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July Natural Gas Forwards Tick Higher on Week as Near-Term Heat Intensifies

July natural gas forward prices rose an average 2 cents from June 7-13 as weather models trended hotter for the near term, according to NGI’s Forward Look.

Most pricing locations followed Nymex futures higher, although some markets softened on the week amid mild temperatures and maintenance events that limited supply transportation.

The July futures contract peeled back 4 cents ahead of the June 9-10 weekend, but then spent the first half of the next week mostly in the black. The prompt month eventually settled Wednesday at $2.963, up 3 cents for the June 7-13 period. August was up just a penny to $2.948, as was the balance of summer (August-October), which hit $2.94. The winter 2018-2019 strip was also up 1 cent to $3.09.

Weather was front and center as hot conditions were expected to continue dominating the central and southern United States, with high temperatures in the 90s to 100s making for strong demand in those regions. The northern part of the country was forecast to see mostly comfortable conditions for another day or two with highs of 60s to mid-80s for light regional demand, NatGasWeather said.

Rapid warming was still on track to arrive across the Midwest and East into the weekend and early next week, where daytime temperatures were expected to reach the upper 80s to mid-90s from Chicago to the Ohio Valley, likely hitting major Northeast cities as well.

The pattern late in the June 14-18 work week still looked quite comfortable across the central and northern United States, and included a weaker southern upper ridge, which should ease the intensity of heat and drop national demand to near normal, the weather forecaster said.

“We still expect the southern U.S. upper ridge will gain strength June 23-28, which would result in highs of 90s to locally 100s dominating most of the southern and central U.S. However, the latest weather data continues to favor the heat dome being focused more strongly over the west-central U.S. instead of the east-central U.S., leaving the Great Lakes and Northeast not quite hot enough to impress,” NatGasWeather said.

Still, Nymex futures appeared to think the near-term heat was enough to keep prices relatively supported, even after a shocker Energy Information Administration (EIA) storage inventory report Thursday morning.

The EIA reported a 96 Bcf build into storage inventories for the week ending June 8, lifting storage inventories to 1,913 Bcf, 785 Bcf less than last year at this time and 507 Bcf below the five-year average of 2,420 Bcf.

Storage Reaction ‘Ho-Hum’

Before the EIA released the report, market consensus was around a build in the upper 80s Bcf range. EBW Analytics favored a slightly smaller build, while Bespoke Weather Services projected a 90 Bcf injection. Kyle Cooper of ION Energy Services expected a 93 Bcf build, and a Bloomberg survey had a range of 82-95 Bcf, with a median expectation of 90 Bcf. A Reuters poll also had a range of 82-95 Bcf, with a median expectation of 90 Bcf.

“This indicates that much of the looseness last week was not holiday demand destruction but rather loosening in power burns we have been observing, a trend that has continued even into this week,” Bespoke chief meteorologist Jacob Meisel said.

Last year, the EIA reported an injection of 82 Bcf, while the five-year average build stands at 91 Bcf. The East region injected 26 Bcf into storage, while the Midwest injected 31 Bcf. Inventories in the South Central region rose by 27 Bcf.

The initial market reaction to the bearish build was rather muted as the prompt month barely budged after the storage report’s 10:30 a.m. release.

“Prices didn’t fall that much. We were at $2.97 when the number came out, then we dropped a penny,” INTL FC Stone’s Tom Saal said. By 11 a.m., the Nymex July contract had dropped to its low of the day at $2.93 before regaining some ground to trade relatively flat to Wednesday’s settle.

Saal said Thursday’s late-morning trading action was likely due to high-frequency traders that don’t necessarily care about such a large discrepancy in storage estimates versus the actual reported build. “The market is groping along now. There’s only so many things it can react to,” he said.

With storage deficits to historic levels remaining, Mobius Risk Group said an average injection of 73 Bcf per week would be needed in order for storage to reach the 3.5 Tcf mark ahead of the winter withdrawal season. Over the 23-week period from June 8-Nov. 2 last year, weekly injections averaged 53 Bcf.

A simplistic view suggests each week would need to be 3 Bcf/d loose to the prior year’s comparable injection to reach the 3.5 Tcf threshold. As a result, Thursday’s storage report should not be considered a bearish indicator unless the injection was larger than 103 Bcf.

Indeed, being closer to 3.5 Tcf of storage may be a bit more necessary this winter, since at least two additional pipelines in Mexico should be up and running by the end of 2018, NGI’s Patrick Rau, director of strategy and research, said.

“That could mean an extra 1 Bcf/d or so of exports to Mexico going into winter. Nothing that the market cannot handle, but if we have another really cold winter, that extra little buffer could certainly help,” Rau said.

But Bespoke said with average weather, the print is loose enough to put 3.6 Tcf in play, and though its current end-of-October estimate sits at 3.56 Tcf with a hot July, “we do not see the print as indicating much of a reason to rally, especially given cooler forecasts,” Meisel said.

With forecasts likely to trend hotter to close out June and with production limited, however, the weather forecaster said “$2.87-2.90 should hold and be a strong long entry, but the print is clearly bearish.”

El Paso, Columbia Cause Regional Dips

Turning to other forward markets across the country, most pricing hubs followed the direction of Nymex futures. There were several markets, however, that posted steep declines.

Among them were points in the Permian Basin, where a revision to the El Paso Natural Gas maintenance schedule led to a cut of more than 200 MMcf/d of flows through the Waha GE constraint point in West Texas, according to Genscape Inc.

This location tracks volumes moving west near the Waha hub and has been substantially limited for several months because of an ongoing force majeure repair event. A separate meter replacement event that began Tuesday had its associated operating capacity reduction revised, changing the operating capacity limit to 152 MMcf/d from 272 MMcf/d. This point averaged 350 MMcf/d of flows in the previous month, Genscape analyst Joe Bernardi said.

The maintenance event took its toll on spot gas prices in the region, sending both El Paso-Permian and Waha prices down more than 10 cents in Wednesday trading.

In the forward markets, El Paso-Permian July plunged 19 cents from June 7-13 to reach $1.87, a 10-cent discount to spot gas prices for Thursday’s delivery. The rest of the forward curve posted sharp declines as well, with August sliding 20 cents to $1.81, the balance of summer (August-October) tumbling 19 cents to $1.59 and the winter 2018-2019 shedding a dime to reach $1.63, according to Forward Look.

At Waha, 20-cent declines were seen from July through the rest of summer. July fell to $1.91, just a penny below the spot gas price for Thursday’s gas day. August dropped to $1.87, and the balance of summer (August-October) fell to $1.64. The winter 2018-2019 strip was down 12 cents to $1.69.

Meanwhile, the effects of the June 7 explosion on Columbia Gas Transmission’s (TCO) Leach XPress continue to be seen. Genscape reported on Tuesday that Columbia Gulf Transmission’s supply from the Gulf Leach interconnect had fallen dramatically as a result of the force majeure that went into effect following the incident.

Gulf Leach is Columbia Gulf’s single largest supply point, accounting for up to 53% of its total supply, but receipts at the interconnect have fallen by 1.18 Bcf/d since the force majeure was declared. “Receipts from other locations have risen in partial compensation, but overall receipts are still down 693 MMcf/d from the week prior to the explosion,” Genscape natural gas analyst Josh Garcia said.

As for forward prices in the Appalachia supply region, Columbia Gas’ July package rose 7 cents from June 7-13 to reach $2.798, while August climbed a nickel to $2.785 and the balance of summer (August-October) rose 4 cents to $2.73. The winter 2018-2019 strip was up 3 cents to $2.85, Forward Look data show.

Dominion South, meanwhile, posted prompt-month gains that were more in line with Nymex futures. July edged up 4 cents to $2.325, but August and the balance of summer (August-October) slipped a penny each to $2.34 and $2.30, respectively. The winter 2018-2019 strip was up 3 cents to $2.65.

Other pricing locations along the West Coast posted small prompt-month losses of less than a nickel for the June 7-13 period, although SoCal City-gate put up far more substantial decreases as demand was expected to remain low for the next several days.

SoCal City-gate July prices plunged 25 cents to $3.56. August tumbled 18 cents to $3.94, the balance of summer (August-October) dropped 15 cents to $3.58 and the winter 2018-2019 slid 6 cents to $4.28, Forward Look shows.

Prices across the West could see some support in the coming days as a strong ridge was expected to bring record-challenging heat to the Pacific Northwest for the middle of the week. Highs are forecast to peak in the low 90s in Seattle and upper 90s in Portland, OR.

“Furthermore, this upcoming heat is part of a longer-term pattern that is expected to be persistently hotter than normal on a nationwide scale in the coming weeks, leading June 2018 to challenge June 2010 for the hottest June among records since 1950 from a population-weighted cooling degree day perspective,” forecaster Radiant Solutions said.

Elba Island Commissioning Process Not Yet Under Way

In other news, the liquefied natural gas (LNG) export terminal in Georgia, Elba Island LNG, should be approaching initial operations, according to a standard liquefaction commissioning schedule, which typically accounts for about three months prior to commercial service, Genscape said.

In a first quarter earnings call in April, Kinder Morgan Inc. executives outlined a timeline for the project, stating that the first train would be operational by 3Q2018, and each additional train would come online in about 30-45 day sequences.

Genscape proprietary power readings, however, had not yet shown any power being drawn to the facility. Furthermore, recent FERC filings indicate contractors were still adding components such as resistance temperature detector sensors and tank skirt systems.

Elba submitted data on these designs to the Federal Regulatory Energy Commission June 4, which indicated that approval was still necessary before the commissioning process could begin.

Genscape plans to continue to monitor flows and power into Elba to detect initial commissioning activity.

The federally approved liquefaction project at the existing Southern LNG Co. facility at Elba Island near Savannah, GA, is to have a total liquefaction capacity of about 2.5 million metric tons/year, equivalent to about 350 MMcf/d. The project is supported by a 20-year contract with a unit of Royal Dutch Shell plc.

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