We now project a 3.68 tcf (104 bcm) end-October US carryout, up by 60 bcf (1.7 bcm) from our projection last month. The higher end-of-season projection and the likelihood of potentially looser US balances outside of weather factors has led us to revise down our Henry Hub forecast for injection season 2019 by $0.17 mmbtu to $2.60/mmbtu. Projected y/y domestic production growth remains robust at 7.4 bcf/d (0.2 bcm/d), while timing issues still provide significant downside risk to structural demand gains this season. Despite the current weakness in global gas markets, our reference case remains that all US cargoes will find homes and LNG exports will climb by 4.6 Mt y/y over Q2 19–Q3 19.
The foundation of our view for injection season 2019 has always rested on the fact that the largest component of demand growth—structural demand—was laden with timing risks that could easily cause our end-October carryout to grow even further. Those risks have borne themselves out, with Cameron LNG T1 and Elba Island both having first LNG delayed until late Q2 19 and news breaking of further delays for Cameron T2 and T3. As for pipeline flows into Mexico, we continue to be conservative on ramp-up given the significant risk of delays to start-up still present for both the 2.6 bcf/d (74 mcm/d) Sur de Texas-Tuxpan pipeline and Wahalajara system. In addition, the start-up dates for several ethane crackers have already been pushed back from heating season 2018-19 to Q2 19. All of this has occurred amid a backdrop of weak global LNG prices, which gave the market reason to wonder whether or not all US cargoes would find a home given such a loose global supply-demand balance.
The JKM-TTF spreads for the remaining summer 2019 contracts are currently above 80 cents/mmbtu. At that level, NE Asia is still an attractive destination for US cargoes. We think a JKM-TTF spread of 60 cents/mmbtu would be needed to make the TTF the destination of choice for US cargoes. Given current regional-supply demand fundamentals, the JKM peak summer contracts should continue to see enough buying for the JKM-TTF spread to not dip below the arb threshold and favour Europe. The TTF, meanwhile, could see some additional downward pressure as continued LNG imports have left the EU continental storage surplus unsustainably high. At this point, we continue to see global balances absorbing US cargoes. Around 60 days of notice is needed from offtakers if they decide not to lift from Cheniere’s trains. With the arbs to Europe and Asia still open, that should prevent a price-induced shut-in of US supply this injection season as decisions today will be felt in offtake volumes in July/August. As such, we forecast US exports to climb by 4.6 Mt y/y to 15 Mt in Q2 19-Q3 19.
That is still not to say that supply-demand fundamentals portend doom and gloom. We now anticipate two ethane crackers could enter service this quarter and underpin a modest step-up in industrial demand. Timing risks around infrastructure start-up remain significant in Mexico, as we have underscored for some time, given a range of issues from permitting delays to protests by indigenous peoples and local groups. Our view continues to be conservative on the ramp up of Sur de Texas-Tuxpan while we peg a Wahalajara pipeline system start-up to take place only after injection season 2019.
For LNG, continued progress at the 4.0 Mtpa Cameron LNG T1 raises the possibility that it could meet its latest stated target of first LNG production in June. With the 4.4 Mtpa Freeport LNG T1 receiving permission to introduce hazardous fluids (and taking in a minor amount of gas via the Coastal Bend Header), it could meet its stated target of introducing feedgas in May. However, given that construction works at the site are still ongoing, there is still some risk of delays.
At a projected 3.68 tcf (104 bcm) end-October carryout, which is 60 bcf (1.7 bcm) more than our projection last month, ‘constructive’ is not a term we would use to characterise the supply-demand fundamental backdrop. An increase of 60 bcf (1.7 bcm) is not colossal, but it does include the impact of lower gas prices on our estimate of power sector gas burn. The higher end-of-season projection and the risk of potentially looser balances outside of weather risk has informed the downward revision to our forecast for injection season 2019 prices to $2.60/mmbtu, from $2.77/mmbtu last month.
As we look to the heating season 2019-20, a fair amount of new demand is set to come online from the start-up of a string of new ethane crackers, Mexican pipe potentially finally entering service, and additional LNG trains including Freeport T1 and Cameron T2. The latter trains, alongside other liquefaction capacity additions since the previous heating season, support our expectation that US LNG exports will increase by 9.3 Mt y/y to 22.5 Mt. However, the US market is looking well-stocked, which should rule out the winter-risk rally that punctuated trading ahead of the 2018–19 heating season. We expect Henry Hub prices will average $2.86/mmbtu in the coming heating season. That said, concurrent cold events in the Gulf and US Northeast, like those in January 2018, could still send cash prices far higher than projected central tendency pricing.
|Fig 1: LNG breakevens to NE Asia, $/mmbtu||Fig 2: US 2019 injection season y/y change, bcf/d|
|Source: Refinitiv, Energy Aspects||Source: Energy Aspects|