The remaining summer 2019 global gas contracts are struggling for price support given an oversupplied TTF and a JKM still weak after a mild winter in Northeast Asia. A couple of big supply tenders for the coming couple of months from Egypt and Indonesia should help keep the Pacific basin’s demand satisfied, while only Mexico was showing a more sizeable demand-side tender, and that was just to backfill for a delayed pipeline. We maintain our long-held contention that Q2 19 will be the weakest period for the global markets, with Q3 19 contracts better bid on summer cooling demand and then for stockbuilding ahead of winter 2019-20. However, the key arbs—TTF-Henry Hub and TTF-JKM—are narrow and any further narrowing in the spreads could nominally close the arb windows and lock-in US supply.
The TTF dropped sharply in price last week as late-season heating demand came to an end and put into stark relief how high EU storage levels are for the time of year. The EU market is still on target to end May with a y/y storage overhang of some 23 bcm, which it will need to whittle down to no more than 12 bcm by October (at which point stocks would be full). For the summer, there looks to be little potential upside now to TTF prices, with most of the risk biased to the downside. Despite a strong 8% w/w drop in prices for the prompt contracts at the TTF, the JKM-TTF spread for the remaining summer 2019 contracts (Jul-19 onwards) all narrowed by an average 20 cents/mmbtu w/w on average to close Friday at 0.7-0.8 $/mmbtu. With average spot freight rates going up by some 8,000 $/day to 49,000 $/day over the last week according to Fearnleys, the JKM-TTF arb is now very narrow but still marginally favours sending US cargoes to Asia (with the breakeven arb now at 70 cents/mmbtu) rather than Europe. With the TTF repricing down to around 4.3 $/mmbtu at Friday’s close and variable cost recovery of the TTF-Henry Hub arbitrage trade around 0.9 $/mmbtu, the arb window is still open for another 70 cents/mmbtu given a Henry Hub summer 2019 strip currently at 2.7 $/mmbtu. With arb decisions already made for Q2 19, any further TTF softening is only going to impact flow decisions for Q3 19. For the winter, the TTF price has been more resistant to falling due to concerns around whether Russia will be contractually able to flow gas through Ukraine in Q1 20. With winter also carrying the risk of cold weather, near-record wide contango at the TTF means the TTF-Henry Hub arb windows for peak winter remain wide open.
The JKM remained soft. Chinese demand is still growing but has largely been lagging our expectations for growth. Underlying Chinese natural gas demand was up by around 10 bcm y/y (10%) over the first four months of the year according to NDRC data, compared to our start-of-the-year expectations of 12% growth over the period. The slower-than-expected growth rate was due to the very mild Q1 19 in Northeast Asia, which delivered a y/y reduction in heating demand. We expect the growth rate over the rest of the year to edge back up to around 12% y/y as we are out of the months where weather can make such a big difference to demand. Chinese domestic gas production was up by 6 bcm to 58 bcm (+10% y/y), which is higher than we had expected—we had expected the majors to switch back to drilling predominantly for liquids given the price increases seen in crude but gas production growth has remained strong.
Some modest JKM support could well come from news that the 4.8 Mtpa Sakhalin train 1 has shut after an unexpected issue forced it to bring forward planned maintenance at the end of last week. The train was shut on Friday because of a "minor" issue and is expected to restart sometime in the first half of June, largely in line with the duration of a scheduled maintenance event. Provided the outage is not materially longer than the scheduled maintenance, the impact on summer balances will be negligible.
Bids and offers – some bigger supply tenders
While the short-term LNG spot market has been growing for a while, the last week did see some big individual tenders, with tenders offering supply looking larger than those on the demand side. The biggest of the tenders was from EGAS, which offered to sell 13 cargoes loading from the Idku plant over June and July. This schedule would mean the export plant would be running at pretty high utilisation, at least at one of its trains (E-mail alert: Egyptian LNG export tenders for June/July lead us to increase export forecast, 17 May 2019). Indonesia offered five cargoes for delivery, loading from June. The move came after Indonesian exports were down by around 0.9 Mt y/y in Q1 19 and dipped by an indicative 0.2 Mt in April. Indonesia has been exporting below our forecast levels so far this year and the latest tender looks like an attempt to reverse that. We also saw the first tender to be offered from YPF, which has a first cargo to sell from its FLNG unit in Bahia Blanca, while PetroChina was offering up another three Yamal cargoes, loading in June.
On the demand side, there were a number of smaller tenders, with Mexico’s CFE looking for seven cargoes for delivery—one in May, two in June and four in July—into Altamira. CFE was previously very bullish that some of the main pipelines linking with US supplies would be up and running this year, allowing it to stop LNG imports. The main pipe that needs to come online to replace most of the LNG imported through Altamira is the 2.6 bcf/d Sur de Texas-Tuxpan, which had a latest in-service date of June. The pipeline has been repeatedly delayed due to permitting and technical issues and the CFE tender for supply delivered into the east coast of Mexico suggests further delays are expected.
Trinidad – some problems, some worry
One of the supply surprises of the last 18 months or so has been Trinidad and Tobago's 14.8 Mtpa Atlantic LNG facility. The facility had seen its production peak back in 2016 at 14.3 Mt, then begin to decline on a variety of issues around exploration and development, taking production to as low as 10.3 Mt in 2017. However, several new wells helped address the decline and 2018 production rose to 12.6 Mt. While there was a modest y/y reduction of 0.2 Mt in Q1 19, that still did not really create the expectation that the project was moving back to have feedstock problems. However, BP announced earlier this month that it and Shell may need to shut-in 20% of the capacity of the facility since infill drilling had failed to deliver at forecast levels to ensure supply after 2019. In particular, BP highlighted recent disappointing results from infill drilling programs, which reduced the company’s forecast production for gas for the site for 2020 and 2021. The shortage affects the 3 Mtpa train 1, while the other three trains at the Atlantic facility are not expected to be affected by the dip in production from the wells. The reduction in feedstock could limit Atlantic LNG production to no more than 11.8 Mt in 2020, around 0.7 Mt below our current forecast for 12.5 Mt in 2020.
|Fig 1: Mexican imports of LNG, Mt||Fig 2: Trinidad LNG exports, Mt|
|Source: Kpler, Energy Aspects||Source: Bloomberg, Energy Aspects|