London — European natural gas and power markets are entering the winter season under strain, with a significant risk premium priced into the forward curve.
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Limited supply-side flexibility in the gas market, a shortfall in Belgian nuclear and Nordic hydro in the power sector and a bullish wider energy complex have pushed gas, power and carbon prices to record highs, improving coal-fired generation spreads in the process.
The northwest European gas market has tightened ahead of the winter because of low storage levels, a number of structural domestic supply-side issues and strong competition from Asia for LNG cargoes.
In power, recent Belgian nuclear delays have spooked an already bullish market, although a healthier French nuclear outlook is expected to help offset any Belgian shortfalls.
A key factor set to define both markets will be the weather. Forecasts suggest a mild start to the winter, but the Beast from the East weather system that hit Europe at the back end of last winter is still very fresh in people's minds.
Surging gas prices have widened the premium versus the coal switching price to the extent that the Winter TTF price is now above the upper limit of the European switching channel, even testing the UK coal switching price.
This indicates lower gas demand for power generation and higher reliance on coal.
According to Platts Analytics, the high gas price can to some extent be explained by a winter risk premium given how tight the market looks and how little it would take in terms of new outages to knock the market.
"The gas price on the curve for the Winter 18 contract has clearly been driven by the level of risk the market is willing to price in," Simon Wood, analyst at Platts Analytics, said.
Gas demand in northwest Europe has witnessed 20 Bcm swings seen over the past five winters, according to S&P Global Platts Analytics, so the prevailing weather conditions will play a key role in how the system balances.
Gas storage in northwest Europe has finally caught up to last year's levels having started 6 Bcm lower, with stocks in the key northwest European market (Germany, Netherlands, France, Belgium and Denmark) built to more than 34 Bcm.
With supplies from Norway and domestic production expected to be maxed out through the winter, the arrival of LNG cargoes could be a determining factor in the market.
The JKM-TTF spread has narrowed considerably in recent weeks and LNG sendouts in NW Europe have risen strongly to make way for new cargoes, with the gas likely headed straight into storage.
According to S&P Global Platts calculations, the netback for US LNG supplies to Europe is higher than for exports to Asia in October, November and March 2019, incentivizing European LNG imports in those months.
But whether the cargoes land on NW European shores remains to be seen. According to Platts Analytics' latest forecasts, LNG imports in northwest Europe (UK, France, Belgium and the Netherlands) are expected to total around 5.4 Bcm in Q4 and 5.9 Bcm in Q1.
Russian supplies are also set to continue at record high levels given the competitiveness of contracts with oil indexation versus the European hubs, with flexibility provided by the spare capacity on the Ukrainian route.
There are, though, a number of supply constraints and downside risks.
Dutch production is in steady decline, with the Groningen production cap for the start of the next Gas Year on October 1 set to be 2.2 Bcm lower than this year at 19.4 Bcm.
The lack of the Rough storage site will again see the UK stretched during times of high demand, while Norway is prone to unplanned outages.
The leak on the Forties pipeline last winter -- which saw UK gas output halved -- also reminded the market of the fragility of the North Sea's ageing infrastructure.
The UK may need additional imports from continental Europe to cope this winter, though the Q1-19 NBP-TTF spread implies strong imports that would see the UK covered in all but the most extreme demand cases. Already some 67% of IUK capacity in the direction Belgium-UK for Q1 has been booked, while around 89% of capacity in the BBL pipeline from the Netherlands to the UK has been reserved.
There are two factors that may offset some of the bullish elements in the northwest European market -- the startup of the major Aasta Hansteen field in Norway (with expected plateau production of some 15 million cu m/d) and the sale of more than 10 million cu m/day of gas by Gazprom Export on its new electronic sales platform.
A wildcard for premium markets in southern Europe could be the early rampup of LNG exports from Egypt, with Platts Analytics forecasting supplies starting small in November and December at around 0.1 million mt/month before rising to almost 0.5 million mt/month by April next year.
A tight electricity market is expected over the winter, with the forward market rising strongly on the back of gas, coal and CO2 costs.
The German Q4 power contract soared to a seven-year-high in September, and is set to go into delivery at a price almost double that of its spot outturn for Q4 2017.
A strong bull-run in gas prices has allowed Q4 18 coal the breathing space to rise above $100/mt while maintaining, or even improving, its competitive position in merit orders compared with gas.
This has led to the expectation that -- all other things being equal -- Europe's coal-fired power stations will be pulled on to the system ahead of gas this winter, even in the UK.
German coal-fired power margins, which hit record lows in Q2, have bounced back with even the oldest coal plants in Germany ahead of modern gas-fired CCGT for the winter with gas-fired margins Eur5/MWh lower than last autumn.
In the UK, high gas prices have seen coal spreads back in the money this winter.
More than ever, out-turned European power prices this winter will depend on the weather.
With around 13 GW of additions set to take Europe's wind park to 182 GW by year-end, a mild, windy season would deflate prices pumped up to multi-year highs by a surge in CO2 and fossil fuel costs.
A prolonged cold period with little wind, however, could expose both the structural and the temporary decline in Europe's conventional plant availability, with Belgian nuclear outages a particular concern on top of years' of ageing coal plant closures.
Just one of seven reactors in Belgium -- already the premium market in NW Europe -- is due to be operating during Q4, though French nuclear availability is seen higher than a year ago, offsetting the Belgian outages.
French nuclear output is expected above Q4 2017 levels averaging just below 50 GW, according to S&P Global Platts Analytics.
Meanwhile, hydro levels across the Alps and Iberia have rebounded from record lows last winter, while the Nordic hydro deficit has been reduced by wet weather in September.
Germany's wind park is expected to reach 60 GW by year-end. With daily load factors swinging between 2% and 68% over the past two winters, the scope for volatility across Europe is akin to the entire output of the French nuclear fleet.
In the UK, outturn prices will also depend on temperatures and wind, with UK offshore capacity up almost 1 GW this year and total installed UK wind capacity now above 20 GW.
CARBON PRICE VOLATILITY
EU carbon allowances are facing a period of continued extreme price volatility in Q4 2018, as the market braces for the start of deep supply cuts starting in January and ongoing uncertainty over the UK's participation in the EU carbon market with a Brexit deal yet to be agreed with the EU.
Carbon prices surged to a 10-year high of Eur25.79/mt in September, linked to the bullish effects of upcoming supply cuts, strong hedging demand from the power generation sector and the return of financial entities to the market in 2018.
On the supply side, total volume from auctions is expected to rise to 104.9 million mt in October and 81.2 million mt in November, including carried-over volume from cancelled UK and German auctions on September 19 and 21, respectively.
These are the last two months of regular volume before supply falls sharply to 37.6 million mt in December due to the holiday season, and ahead of cuts in January due to the Market Stability Reserve.
On the demand side, electricity spreads in Germany, Europe's largest CO2 emitter, continued to favor coal-fired generation over gas-fired units in Q3 and this looks set to continue into Q4, maintaining strong demand for EUAs moving into the winter season.
Uncertainty over Brexit is also a risk factor for carbon prices. A UK-EU deal would be expected to have less impact on CO2, as the UK has informally agreed to stay in the EU Emissions Trading System until the end of 2020.
However, a no-deal outcome could see the UK drop out of the EU ETS on March 29, 2019.
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