July natural gas prices fell more firmly into the red Tuesday as cooler weather on tap for the second half of June in the United States stole the spotlight from substantial storage deficits and lackluster production.
Spot prices were also mostly lower as a weather system and associated cool front were expected to bring showers and cooler-than-normal temperatures across the Northeast and Mid-Atlantic over the next few days. The NGI National Spot Gas Average fell 4 cents to $2.59/MMBtu.
Nymex July futures traded in a tight range of less than a nickel throughout the day, with deals in the last half hour of trading being on the lower end. The prompt-month contract settled Tuesday at $2.89, down 4 cents on the day. Losses of around 4 cents were seen through the remaining summer months, with balance of summer (August-October) sliding to $2.90. The 2018-2019 winter strip, meanwhile, once again held in the $3 range, slipping 3 cents to $3.041.
The latest mid-day global forecasting system model was a little hotter trending through the middle of next week, but then cooler trending and still not hot enough June 16-20, according to forecasters at NatGasWeather. A very warm U.S. pattern is still expected the next couple weeks with near or above-normal cooling degree days (CDD) on most days, “just not ominous enough across the northern U.S. going into the second half of June to justify prices rallying further.”
Forecasters are now looking to the last week of June for signs of the southern U.S. ridge strengthening and expanding in size, which the latest data is mixed on, NatGasWeather said.
Still, the bearish sentiment presents risks that weather guidance begins losing additional CDDs, Bespoke Weather Services said. The cooler risks also have “solidly raised” the forecaster’s storage injection expectations over the next several weeks, chief meteorologist Jacob Meisel said.
Early indications point to another sub-100 Bcf injection for this week’s Energy Information Administration (EIA) report for the week ending June 1. The next two weeks’ injections are now predicted by traders on the Intercontinental Exchange to be 94 Bcf and 83 Bcf, respectively. Taken together, this would still be supportive of around 2 Bcf/d of demand growth year/year, Mobius Risk Group said.
“All of the injections so far this year have implied demand growth of between 1 Bcf/d and 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,” Mobius said.
For its part, NatGasWeather expects storage deficits will remain near or a little more than 500 Bcf through the next three to four storage reports as the markets wait for record production to begin reducing them.
If production grows by an additional 1.75 Bcf/d from now until the end of October, and if total demand shows year/year growth of just 1 Bcf/d, that would still result in an end-of-October inventory level of around 3,400 Bcf, Mobius said. If demand growth turns out to be closer to what recent EIA storage reports have implied (2 Bcf/d of growth), then end-of-October inventory levels could fall below 3,300 Bcf, “which should be supportive of higher prices heading into the winter months.”
On the other hand, greater-than-expected production growth and mild summer temperatures could send prices lower, but still shouldn’t 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.
Genscape Inc. reported that production declined Tuesday, with its pipeline data estimating total volumes at 77.27 Bcf/d, about 1.19 Bcf/d below Monday. Production is now coming in nearly 1.6 Bcf/d below forecast, “although we do not expect that delta to last long once maintenance season winds down here in the next couple of weeks,” Genscape senior natural gas analyst Rick Margolin said.
Northeast production led the declines, falling 459 MMcf/d day/day. Declines in Texas Eastern Transmission (Tetco) pipeline receipts led the drops in Ohio and Southeast Pennsylvania, and “may be partially associated to constraints moving gas southward on Tetco’s 30-inch line,” Genscape said. Monday morning, Tetco experienced an unplanned outage on its Danville, KY, compressor station (CS) on its 30-inch diameter South line, with repairs expected to take three to four days.
“This line is currently maintenance constrained from the Berne compressor station (CS) to the Barton CS until June 16, and this outage further reduced operational capacity by 100 MMcf/d,” Genscape analyst Josh Garcia said. Flows were constrained throughout the line over the weekend, running at 99.7% capacity at the Tompkinsville CS as of Monday (June 3), and it remains constrained at the southern end of the line as of timely cycles for Tuesday (June 5).
Meanwhile, nearly the entirety of northeastern Pennsylvania day/day declines were on Tennessee Gas Pipeline in Tioga and Susquehanna counties, where sample receipts are down 140 MMcf/d and 86 MMcf/d, respectively. West Virginia declines were led by a 95 MMcf/d drop in Columbia Gas Transmission receipts, along with a 76 MMcf/d drop on Equitrans.
Gulf Coast area volumes were down 256 MMcf/d, while Rockies volumes were down 357 MMcf/d. Kern and Ruby receipts from the Opal processing complex also dropped, according to Genscape.
“Usually when Opal plant volumes are disrupted, we see volumes from the neighboring Pioneer plant ramp up to help compensate, but that is not occurring at present,” Margolin said. Rockies production was also being hit by a 109 MMcf/d drop in Bakken Shale production, while San Juan Basin volumes slid about 166 MMcf/d.
Across the border in Mexico, hot weather, strong demand and limited supply reportedly caused blackouts during May in the Yucatan Peninsula. The first event occurred on May 11 as a midday drop in natural gas supply led to the loss of about 400 MW of generation at the MÃ©rida Potencia and Valladolid power plants, according to the National Center for Energy Control (CENACE).
During the event, CENACE, which serves as the electric grid operator, then implemented rolling blackouts in 30-minute increments that began at 2:20 p.m. and lasted until 6:17 p.m., reaching a total of 110 MW, which represents 7% of the total demand in the peninsula. Increased night-time demand prompted the need for additional rolling blackouts beginning at 11:24 p.m. and lasting until 12:04 a.m. May 12, reaching a maximum of 96 MW.
A similar event took place on May 30, causing a reduction in the operating reserve margin to less than 6%, which prompted CENACE to implement rolling blackouts again in 30-minute increments. CENACE’s website did not specify the duration of the blackouts, but said the effort was carried out in coordination with the ComisiÃ³n Federal de Electricidad (CFE), market participants, generators and CFE distribution.
Turning to U.S. spot markets, prices were mostly lower for Wednesday’s gas day even as a hot upper ridge will dominate the western, central and southern U.S. with highs of 80s to 100s for the remainder of the week.
Late in the week, however, the hot high pressure will expand to cover most of the country with very warm to hot conditions and stronger-than-normal demand. The East is forecast to see light demand return early next week as weather systems return with additional showers, NatGasWeather said.
Pricing locations in the Permian Basin posted declines as additional maintenance events in the region were announced. Genscape said another cut to 230 MMcf/d of Permian outflows on El Paso Natural Gas (EPNG) was set to take effect Tuesday due to a new maintenance event. Permian flows on EPNG have been disrupted over the last several days due to three forces majeures declared last week.
PNG is performing a test at its Plains Station through Thursday, which may reduce the operating capacity of the PERM N meter to zero. This meter flowed an average of 176 MMcf/d in May, tracking flows north out of the Permian Virtual Area toward the affected Plains Station, Genscape’s Joe Bernardi said.
The maintenance will also separately affect 60 MMcf/d on three receipt/delivery meters in that area: INN30PLA, IMUSTANG, and INN26PLA. Tuesday’s timely cycle data for EPNG’s Permian production was roughly 100 MMcf/d higher day/day, although Monday’s data was ultimately revised upward by more than 150 MMcf/d due to two of the three previously mentioned forces majeures ending.
Meanwhile, a one-day planned maintenance on Wednesday was expected to affect about 200 MMcf/d of Transwestern flows. A valve replacement at the P-1 station in eastern New Mexico is to limit Panhandle Lateral throughput to 0; the average flow in May was 210 MMcf/d.
This would affect both receipts and deliveries at up to eight receipt/delivery locations, which are specified in the full maintenance event, Genscape said. A similar but unplanned maintenance event occurred last summer, cutting flows essentially to zero for one day; Waha prices dipped slightly but did not venture significantly out of range.
“That said, flows have been running higher this year than in years past,” Bernardi said.
Indeed, Waha spot prices did come off in Tuesday trading, sliding 7 cents to $2.21 for Wednesday’s gas delivery. El Paso-Permian was flat at $2.19 but again traded in a wide range, of more than 50 cents on Tuesday. Transwestern fell 8 cents to $2.22.
California markets slid as temperatures in the state were expected to be near to just slightly above normal for the rest of the week. Highs in Los Angeles were expected to top out in the mid-70s on Wednesday and then climb to the low 80s by Friday, according to AccuWeather. San Francisco temperatures were forecast in the low to mid-60s throughout the rest of the week.
Given the comfortable weather pattern, SoCal Citygate spot gas tumbled 77 cents to $2.92 after trading in a 20-cent range up to $3.00. PG&E Citygate averaged $2.97 but traded in a far tighter range of less than a nickel.
Along the Gulf Coast, Houston Ship Channel slipped a couple of cents to $2.98, while Katy fell 4 cents to $2.95. Benchmark Henry Hub prices fell 4 cents to $2.87.
In the Appalachian supply region, Tennessee Zone 4 Marcellus pricing continued to improve, with next-day gas climbing 13 cents to $1.77. Dominion South, meanwhile, slipped 3 cents to $2.47.
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