As what remains of the Henry Hub summer strip moves below $2.30/MMBtu, US natural gas prices at multiple hubs could stay subdued during the summer months.
Regional dynamics mean underground storage sites are likely to continue to fill at an average or above-average pace – at least, until rising temperatures and exports draw down on the supply glut.
Northeast risingSince the beginning of this year’s injection season in April, Northeast storage facilities have posted substantial weekly inventory builds, largely erasing running inventory deficits relative to historical averages. The trend has been aided both by strong regional production and weak seasonal demand, and comes in spite of dismal seasonal spreads – the differential that traditionally provides the price signal to inject now and withdraw later.
Both Dominion and Columbia Gas systems have seen storage inventories rise at a much faster clip than usual. In the case of Dominion, inventories have increased by a cumulative 102 Bcf so far this year, which is 23% greater than the five-year average cumulative build, and 46% greater than additions to storage over the same period in 2018, according to S&P Global Platts Analytics.
Likewise on Columbia, storage inventories grew by 82 Bcf this year, which is 23% more than the five-year average, and 40% more than the inventory increase over the same period in 2018.
Between April and June, total Northeast production averaged 31.1 Bcf/d, while demand has averaged only about half that, at 16.1 Bcf/d, according to data from Platts Analytics.
Looking ahead, it’s quite possible the current pace of above-normal injections will continue.
Basis futures at Dominion South show an average 42 cent/MMBtu discount to Henry Hub for the balance of the summer, which is only 8 cents lower than the winter 2019-2020 average. However, from a fixed-price perspective, balance-of-summer Dominion is currently priced at $1.88/MMBtu, and winter Dominion is priced at $2.25/MMBtu, which translates to a roughly 37-cent seasonal spread.
Typically, summer prices are lower and winter prices are higher, which leads to gas getting cycled into storage during the cheaper months and cycled back out when it’s more valuable. From a basis perspective, there is little economic incentive to inject gas this summer and withdraw it next winter.
The underlying factor driving the above-average pace of injections this year is a looser regional supply-demand balance compared with years past.
Pacific upswingPacific Gas and Electric storage inventories began this summer at a 10-year low of 64 Bcf, which at the time was 45 Bcf below 2018 levels, according to Platts Analytics. The large deficit to the previous year’s already low inventory level left PG&E with a low likelihood of closing the gap this summer.
However, with below-average demand this spring and well above-average pipeline receipts, PG&E has been able to close the original deficit.
PG&E on-system demand has had the weakest start for July since 2010, allowing for the continuation of strong storage injections. Total inventories have now pushed above 167 Bcf, which is 7 Bcf stronger than 2018 levels and 22 Bcf above last year’s summer ending levels. Although temperatures in California this June and July have averaged only 1 degree cooler than last year, significantly stronger hydro generation in the state has caused a much lower need for thermal generation to meet power demand.
With California snowpack still above normal, gas demand along PG&E is expected to remain depressed through at least mid-July, which will continue to allow for strong storage injections.
The PG&E city-gate forwards for both the balance of summer and upcoming winter have fallen 36 cents/MMBtu and 35 cents/MMBtu, respectively, since April 1. Some upside risk to prices may materialize in the third quarter as PG&E has historically withdrawn gas during July and August in order to meet peak summer cooling demand.
Midwest increases injectionsThe Midwest, currently sitting with 497 Bcf in storage, has injected an average of 3.3 Bcf/d so far this summer, which is 126% higher than the five-year average, according to Platts Analytics.
If the region keeps injecting this much more than the five-year average, it will reach the five-year maximum by mid-October, well before the November 6 average end of injection season. In fact, since 2011, October 31 is the earliest the Midwest has ever ended injection season.
Regional storage in the Midwest topped the five-year average for the first time this year on July 8 after trailing it by as much as 90 Bcf earlier in the year. Notably, the Midwest has closed the storage deficit despite demand this summer coming in roughly 1.5 Bcf/d higher than 2014-2018's average demand, mostly on the back of strong power generation.
Midwest inventories stand at 555 Bcf, 120 Bcf higher than 2018's mark and 1 Bcf above the five-year average, according to Platts Analytics. While Midwest demand has risen in 2019, robust inflows from neighboring regions have helped maintain the pace of injections. Net inflows to the Midwest are up 1 Bcf/d this summer versus last at an average of 13 Bcf/d.
The Northeast region fueled the rise. However, Northeast net flows have started to slacken, falling from an average of 5.9 Bcf/d between April and June to 5.6 Bcf/d in July, a sign the storage refill may begin to slow.
Mountain region climbsElevated Rockies production coupled with nearly flat regional demand to last year has allowed the Rockies to average storage injections of 590 MMcf/d so far this summer, 130 MMcf/d stronger than last year, according to Platts Analytics.
Despite the stronger injections, the region’s storage inventories are still 15 Bcf below 2018 levels at 93 Bcf. However, the deficit has narrowed by 7 Bcf since April 1.
While the Rockies as a whole is not dependent on storage to the same degree as the Pacific region, adequate inventories allow the region to maintain strong outflows while also being able to meet regional demand.
South Central surgeSoutheast storage inventories have surged since the start of the injection season assisted by maintenances at Sabine Pass LNG, helping inventories surpass 2018 levels and shrinking the deficit to the five-year average.
At the start of the injection season, storage inventories sat at 208 Bcf, trailing the five-year average by 106 Bcf and 88 Bcf below 2018 levels, prior to making significant gains. Inventories ended at 305 Bcf, surpassing 2018 stocks that sat near 294 Bcf, and tightening the deficit to the five-year average to 42 Bcf. The massive build happened in large part due to a decrease in feedgas demand at the Sabine Pass LNG Terminal in Louisiana, with Trains 1 and 2 undergoing maintenance.
The strong storage injections in the southern US have continued to drive Henry Hub prices lower, although the hub has seen some slight gains over the past week due to rising power burn demand.
US stocks rising at record levelStorage increased at a record rate over the first half of the injection season, which typically ends about October 31. Weekly injections over the past 12 storage weeks averaged 101 Bcf, according to data from the US Energy Information Administration. Total injections outpaced the five-year average by 42%.
If the remainder of the season’s builds match the five-year average, cumulative net injections would total about 2.4 Tcf, which would represent the fifth-largest refill total, trailing only 2014, 2015, 2003 and 2001. The heating season would begin with 3.6 Tcf in storage, or about 100 Bcf below the five-year average.
However, due to stronger power burn demand expected during the months of July and August, combined with higher exports, in the form of pipeline flows to Mexico and LNG cargoes, Platts Analytics currently expects there to be 3.431 Tcf of working gas in storage at the end of the injection season.