Today’s report (week ended 30 Nov): EIA: -63 bcf, EA: -64 bcf
- Today’s print was nearly spot-on with consensus. A 1.3 bcf/d w/w increase in power burn helped to absorb output that was nearly 1.1 bcf/d higher w/w.
Next Thursday’s report (week ending 7 Dec): EA preliminary: -82 bcf
- A 3% w/w increase in GWHDDs results in a 1.2 bcf/d increase in res-com demand. A 0.6 bcf/d boost to power demand and a return of industrial demand from any lingering Thanksgiving effects will trump a modest 0.3 bcf/d increase in total supply.
Waking up to summer risk
The market has been moving on weather forecasts again this week. Balmy weather is forecast to take hold mid-month. Despite this warmth, our view remains the same—deliverability continues to be a concern and will support pricing. While the continued vacillation in the winter contracts has marked the week’s trading, the injection season 2019 contracts—which previously had not seen much movement—are now up by about 10 cents/mmbtu since the final week in November.
Prices on the injection season strip may have risen, but fundamentals have not shifted perceptibly. Our current view still places end-March inventories at 1.3 tcf. That figure is based on 10-year normal weather and makes no assumption for freeze-offs or other winter weather disruptions to production, suggesting there is downside risk to that number. Our current view is that end-March inventories are thinly balanced. If we assume 70 bcf of freeze-offs over winter (which would be at the higher end of typical interruptions over the last few years), our balances would still be thinly balanced near 1.23 tcf. Importantly, though, there has been no major shift in our end-March storage inventory projection since late November. At this point, there remains a risk that end-March storage could move from thinly balanced to too low. By that token, end-March could still move from thinly balanced to a carryout that would begin to look high for the fundamentals. We expect this summer to remain heavy on supply, with production gains forecast on the order of 6.5 bcf/d y/y.
Given how sticky power burn has been versus modelling, a view that strength will extend into gas power demand this injection season versus some models calling for a y/y decline could also be taking hold. Prices have also had to climb higher to bring on incremental coal, a factor that will be exacerbated by mid-2019 due to further unit retirements.
For structural demand projects that we track, there have been no announced schedules that would suggest a more bullish view on demand for the injection season. Our view on LNG remains the same. The latest Generator Interconnection Status (GIS) report from ERCOT showed the Freeport commercial operation date in August 2019. Cameron LNG timing for first LNG remains unclear, but FERC construction updates still place its trajectory for H1 19. We continue to foresee potential delays to the start-up of Mexican pipeline projects. We had viewed the timing of the Wahalajara pipeline system, which in October was delayed until March 2019 amid rumours of financing problems, as a delay risk. It now has been delayed until May 2019. For the major 2.6 bcf/d Sur de Texas-Tuxpan pipeline, local media reports that it has started taking linepack gas, though we still view potential delays from downstream pipes as likely to limit the ultimate ramp-up on the project through the injection season.
The market seems to be sensing some upward price risk, given how thinly balanced the market currently appears. Swap Depository Report (SDR) data have pointed to increased prices in vanilla swaps transacted in December so far, with a small volume of trades being done near $2.85/mmbtu versus similar transactions in November that were done closer to $2.75/mmbtu. On the options front, according to CME, $2.50/mmbtu puts dominate open interest (OI) for the summer strip. However, in recent weeks, we have been observing more OI growth in calls than puts for the summer strip, especially for Jun-19, with $3/mmbtu and $3.25/mmbtu strikes in strong demand. Given our outlook for 1.3 tcf March 2019 inventory carryout, $3/mmbtu-handle prices in peak summer months are not implausible if hot weather encourages strong power burn.
|Fig 1: Projected EIA weekly storage change, bcf||Fig 2: Projected y/y storage activity, bcf/d|
|Source: EIA, Energy Aspects||Source: EIA, Energy Aspects|