With May storage injections coming in 2.6 bcf/d (74 mcm/d) higher y/y, our end-October US storage forecast stands above 3.7 tcf (105 bcm). The TTF-Henry Hub arb for Jul-19 and Aug-19 has closed even with Henry Hub plumbing lows in the high $2.30s/mmbtu, and the Sep-19 arb could close imminently. The prospect of the arb closing for Sep-19 would add even more bearish sentiment to an already loose US market. Given the low level of sequential production growth we expect until Gulf Coast Express enters service, the only other factor that could provide price upside would be hotter-than-normal weather.
In line with our expectations, weekly storage reports in May have been littered with triple-digit EIA injections that have helped keep pricing soft. The delayed start to the peak cooling season has helped to prop up injections. With peak cooling season imminent, we expect the monthly injection rate to step down. However, weather remains a wild card, and US production has only eclipsed the weekly peaks set in December 2018 recently, and has since backed off again once more. But even assuming only minor production increases throughout the summer on the order of 0.3-0.4 bcf/d (8.5-11.3 mcm/d) and 10-year normal weather underpinning power sector gas balances, our end-October storage estimate is still above 3.7 tcf (105 bcm), which assumes some minor LNG facility maintenance that month. That estimate would have to be chopped substantially to lead to a meaningful shift in pricing sentiment.
Outside of a notably hot summer, chopping that storage carryout figure and moving price into a higher trading band appears difficult unless sequential production gains end. With Range and Cabot citing a backloading of production growth this year and Gulf Coast Express expected to enter service in early October, an end to sequential production gains appears to be a foolhardy assumption. Our 3.7 tcf (105 bcm) figure builds in some delay to Mexican pipeline trade. While both TransCanada and IEnova confirmed the end-June start-up for Sur de Texas-Tuxpan in their Q1 19 earnings calls, CFE’s mid-May tender for seven additional cargoes into Altamira from May to end-July suggests backfill is needed for cooling season demand and that the pipeline is subject to very real timing risk. We now assume an end-July/early August start for the 2.6 bcf/d Sur de Texas-Tuxpan.
For LNG, although the JKM-Henry hub Sep-19 arb is still open, there remains a very real risk that the arb could close if European storage fills too quickly. The current European inventory y/y overhang stands at 848 bcf (24 bcm) and needs to pare down to 420 bcf (12 bcm) by end-October for the market to end the injection season within physical capacity limits. If TTF pricing does not engender more coal-to-gas switching, there remains a risk that the TTF falls to coal parity. Together with an increasing tanker day rate, the arb for US cargoes headed to Europe could be under increased pressure in Q3 19, although only the most marginal of cargoes are likely to be affected by those arb windows closing. From a timing perspective, the US liquefaction capacities slated to come online this injection season are on track to meet their in-service dates. Cameron LNG loaded its first cargo on 28 May, and the 4.5 Mtpa Corpus Christi and 4.4 Mtpa Freeport LNG projects should both start exports over Q3 19.
For the power sector, gas burn on a $/mmbtu basis has appeared anaemic y/y in Q2 19, but there has been no real cooling load as of yet. We have been expecting lower gas burn intensity, given new efficient combined-cycle generation capacity commissioned over the past year will take market share from older, less-efficient gas plants. While that trend will slow this year—less than 5 GW of new plants are due online in 2019 compared to 17 GW in 2018—the impact from units that began operating in 2018 will be felt throughout most of this year. Given how much gas market share is already being captured by lower prices at Henry Hub, even in a 10% warmer-than-normal scenario from June–September, our model suggests only 170 bcf (4.8 bcm) of incremental power burn, chopping our projected end-October storage forecast to just below 3.55 tcf (100 bcm).
A storage carryout of 3.7 tcf (105 bcm), with risk that it can move higher still, should rule out the winter-risk rally that punctuated trading ahead of the 2018–19 heating season. The start-up of the 2.0 bcf/d (56.7 mcm/d) Gulf Coast Express in early October should unleash incremental supply. While the pipe is fully subscribed, it is still unclear how much new supply versus rerouted supply may initially flow on the line, but it should lead to further sequential production gains heading into heating season 2019-20, when we expect Henry Hub prices to average in the low $2.80s/mmbtu.
|Fig 1: US 2019 injection season y/y change, bcf/d||Fig 2: Henry Hub to JKM and TTF arb, $/mmbtu|
|Source: Energy Aspects||Source: Refinitiv, Energy Aspects|