Even as Covid-19 continues to shatter demand across the Lower 48, weather reclaimed its dominance on natural gas futures Friday as persistently colder forecasts pushed up prices to end the week. After trading a few pennies higher for most the day, a late-session bid sent the May Nymex contract up 6.9 cents to settle at $1.621. June climbed 6.6 cents to $1.738.
Spot gas prices, however, continued to slide at the majority of market hubs even as a chilly weather pattern started to emerge in the Rockies. NGI’s Spot Gas National Avg. fell 5.0 cents to $1.280.
May futures traded both sides of even Friday as a battle got underway between demand loss from Covid-19 measures and cooler-trending weather forecasts. Given the sudden rally that transpired in the last half hour of trading, however, it appears other factors may have come into play.
“It is not entirely clear what prompted that late move higher,” Bespoke Weather Services chief meteorologist Brian Lovern said. “We do have higher weather demand on the way, but we’ve been seeing that colder move for three to four days now, so it is difficult to pin the move solely on that, although it helps, to be sure.”
Lovern said gas may be simply following the move of oil, “with just general buying in energy as a whole.” Friday’s market behavior “certainly leads one to wonder if we can say that the final bottom is in. We do feel like prices down in the low $1.50s are not sustainable longer term, but we hesitate to say that *the* final low is in, as it has felt that way before, only to see a renewed downturn.”
The market still has no good idea how long demand destruction will carry on, “which really is the big issue going forward,” according to Lovern.
That’s not to say weather data hasn’t become more supportive. The latest midday weather data showed a more aggressive push of subfreezing air into the Midwest late in the week into the following week, according to NatGasWeather. However, the Global Forecast System (GFS) was milder for the April 14-17 period, forecasting cold air to pull back near the Canadian border and return mild conditions to cities from the Midwest to the East Coast.
“The April 14-17 period has been inconsistent but currently not quite cold enough as cold air retreats into Canada,” NatGasWeather said.
Meanwhile, the Energy Information Administration’s (EIA) latest storage report offered the first glimpse into the impact of shuttered businesses, schools and other coronavirus-led restrictions on demand. The EIA said that storage inventories for the week ending March 27 fell by only 19 Bcf, a much smaller draw than what was expected by the market but one that matched the five-year average.
Genscape Inc. said the EIA figure, likely the last draw for the season, indicated the market was 3.1 Bcf/d looser than the five-year average when compared to degree days and normal seasonality. Even accounting for some possible make-up from the prior EIA report, which was 4 Bcf larger than Genscape’s estimate, “we clearly saw a large week/week decline in gas demand that was unrelated to weather,” senior natural gas analyst Rick Margolin said.
“Given that weather, net renewable generation and gas prices were nearly unchanged versus the prior week, a meaningful portion of the week/week decline in demand appears to be attributable to demand destruction from Covid-19. Total power generation across the Lower 48 fell by 3% week/week, while Lower 48 total degree days were essentially flat.”
Tudor, Pickering, Holt & Co. (TPH) analysts estimated 2 Bcf/d of oversupply based on the latest EIA print. Flow data for the current week, to be reflected in the next EIA report, shows demand off nearly 7 Bcf/d week/week, led by a 3 Bcf/d drop in the residential/commercial sector as the heating season winds down, according to TPH.
With the demand decline, and the likelihood that Thursday’s print was “almost certainly” the final pull before the next withdrawal season gets under way, cumulative winter-season draws fell “5% short of the five-year average on degree days that were 4% below norms,” TPH analysts said.
Nevertheless, the bearish EIA print does not imply that Nymex futures will decrease daily, according to EBW Analytics Group. The firm pointed out that after support for the May contract held Thursday near $1.52, futures moved up sharply.
“From a technical standpoint, it would not be surprising if the front month continued to probe higher, potentially testing resistance as high as $1.60,” EBW said. Notably, however, the cut-off for the most recent EIA storage report pre-dated shutdown orders in Texas, Georgia, Florida and several other states. “As doors close in these states, demand is likely to fall further, increasing downward pressure on the near-month contracts.”
Cash posted another day in the red amid a mostly mild set-up forecast for the Lower 48 through the next several days.
NatGasWeather said the southern states were expected to be “very nice” into the first full week of April, with highs of 70s and 80s making for “very light demand.” There’s a “decent” cold shot forecast over the Rockies and Plains, but the firm noted the cooler weather would hit lower population states. The Midwest and Northeast, meanwhile, were expected to warm well above normal beginning late in the weekend, keeping demand at bay in those regions.
Even with widespread stay-at-home measures, losses in the cash market were fairly small in most areas of the United States. Interestingly, prices were hit harder in the Rockies, where some of the chilliest weather was expected in the coming days.
Some East Texas points posted small increases day/day, as did a handful of pricing hubs in Louisiana. Henry Hub, however, fell 3.5 cents to $1.445.
On the East Coast, the majority of markets softened a bit day/day, but some posted much larger declines from ongoing pipeline maintenance. PNGTS cash was down 30.5 cents to $1.885, but the typically far more volatile Algonquin Citygate was down 1.5 cents to $1.395.
On the pipeline front, Tennessee Gas Pipeline (TGP) notified shippers on Thursday of an emergent repair on its Regency Dunkleberger gathering system meter in Tioga County, PA, that requires the meter to shut in for 16 hours on Monday (April 6).
This meter has nominated as much as 109 MMcf/d in the last month, but production has trended downwards, nominating 76 MMcf/d for Friday’s gas day, according to Genscape.
“It is unlikely that production will fully shut in on Monday,” Genscape natural gas analyst Josh Garcia said.
Then, beginning Tuesday through June 8, TGP is to conduct anomaly remediation from “MLV 114-2 to MLV 110-2,” on Segment 114 in Northeast Kentucky. This outage will lower its operational capacity from 923 MMcf/d to 760 MMcf/d for the rest of the week before a larger restriction takes place from April 13-29 that would lower operational capacity on this segment to 680 MMcf/d, according to Garcia.
“TGP’s outage impact report states that primary impact restrictions may be necessary for these events, the highest risk of impact on the report,” the analyst said.
Reported flows from Station 111 to Station 114 have maxed at 929 MMcf/d over the last two weeks and averaged 812 MMcf/d, meaning up to 249 MMcf/d of flows may be impacted.
“Export capacity on this production zone will be constrained, incentivizing lower TGP Z3 prices as producers will compete to export their gas,” Garcia said.
Meanwhile, New York is weeks away from retiring the 1,028 MW Indian Point Nuclear Plant’s Unit 2. The scheduled April 30 retirement follows that of the 675 MW Somerset Plant, the New York Independent System Operator’s last coal generator, which retired on March 31.
Indian Point has not contributed consistent generation in the last few years, and several recent gas builds throughout the Northeast started contributing more generation in light of the retirements, according to Genscape. These include the 1,100 MW Cricket Valley Plant on the Iroquois Pipeline, the 680 MW CPV Valley Plant on Millennium Pipeline and the 350 MW Canal Unit 3 on Algonquin Gas Transmission.
Older, less efficient gas generators no longer contribute as much baseload generation as they used to, but still are capable of assisting with peak demand if needed, Garcia said. Meanwhile, renewable capacity additions such as wind, utility scale and behind-the-meter solar, and batteries continue to grow amid a state push for 50% renewables in the electricity mix by 2030 and 100% renewables by 2040.