A steep rise in coal and carbon prices has dragged European gas contracts up so far this month, but the uptick should not obscure the fact that balances remain precarious. If June was a test of how efficiently the Northwest European market can absorb plentiful supply, the results were poor enough to cause more concern about the Q3 19 balance. Given June’s low prompt prices, Germany should have been able to realise more power sector gas burn, but a much-recovered Nordic hydro balance has boosted power exports into Germany, cutting domestic power generation y/y. With limited demand increases, a 15.5 bcm y/y NW European storage overhang, and our forecast for Q3 19 incremental LNG into Europe revised up by another 1.3 bcm, the outlook remains bearish in both relative and absolute terms. Given weaker-than-expected German gas burn growth in June, we have reduced our forecast for Q3 19 NW European power sector gas demand. Once the current price uptick runs out of steam, prices will need to move to levels that will encourage reduced Russian pipeline supply.
TTF prices dropped to multi-year lows in June, stepping down yet another fuel switch price trigger to swing between the parity level and the level at which a gas plant with a 5% efficiency advantage to coal is in merit. And yet the power sector gas demand response in Germany—the region tasked with absorbing the highest share of gas demand this summer—was less impressive than expected, rising y/y by 0.28 bcm (62%). The fact that German hard coal burn dropped by 41% y/y to a record low of 2.6 TWh shows that coal is far from economic and coal facilities are increasingly becoming the marginal plant. However, the barriers to higher gas burn were in part due to a slump in domestic German power generation, as Germany swung to making net power imports of 0.5 TWh, compared to 1.8 TWh of power exports at the same time last year.
The big y/y change in power exports has come as the Nordic hydro balance has recovered so well this summer, now at seasonally normal levels compared to the record low of -36 TW below the seasonal average measured this time last year. The resumption of Nordic power exports will cut German generation considerably across the rest of the summer. Q3 18 German power exports into the Nordic region and the Netherlands averaged 1.9 TWh per month, peaking at 2.6 TWh in July. Given that this is generation that could have been met by gas this summer, a halting of those exports alone represents a loss of roughly 0.39 bcm/m of gas burn, and even more if we assume that Germany continues to make Nordic power imports through the rest of the quarter.
Given June’s poor power sector gas burn, we have cut our Q3 19 expectations for German power sector gas demand to be up by 1.4 bcm y/y, down from the incremental 2.3 bcm y/y forecast last month. On the supply side, we have lifted our Q3 19 European LNG imports forecast by 1.5 bcm y/y to show a 7 bcm y/y gain—due to a continuation of weak Asian demand and strong global supply—with roughly 2 bcm of that going into the NW Europe market.
This paints a picture of an even looser supply-demand balance than in Q2 19. As such, prompt prices should start to settle more consistently at the parity fuel switch level (now at 11.3 €/MWh), as the market seeks to force all coal—and even some lignite—out of the generation mix. At the same time, it looks increasingly likely that the market will need a supply-side response, in the form of either a sharp slowdown in Russian supply, or a closure of the TTF-HH arb to slow late summer LNG deliveries. Certainly, with stocks on track to fill by early September, that month looks the most vulnerable to coming under significant price pressure.
|Fig 1: German power imports, TWh||Fig 2: Nordic hydro balance, TWh|
|Source: Fraunhofer, Energy Aspects||Source: Nordpool, Energy Aspects|
While high Nordic hydro stocks have been a thorn in the side of German power sector gas demand, French power sector gas demand has been strong so far this summer, which was unexpectedly Impressive given that French nuclear capacity has been higher y/y on most days. It was very weak hydro generation (-1.6 TWh, or 22% in June) that was the most supportive factor for French gas demand. The French hydro balance is 5.9 TWh below the seasonal norm, compared to a 1.1 TWh seasonal deficit a year earlier. Incremental French nuclear capacity is expected to rise more sharply in Q3 19 than in Q2 19, so gas power sector gas demand should finally soften, but poor hydro generation will certainly curb some of those incremental losses in late Q3 19.
The NW Europe balance continues to look very loose given the massive y/y storage overhang, calculated at 15.5 bcm (just 0.5 bcm less m/m) on 6 July. Dutch stocks—excluding Norg, which is filled directly from the Groningen field—are already at 97% capacity, leaving France and Germany with most of the spare capacity at this point. The region will have to shave 9.6 bcm off the surplus through the rest of the summer, or storage limits will be hit well before the end of the season. We forecast that incremental LNG into Europe will be lower in Q3 19 (+7 bcm y/y) compared to the 15.4 bcm delivered in Q2 19, with still some 2 bcm coming into the NW European facilities. Together, that is some 11.6 bcm of gas that will need to be balanced. We expect Norwegian receipts will be around 4.0 bcm lower y/y due to heavier maintenance, and the NW Europe will benefit from some increased exports into the southern European markets of Spain (+ 0.7 bcm) and Italy (+1 bcm), the key to balance will be in just what Gazprom does with regards to its ESP selling. Another record month of ESP sales could be hard to manage, despite starting July with a record sales week, as Nord Stream maintenance on 16-30 July will reduce direct flows to Germany and some Yamal maintenance will cut deliveries through Kondratki. Still, the impact of that maintenance could be offset in part by ESP sales through the southern pipeline routes and Gazprom has been happy to ratchet up sales in Q2 19. The jump in gas prices in early July, if anything, should encourage more Russian sales, making that necessary pull back in Russian supply even harder to achieve.
Eventually, something has to give, and with the demand side underperforming, the work may fall to the supply side. The longer we see a delay to a material slowdown in y/y injections, the more pressure late summer contracts will come under. The TTF August-September spread already moved to -57 cents/MWh by 10 July, from -95 cents/MWh on 1 July, and while September normally trades at a premium, this year the September prompt could get well and truly pummelled. We expect that spread to keep narrowing as we head through July.