- Daily production receipts in the past week have now eclipsed the previous peaks registered in December. Notably, these new highs are occurring without a recovery in Appalachia. Our expectations had been for healthy sequential production gains once wells returned from freeze-offs, in the process not only returning readings to those previous peaks, but also unlocking the sequential gains that otherwise would have occurred in Q1 19. The key to assessing production growth will be the size of sequential gains beyond that recovery.
- We have modestly increased our injection season production view to 7.4 bcf/d y/y versus 7.2 bcf/d y/y. There are a number of factors that indicate production this summer could be sticky. Our sample of US producers is better hedged y/y, with more than 60% of production protected. Private producers are running about one-third of the rigs in Appalachia while the pursuit of liquids still provides an attractive netback.
- LNG feedgas is the largest driver on the demand side of our ledger, up by 2.5 bcf/d y/y. Our reference case does not assume LNG volumes are shut-in, but global weakness bleeding into the US remains a risk. For Mexican trade, timing risk remains. CFE has stated that permitting issues with Sur de Texas-Tupxan have been cleared, and the pipeline should enter service between 15 April and 1 May. However, we still see delay potential. LNG cargoes have been tendered into Altamira through the third week of April, which could still see send-out continue into mid-May.
- We foresee 0.5 bcf/d y/y gains in the power sector. Burn is skewed to the early part of the injection season, when gas will take market share from coal units. Some 10 GW of coal generation will be offline y/y by the summer due to retirements. Rising eastern coal prices mean new CCGT units will be in merit, especially in PJM and the Southeast (or most of the East storage region). Northern Appalachian coal prices have floated back toward $70/t this month, or $2.60/mmbtu before transport costs.
Storage and price outlook
- Since last month, based on a mild end to March, our end-March estimate has moved to 1.12 tcf, helping to translate to 3.62 tcf by end-October. What we had previously viewed as a critical balancing point ahead of winter 2019–20 now looks well-stocked. In addition to the shift in storage outlook, based primarily on end-of-winter weather together with the minor increase in production, is an incredibly bearish global gas price backdrop.
- Even if the global arb were to close, the US market should not be put into a tank top situation. Lost cargoes are likely to be limited, and we expect some of the gas not exported to be diverted to price-induced domestic coal-to-gas switching. Of course, that implies global price weakness bleeding into the US market. At most, we expect 96-144 bcf (2-3 Mt) of LNG could be at risk of being shut-in over summer 2019. That range suggests a maximum loss of two trains during the months most oversupplied. If we assume that loss is sustained over a three-month period, that is 1.0-1.5 bcf/d less LNG feedgas demand than otherwise expected. Such a level of added gas to the balances is likely to be absorbed by power sector gas burn and more volumes into storage.
- Our models suggest that a price of around $2.70/mmbtu in the injection season would induce an additional 0.7 bcf/d of gas into power demand above our reference case. A price of $2.60/mmbtu would induce an additional 1.5 bcf/d incremental burn above our reference case.