- Each passing month now appears to feature a new weekly record for output in the US. However, the past three months have shown choppiness in flow data on the back of maintenance and other transitory disruptions that have shaved m/m gains toward 0.6-0.8 bcf/d, vs staggering levels in the summer approaching 1.5 bcf/d m/m. Moving forward, we expect rates of growth to begin to pare, though our balances call for a whopping 10.5 bcf/d y/y gain in Q1 19—considerably inflated by last year’s freeze-offs—and closer to 7.0 bcf/d during the summer.
- Some producers have taken advantage of higher prices earlier in November and December. Swap Data Repository (SDR) figures suggest a notable pick-up in hedging activity in Q4 18 for Cal-19, with transactions trending as high as $3.25/mmbtu. While Q3 18 earnings reports had shown some 50% of publicly traded volumes have been hedged near $3.10/mmbtu, it is difficult to gain insight into hedging of private producers that dominate the Haynesville and are still prevalent in Appalachia. For those producers that have room for discretionary or additional hedging, that $3.25/mmbtu price would be attractive. However, we do not anticipate this uptick in late season hedging will have a notable impact on our production expectations for injection season2019.
- Sum-19 contracts at Waha, as traded on ICE, appear to be pricing in a timely start to the Wahalajara system in May 2019. Our view is for a deep Waha discount to remain through the summer, given our more cautious view on the timing of Mexican infrastructure. The rise in flaring permits in recent months also highlights the intensifying constraints on evacuation in the area. Small additions, such as reinstatement of the Old Ocean pipeline, will easily be overwhelmed.
- Gas burn figures have stayed sticky in the winter season to date despite cash prices at Henry Hub averaging more than $1.25/mmbtu (+40%) above the same period in 2017. With consumption remaining in line with or above year-ago levels, we are even more constructive on our outlook for gas-fired power generation demand into next year.
Tying it together—storage and price outlook
- Mild weather and the expectation for a tropical-feeling winter holiday season have led to a foray back to ‘3-handle’ territory for the Q1-19 contracts. Yet, it is too early to call winter off just yet. GWHDD accumulations (and weather forecasts) will be crucial for the first six weeks or so of Q1 19. Typically, by mid-February, the market has a narrower range of possible end-March storage scenarios in its view, and the degree of deliverability concern (if any) for the weeks ahead is clear. By that token, an extended period of warmth (or the forecast of one) in those critical early weeks of Q1 19 could begin to perceptibly ease deliverability concerns and prices. Physical participants, such as local distribution companies and utilities, have likely been preserving their inventories when possible to ensure deliverability later in the winter season. Their weighted-average cost of gas in storage is likely significantly cheaper than spot purchasing, so once they feel assured they can meet customer needs, they will likely begin to rely more heavily on storage withdrawals than spot purchases, effectively lessening the degree of spot market support that they have provided throughout the heating season.
- Based on 10-year normal weather, supply-demand fundamentals are still thinly balanced with a projected end-March inventory level of 1.32 tcf, a figure that makes no allowance for freeze-offs. If that figure begins to top 1.4 tcf, the deliverability concerns that have been propping up the market will begin to ease considerably. However, cold—or a credible forecast of chilly weather— would still chip away inventories enough to lead to a return of the heightened concerns about deliverability that were priced into the market several weeks ago.
- Since our last Outlook, the injection season strip has moved up by a nickel. Our injection season view remains sensitive to winter weather, especially given our forecast of tightly balanced end-of-season inventories. A 1.32 tcf end-of-season inventory position could easily be transformed toward 1.56 tcf, under 5% milder-than-normal weather. This would be bearish for prices throughout the injection season, bringing the injection season at least temporarily toward $2.50/mmbtu. A 5% colder-than-normal scenario would shift inventories below 1.1 tcf and offer significant support throughout the injection season, shifting prices toward $2.90-3.00/mmbtu. For the injection season, our demand-side outlook is guided by investment-driven, structural demand projects—feedgas for LNG, pipeline exports to Mexico and gas use in the industrial sector. Some major projects in these categories have already been subject to some delay to start-up, and timing risks abound. Timing risks are crucial, given this form of demand contributes 3.6 bcf/d in y/y growth in our balances, vs a far more muted 0.5 bcf/d y/y increase in power sector gas demand.