Henry Hub prices could see upward pressure later this summer as the current supply/demand balance erodes a roughly 300 Bcf storage surplus to the five-year average by August, according to analyst firm PointLogic Energy.
During a recent webinar forecasting a “Cruel Summer” for the 2017 natural gas market, PointLogic’s Jack Weixel noted that much of the current storage surplus is concentrated in the South Central region.
“As the South Central region goes, so does the U.S. This extends to Henry Hub and also extends to the general surplus to the five-year average,” Weixel said. “We think that regional supply/demand dynamics — including increased export demand, increased power demand, the warmth that we’re going to see from a weather perspective in the South Central — will all impact prices and could cause a dearth in injections over the course of the summer.”
Erosion in the South Central’s 220 Bcf surplus to the five-year average would “make that region tighter and make the U.S. tighter as a whole,” he said.
Along a corridor connecting the Gulf Coast and Southeast to the Northeast, regional basis differentials should strengthen year/year, with “weaker basis versus last summer in the rest of the country,” Weixel said. Spreads between the Henry Hub and the Northeast will tighten this summer, and the “Chicago and Northeast markets [will] become connected by Rover” with generally widening spreads everywhere else, he said.
This upward pressure on Henry Hub through the summer may not last, and it will depend largely on the production response anticipated later this year.
“We’re getting ahead of the market here, but we can see downward price pressure on the back half of the curve as the market begins to realize that even with a normal winter, things aren’t so dire,” Weixel said, noting PointLogic forecasts for inventories of 3.7 Tcf by November and 1.7 Tcf exiting the heating season in April 2018.
Versus the five-year average, PointLogic expects the U.S. market to be 1.4 Bcf/d short this summer, with demand up 3.4 Bcf/d versus the average and supply up 2 Bcf/d. But summer on summer the market looks to be long about 0.9 Bcf/d, with a 1.7 Bcf/d year/year drop in demand offsetting a 0.8 Bcf/d drop in supply, the firm said.
Supply is “down summer on summer, but the demand is down as well. Mexican exports and LNG [liquefied natural gas] can’t do it alone,” Weixel said.
The 2015 and 2016 summers featured 959 and 977 cooling degree days (CDD) respectively, well above the 890 CDD eight-year norm. “The consensus view from some of the forecasters I’ve spoken to is that the U.S. could see up to 1,000 CDDs this year,” Weixel said, “which would make it hotter than what we saw in the last two summers.”
He added, “Where it’s hot is important in addition to the price of gas versus competitive fuel sources.”
There are “a lot of reasons” why PointLogic sees power burn dropping in 2017 compared with 2016 levels.
For one, the coal market is well supplied, up about 8.5 million short tons compared to a year ago. Then there’s the year/year strengthening in natural gas prices. Recent summer strip pricing has gas averaging $3.34/MMBtu, well above last year’s average $2.57/MMBtu, meaning coal figures to be much more cost-competitive and “is insulated a lot more than it was in summer 2016,” Weixel said.
PointLogic forecasts power burn to average 27.3 Bcf/d this summer, down from 30.1 Bcf/d last summer. But power burn could drop as much as 3.5 Bcf/d “as you get to the peak power demand months,” Weixel said. “This is also where we see the price of natural gas becoming more and more expensive given the rather weak production response we’ve seen so far this year.”
Production has been flat since the winter but could jump up by the end of the year, weighted to the back half of the year when large Appalachian takeaway projects like the Rover Pipeline are slated to come online, according to PointLogic analyst Warren Waite.
Many major northeast producers are forecasting year/year production growth weighted to Q3 and Q4, “and mainly because these same producers are anchor shippers on some of the takeaway pipeline projects” planned to enter service around the same time, he said.
Production has averaged around 70-71 Bcf/d the last few months, “so we’ve been running in place for a while, and we haven’t really had an opportunity to take production to new heights,” Waite said. “But we’re forecasting summer production from the U.S. Lower 48 to average 70.6 Bcf/d and climb to 75 Bcf/d this winter.”
Pipeline exports to Mexico are expected to average 4.2 Bcf/d this summer, up from 3.9 Bcf/d last summer, with supply sourced Texas plays like the Permian Basin and the Eagle Ford Shale expected to feed most of those volumes, Waite said.
As for LNG, pipeline deliveries to terminals could begin to see an uptick from around 2 Bcf/d to as much 2.5 Bcf/d this summer as Cheniere Energy’s Sabine Pass Train 4 and Dominion’s Cove Point prepare for start-up later this year, Weixel said.
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