After months of incremental LNG sendout in the UK topping 1 bcm, June saw incremental sendout drop sharply to 0.25 bcm. European markets are still looking overwhelmingly bearish. Asian demand is weak, leading us to revise up our forecast for Q3 19 European incremental LNG takes by 1.8 bcm to 7.5 bcm. Of that, we expect around 2.1 bcm (+1.1 bcm y/y) to go into the UK. For winter 2019-20, a strong start-up at Culzean in June provides confidence that the field could plateau by Q1 20, reinforcing our view that the UK will only need to make continental imports in January. With new export capacity soon via BBL, the NBP basis to the TTF should stay narrow for the coming quarters.
Aggregate UK consumption grew by 0.5 bcm in June, as mild weather boosted res-com demand by 0.4 bcm y/y and low nuclear generation left more room for gas-fired output, supporting power sector gas demand by 40 mcm y/y. With outages at the 1.1 GW Dungeness B and the 500 MW Hunterston B unit 3 expected to continue until the end of summer, gas into power demand in Q3 19 should make some small y/y gains, even though total generation is set to be lower y/y because of Belgian power imports via the new Nemo Link.
On the supply side, June saw a substantial easing of incremental LNG sendout (0.4 bcm, +0.25 bcm y/y) from May’s record high (2 bcm, +1.8 bcm y/y). Although we have revised up our expectations for total incremental European LNG takes in Q3 19 by 1.8 bcm to 7.5 bcm, we expect the lion’s share of that supply to seek the higher-priced continental hubs. We expect UK LNG sendout of around 2.1 bcm in Q3 19, 1.1 bcm higher y/y.
The loss of Rough storage in the UK has meant that forecasting injections into UK storage, now dominated by mid-term and quick-cycle capacity, is complicated. The difficulty in understanding injections was underlined by activity at UK facilities in June, which actually posted a net withdrawal of 68 mcm over the month. This meant the UK y/y storage surplus has been eroded, (-29 mcm y/y by 8 July) so this is no longer a bearish issue for the balances. As such, the UK only needs to balance out the incremental 1.1 bcm of LNG deliveries and could do that solely by higher injections into storage facilities. Still, given the short-term nature of that storage capacity, injections will be sensitive to the relationship between D+1 and M+1 prices.
|Fig 1: NBP D+1 bases, €/MWh||Fig 2: UK LNG supply, y/y, bcm|
|Source: Refinitiv, Energy Aspects||Source: DBEIS, National Grid, Energy Aspects|
NBP-TTF basis: Summer seesaw
For now, the UK looks like it will be able to balance comfortably this quarter without maxing out exports to continental Europe. But how much the UK ultimately unloads into Europe will depend not just on LNG receipts but also on how much Norwegian supply turns down, and the strength of new UKCS supply. Norwegian maintenance constraints in Q3 19 are now scheduled to be 4.0 bcm lower y/y and we currently have pegged Q3 19 production as such. Given prompt prices are at a record-wide discount to the front-summer contract, we do not expect to see Troll and Oseberg production ramping up much to offset those production losses. The question of course is which market will see a more dramatic supply drop—the UK or those in continental Europe? June saw the UK’s takes from Norway rise y/y and Norwegian flows into the Netherlands fall, as Dutch stocks are filling and the NBP D+1 carried a small premium to the TTF on most days. But given that the UK has just 0.8 bcm of storage capacity left to fill, the hub’s flexibility is limited. A positive NBP-TTF basis is bound to drive more LNG to the UK, which would force stocks to fill or exports to rise, reversing the basis again. As both hubs attempt to manage the oversupply, the basis should remain tight, with short-term swings from positive to negative remaining common.
Another factor that should affect the Q3 19 basis is the strength of UKCS supply. While we still expect aggregate UKCS flows to remain lower y/y owing to declines in production at old fields, NBP Q3 19 contracts could come under additional pressure if the new Culzean field, which began production in mid-June, ramps up quickly. Since then, the field has boosted CATS deliveries by around 4 mcm/d, from a Q1 19 average of 7 mcm/d. Total said the field will plateau at 14 mcm/d in early 2020. A quicker-than-expected ramp-up of Culzean this quarter would soften the 3% decline in UKCS production we currently forecast for Q3 19, which would weigh on NBP prices.
One notable event schedule for 12 July is the start of reverse physical flow capacity on the BBL pipe, which will allow gas to move from the UK to the Netherlands. The BBL will offer firm capacity of 7 GWh/h, which translates into 5.8 bcm of potential gas exports annually. The capacity charge is roughly 0.3 €/MWh, while a commodity charge of 0.11 €/MWh is also applied, meaning a fully profitable trade will happen only with the NBP trading at a 0.41 €/MWh discount to the TTF. In terms of that happening, even this year when the NBP has been weak, the arbitrage opportunities have been limited and really concentrated in the shoulder months of April and May and were most acute when the IUK pipe was offline for maintenance. While the BBL reverse capacity should help limit the incidence of periods where the NBP has a deep discount to the TTF, the reality is that BBL reverse flow capacity has not actually increased the UK’s export capacity to the continent. With Bacton export capacity not being expanded, what the new reverse capacity will do is provide traders the option of sending UK exports either to Zeebrugge or directly into the more liquid TTF. Leaving full export capacity unchanged but just diversifying the destination will mean that the impact of the physical reverse flow capacity will be limited and will instead possibly facilitate higher utilisation of the existing Bacton export capacity.
Looking ahead to winter 2019, we are forecasting that the UK will balance in Q4 19 without any continental imports. January looks to be the only month where the UK will need to take continental gas and, even then, we see a 0.13 bcm (10%) y/y reduction. Limiting IUK/BBL net inflows to January does hinge on how strong Norwegian production is in Q1 20. With Johan Sverdrup and Snefrid Nord still on track to start up by the end of the year, Europe could see flows from Norway near record highs, with the UK obliged to max out Norwegian takes regardless of whether underlying demand at the hub is strong. With both Norwegian and LNG supply into the UK forecast to be higher y/y in Q1 20, the UK should only need to rely on IUK and BBL flows to balance during peak winter or if the weather is unusually cold. This should keep the NBP-TTF Q1 20 basis much tighter than in previous years.
Of course, a well-supplied outlook also hinges on whether Russia and Ukraine reach an agreement on transit flows, as otherwise the resulting chaos in the continental markets will tighten all European gas markets, including the NBP.