Growing production in the Permian basin has increasingly run into takeaway constraints, putting downward pressure on Waha and other western supply hubs as gas discounts itself to incentivize flows out of the region. Last week’s feature explored how a lack of new takeaway capacity is causing gas to push out of the region in all directions. This week’s feature will explore takeaway options on the Mexican side of the border, delays to expected in-service dates, and how Permian and Southwest fundamentals may be impacted by completion of these downstream projects. The eventual in-service of those pipelines will provide a substantial outlet for Permian gas and will place upward pressure on basis at Waha and other western supply hubs. Timing will be critical, however, as the current pace of drilling activity in the Permian suggests that takeaway constraints and basis weakness may reappear as early as this fall.
A drop in Rockies production is limiting outflows to the PNW and to the Southwest, primarily impacting volumes flowing on Ruby and Kern River. Production volumes at the Echo Springs plant in western Wyoming fell to 0 MMcf/d for gas day 15 and increased to 20 MMcf/d for today’s gas day. The production drop caused flows on Kern River to decline to an average of 2.06 Bcf/d over the past two days, down 140 MMcf/d from the previous ten day average. The drop in flows on Kern had little impact on downstream basis as SoCal Citygates closed at negative $0.15/MMBtu, its lowest close since the July 4 weekend, as low demand spreads across the Southwest. Flows on Ruby were also impacted by the drop in GRO production, falling to 750 MMcf/d, their lowest level in two weeks. Although processing plants do not issue maintenance notices, a related notice on a pipeline than receives gas from the Echo Springs plant is expected to last through August 17.
Northeast demand is expected to peak for the week on gas day 16, reaching above 15 Bcf/d for the first time since the start of the month before steadily declining into the high-13 Bcf/d range this weekend. Total demand this month has averaged 14.2 Bcf/d in the region, a notable drop from last year's average 16.1 Bcf/d over the same period. From a month-over-month perspective, August demand has under-performed relative to July by roughly 430 MMcf/d, almost all of which has been the result of lower power plant deliveries. On the other hand, modeled storage injections have increased by nearly 900 MMcf/d since July, offset in part by lower regional outflows. Weather has been the largest driver behind the variances, although higher prices this year have also driven burn-per-degree declines. August 2016 temperatures averaged 3.3 degrees F above normal, while August 2017 temperatures have come in 2.2 degrees below normal. At the same time, prices this year are trading stronger than in 2016 at virtually all Northeast hubs, with higher supply costs resulting in higher delivered prices for ultimate consumption. Dominion South cash has traded at an average $1.66/MMBtu this month, 30% higher than in 2016.