partners including ASN Bank and PWC.

PORTUGAL

Thermal steps up for hydroPortuguese thermal generation increased 43% year-on-year to 1.9 TWh in October as hydro generation fell and export demand increased, data released November 2 by grid operator Redes Energeticas Nacionais showed.

Total national demand was 4 TWh in the month, a fall of 1% year on year on both an adjusted and unadjusted bases.

Hydro output was down 7% year on year in October to 691 GWh, while renewable output rose 15% to 1.9 TWh, REN said. This included wind output of 1.2 TWh in the month, an increase of 34% year on year.

Portugal’s electricity imports from Spain were down 69% year on year at 152 GWh in October while exports increased 492% to 494 GWh.

Usable hydro stocks (in reservoirs and rivers) at the end of October were 1.7 TWh or 54% of the maximum, up from 52% at the end of September.

SPAIN

October demand edges upSpanish gross power demand rose 0.3% year-on-year in October to 19.75 TWh, grid operator Red Electrica de Espana (REE) said October 30. The increase followed a 3.7% decline in September, the first of the year, according to REE data.

Adjusted for working days and temperature, demand was up 3.7% year-on-year in October, REE said.

For ten-months 2015, gross demand was up 2.4% and adjusted demand 1.4% compared to the year-ago period, for a total 207.177 TWh.

During October, production by generation type was: wind 19.9%; hydro 8.2%; nuclear 21.0%; cogeneration 12.0%; CCGT 10.7%; coal-fired 22.2%; photovoltaic 2.7%; renewable thermal 2.2% and thermosolar 1.1%.

Generation from renewable sources provided 34.1% of total October output, REE said. Wind-powered generation was 3.77 TWh in the month, up 15.6% year-on-year.

PORTUGAL: ENERGY BALANCE OCT 2015 Peak capacity, Oct 2015 Oct 2014 % change Oct 2015 (MW) (GWh) (GWh) YoYLarge Hydro 2,122 691 745 -7.2Conventional thermal 2,791 1,859 1,301 42.9Total production, ordinary regime 4,891 2,550 2,045 24.7Imports (commercial) 595 152 489 -69.0Exports (commercial) 1,385 494 84 491.5Import balance -1,393 -342 408 -184.0Pumping 715 149 105 42.0Small Hydro 210 72 104 -33.0Special regime thermal 890 628 637 -1.5Wind 3,680 1,177 878 34.0Solar PV 165 45 47 -4.3Other 0 0 0 0.0Total production, special regime 4,519 1,922 1,666 15.1Consumption 5,974 3,981 4,014 -0.9

Source: REN



�� Spanish hydroelectric production totaled 22.41 TWh during the first 10 months of the year, 26.9% below the 30.67 TWh generated in the same period of 2014, according to environment ministry figures November 3. Following a five and a half month decline, hydro reserves rose in week 44 to October 30 by 1.4 percentage points to 46.4%, or 10.32 TWh. That compared to 53.9%, or 11.98 TWh, at the same time last year and the 10-year average of 41.9%, or 9.37 TWh.

Spanish tariff deficit narrowsSpain’s power sector recorded a shortfall between expenditure and income of €1.2 billion by the end of August, down from €1.9 billion at end-July, the country’s market regulator said October 27.

The tariff deficit follows from Spain failing to hit a zero target for full-year 2014 and was €530 million beneath the expected deficit for the end of the month, according to Comision Nacional de los Mercado y la Competencia (CNMC). This is because some of the lagging income items are accounted for after the end of the year.

The January-August data this year show that a 3.3% gain in power demand, compared to the average of previous years, pushed income from grid access fees up 2.4% from the trailing average to €8.4 billion, CNMC said. At the same time, costs came out €300 million lower than forecast for the period due to lower capacity payments for thermal generation units and lower-than-expected renewable payments, it said.

The deficit registered at end-August means that only 87% of the €4.5 billion worth of renewable subsidies for the period will be paid, CNMC said.

Spain recorded a debt of €465 million in 2014, or about 3% of total system costs, an amount CNMC said it will eliminate by December. This means about €30 billion of debt has been generated since the early 2000s, an amount which has been largely correlated to the boom in renewables that took place at the end of the last decade.

However, with the system returning into balance, the government said earlier this month that it was lining up a new royal decree to allow an auction for 500 MW of new wind and 200 MW on new biomass capacity, which would be the first new renewable awards since a moratorium that was put in place in 2013 to help rein in the tariff deficit.

Industry Minister Jose Manuel Soria said he sees the system generating a surplus of €500 million in 2015, meaning that the target of sustainability would be met.

SWEDEN

Bottlenecks ‘costing €200 million/yr’Swedish and Norwegian electricity producers are losing as much as €200 million/yr because of transmission bottlenecks between the Nordic region and Germany, Anne Vadasz Nilsson, general director of the Swedish Energy Markets Inspectorate, said November 4.

A study by the inspectorate between 2012 and 2014 showed producers lost a total of between €120 million and €200 million each year “because they can’t sell their electricity” to Germany, or export electricity from Germany to Poland and the Czech Republic.

Nilsson said the problem “is being taken seriously in the EU at a very high level.” It could take 10 years, however, before cross-border grid connections improved.

Vadasz was speaking in Stockholm on the sidelines of the Vind 2015 wind power conference. Also there was Mikael Odenberg, general director of Swedish grid company Svenska Kraftnat. He said the TSO was investing in cross-border connections to Finland and Lithuania as well as improving the grid in Sweden to handle more wind power.

Svenska Kraftnat has its most recent development plan out for comment. The plan runs for 10 years and is updated every other year. Odenberg said the plan takes into account earlier-than-planned closure of nuclear reactors. “For several years I have been saying that reactors are going to be shut not for political reasons, but for economic reasons, and we have factored that in,” he said.

The TSO could help ensure stable energy supply post-closures by using new technology such as battery storage for solar energy, increasing imports via stronger interconnections and by offering demand-side incentives to encourage consumers to be more flexible in their consumption, Odenberg said.

SWITZERLAND

Conventional hydro support nearsThe Swiss parliament is preparing to extend subsidies to the nation’s hydropower stations. The energy committee of the lower house (National Council) followed the lead of the upper house (Council of States) and voted 13 to 11 in favour of a government handout.

The lower house wants to grant the utilities a premium of at most 1 centime/kWh (0.923 eurocent/kWh) for electricity that has to be sold at below the cost of production.

In the version approved by the Council of States, only utilities that are in “economic straits” would be eligible. The committees of both houses would also reserve a maximum of 0.2 centimes/kWh out of the KEV renewables subsidy scheme for hydro, up to a maximum CHF 120 million/yr.

Meanwhile the Swiss government October 28 adopted a “climate and energy incentive system” tax reform which, if approved by parliament, would result in an incentive tax on fuel and electricity as of 2021.

SPAIN, JAN-OCT PRODUCTION SHARE (%) Jan-Oct 2015 Jan-Oct 2014Wind 19.200 19.600Nuclear 21.800 22.100Coal 19.700 16.300Hydro 11.600 15.900Cogen, other 10.500 10.300Gas CCGT 9.700 8.300Solar PV 3.300 3.300Solar thermal 2.300 2.300Other thermal renewables 1.900 1.900Total production (TWh) 207.177 202.202

Source: REE



The electricity tax would initially be 2.3 centimes/kWh, rising to 4.5 centimes/kWh by 2030, with the proceeds used to promote renewables. The tax would replace the existing KEV federal subsidies system.

According to press reports, however, the project is likely to be still-born, being already opposed in parliament by both left and right. The adoption coincided with the announcement of the departure from the government of the author of the green tax project, minister of finance Eveline Widmer-Schlumpf.

�� The parliament of canton Zurich voted November 2 in favour of a motion requiring the cantonal government to install photovoltaic panels on all suitable buildings belonging to the canton. Councillor Martin Neukom noted that since 2005 the cost of solar power had fallen from 70 centimes/kWh to 18 centimes/kWh. The canton has 2,100 buildings. At present 22 have solar panels.

�� The new Hagneck hydropower station began official production October 24, following a CHF 150 million, four-year retrofit that has resulted in a 40% gain in production to 110 GWh/yr. Owned on a 50-50 basis by BKW and the city of Biel/Bienne, Hagneck is operated by the Bielersee Kraftwerken, which was granted an 80 year-concession by the Bernese parliament in 2010.

Small hydro costs denouncedSmall hydro is the Achilles heel of the Swiss government’s renewables strategy according to Gallus Cadonau, CEO of the Greina Foundation, which has been defeated twice in its opposition to the CHF16.5 (€15.24) million Berschnerbach hydro project at Walenstadt, St Gallen canton.

The Foundation, devoted to the protection of Swiss waterways, has decided against taking its case to the Federal Supreme Court because, according to Cadonau, since the government itself is behind the nationwide promotion of small hydro, it would stand no chance.

Paid a maximum of 35 centimes per kWh, over a period of 25 years the Berschnerbach owner stands to earn CHF 37.7 million in KEV renewable subsidies for an investment of CHF 16.6 million, a 226% ROI, according to Cadonau.

Since the start of the KEV scheme between 500 and 900 small hydro projects have been planned, are in construction or are in operation.

Martin Boelli of the national small hydro association said November 4 that Cadonau had not taken into account either the costs or the risks of small hydro, including CHF 1 million planning costs and CHF 900,000 annual interest, controls which need to be renewed after 15 years, turbine and generator after 25 years. As for small hydro’s contribution, Berschnerbach alone would produce 10.6 GWh or enough electricity for 2355 households.

Recent small hydro projects include Elektrizitätswerk Altdorf’s CHF 18.5 million Bristen power station, under construction as of October 30 on the Charstelenbach. Commissioning is due in the first quarter of 2017.

Beznau ‘won’t generate again’The 380-MW Beznau I nuclear reactor is unlikely to produce electricity again according to Swiss Socialist MP Roger Nordmann, who sits on the energy committee of the lower house of parliament.

Nordmann has had access to operator Axpo’s report on the world’s oldest operating nuclear power station, commissioned in 1969, which has been out of action since mid-March.

In an October 30 email to Platts Nordmann said the report says 925 cracks or inclusions were found towards the internal angle of the C ring close to the fuel rods, the most sensitive area of the reactor pressure vessel, with an average 0.7 millimetre diameter.

“The content and genesis of these cracks or inclusions is not clear. The Federal Nuclear Safety Inspectorate has asked the operator for a plan of additional analyses to be validated then carried out. Only then might it be possible to restart Beznau 1, in the first quarter of 2016 at the earliest,” he said.

“At the time of manufacture only two inclusions or cracks were found during ultrasound measurement. Unless there was an error then, this means these defects occurred over time,” he said.

“The Inspectorate requires knowledge of what is in the cracks, and their genesis. A very difficult exercise therefore. And costly,” he said.

“To this must be added the ‘ordinary’ process of embrittlement of the steel of the RPV, especially in the C ring near the nuclear chain reaction. According to current projections based on the rhythm of neutron bombardment it would take another 14 years to reach the critical threshold for the final shutdown. But these projections are based on metal without 925 cracks or inclusions,” he said.

Beznau-1 was shut down for renovation and tests in mid-March and was due to restart in mid-July. This was postponed to August and then October. A further postponement followed after the discovery of irregularities in the reactor pressure vessel, which most likely existed since the unit began commercial operation in 1969, an Axpo spokesman said July 15.

�� The Leibstadt nuclear power station resumed service November 2 after an October 17 shutdown due to a hairline crack in the generator stator water cooling ring. This followed an earlier shutdown for one day at the end of September to repair an oil leak in the turbine control system. The estimated cost of one day of non-production is CHF 1.3 (€1.2) million.

TURKEY

Turkish blackout explainedThe grid collapse that saw most of Turkey left without power March 31 this year was caused by a combination of events and is unlikely to happen again, according to a



report from European network group Entso-e released late October by Turkish grid operator TEIAS.

The blackout occurred due to a seasonal pattern in spring when water levels in the major hydro dams in eastern Turkey are high, prompting substantial flows of cheap hydro power to western Turkish demand centers. This is turn sees more expensive thermal plants in the west taken offline.

The problem occurred because four of Turkey’s 12 east-west transmission lines had been closed – three as a safety measure during construction work, and one for routine maintenance.

As demand was still below peak summer levels the eight remaining transmission lines had been expected to cope. However when one overloaded, this caused the others to overload in succession, disconnecting the two halves of the grid and causing a frequency imbalance that effectively tripped both.

The report recommends that TEIAS improves its coordination of scheduled outage planning and maintenance work in order to avoid overloading the east-west corridor.

Overall the report concluded that the blackout was comparable in cause and nature to similar events that occurred in Italy in September 2003 and Germany in November 2006, when severe imbalances between two parts of the grids caused a frequency drop and widespread power cuts.

“It could have happened anywhere,” an Entso-e official told Platts, stressing that he was confident that TEIAS was perfectly competent and that such a countrywide blackout could not happen again.

The official praised TEIAS for having implemented correct procedures, which prevented the problem triggering overloads in Greece and Bulgaria.

TEIAS signed a long term grid synchronization agreement with Entso-e earlier this year, having been synchronized on a test basis since September 2010.

UNITED KINGDOM

UK generation updatesDong Energy has made a Final Investment Decision to build the 660-MW Walney Extension offshore wind farm in the Irish Sea, having secured all consents, completed site assessments and signed the majority of contracts for supply and installation of equipment, it said October 28.

Walney Extension is expected to be commissioned in 2018. It would then be the biggest offshore wind farm in the world, surpassing the 630-MW London Array. The wind farm is to be supported by a Contract for Difference under the UK’s FID-enabling regime, with a guaranteed strike price of £140/MWh for the first 15 years of production if commissioned in 2018. Dong is to use two different turbines at the site – 40 8-MW turbines from MHI Vestas and 47 7-MW machines from Siemens.

The UK’s Green Investment Bank, Siemens Financial Services and Macquarie Capital have joined RWE Innogy in taking 25% equity stakes in the 336-MW Galloper offshore wind project, RWE said October 30. Construction of the project off the coast of Suffolk is to start this November. Debt financing for Galloper has closed with a consortium of 12 banks and the European Investment Bank providing £1.37 billion of debt facilities. Siemens is to supply and install 56 6-MW turbines and has a 15-year maintenance contract. Galloper is close to its existing sister project Greater Gabbard off the Suffolk coast. It was awarded development rights by The Crown Estate in May 2010 and is scheduled to start operations by March 2018.

Multifuel Energy has gained approval to build a second 90-MW Ferrybridge multifuel unit at Knottingley, West Yorkshire, DECC said October 28. A final investment decision is still needed, said Tom Maillet, Multifuel Energy Ltd director. If positive, construction could start in 2016, with commissioning in 2019. The plant will burn municipal waste, commercial and industrial waste and waste wood on land at the existing Ferrybridge coal-fired power station site. Multifuel Energy is a 50:50 joint venture between utility SSE and waste management company Wheelabrator Technologies. A first 70-MW phase started operation in July, 2015. A three-year construction process was led by main contractor Hitachi Zosen Inova.

Canadian energy company Enbridge has taken a 24.9% stake in the 400-MW Rampion offshore wind project. E.ON remains the controlling shareholder at 50.1%, with the UK Green Investment Bank continuing to hold 25%. A final investment decision to proceed was taken in May, construction began in September and full operation is scheduled in 2018.

ROCs slip to £42.75Some 97,901 UK Renewable Obligation Certificates were sold October 27 in the Non Fossil Purchasing Agency’s e-ROC auction at an average price of £42.75, the agency said October 27.

The price was down 19 pence on the agency’s September auction, when 67,329 ROCs sold at £42.94. Over 500 bids were made during the auction, which saw more than twice the volume of ROCs sold than in the October, 2014 auction.

The next e-ROC auction is scheduled for November 26.ROCs are issued to eligible producers of renewable

energy in the UK.

CP13 SHARE OF BUY-OUT PAYMENTS RECEIVED: MAJOR ROC SUPPLIERS British Gas Trading 13.45%E.ON Energy 8.17%E.ON UK 7.09%EDF Energy Customers 16.72%GDF Suez Marketing 3.24%Haven Power 4.22%Npower 11.17%Scottish Power Energy 6.92%SmartestEnergy 1.96%SSE Energy Supply 13.64%Total Gas & Power 1.75%

Source: Ofgem



Electricity suppliers have to meet a percentage of their supply with ROC-accredited power. For the CP13 2014-15 compliance year the obligation level was 0.244 ROCs per MW, or 24.4% of supply. For the current 2015-16 CP14 period the obligation has risen to 0.290 ROCs per MW, or 29% of supply.

The NFPA said the average price in October “was subdued somewhat by the high number of CP13 ROCs sold.”

On September 10 energy regulator Ofgem confirmed that 71.922 million ROCs had been submitted by suppliers for CP13, a compliance rate of 99.1%, exceeding the 98.2% set for CP12.

Suppliers that presented ROCs towards their obligations received buy-out fund recycle payments October 16 (see table). Suppliers received £0.24 in recycle payments for each ROC presented. The biggest payouts were made to

A shortfall of £7.75 million in buy-out funds was due to seven suppliers not meeting their total obligations in time, Ofgem said. Late payments will be redistributed to complying suppliers, increasing the final recycle value of £0.24/ ROC, it said.

Cornwall Energy calculates the amount of banked ROCs carrying over into Compliance Period 14 (2015-16) in the range of 2.3 million to 2.7 million. A central view of 2.5 million banked ROCs “represents 3% of the market and is above the previous record levels set for banking set between CP12 and CP13 (2.4 million),” the consultancy said.

FiT deployment exceeds 4 GWOverall Feed-in Tariff deployment at the end of September 2015 was 4,010 MW across 763,606 installations, DECC said October 23. This was a 28% increase in FiT-installed capacity compared to end-September 2014, and a 26% increase in the number of installations.

Photovoltaics (PV) were responsible for 99% of the increase in installations and 81% of growth in capacity, with wind contributing 14% to capacity growth. The largest growth since September 2014 was seen in wind (up 37% to 442 MW) and anaerobic digestion (up 30% to 115 MW).

As at end-September 2015, PV installations represented 84% of FiT capacity (3,374 MW) and 99% of installations (755,036).

Sub-50kW PV installations represented 82% (2,767 MW) of total PV installed capacity and 99% (750,501) of installations.

Wind was the second largest technology representing 11% of total installed capacity (442 MW) and 1% of installations (7,047).

DECC noted that these figures reflected commissioned FiT projects, not accredited FiT projects. There is a time lag between when an installation is accredited, commissioned

RO BUY-OUT FUND, 2014-2015 Obligation Total Obligation ROCs presented Percentage of Buy-out payments Buy-out (ROCs) by suppliers obligation met by ROCs made by suppliers redistributedEngland & Wales (RO) 64,502,089 63,991,929 99.20% £17,772,168.40 £15,020,418Scotland (ROS) 6,579,671 6,527,541 99.20% £1,914,379.60 £1,619,421Northern Ireland (NIRO) 840,240 757,055 90.10% £515,010.20 £435,261Total 71,922,000 71,276,525 99.10% £20,201,558.20 £17,075,100

Source: Ofgem

and confirmed on the FIT scheme, which can vary for each installation, it said.

In its mid-October Winter Outlook 2015/16, National Grid said current embedded (distribution network-connected, effectively reducing demand on the transmission grid) wind generation capacity is 4 GW and embedded solar generation capacity is 7.8 GW. “We have assumed a 90 MW increase per month in solar generation in our forecasts,” it said.

The largest within-day variations for wind and solar generation combined last winter were approximately 8 GW, with an average of 3 GW. If this was all to be covered by changes in gas-fired power generation, it would result in average gas demand rate changes of around 15 mcm/d and a maximum of around 36 mcm/d, the TSO said.

For winter 2015/16, with the increase in renewables considered, it would result in gas demand changes with a potential of 16 mcm/d rate for an average day and around 40 mcm/d rate change for the maximum day.

“Significant within day variation of renewable generation, which could have resulted in potential gas demand changes over 30 mcm/d, occurred on only 5% of days last winter,” National Grid said. “With so few days likely to experience this level of demand change, and not all renewable variability being met by gas-fired power generation, within day variations are unlikely to cause operational issues this winter.”

In its October UK Power Price Pilot report, Eclipse Energy, an analytics unit of Platts, forecasts UK solar capacity at 10.1 GW by the start of next summer. Average solar generation during summer 2016 peak hours is expected to be 3.1 GW, up from 2.7 GW through summer 2015. The potential to hit peaks approaching 6 GW next summer, however, implied “a strong downward pressure on midday prices as thermal generation is curtailed between the morning and afternoon peaks,” it said.

FEED-IN TARIFF DEPLOYMENT Sep-14 Sep-15

Capacity (MW)

PV 2,661.90 3,373.70Hydro 63.30 79.10Wind 322.20 441.80Anaerobic digestion 88.50 114.80Micro CHP 0.60 0.70Total 3,136.50 4,010.20

Number of Installations

PV 599,415 755,036Hydro 611 695Wind 6,603 7,047Anaerobic digestion 123 181Micro CHP 621 647Total 607,373 763,606

Source: DECC



INDUSTRIAL WOOD PELLET PRICE ASSESSMENT $/mt Chg €/mt Chg

CIF Northwest Europe (45 day)*

October 30 158.00 0.00 143.10 -0.13November 06 158.00 0.00 147.10 4.00

*Net CV: 17 GJ/t

UK WOOD PELLET PROMPT SPREADS, OCTOBER 30, 2015 30% 35% 40% 30% 35% 40% (£/MWh) Chg (£/MWh) Chg (£/MWh) Chg (€/MWh) Chg (€/MWh) Chg (€/MWh) Chg100% dedicated (ROC x 1.5) 31.40 -0.75 41.72 -0.81 49.46 -0.85 43.91 -0.83 58.34 -0.84 69.17 -0.84100% conversion (ROC x 1) 10.02 -0.66 20.34 -0.72 28.08 -0.76 14.01 -0.85 28.44 -0.87 39.27 -0.8685-100% co-fired (ROC x 0.9) 5.75 -0.64 16.07 -0.70 23.81 -0.74 8.04 -0.85 22.47 -0.87 33.30 -0.8650-85% co-fired (ROC x 0.6) -7.08 -0.58 3.24 -0.64 10.98 -0.68 -9.90 -0.85 4.53 -0.87 15.35 -0.88Up to 50% co-fired (ROC x 0.3) -19.91 -0.53 -9.59 -0.59 -1.85 -0.63 -27.84 -0.87 -13.41 -0.89 -2.59 -0.89

Wood Pellet Cost – adjusted

Prompt 45-day 72.23 -0.43 61.91 -0.37 54.17 -0.33 101.01 -0.10 86.58 -0.09 75.75 -0.09

Monthly Average ROC auction price* (£)

October 42.75 -0.19

*Provided by NFPA Ltd

I2 pellet market bearish on high stocksIndustrial wood pellet traders maintained a bearish outlook for the rest of the year early November, with the spot market for volumes delivered into Northwest Europe remaining offer heavy as utilities sat on plentiful stocks.

Platts on November 6 assessed the weekly price of CIF NW Europe 'I2' industrial wood pellets basis 17 GJ/mt for delivery within the next 7-45 days, November 13-December 21 at $158/mt, unchanged for a second successive week.

Although consumption levels at European generators are healthy, sources said there were few signs that any of them needed to make a spot acquisition.

"It seems that the major burners have imported quite lot of pellets over the last few weeks and all look fairly balanced," one utility trading source said.

On the afternoon of November 6 the euro fell to below $1.075 against the US dollar on the back of higher than expected US non-farm payroll data.

The weaker euro against the dollar has often been cited as a key reason why shorts in the European industrial market have tried to source euro-denominated local volumes rather than from the US.

Offers for prompt December delivery Handysize cargoes of US pellets have stalled at around the $159-60/mt level with sellers not wishing to go any lower in the face of no firm bids.

One trader said that UK generator Drax was now operating two 645-MW biomass units and a third co-firing 85% pellets "at full speed."

Any delays in supply they've experienced are likely to be pushed to the very end of the year or even Q1," he said.

Expected Langerlo demand Sources said producer German Pellets' plan to convert the 556-MW Langerlo coal-fired plant in Belgium once it closes the purchase from German utility E.ON, would give industrial pellet demand a healthy lift.

However, one utility said he believed that much of the supply for the plant once converted had already been sourced.

According to Platts calculations, a 556-MW biomass plant operating at 45% efficiency and 90% overall availability would consume 1.75 million mt of pellets/year.

In the residential heat market, traders said that amid mild weather for the time of year, they were still waiting for the expected seasonal uptick in demand that could eventually filter through to the industrial market.

A European producer was heard buying two spot coasters of Portuguese origin pellets on a CIF Rotterdam basis, although no pricing has been disclosed.

One source estimated that prompt premium grade tonnage for delivery in Northwest Europe would be priced at around €135-140/mt.

— Gareth Carpenter

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German spot hits two-year high German spot power prices rose to a two-year high in October as supply from wind and solar fell away and outages hit conventional generation. Day-ahead OTC prices averaged €38.47/MWh for the month, up 20% from September and 9% above October 2014. Cross-border demand from higher-priced markets (notably France) added pressure, with net outflow rising to 1.4 TWh for the month. However, with three reactors (Leibstadt, Grohnde, Neckarwestheim 2) returning and the first winter forecast, sentiment changed early November. Wind peaks nearing 30 GW for the start of week 46 sliced over 30% off the week-ahead contract (week 46 vs 45), with Armistice Day November 11 further reducing regional demand amid mild temperatures. High winds could push week day-ahead prices below November 10’s current €20/MWh mark, traders said.Forward prices registered a short-lived recovery mid-October amid a rebound for coal but this was short-lived, and year-ahead base was back down to €29.30/MWh November 5 despite a strong carbon price. Front-year coal had staged a modest recovery to $49/mt, but fell back below $48/mt November 5 amid strong volatility in FX markets with the dollar strenghtening and the euro dipping below $1.09 for the first time since July, making coal more expensive for eurozone buyers.Meanwhile low river levels, especially on the Rhine, may pose challenges with reports of barges unable to reach southern German coal plants fully loaded, adding a premium to prices with some of the plants possibly ramping down at weekends. This could dampen any upside potential for ARA coal into Europe, a trader said.

France Early November spot prices climbed down from October highs, which had been driven up by cold temperatures, reduced nuclear availability, low wind and a tight system in Belgium. DA base was assessed at €45.55/MWh November 2, down from €56/MWh October 15. A declining day-ahead price persisted through a strike November 4 organized by workers opposing the opening up to competition of hydro power concessions. Instead it was intra-day prices that spiked that day, to as high as €267.24/MWh during the evening peak on unplanned outages after EDF unexpectedly removed 2.9 GW of nuclear capacity and hydro availability dipped. On the curve, Cal 16 base rebounded to €37.25/MWh November 4, having fallen to a ten-year low October 21 at €36.50/MWh, €5.50/MWh lower than the ARENH nuclear offtake price.

United Kingdom UK day-ahead power contracts posted steep losses early November as wind power was forecast to surpass 6 GW November 6 and unusually mild temperatures persisted. Day-ahead base power tumbled to £37.40/MWh November 5, the lowest value since January 27 when the contract

was assessed at £36.30/MWh, Platts pricing data showed. Peak demand of 48.2 GW November 2 was the highest so far this winter, but below the 49.7 GW peak recorded during the same quarter last year. Despite unexceptional demand, National Grid issued a warning of tight supply margins November 4 (see page one). This triggered a hike in the system imbalance price, sending the system buy price to £419.50/MWh for the 15:30 GMT settlement period. The warning failed to influence the spot over-the-counter market, which responded instead to bearish fundamentals, traders said, closing at £39.90/MWh in base and £45.45/ in peak. On the curve, November baseload ended October at £39.90/MWh, having opened at £42.10/MWh. Meanwhile a benign weather outlook, sufficient supply and bearish gas prices depressed the quarter-ahead power contract. Q1 16 base, valued at £43.20/MWh October 1, declined through the month to trade at £40.70/MWh November 5, Platts data showed.

Spain, Italy Healthy renewable power production throughout October saw average day-ahead power prices dip lower in Spain to average €50.05/MWh, down 3% from in September and 10% from October 2014, Platts data showed. A changing wind profile and a reactor outage saw day-ahead power prices climb higher in the first week of November to reach €52.50/MWh on November 5. After surging above 12 GW at the start of week 45, wind power generation declined to range between 3-5 GW in the second half of the week, data from Red Electrica de Espana showed. This was compounded by the planned outage of the 1 GW Asco-1 nuclear reactor, taken offline October 30 for refueling. December base began trading as the front-month contract at €46.65/MWh, while bearish sentiment saw year-ahead base dip below €47/MWh for the first time in four weeks, closing at €46.90/MWh November 5.

Italian curve power prices fell November 5, in line tracking PSV gas prices. December baseload was assessed 10 euro cent lower day on day at €46.85/MWh. Further out, Q1 2016 and Cal 16 both fell by 15 euro cent to €46.60/MWh and €45.70/MWh. PSV gas curve prices had backtracked that day amid declines at the Dutch TTF hub and mild weather. On the front end of the curve, December gas retreated 17.5 euro cent to close at €19.825/MWh, while Q1 gas was down 12.5 euro cent to €19.80/MWh. In the promptpower market, the PUN – single national day-ahead purchasing price –closed lower day on day at €49.97/MWh November 5, with minimum and maximum hourly prices of €37.61/MWh and €73.56/MWh.

Platts European Power TeamTel: +44 (0)207 176 6174E-mail: [email protected]



PLATTS BASE POWER ASSESSMENTS (Eur/MWh)

2015 12/18-sep 19/25-sep 26/2-oct 3/9-oct 10/16-oct 17/23-oct 24/30-oct 31/5-nov

United Kingdom

Day ahead 58.60 57.75 55.10 55.90 54.44 54.92 55.29 55.38Week ahead 57.52 56.53 53.38 55.67 54.37 55.75 54.61 53.45Month ahead 56.74 56.20 55.73 57.24 56.04 55.92 55.67 55.87Quarter ahead 58.78 58.06 57.39 58.80 57.83 57.55 57.27 57.032nd Q ahead 60.58 60.23 57.10 54.91 54.07 54.06 54.06 53.90

Germany

Day ahead 30.44 35.91 35.18 40.26 43.07 39.74 40.69 41.11Week ahead 34.26 32.84 33.06 36.16 35.75 33.81 39.25 29.65Month ahead 32.97 32.92 32.32 32.80 32.14 32.82 35.30 30.20Quarter ahead 32.04 31.59 30.90 30.84 30.07 29.91 30.89 30.612nd Q ahead 31.53 30.93 29.04 27.38 27.09 26.95 27.50 27.543rd Q ahead 27.74 27.45 27.49 28.48 28.31 28.15 28.61 28.69

France


Netherlands

Day ahead 38.05 40.75 40.50 42.70 41.55 40.35 40.95 42.06Month ahead 39.10 38.97 38.12 38.49 38.13 38.08 39.02 36.89Quarter ahead 39.12 38.95 38.15 38.17 37.59 37.48 37.66 37.362nd Q ahead 40.01 39.46 37.46 35.85 35.70 35.67 35.59 35.11

Spain

Week ahead 51.38 51.03 50.89 47.03 49.21 49.21 50.70 50.04Month ahead 50.45 49.50 48.23 46.14 46.41 46.97 47.81 46.51Quarter ahead 48.16 47.89 47.16 46.10 46.13 46.23 46.48 46.452nd Q ahead 46.16 46.10 44.90 43.22 43.57 43.72 43.73 43.74

2014 13/19-sep 20/26-sep 27/3-oct 4/10-oct 11/17-oct 18/24-oct 25/31-oct 1/7-nov

United Kingdom


Germany

Day ahead 36.58 36.11 39.43 35.16 38.74 34.64 37.82 38.68Week ahead 32.68 33.48 33.48 35.34 30.06 34.00 34.88 36.72Month ahead 33.93 34.69 36.17 36.25 35.04 35.26 35.37 33.83Quarter ahead 35.75 35.82 36.47 36.49 35.59 35.65 36.00 35.882nd Q ahead 37.39 37.24 33.92 31.79 31.51 31.69 31.87 31.843rd Q ahead 31.89 31.80 32.70 33.03 32.94 33.10 33.17 33.23

France


Netherlands

Day ahead 45.10 45.55 46.00 43.70 44.05 43.95 43.95 44.12Month ahead 45.54 45.26 46.91 46.65 45.67 44.90 44.56 44.69Quarter ahead 48.34 47.84 47.77 47.54 46.98 46.54 46.57 45.882nd Q ahead 49.55 48.88 45.85 43.99 43.64 43.48 43.27 42.56

Spain

Week ahead 54.61 56.75 54.26 52.00 56.77 59.13 47.44 48.25Month ahead 50.54 52.08 50.53 50.28 51.61 53.34 51.06 48.97Quarter ahead 49.40 50.06 48.86 48.21 48.68 48.89 48.02 47.382nd Q ahead 47.86 47.98 45.30 43.73 43.93 44.07 43.75 43.64

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: [email protected] Tel: +44 20 7176 6207



25

30

35

40

45

05-Nov22-Oct08-Oct24-Sep10-Sep26-Aug12-Aug

(€/MWh)

CENTRAL & EASTERN EUROPE YEAR-AHEAD BASELOAD

Source: Platts

Czech RepublicPoland GermanyHungary

10

20

30

40

50

60

05-Nov22-Oct08-Oct24-Sep10-Sep26-Aug12-Aug

(€/MWh)

CENTRAL & EASTERN EUROPE DAY-AHEAD BASELOAD

Source: Platts

Czech RepublicPoland GermanyHungary

Outages force Polish prompt up A spate of unplanned plant outages combined with scarce wind production to lift Polish day-ahead power prices above Zloty 200/MWh in the first week of November. Baseload power for next-day delivery settled at Zloty 201.75/MWh, or €47.66/MWh, November 4, the highest level for day-ahead baseload power since September 29.

The corresponding peakload contract cleared at Zloty 138.60/MWh, also the highest level heard in just over a month.

Prices had dipped lower in October as the return of cogeneration plants offset a drop in wind and lignite plant availability. Polish day-ahead base averaged €39.23/MWh in October, down 8% from €42.53/MWh in September, and 15% lower year-on-year.

Prompt prices began to recover early November with nearly 7 GW of conventional capacity taken offline for maintenance. In addition, wind power generation struggled to rise above 500 MW in the first week of the month. A forecast surge in wind at the start of week 46 was likely to boost margins during a period of subdued demand with November 11 a public holiday in Poland, traders said.

After dipping below seasonal norms at the end of the month, milder weather may ease pressure on demand in the coming

days with CustomWeather pegging temperatures in Warsaw 5-7 degrees Celsius above the average of 2-8 C in week 46.

On the near curve, November baseload closed on the last trading day before delivery at Zloty 163.50/MWh, just over Zloty 10 above where it began at the start of the month. December baseload, no doubt factoring a Christmas demand lull, was assessed at a strong discount to the November contract at Zloty 148.50/MWh November 4. Year-ahead base, meanwhile, briefly rallied above Zloty 163/MWh before falling away to trade at Zloty 160/MWh November 4.

Losses stemmed on Hungarian promptHealthy supply fundamentals continued to weigh on Hungarian day-ahead power, while losses were stemmed further out on the prompt on the back of an expected reactor outage and weakened hydro reserves.

Baseload power for next-work-day delivery traded within a €5 range in the last week of October and the first week of November, closing November 5 at €47.25/MWh.

“Next week should have similar availability except [a unit at] Paks is going offline . . . river production will also be declining,” said a trader October 27, adding that dry but colder weather conditions were expected in the next two weeks. “There are too many bullish signals.”

One of four units at the 2 GW Paks nuclear power plant would be taken offline for scheduled maintenance on November 7, curbing supply in the short term.

Weakened hydro levels across the region have also weighed on the prompt with river levels dipping below typical November levels in week 45, hydrological forecasts showed.

Baseload power for delivery in week 46 was assessed at €45.50/MWh November 5, a single euro above week 45’s baseload price close October 30.

November base also rose in the last week of October to close at €45.85/MWh, still below where it began trading at the start of the month. December base meanwhile moved sideways in the first week of November at €43/MWh, while year-ahead base was steady at €40.45/MWh.

In the Czech Republic, day-ahead prices began to align with neighboring Germany in the first week of November despite ongoing outages at CEZ’s Dukovany nuclear power plant. Czech day-ahead base closed OTC at €37.65/MWh November 5, more than €12 lower week-on-week. The peakload contract was also assessed €12 lower from the previous week at €44.25/MWh.

— Petra Witowski



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UK NBP GAS FOR NOVEMBER 5 (pence/th)

Bal Month Nov 37.60 – 37.80

December 38.88 – 39.08January 39.35 – 39.55February 39.70 – 39.90March 38.75 – 38.95Q1 2016 39.25 – 39.45Q2 2016 35.70 – 35.90Q3 2016 35.15 – 35.35Q4 2016 38.50 – 38.70Oct 2016 1 yr 37.10 – 37.30

Source: Platts European Gas Daily

FUEL OIL FOR NOVEMBER 5 ($/mt)

Northwest Europe (1% cargoes)

Spot (1%) 223.75 – 224.25December (1%) 223.00 – 223.50January (1%) 227.75 – 228.25Q1 16 (1%) 232.25 – 232.75

Source: Platts Global Alert; spot= 5-15 days ahead of publication

STEAM COAL PRICES ($/mt)

Nation/Area Price

November 5

CIF ARA 53.85FOB Richards Bay 53.10FOB Kalimantan 47.60FOB Newcastle 51.20

October 30

FOB Colombia 49.70FOB Qinhuangdao 62.90Russia Pacific 54.00CIF Japan 58.25CIF Korea West 53.00

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.

Source: Platts Coal Trader International

Gas UK curve gas prices for Q1-16 and Q3-16 continued to fall through early November, with Q3-16 breaking through the UK Coal Switching Price (CSP) to trade at 35.25 pence per therm November 5, a level not seen since 2009-2010. A well supplied UK market, on the back of a mild late autumn, slack residential heating demand, robust LNG sendout and BBL imports has seen UK storage return to injections. Midday November 6, day-ahead gas was trading at 35.60 p/th (down from 40.90 p/th September 24), week-ahead at 36.00 p/th, December at 38.975 p/th and Summer 16 at 35.50 p/th. LNG sendouts have averaged 51mcm/d in November, according to Platts’ analytics unit Eclipse Energy. “The UK is scheduled to receive three Qatari cargoes by 10th and two cargoes are likely to offload by 13th. If these cargoes discharge at SH, sendouts will be maintained at 50mcm/d until 13th,” it said November 5.“There is 170mcm of injection space remaining at Holford and Aldbrough but with the weather forecast remaining warm the near curve can cycle down as different periods compete for this space,” the unit said.On the continent, Dutch TTF day-ahead gas dealt 30 euro cent lower day on day November 6 at €16.875/MWh, having traded at €18.175/MWh as recently as October 23. The NetConnect day-ahead contract was at €17.15/MWh November 6, down from €18.425/MWh two weeks ago, while GASPOOL day-ahead was at €17.125/MWh, down from €18.125/MWh October 23.

Coal Europe-delivered CIF ARA thermal coal prices fell almost $1 per metric tonne November 5 on a lower December trade and market sources noting that the recent almost $2 eight-day bull-run had been overdone. Platts assessed the price of CIF ARA physical thermal coal basis 6,000 kcal/kg NAR and for delivery within the next 15-60 day period at $53.95/mt November 5, slipping 95 cents on-day. Early in the session, a 50,000 mt DES Amsterdam-Rotterdam multi-origin cargo with US optionality and exchange of futures for physical (EFP) terms attached traded via Atlantic Brokers at $53.60/mt, $1.15 lower than a similar trade November 4. The trade was said to be at a premium of $2.70/mt to paper prices at the time, down from premiums of $3.20/mt the previous day. A London-based trader said offers in the CIF ARA market had started to fall November 4, the market characterized by weak demand on the continent and low coal burn in the UK due to taxes. A European trader said while there was some truth in there being less multi-origin coal available, he had still seen normal shipments from Colombia amid no new demand. “There is still a lot of Russian coal around, but prices are higher so people aren’t as interested in buying it as they were,” he said. The trader added that Polish and US coal was out of the market, except for long-term contracts.

http://blogs.platts.com/



EUROPEAN POWER DAILY

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.

www.europeanpowerdaily.platts.com

EEX PHELIX PEAK AND BASE SPOT MARKETOCTOBER 7 – NOVEMBER 6, 2015

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