Dragged down by loose balances amid weaker export demand, natural gas prices skidded lower in July bidweek trading even as a toasty forecast offered some encouragement for the bulls. NGI’s July Bidweek National Avg. fell 9.5 cents month/month to $1.450/MMBtu.

That marks a 53-cent decline from the $1.980 average NGI recorded for July 2019 bidweek, another indication of the stress Covid 19 has put on the market this summer.

The July Nymex natural gas futures contract rolled off the board Friday at $1.495 after the market absorbed the shock of a mammoth 120 Bcf injection reported for the week ending June 19. The futures settlement equated to a 22.5-cent month/month drop in July bidweek prices at benchmark Henry Hub, setting the tone for discounts throughout the North American market. 

After the August contract surged higher earlier in the week, the new front month remains at risk of near-term declines due to traders re-establishing short positions and potential demand weakness heading into the Fourth of July holiday weekend, according to analysts at EBW Analytics Group.

“By mid-July, however, extremely hot weather, falling injections and only a muted likely rebound in natural gas production may allow prices to push higher,” the EBW analysts said. “The threat of demand destruction — whether from surging coronavirus cases or an active hurricane season — may restrain gains. Signs of stress in the spot market from elevated storage inventories only add to bearish risks for natural gas.”

Promises of robust heat, at least through the first half of the month, helped a few demand hubs along the East Coast buck the general downtrend in July bidweek trading. Algonquin Citygate tacked on 14.0 cents to average $1.480, while Transco Zone 6 NY climbed 6.5 cents to $1.345.

In the Midwest, Chicago Citygate slid 6.0 cents to $1.540, ultimately averaging a small premium to Henry Hub.

The latest guidance continued to show a “very warm to hot” pattern for the country over the next 15 days, NatGasWeather said Wednesday.

“The coming 15-day pattern remains solidly hot and bullish regardless of the dataset but would be more impressively so if not for weak systems across the southeastern U.S. this weekend and next week,” the forecaster said. 

“The focus remains on how long this hot/bullish U.S. pattern will last, and we continue to expect through at least mid-July, as upper high pressure dominates most of the country with highs of upper 80s to 100s besides the far northwest and northeast corners. The net result will be smaller than normal builds as power burns increase to a stout 41-44 Bcf/d.”

A run of smaller builds could provide some relief for bulls after the Energy Information Administration (EIA) last week reported a 120 Bcf print that surprised to the high side of market expectations.

“The 120 Bcf injection for the week ending June 19 was the highest we’ve seen for any week in June since 2010,” RBN Energy LLC analyst Sheetal Nasta wrote in a recent blog post, noting that the build increased inventories to 3,012 Bcf as of June 19, well above the 2,273 Bcf in Lower 48 gas stocks EIA recorded in the year-ago period.

Recent modeling from RBN would put inventories on track to reach the five-year high by mid-July.

“If we then take the five-year average net injection rate from mid-July through the first week of November and carry the inventory forward, we would reach a peak inventory of 4,234 Bcf,” Nasta said. “That would not only be a record high — the highest we’ve reached is 4,047 Bcf in November 2016 — but also would come perilously close to what EIA calls the ‘demonstrated peak working gas capacity,’ or the sum of the largest volumes reported at individual fields (4,261 Bcf as of EIA’s November 2019 estimates).

“…Prices are clearly signaling for some sort of correction in the supply/demand balance to stave off severe storage constraints this fall. We’ve seen this before, most recently in 2015-16 and before that in 2011-12; in both periods, the year-on-year and five-year average surplus in storage climbed close to or above 900 Bcf.”

In these past instances when inventories reached such plump levels, higher power burns from coal-to-gas switching and exports helped to relieve some of the pressure, according to Nasta.

“The problem this time around, though, is that both of those levers lack the torque that they had in past years,” the analyst said. “The surge in gas production over the past decade has priced out coal-fired power generation, in many cases permanently; a massive buildout of gas-fired generating capacity has been accompanied by widespread coal plant retirements. So, structurally speaking, much of the coal-to-gas switching has already happened, and there’s limited ability for power burn to respond to lower prices.”

On the exports front, a drop-off in U.S. liquefied natural gas (LNG) feed gas demand — coinciding with the shocks of the Covid-19 pandemic — has weighed heavily on prices this summer.

The latest estimates Wednesday dealt another blow for the bulls. Data from Genscape Inc. showed U.S. LNG feed gas demand down to 3.1 Bcf/d early Wednesday, a 1.1 Bcf/d day/day drop. Analysts Preston Fussee-Durham and Allison Hurley described the sagging feed gas volumes as “the result of mounting cargo cancellations for this July and August.”

Cameron LNG saw the largest day/day decline in the firm’s latest estimates.

“As of evening cycle for today’s gas day, July 1, nominations to Cameron LNG have declined by 675 MMcf/d day/day to today’s current value of 905 MMcf/d,” Fussee-Durham and Hurley said. “…Aside from Cameron LNG, feed gas deliveries to Cheniere facilities have declined by 362 MMcf/d day/day, primarily led by declines at Sabine Pass. While these declines represent a significant share of today’s drop, it should be noted that feed gas deliveries to Sabine Pass liquefaction facilities increased by 336 MMcf/d day/day” between Monday and Tuesday. Volumes “only averaged 1.15 Bcf/d throughout the month of June — only 0.01 Bcf/d less than today’s current value.”

The weakness in LNG feed gas demand has coincided with considerable downward pressure on July bidweek prices at hubs throughout the Gulf Coast. In East Texas, Houston Ship Channel tumbled 23.0 cents to average $1.460 for July bidweek. Farther south, Texas Eastern S. TX dropped 24.5 cents to $1.435.

“If at the outset of this summer injection season balances were a tug-of-war between declining production and the onset of demand destruction from Covid-19, balances for the dog days of summer now instead show a return of production volumes amid depressed demand, not only across the domestic market but from LNG cargoes left to languish in the gas grid,” Energy Aspects wrote in a recent note to clients.

The languishing LNG feed gas demand puts more emphasis on the amount of deferred production from dry gas-directed activity, according to the firm.

“EQT’s production deferral, which was announced to be 1.4 Bcf/d, has actually appeared to be closer to 0.8-0.9 Bcf/d based on flow data,” Energy Aspects said. “Presumably, if it chooses to extend its deferrals into July, as Henry Hub is at risk of weakness like that seen in June, it could afford to do so without revising its guidance.

“Not all of its Appalachian peers have that advantage, so widespread deferrals would necessitate reinstated guidance, and at this point it is unclear what the appetite for doing so would be. But, unhedged production is subject to increasing downside risk given the already low cash price realization” in June “and risk of more such days moving forward.”

It was in the midst of July bidweek trading that the debt-laden Chesapeake Energy Corp. — once on the vanguard of the shale revolution — filed for Chapter 11 protection.  

“It’s difficult to point to another company that made more of a widespread impact on the U.S. shale sector than Chesapeake,” said Wood Mackenzie analyst Alex Beeker. “Chesapeake showed the market — and its competitors — how quickly production could grow, how fast projects could develop, and what the updated U.S. model for engaging with stakeholders looked like. Remember they brought international upstream investors back to the U.S. onshore.”

With little time to wax nostalgic about an icon of the region’s past, natural gas sellers in Appalachia busied themselves locking in discounts for July bidweek that for most hubs substantially narrowed the differential to Gulf Coast pricing. The regional average finished at $1.200, down 8.0 cents month/month.