- Lower 48 gas output has yet to eclipse the weekly records set in December 2018. But, given the heavy spate of maintenance events across the country, sequential growth in April would have posted stronger than the preliminary 0.6 bcf/d.
- The early reporters in the Q1 19 earnings call season have only made modest changes to 2019 guidance reported in the Q4 18 results. We have made a modest upward adjustment to injection season production growth, which is now forecast at 7.4 bcf/d y/y, due to a change to our exit-to-exit production growth estimate for Appalachia.
- Timing risk is still a factor for structural gas demand growth. CFE has officially delayed the start-up of Sur de Texas-Tuxpan until end-June and permitting issues and local protests still pose potential challenges for additional delay. We estimate Altamira has enough supply to support sendout through mid-June with CFE’s most recent tender for five cargoes. Currently, such a tender would align with the stated end-June in-service date. However, we continue to monitor for additional tenders into the facility. The quantity and timing window specified in those tenders will be telling for the timeliness of the pipe. Similarly, local protests and a lack of local construction and land permits in Villa de Reyes, Jalisco and Aguascalientes suggest start-up of the Wahalajara pipeline system will only take place after injection season 2019.
- For industrial demand, we anticipate two ethane crackers are likely to enter service this quarter. As the year progresses, the global buildout in steam cracking capacity and the potential for weak petrochemical prices suggests potential downside risks to growth. For LNG, progress at Cameron LNG T1 continued, raising the possibility that it could meet its stated target of first LNG production in June. With Freeport LNG 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, active construction at the project still leaves some risk of delays.
Storage and price outlook
- At a projected 3.68 tcf end-October carryout (60 bcf more than our projection in our March Outlook), ‘constructive’ is not a term we would use to characterise the supply-demand fundamental backdrop. 60 bcf is not a colossal increase, 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 what we see as 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 at the time of last month’s Outlook.
- That storage carryout of 3.68 tcf is already looking fairly comfortable and 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 that occurred in January 2018, could still send cash prices far higher than projected central tendency pricing.