- US output hit a new daily peak last week, but that level has not been sustained. In fact, June will only show a marginal m/m gain under 0.3 bcf/d thanks to a bevy of maintenance events so far this month. Timing risk for Appalachia in particular remains an issue, with the approval of two supply laterals of Rover Phase 2 still pending from FERC and the stated mid-2018 start-up of Atlantic Sunrise still appearing on track, with the project 85% constructed as of last week.
- We have upwardly revised our reference case for injection season gains on a baseline revision from the latest EIA monthly. For the period, that translates to an 8 bcf/d y/y gain. Given the ramp-up in production in H2 17, we anticipate 4.5 bcf/d y/y gains in the heating season.
- Net of the changes to the generation stack, we expect a gain of 1.4-1.5 bcf/d y/y in power sector gas demand over July-October, and a rise of 2.1 bcf/d y/y over April-October. By the 2018-19 heating season, the brunt of the impact of coal-fired plant retirements and new gas-fired capacity—which helped propel winter 2017-18 heating season gains—will already have been factored into the dispatch queue. Our view, based on 10-year normal weather for the heating season, is for a 0.2 bcf/d y/y decline for the upcoming winter.
- Current global pricing encourages a maximisation of flows out of the US. Delays to the start-up of three Australian trains until at least Q3 18, together with expected supportive demand from China and South Korea have led to tighter global LNG balances. Mexican net exports could step-up slightly this cooling season on the expected start of service of El Encino-Topolobampo and Nueva Era. We anticipate the potential for peak flows near 4.7-4.8 bcf/d. Together with steady industrial sector growth, the three pillars of structural demand—feedgas for LNG export, pipeline flows to Mexico, and gas use in the industrial sector—account for some 2.5 bcf/d of demand growth this summer and 2.0 bcf/d of growth over the upcoming heating season.
Tying it together: Storage and price outlook
- Recent power burn has been strong thanks to a period of warmer-than-normal temperatures, which have served to tighten balances. Together with production that has been subject to a series of maintenance-related disruptions, that combination leans towards the bullish side for balances. However, the peak cooling season is not yet underway, and the bullish weather momentum of the past six weeks could turn. Consequently, weather still holds the key in this situation for an end-October storage carryout of 3.45 tcf being hit.
- For the peak cooling season, as we have stated previously, some days at $3/mmbtu cash will be hard to avoid, and normal or hotter-than-normal weather could make that foray into three-handle territory more than fleeting, especially in July, given that is when CDDs typically peak nationally.
- Such a historically slim end-October inventory projection has obvious ramifications for the 2018-19 heating season. The crux for pricing for the 2018-19 heating season—outside of typical weather risk—is how ‘long’ production will be on a y/y basis. At a y/y gain in output near 5 bcf/d over the heating season, our estimation for production growth provides an additional 750 bcf or so cushion of supply to otherwise low storage. Given that we do not anticipate the same sort of large-scale gains in power burn that have been a mainstay of the market of late, and instead a minor 0.2 bcf/d y/y decline, total demand growth assuming 10-year normal weather would be near 2.0 bcf/d. These balances translate to a projected 1.43 tcf end-March carryout. That level does not leave the market with too much margin for error if the weather turns out to be appreciably colder than normal. If winter weather is milder than normal, inventories to start the injection season 2019 could be back up around the 1.75-1.80 tcf level assuming 5% milder-than-normal weather. With Sum-19 currently priced at $2.65/mmbtu on NYMEX, inventories that high would support a far weaker price outlook in our view.