Fueled by unrelenting heat across Pacific Northwest, Western Canada and the East Coast, natural gas forwards surged in the trading period ending June 30, according to NGI’s Forward Look.

August prices shot up an average 19.0 cents over the six-day period, led by an astounding C28.0-cent climb at NOVA/AECO C. The stout gains continued throughout the front of the curve and extended through next winter, as the likelihood increased that storage inventories would be much less than normal ahead of the peak demand season.

The oppressive heat led to numerous fatalities. The death toll was in the dozens as of Thursday, with at least 13 deaths in the Seattle area being attributed to the excessive hot weather. In Oregon, the medical examiner’s office in Multnomah County, which encompasses Portland, said that at least 45 fatalities had occurred because of heat exposure.

In British Columbia, after temperatures soared to 121 degrees and broke back-to-back records in Lytton on Tuesday, wildfires began spreading. By Thursday, local officials said more than 90% of the small town of 250 or so residents had burned.

The sweltering conditions also took their toll on roadways and energy infrastructure, including power outages, transmission line voltage reductions, compressor issues and pipelines. They also made for exceedingly high gas demand, especially in light of the record low water levels in the western U.S. reservoirs that were threatening hydroelectric power.

Natural gas demand in the Pacific Northwest, for example, averaged around 1.78 Bcf/d in the seven-day period ending July 1, according to Wood Mackenzie. This was up from the recent 30-day average of 1.62 Bcf/d, as well as last year’s 1.09 Bcf/d average for the same 30-day period.

Gas demand spiked to 1.89 Bcf/d in the region on Tuesday (June 29), Wood Mackenzie data showed. However, power burns were forecast to drop to 1.70 Bcf/d by Friday and then average only around 1.15 Bcf/d average for the first full week of July.

The unprecedented temperatures in what is normally a mild region are because of the intensity of a heat dome that developed and caused a high pressure system to get stuck in place, according to AccuWeather.

“When the jet stream shifts far to the north, it allows extreme heat to surge into places that typically do not experience such conditions,” AccuWeather senior meteorologist Randy Adkins said. “It’s almost like allowing an air mass that you would normally see in the Desert Southwest shift to the Pacific Northwest.”

Though temperatures had fallen to more comfortable levels in some coastal areas of the Pacific Northwest, the National Weather Service (NWS) said excessive heat would continue into the holiday weekend from the interior Northwest to the Northern High Plains. Highs were forecast to reach the 90s and 100s, with a handful of daily records possible across parts of the Northern Plains and Northern Great Basin.

“The heat has moderated somewhat,” according to NWS, “however conditions remain oppressive just given the prolonged heat wave and ongoing heat stress.”

Can’t Take The Heat

Meanwhile, Aegis Hedging Solutions said several compressor stations in Western Canada were offline for periods of time because of the extreme heat. The unplanned compressor outages began in the final weekend of last month (June 26-27) and resulted in a decline in field receipts.

“Exports to the Northwest are flowing near capacity as power outages in California and western states lead to higher gas prices,” the hedging adviser said. “It is likely that supply continues to be impacted particularly if overnight temperatures do little to give equipment a reprieve.”

The strained conditions, and projected impact on Western Canada storage, were on full display across the forward curve.

Forward Look data showed NOVA/AECO C August prices climbing C28.0 cents from June 24-30 to reach C$2.8390/GJ. Although posting the largest increase across North America, the price for August delivery still proved to be a bargain, coming in more than C$1.30 less than August gas at Malin, OR, which delivers into Pacific Gas & Electric Corp.’s Redwood Path. The basis to Henry Hub stood at about 81.0 cents for the prompt month.

Further along the curve, gains were as impressive. AECO’s winter strip (November 2021-March 2022) tacked on C21.0 cents to average C$3.090, according to Forward Look. Summer 2022 prices were up C12.0 cents to C$2.250. The steep rise in prices further out the curve come amid below-average storage inventories that in Western Canada that were expected to fall further below historical levels after the blistering heatwave.

Meanwhile, Malin, which is comprised in part of deliveries from TC Energy Corp.’s Gas Transmission Northwest Pipeline, saw the August contract edge up only 8.0 cents in the trading period, but to a much higher $4.201, Forward Look data showed. However, the rest of the summer notched far plumper gains. The balance of summer added 41.0 cents during the period to average $3.940. Winter prices tacked on 7.0 cents to $4.20.

Falling TCO Production

As if the historic heat and various issues it caused weren’t enough to wreak havoc on the market, Wednesday’s news that about 2 Bcf/d of Northeast production was being curtailed sealed yet another move higher for Nymex futures.

In a pipeline notice, Columbia Gas Transmission (TCO) attributed the decline in production to an operational event upstream at MarkWest Energy Partners LP’s Sherwood and Mobley plants in West Virginia. The events were effectively curbing production and necessitated “a curtailment of scheduled volumes by the upstream point operators” to zero for Thursday.

Criterion Research LLC natural gas analyst James Bevan explained the impacts during The Desk’s online energy chat Enelyst. The outage, he said, had a “severe impact” on flows across the Northeast, with major production drops on TCO, EQM Midstream and Rover pipelines. Since Tuesday (June 29), Appalachian on-pipe production nominations had crashed by a combined 4.5 Bcf/d, with the largest taking place on TCO (minus 2.1 Bcf/d), Rover (minus 0.7 Bcf/d) and EQT (minus 0.59 Bcf/d).

“Overall, Appalachian production dropped hard with the late-cycle nominations, giving up minus 0.95 Bcf/d as the new flow data rolled into the models,” Bevan said. “Appalachian production fell even harder Thursday, dropping by another 2.66 Bcf/d to a modeled rate of 30.3 Bcf/d, which represents by far the lowest levels in the last 12 months.”

TCO said the reduction on system supply was around 2 Bcf. However, as of Thursday (July 1), the pipeline’s Appalachian receipts had dropped to 4 Bcf/d, from more than 6 Bcf/d on Tuesday.

Bevan said Thursday’s pipeline nominations indicated that the production drop immediately pulled back outflows to the Midwest to 10.6 Bcf/d.  Liquefied natural gas (LNG) exports at the Cove Point LNG export terminal in Lusby, MD, also were impaired. However, Transcontinental Gas Pipe Line appeared to be able to increase its exports toward the southeastern part of the country.

“Northeastern outflow into the Midwest was already struggling earlier this week due to high regional demand, but the MarkWest outage has knocked flows down even further to 10.6 Bcf/d,” Bevan said.

Storage Shocker

The TCO discussion was part of a larger segment on Enelyst’s chat following the latest round of government storage data, which also made some waves on Thursday.

The Energy Information Administration (EIA) launched a “bear bomb” on the natural gas market, reporting a much larger-than-expected 76 Bcf injection into storage for the week ending June 25. The EIA figure was slightly outside the range of expectations in major surveys and 3 Bcf above last year’s build for the similar period. The five-year average stood at 65 Bcf.

Bespoke Weather Services said the 76 Bcf injection was “much looser, balance wise,” than last week’s 55 Bcf build. However, it is “still a little tighter than the five-year average supply/demand balance.”

Broken down by region, the Midwest added 28 Bcf into inventories, and the East added 25 Bcf, according to EIA. South Central stocks rose by 14 Bcf, including 12 Bcf into nonsalt facilities and 1 Bcf into salts. Pacific inventories rose by 5 Bcf, while Mountain stocks increased by 4 Bcf.

Total working gas in storage rose to 2,558 Bcf, which was 510 Bcf below last year at this time and 143 Bcf below the five-year average, EIA said.

Meanwhile, the market is on track for another tight number next week, according to early estimates.

Tudor, Pickering, Holt & Co. (TPH) analysts said as temperatures have soared over the past week, power generation increased about 5 Bcf/d week/week. In addition, upstream issues at two MarkWest gas plants interrupted about 2 Bcf/d of Marcellus Shale production. Liquefied natural gas (LNG) feed gas demand also remained strong north of the 10 Bcf/d mark, while Mexico exports remained well above 7 Bcf/d. Finally, the oppressive heat in Western Canada curbed imports. Gas flows into the United States fell below 5 Bcf/d, TPH said.

For the next EIA report, the TPH analysts’ preliminary modeling points to a 17 Bcf injection. This compares with norms of 57 Bcf.

As for the end of October, TPH’s latest modeling points to inventories sitting at 3.5 Tcf, primarily on higher supply. The firm said given the recent rally in Nymex futures, both associated and dry gas supply are likely to accelerate through year-end on a combination of private exploration and production and Haynesville Shale activity.

However, exports are also set to remain strong. This past week, European inventories continued the trend of widening versus the five-year average. TPH noted that inventories rose by 78 Bcf, which compared with the 5-year average build of 100 Bcf.

“The result is that the gap to the five-year average has now extended to 538 Bcf, as the continent continues to struggle to fill its caverns,” TPH analysts said.

Russia and Norway have increased flows to 15.2 Bcf/d (up 0.4 Bcf/d week/week) and 10.7 Bcf/d (up 1.3 Bcf/d), respectively, according to TPH. Despite these efforts, the continued heat wave that has gripped the continent has caused gas demand to remain robust and above historical norms.

“This combined with strong pricing out of Asia continues to keep the gap to the five-year large, thus keeping the LNG market running hot.”

Despite a drop in LNG feed gas demand, along with a cooler turn in the latest weather models, Nymex futures continued to climb. The August contract notched a ninth straight day in the green, settling Friday at $3.700, up 4 cents.