Natural gas forward prices for July slid an average 7 cents from June 1-6 as weather forecasts pointed to cooler temperatures for the second half of June, according to NGI’s Forward Look.
Most of the action occurred in the middle of the week, first when weather guidance began showing hints of moderate temperatures for the third week of June and then again once the forecast became more of a certainty. The most recent trends were mixed, with some datasets a little hotter and a few cooler, but most important, still not hot enough across the northern half of the country June 16-20, NatGasWeather said.
“The upper ridge has the potential to strengthen near or just after June 21,” but failed to gain traction in the overnight Wednesday data, which could begin to make the markets impatient, the forecaster said. “Until the mid-June upper ridge expands in strength or size, weather sentiment is likely to be viewed as neutral to slightly bearish.”
Nymex July futures ended the June 1-6 period down 6.6 cents to $2.896, while August slid 6.7 cents to $2.909 and the balance of summer dropped 6 cents to $2.903. The winter strip managed to fare slightly better as it held above the $3 threshold, easing just 4 cents to $3.05.
While it is not unheard of to see July benchmark pricing realize lower than June, summer heat does not peak until late July and thus upside risk remains, Mobius Risk Group analysts said. “Historical observations show that July has indexed lower than June (Henry Hub) in four out of the past nine years,” it said. The June contract rolled off the board at $2.875.
Thursday’s storage report from the Energy Information Administration (EIA) brought about some support for prices as the Nymex July contract was up a nickel just before the start of trading. It jumped as high as $2.987 before the storage report release, but fell back to $2.96 as the storage figure crossed trading desks. The prompt-month eventually ended the day at $2.93, up just 3.4 cents.
The net 92 Bcf storage build compared with a 103 Bcf injection for the same week last year and the five-year average build of 104 Bcf. There were 71 cooling degree days (CDD) last week compared with 44 CDDs at the same time last year and a 30-year normal of 42 CDDs. In the week ended May 25, 96 Bcf was added to storage.
At 1,817 Bcf, stocks are 799 Bcf below year-ago levels and 512 Bcf below the five-year average of 2,329 Bcf.
Before the data’s release, market estimates were wide ranging, between 77 Bcf and 98 Bcf, and far short of the triple-digit injection some would expect from a holiday weekend.
INTL FCStone Financial Inc. Senior Vice President Tom Saal told NGI that the story was the Memorial Day weekend. “If we got over 100 Bcf, I wouldn’t be surprised. That weekend should produce a big number.” His official estimate, however, was for a 97 Bcf injection.
ION Energy’s Kyle Cooper projected a 97 Bcf injection, while a preliminary Bloomberg survey had a median estimate of an 89 Bcf build. A Reuters poll pointed to a 90 Bcf injection, and the Intercontinental Exchange EIA Financial Weekly Index settled Wednesday at an injection of 94 Bcf.
“This print is significantly looser from last week, indicating a slightly smaller injection despite very significant heat,” Bespoke Weather Services said. “However, Memorial Day holiday demand destruction likely played a large role, keeping us from reading too much into this.”
The forecaster was right on target with its 92 Bcf storage injection estimate. Bespoke’s Jacob Meisel said Thursday’s EIA print indicated that the market is not tightening, something its daily power burn tracking had shown.
Awaiting Production Ramp-up
Meanwhile, the market is eagerly expecting production growth to ramp up in the next few weeks in order to begin tightening the year/year storage deficit. Lower 48 dry gas production has continued to hover around 78 Bcf/d range, about 1.6 Bcf/d below Genscape Inc.’s forecast, although the data and analytics firm said it did not expect that delta to last long once maintenance season ends.
But Mobius said all the storage injections so far this year have implied demand growth of 1-3 Bcf/d, with an average of about 2.25 Bcf/d. “Continued implied year-on-year demand growth in excess of 1 Bcf/d throughout this summer could result in an end-of-October inventory level of less than 3,400 Bcf, which may not provide enough safety margin for a colder than normal winter,” analysts said.
If demand growth, however, turns out to be closer to what recent EIA storage reports have implied (2 Bcf/d), the end-of-October inventory level could fall below 3,300 Bcf, which should be supportive of higher prices heading into the winter months, Mobius said.
On the other hand, greater-than-expected production growth and mild summer temperatures could send prices lower, but should not create “containment pricing” in late October and early November (i.e., October and November cash trading significantly below summer 2019), “since inventory levels are not projected to exceed 3,700 Bcf, even in the mildest of weather scenarios,” Mobius analysts said.
Some industry experts have lowered their end-of-October storage targets and opined that the market does not need as much storage as it has historically thanks to robust production growth, but Saal said having adequate storage levels ahead of the peak winter season remains critical.
“The supply has to be where the demand is,” he said. “That Marcellus supply didn’t keep prices from going higher in January. We still pulled a lot of gas out of storage.”
If the United States experiences another winter like 2017-2018 and storage inventories start the season lower, “then we might get higher prices. You can’t assume shale production is going to bail us out in the wintertime,” he said.
AECO Ends Week Stronger
In an unusual twist, Western Canada was one of only two markets to end the June 1-6 period in the black. Ongoing pipeline maintenance that has led to volatile production swings, equally erratic demand and strong power demand have combined to lend some much-needed support for AECO pricing, at least for the summer.
AECO July forward prices edged up 2 cents to $1.162, while August tacked on a penny to $1.191 and the balance of summer (August-October) moved up a penny to $1.22, according to Forward Look. The winter strip, meanwhile, slipped 3 cents to $1.51.
Production numbers in the past 30 days have swung by as much as 1.4 Bcf/d, with current levels coming in about 0.4 Bcf/d below the month’s open, according to Genscape. The production numbers are swinging primarily due to ongoing maintenance on TransCanada Corp.’s Nova system.
Taking a bigger picture view, though, Alberta gas production in the past 30 days or so was averaging close to 11.6 Bcfd, about 0.4 Bcf/d (3.5%) above last year’s same-date average. Summer-to-date is running nearly 0.58 Bcf/d higher than last year and -- so far -- showing the biggest summer-on-summer growth in history.
“Those maintenance events also restrict how much gas can be exported and/or injected,” Genscape’s Rick Margolin said. “Daily volumes out of the province have printed in a 0.9 Bcf/d range. For the summer-to-date, exports out of Alberta have been averaging about 6.57 Bcf/d, about 0.4 Bcf/d higher than last year same date.”
Demand-side fundamentals have also been volatile, running within a 1 Bcf/d range. Structural demand in Alberta continues to grow with increased gas demand for oilsands production (which can swing with plant turnarounds) and retirements of coal-fired generation in the power sector, Genscape said.
“On a daily basis, power fundamentals have been wild,” Margolin said. The Alberta Electric System Operator power price has printed a few days at the regulated max of $999/MWh due to nongas-fired generation unexpectedly tripping offline and swinging generation over to gas-fired sources, he said.
In the broad context, though, provincial demand is running about 0.58 Bcf/d higher summer-on-summer. “At 4.93 Bcf/d, this summer is on pace to be the second strongest summer of demand in the province,” he said.
On the storage front, roughly 13.9 Bcf has been injected into inventories from April 1 to May 31, but maintenance restrictions interrupt how much gas can be injected on an interruptible basis. With the restrictions currently in place, injections are running at their lowest summer-to-date total since at least 2008, Genscape said.
Injections are running about 69% lower than last year and 75% less than the prior five-year summer-to-date average. Inventories are estimated to be around 180 Bcf versus last year at 247 Bcf and the five-year same-date average of 226 Bcf, the Louisville, KY-based firm said.
With limited ability to inject and constraints on exporting, AECO basis has had to feature some hefty discounts. In early May, AECO cash went negative, and since then has been trading in a range of U.S.$0.17 up to U.S.$1.50, per NGI price data.
Elsewhere across the country, most pricing locations posted losses that were roughly in line with the Nymex, although some steeper declines were seen in the eastern part of the country where cooler temperatures were on tap for the third week of June.
While most hubs saw drops of around 10 cents or so, Transco zone 5 South posted a far more substantial loss of 28 cents for July forward prices, which fell to $2.919, according to Forward Look. August was down 14 cents to $3.05, the balance of summer (August-October) was down 11 cents to $2.92 and the winter 2018-2019 was down 4 cents to $4.35. Transcontinental Gas Pipe Line, i.e. Transco, also has several maintenance events planned for various sections of its pipeline throughout the summer.