Thought prices were low in 2019?

Published at 14:43 8 Oct 2019 by

Global gas prices could be even lower in summer 2020 than in summer 2019 if the weather in the northern hemisphere is not colder than normal over the heating season and supply risks in Europe do not materialise. Growth in LNG supply continues to outpace demand. Europe is acting as a sink for LNG supply and is a key price driver for global markets, but balances for the region are weak, with stocks almost at capacity. There are some potential events keeping risk premium in the TTF Q1-20 contract: the halting of Russian gas transit through Ukraine, French nuclear outages, a tighter cap on Dutch gas production and cold weather. If some of these risks fail to transpire then global gas markets are likely to plummet, and some US LNG exports could be shut in. We have built in just over 100 bcf of US LNG terminal maintenance next injection season, which could serve as a catch-all for the volumes at risk of potential shut-in. This number could rise depending on the fullness of European storage exiting winter 2019–20.

LNG supply is rising and there is simply not enough demand growth to absorb it. Europe has sponged up that supply this year, but the continent will become increasingly hard pressed to do so, especially in 2020. This dynamic is weighing on gas prices globally (see Fig 6). We forecast global LNG supply to be up by 4.5 bcf/d (17.3 Mt) y/y over October 2019–March 2020 and Asian demand to rise by 2.1 bcf/d (8.0 Mt) y/y. LNG demand in the rest of the world looks soft, leaving 2.6 bcf/d (9.9 Mt) of LNG supply more y/y for the European market.

It is hard to see Europe being able to absorb all the new LNG supply in injection season 2020 if the weather in winter 2019–20 is seasonally average. Stocks would be 141 bcf (4 bcm) higher y/y at end-March 2020, which would be a record-high carryout. There would also be less potential for the power sector to soak up excess gas, given much of the possible coal-to-gas switching has already been realised.

This would mean that 1.2 bcf/d (4.5 Mt) of supply would not be able to find a home in Europe and would have to be locked into the US or other production markets. Our balances contain an expectation that over 100 bcf of potential LNG exports could be disrupted by maintenance at US LNG terminals in injection season 2020, which could act as a catch-all for volumes at risk of shut-in. However, US gas is unlikely to be locked in over the heating season given risk premium in European winter-delivery contracts.

There are some risks that could create more space for LNG to be absorbed in Europe. Gazprom’s contract for transiting gas through Ukraine to Europe expires on 1 January 2020, which has pushed the TTF Q1-20 to a large premium over the Q4-19 contract. In addition, Nord Stream 2 (NS2), a pipe which will bring Russian gas into Germany, still needs final approval to be constructed in Danish waters. We expect the issues surrounding Ukraine transit (at least for Q1 20) to be resolved, which would be broadly bearish for TTF Q1-20 and Sum-20 prices. We also expect NS2 to be completed in H1 20, which would add further pressure to prices in 2020.

Another issue concerns Gazprom’s use of the OPAL pipeline, which is downstream of the existing Nord Stream system. A court ruling has already constrained Gazprom’s use of OPAL to 50% of the pipe’s capacity (see Fig 2), which will likely interrupt around 318 bcf (9 bcm) of flows on OPAL over the heating season. There are ways the Russian company could mitigate some, but not all, of that loss in flows. Another risk to supply is a Dutch government proposal for a faster reduction in gas production at the Groningen field, which should lead to Dutch gas production dropping by as much as 177 bcf (5 bcm) y/y in gas year 2019–20.

French nuclear outages could lead to some extra gas demand in Europe. The TTF jumped on news in September that utility EDF had found manufacturing anomalies in an unspecified number of reactors. But clarity came that the number of potentially affected reactors amounted to 5.8 GW (see Fig 3), which was lower than expected. However, any outages could still support gas burn in the European power sector. French nuclear regulator ASN needs to decide what to do with the reactors in question. If all those plants must go offline until the components are replaced, that would add 18 bcf (0.5 bcm) per month to European power sector gas demand.

Fig 1: European heating season 2019–20 balance
Source: Reuters, Energy Aspects

TTF Q1-20 prices could fall towards $5.40/mmbtu (€16.70/MWh) if there is normal weather and there are no major supply outages in Europe over the winter. Our forecast JKM-TTF spread of $1.10/mmbtu would take JKM pricing to $6.50/mmbtu for the peak Jan-20 and Feb-20 contracts. European stocks would likely be high in this scenario, meaning the market would need to be strongly backwardated to incentivise gas in storage to be withdrawn. Storage withdrawals could end up competing with LNG supply, which would weigh on prompt prices. But the need for backwardation to get more gas out of storage would then push contracts for delivery in injection season 2020 down even further. European prices in injection season 2020 are likely to be even lower than in injection season 2019. The northern hemisphere will need a colder-than-usual winter for a less bearish scenario to emerge. The JKM is likely to track the TTF unless there is cold weather in Northeast Asia to widen the TTF-JKM spread.

South Korea might be able to absorb some of the LNG that would otherwise go to Europe. The South Korean government plans to improve air quality by closing up to 6.5 GW of coal-fired power plants over December 2019–February 2020 and up to 13.6 GW in March. The total impact of this depends on how much nuclear availability will change y/y. We expect power sector gas demand to rise by 0.5–0.8 bcf/d (1.3–2.0 Mt) y/y over December 2019–March 2020, with more nuclear capacity scheduled to be online this year. If nuclear availability is unchanged y/y, power sector gas demand would rise by 1.0–1.3 (2.6–3.4) Mt y/y over December 2019–March 2020.

Nuclear outages in Japan are set to encourage some gas demand. Sendai nuclear power plant units 1 and 2 (1.8 GW combined capacity) will be offline for much of 2020 following a failure to meet counterterrorism safety requirements. We expect Takahama units 3 and 4 to go offline in H2 20 for the same reason. Despite the outages at Sendai, we still forecast that Japanese gas demand will fall by 0.3 bcf/d (1.1 Mt) y/y to 6.4 bdf/d (24.3 Mt) in summer 2020 due to higher nuclear availability y/y overall across the rest of the fleet.

Fig 2: OPAL and Velke Kapusany flows, bcf/d  Fig 3: Identified French nuclear units
Source: OPAL, EUSTREAM, Energy Aspects  Source: EDF, Energy Aspects


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