- Our highlighted injection season production risks remain focused on Permian takeaway constraints. In the US Northeast, the main risk is the timeliness of takeaway capacity additions, and the pace of ramp up. As most Northeast producers reaffirmed in the latest round of earnings calls, some initial flows through new pipes would be volumes shifted from existing pipelines, suggesting a limit to the ‘organic’ production growth out of the basin. We have moderately dialled-back our growth forecast for the injection season, though it remains at a weighty 7.4 bcf/d y/y.
- A heavy slate of maintenance activity in May led to subdued WCSB output and some counter-seasonal withdrawals from Alberta storage. The 200 bcf or so that remains to be filled in Dawn inventories, with further maintenance on the books, governs our outlook for net exports, which we expect will be 0.2 bcf/d higher y/y over the injection season.
- We continue to foresee only minor uplift in net Mexican trade this summer given pipe delays, which we track every month in our Mexico Data Review. Not only does this expanding list of delays cap our outlook for peak injection season flows near 4.7 bcf/d (equating to 0.3-0.4 bcf/d of growth y/y), it has also led us to revise down our forecast for net exports through injection season 2019.
- A higher NYMEX forward curve—up by nearly 0.10 $/mmbtu m/m—and tighter basis in the Midcon indicates slightly less coal-to-gas switching than we had forecast. Also, western hydro remains robust, with above-normal generation in the Pacific Northwest somewhat offsetting lower-than-normal levels in California. This leads us to trim our power sector gas burn forecast by 0.4 bcf/d through October—we now forecast 1.7 bcf/d growth y/y, assuming normal weather.
Tying it together: Storage and price outlook
- End-October stocks, which already looked precariously low at 3.45 tcf on our balances last month, are now pegged at just 3.41 tcf. As we have been saying for some time, an outperformance in the power sector and/or a slower ramp-up in production would cause a repricing to our reference case. So far, both of those factors have come to fruition in May. Last month, we noted only a token move above our 2.75 $/mmbtu injection season reference case was merited in any potential repricing, but the lower projected inventories now make that moderate repricing appear more necessary, and we have thus revised higher our price outlook for the injection season to 2.85 $/mmbtu.
- The rest of the injection season ultimately remains a weather play. Current forecasts are pointing to milder weather nationally in June (though with strong heat in Texas), and the market has reacted accordingly earlier this week by trimming price gains for the remainder of injection season strip back toward 2.90 $/mmbtu. However, this morning’s hotter revision to the 15-day forecast showed just how sensitive prices are, with the injection season strip gaining back another 0.05 $/mmbtu. Aside from weather, the timeliness of infrastructure in the Northeast is the next bullish wildcard if Appalachia output underperforms expectations.
- Further out, our 3.41 tcf reference case, combined with still sizeable output growth, informs our agnostic view on the 2018-19 heating season curve. However, low expected stocks by end-October 2018 and end-March 2019 (1.4 tcf) leave little margin for error if weather is colder than the 10-year normal. Indeed, our forecast price for the heating season would have to push meaningfully above our reference case if elevated weather-aided demand needs to be satisfied.