We forecast North American LNG exports to step up by 10.9 Mt y/y to 32.4 Mt in 2019 as several new liquefaction trains are on track to enter service this year. Potential delays to start-up, which are still very substantial, provide downside risk to our forecast. We expect export growth to be biased towards H2 19, although Q1 19 will grow by 1.0 Mt y/y to 6.2 Mt as Sabine Pass T5 and Corpus Christi T1 ramp up, while Q2 19 will rise by 2.2 Mt y/y to 7.6 Mt. Despite all of that growth in exports, Henry Hub still looks set to languish at sub-3 $/mmbtu prices for the coming storage injection season because of healthy supply.
The start of 2019 in the North American gas market has coincided with a new trading range for Henry Hub. Early in December 2018, we noted that if a warming trend were to start in January, it could lead to the market anticipating a de-risking of deliverability concerns, easing prices. Indeed, the arrival of that warm weather pattern has seen Henry Hub fall by more than $1 since early December 2018, leaving most of the near-curve contracts trading in the 2.90-3.00 $/mmbtu range in early January. That move comes from the significant amount of demand lost since the third week of December 2018 and into the start to January. At this point, the last big bullish card for the US gas market is for a sustained colder-than-normal period, although how much prices will move up will depend on the duration and the extent of the temperature deviation from normal. Such a weather event would need to be cold enough to return some 350 bcf (9.9 bcm) of demand to our balances. With seasonally normal weather in Q1 19, our current end-March inventory projection of 1.55 tcf (43.9 bcm) suggests there will not be scarcity concerns.
Supply growth moderating but still buoyant for 2019
The return to weak prices in the US reflects not only a big drop in demand, but also the still-significant y/y gains in production. Each passing month has featured a new weekly record for output in the US, even if Q4 18 did feature some choppiness in pipeline flow data on the back of maintenance and other transitory disruptions. These past few months have seen sequential m/m growth in US output pare back toward 0.6-0.8 bcf/d (17-23 mcm/d) from rates closer to 1.5 bcf/d (42 mcm/d) during the peak cooling season in June-August 2018. We anticipate lower m/m production growth rates going forward, simply because prices have tended in 2018 to trade on the low side, where they are now starting 2019. Still, despite a slowing of growth rates, growth will be healthy. We anticipate y/y gains in excess of 10 bcf/d (0.3 bcm/d) in Q1 19, albeit that is a number that is inflated due to last year’s production freeze-offs. For the injection season, we anticipate the rate of growth in total US output will moderate, but still clock in at a very healthy 7.4 bcf/d (0.2 bcm/d) y/y.
Appalachia flows have risen steadily, with the start-up of new infrastructure in Q4 18. Regional takeaway capacity of 33.4 bcf/d (1 bcm/d) is well above January-to-date output of 30.8 bcf/d (0.9 bcm/d). A meaningful gap should remain between production and takeaway capacity throughout most of 2019, assuming Mountaineer XPress (MXP) comes online in Q1 19, as we currently expect, although other large-diameter Appalachia pipelines could slip into 2020. As a result, infrastructure additions in 2019 are likely to significantly lag the banner year Appalachian takeaway additions in 2018. In Texas’s Permian basin, very low Waha prices currently reflect the lack of sufficient gas evacuation capacity in the region. Our reference case foresees an average discount of more than $2.00/mmbtu to Henry Hub for 2019 and, most importantly, we foresee even deeper discounts on a daily or intra-day basis, given the extent of congestion.
The price weakness at the prompt has extended to the injection season 2019 contracts. Injection season prices will ultimately depend on end-March storage levels. Assuming normal weather for the rest of the winter and the injection season, our balances put end-October inventories at just above 3.8 tcf (107 bcm), 0.6 tcf (17 bcm) higher compared to last year. Our balances make an allowance for LNG maintenance in April and October, but overall reflect a comfortable injection season that will not be wanting for supply.
Demand growth driven by exports
Beyond weather uncertainty, the injection season will also be characterised by significant demand-side timing risk from LNG projects and pipe exports to Mexico. There was a flurry of activity for approvals requests for permission from FERC in the new year to push forward with new LNG infrastructure. Chief among the projects facing timing risks is Cameron LNG T1. Sempra Energy has said the train will have a Q1 19 in-service date, but the fact that Cameron LNG only received approval to commission its flare on 3 January and has not yet even filed for feedgas introduction points to delays into Q2 19. Kinder Morgan’s 10 mini-trains at Elba Island likewise face headwinds regarding start-up. The first train was scheduled to take feedgas in Q1 19 but will likely face delays after returning its compressor to the manufacturer for corrosion repairs in late December 2018. Corpus Christi T2 was approved to introduce fuel gas on 3 January and is on track to take feedgas in late Q1 19/early Q2 19. We expect that demand for feedstock for LNG exports will grow by 2.6 bcf/d (74 mcm/d) to 5.9 bcf/d (0.2 bcm/d) in the injection season, with a steady stream of new trains coming online.
Regarding pipe exports to Mexico, the developer of the Valley Crossing pipeline, the US-side of the massive 2.6 bcf/d (74 mcm/d) Sur de Texas-Tuxpan pipeline project in Mexico, still had not completed checks to identify subsea pipeline elevation as of 24 December, potentially delaying the pipe’s Q1 19 start. All of this highlights the ongoing risks of pipeline infrastructure timeliness capping growth on cross-border flows from the US to Mexico, which in turn could continue to sustain Mexico’s desire for LNG imports. Although subject to downside risk, we expect that pipeline exports to Mexico will average 5.5 bcf/d (0.2 bcm/d), thus adding 0.8 bcf/d (22.6 mcm/d) y/y to US demand over the injection season.
All of this demand will play a role in balances, but the still-healthy supply growth means that it will be hard for Henry Hub to price above 3 $/mmbtu in injection season 2019, unless there is a much bigger storage draw in the remainder of this winter than promised by normal weather.
|Fig 1: US Q1 19 y/y change, bcf/d||Fig 2: US 2019 injection season y/y change, bcf/d|
|Source: Energy Aspects||Source: Energy Aspects|