Natural gas futures traders took the curve down a notch Friday as the latest weather data moved the needle slightly lower in terms of the overall demand picture for the next couple of weeks. The November Nymex contract settled 1.6 cents lower, and December slipped fractionally to $2.459.
Spot gas prices finished the week down even as a strong weather system moved into the southern Plains, bringing rain and snow as far south as Texas and fueling demand. However, with the chilliest air confined to the country’s less densely populated midsection, the NGI Spot Gas National Avg. dropped 9.0 cents to $1.915.
Weather forecasts pointed to an even stronger, more widespread cold front in the days ahead, but Nymex futures appeared to have already priced in the expected bump in demand. The latest Global Forecast System model run Friday lost a little demand for the last week of October, with cold expected to be slower to arrive in the East, but then adding a little demand back Nov. 3-4 by seeing a reinforcing cold shot into the northern United States, according to NatGasWeather.
Recent data had been inconsistent beyond those dates, with most runs showing warm conditions quickly returning Nov. 5-8, “while another smaller camp tries to sneak cold air across the Canadian border,” the forecaster said. “The milder, more bearish case has the greater odds for Nov. 5-9, but is not a certainty since cold air will be right at the Canadian border and could trend a little deeper into the United States in time.”
With little indication that cold would remain in place after the first week of November, forecasts Friday offered little encouragement for bulls. If that weren’t enough, Thursday’s storage report was yet another reflection of an extremely loose market in which production has dominated.
The U.S. Energy Information Administration (EIA) reported an 87 Bcf injection into storage inventories that boosted stocks as of Oct. 18 to 3,606 Bcf, more than 500 Bcf above last year and 28 Bcf above the five-year average.
The reported build was 2 Bcf larger than Genscape Inc.’s call for an 85 Bcf and 1.7 Bcf lower than the average of the major surveys. Compared to degree days and normal seasonality, the reported injection appeared loose by about 5.6 Bcf/d versus the prior five-year average, according to the firm.
“The last three weeks have been very loose (more than 5 Bcf/d loose on average), with injections over that time frame totaling 49 Bcf larger than the five-year average, despite the fact that degree days over the last three weeks have been 39 Bcf larger than the five-year average,” Genscape senior natural gas analyst Eric Fell said. “We saw three comparably loose storage weeks back in late March/early April, but Henry Hub cash averaged $2.69 over those three weeks in March/April, while cash has averaged $2.26 over the last three storage weeks (Henry Hub cash prices per NGI).”
Meanwhile, the fall nuclear turnaround season appears to have reached its peak, barring any additional unscheduled outages. Operating data from the U.S. Nuclear Regulatory Commission showed the amount of capacity on outage hit 22.6 GW on Oct. 19, but since then it has gradually been restored to bring capacity on outage down to about 18.2 GW.
“If one were to assume a purely 1:1 gas burn replacement, this would equate to about 3.3 Bcf/d of gas demand,” Genscape senior natural gas analyst Rick Margolin said. “However, the actual figure is much lower given loads this time of year are lower and other fuels contribute to replacing lost nuclear generation.”
Last fall, outages peaked on Oct. 28 at 25.6 GW. Schedules for plant turnarounds indicated current outages should continue sharply declining so that by the second week of November, there should be less than 1 GW of nuclear capacity offline, according to Genscape.
Liquefied natural gas (LNG) intake may be one of the few factors working in favor of market bulls. LNG feed gas demand has reached 7.0 Bcf/d on a weekly basis, an all-time high, with the Dominion Cove Point terminal back online following a 24-day maintenance outage and most LNG trains operating near capacity.
Uneven demand in recent months, however, may be an indication of variability in LNG exports to come, with potentially significant impacts for natural gas prices, according to EBW Analytics Group. Maintenance outages, uneven start-up of new trains, reduced utilization because of poor economics at some terminals and weather threats from both hurricanes/fog can cause temporary yet significant swings in demand.
“It is possible that demand will rise toward 7.3 Bcf/d by year-end if global needs become greater, but the next step change increase is only likely once Cameron Train 2 comes online in the first half of 2020,” the firm said.
Even then, analysts with BofA Merrill Lynch Global Research believe the upside in prices is limited. With the implosion of Appalachian coal prices, which are down more than 40% year/year, they estimated the soft cap on natural gas prices is just above $3, compared to $5 a year ago.
“Further, any early mild weather would provide salts an opportunity to replenish stocks and could be detrimental to winter prices. As such, we lower our 1Q2020 price forecast 50 cents to $2.50/MMBtu,” researchers said.
The BofA team also lowered its projections for 2020 to $2.35, from $2.60, assuming normal weather and continued growth in LNG exports.
Chili-making weather in Texas was not enough to boost spot gas prices on Friday, while mild conditions on the East Coast took a chunk out of cash prices there.
In the Northeast, Algonquin Citygate tumbled 27.5 cents to $1.560, while most other pricing hubs fell between 15 cents and a quarter.
Appalachia cash markets softened in a similar manner, although Columbia Gas finished the day a half-cent higher at $1.855.
Weakness spread across the Southeast and into Louisiana, with losses capped at 15 cents throughout the area.
Meanwhile, market observers on Friday were monitoring a tropical depression in the Gulf of Mexico, but the weather system was expected to be picked up by the cold front advancing through Texas and the South. This was expected to bring heavy rains across the Gulf Coast that could then spread northward into the Ohio Valley on Saturday, according to NatGasWeather.
Spot gas prices across Texas were lower, but Permian Basin cash remained in positive territory to close out the week.
Prices out West were also mostly a sea of red, although a glaring exception was Northwest Sumas in the Rockies, which saw cash prices surge 47.5 cents to $3.240 amid ongoing restrictions on critical import lines.
However, lower prices could be ahead as an updated maintenance calendar posted Thursday by Westcoast Transmission showed its southbound flow capacity returning to near normal capacity in November after being limited for more than a year following an explosion on its system near Prince George, British Columbia, last October.
Westcoast’s flow capacity is expected to generally range between 1,630 MMcf/d and 1,730 MMcf/d at Station 4B in November, an increase of 380-480 MMcf/d over the year-to-date average. The year-to-date maximum flow is also only 1,650 MMcf/d, “so if flows come in equal to operational capacities, as they generally do, November should see a new maximum flow for this point for 2019,” Genscape analyst Joseph Bernardi said.
In California, public safety power shutoffs were in effect on Friday and Gov. Gavin Newsom had declared a state of emergency as Santa Ana winds were expected to peak. By midday, Southern California Edison had about 20,000 customers still without power after shutting off service to nearly 27,000 customers across five counties by midday Thursday.
San Diego Gas & Electric Co. had about 16,000 customers without power, and Pacific Gas & Electric Co. (PG&E) began curtailing power on Wednesday to customers in Sierra foothills counties, with shutoffs to be implemented on a phased basis through Thursday. On Friday, a notice on its website indicated that power had been restored to most of the counties in its service territory, although only about half of the customers in Tehama and Sierra counties had been restored and all affected customers in Kern County were still without power.
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