Supported by warmer weather trends and a modest recovery in export demand after flows reached new lows over the Memorial Day weekend, natural gas futures were up several cents in early trading Tuesday.
The soon-to-expire June Nymex contract was up 5.9 cents to $1.790/MMBtu at around 8:40 a.m. ET. The July contract was trading around $1.938, up 5.7 cents.
Natural gas futures traded both sides of even on Friday as the market steadied a bit while continuing to weigh steep production cuts, seasonal weather and hefty liquefied natural gas (LNG) demand losses. The June Nymex gas futures contract ultimately closed the week at $1.731/MMBtu, up 2.1 cents from Thursday’s close. July picked up 2.9 cents to reach $1.881.
Spot gas, which traded Friday for delivery through Tuesday, was mixed, with the majority of moves limited to around a dime or so. NGI’s Spot Gas National Avg. finished the week off 3.0 cents to $1.510.
With futures latching onto and running with various fundamental shifts throughout the week, especially amid the ongoing impacts from Covid-19, Bespoke Weather Services pointed out that when the smoke clears, the prompt month continued to be stuck in a range as it rallies off the $1.60-1.65 level, but then gets sold once above $1.90.
“Given the uncertainties ahead regarding production, LNG, and of course how much demand comes back” amid the coronavirus, “we may well continue to simply trade in this range with some sharp moves, but no logical reason to deviate from said range,” said Bespoke. “We also have June expiration” on Wednesday, “which could promote some erratic moves as well.”
With only pockets of heat so far this summer, widespread cooling demand doesn’t appear to be in the cards until mid-June at the earliest. The latest weather models shifted cooler in the eastern United States for early June in the wake of a weak trough passing through the region, Bespoke said. This includes in Texas, where an upper-level weakness could result in more rainfall for the next couple of weeks, “blunting heat attempts there, though keeping wind rather low in the process,” according to the forecaster.
“Toward mid-June, we suspect some heat expands eastward, though that is beyond the 15-day time frame for right now,” Bespoke said.
The bearish outlook keeps the threat of filling storage later this fall in play, with EBW Analytics Group projecting a string of triple-digit injections that could boost inventories by more than 350 Bcf over the next three weeks. Stocks as of May 15 were already at 2,503 Bcf, 779 Bcf above year-ago levels and 407 Bcf above the five-year average, according to the Energy Information Administration (EIA).
Tudor, Pickering, Holt & Co. (TPH) analysts said the EIA’s latest reported injection of 81 Bcf was “constructive” versus their 91 Bcf forecast as well as consensus of an 83 Bcf build. Looking ahead to the next report, the analysts see week/week demand down around 4.3 Bcf/d, driven by lower residential/commercial loads but partially offset by higher power burns as cooling demand begins to pick up.
“Thankfully, the supply side has come off meaningfully as well, preventing what could have been a very ugly storage print. EQT’s removal of 1.4 Bcf/d of supply from the market was the key piece, with Texas volumes also down around 1 Bcf/d week/week, contributing to an aggregate drop of about 2.6 Bcf/d.”
TPH’s preliminary estimate for the week ending May 22 is for a build of 100 Bcf.
However, weak global gas pricing and the knock-on impact on domestic LNG feed gas demand continues to be a major headwind for gas, the TPH team noted. Feed gas deliveries to U.S. terminals have remained soft throughout the week and sat Friday at around 5.5 Bcf/d. With expectations for around 30 cargoes canceled in June and speculation of 35-45 canceled cargoes for July, the TPH team said, “things are likely to get worse.
“We’re modeling 5.5 Bcf/d of feed gas demand in June, falling to 4.5 Bcfd in July. Arbs continue to weaken as European prices plummet in an attempt to price supply out of the market, as the Dutch Title Transfer Facility (TTF) price dipped to a U.S. equivalent of $1.23, a record low.”
EBW also noted the “stark” decline in TTF pricing. On Thursday alone, the TTF front month lost 13 cents (-9.2%), while day-ahead prices plunged 24%. Meanwhile, Asian Japan Korea Marker futures prices were similarly down to just above $2.00.
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“In Europe, physical storage constraints are coming into clearer view as storage builds, sending gas prices lower,” EBW said. “Globally, the closing of LNG export arbitrage is a price signal directing excess supplies to the U.S., the only location with significant storage capacity. As LNG export demand stumbles, however, Nymex futures are slipping, a pattern that may continue well into early summer.”
The start of the official Atlantic Hurricane Season is days away, and forecasters are warning that it could be an unusually active one. The National Oceanic and Atmospheric Administration’s (NOAA) Climate Prediction Center said the 2020 hurricane season is expected to produce 13-19 named storms, including six to 10 hurricanes, with up to six of them being major hurricanes, which are Category (Cat) 3 or higher.
The forecast dovetails with an earlier prognostication by AccuWeather meteorologists, who also expect an above-average season. NOAA is expected to update its outlook in August prior to the peak hurricane season.
Though storms don’t pack the same punch they once did on gas supplies, they now can have a more pronounced impact on the demand side. Genscape Inc. examined several hurricanes that have hit the Lower 48 in the past few years, highlighting the demand destruction brought on by each storm.
In 2016, Matthew hit land in South Carolina as a Cat 1 hurricane and dropped gas demand by around 1 Bcf/d, while Cat 4 Hurricane Irma made landfall a year later on the east coast of Florida, dropping power demand by 2.5 Bcf/d and causing an overall 10 Bcf impact on power demand over a seven-day period, the firm said. Hurricane Michael, the first Cat 5 hurricane to hit the contiguous United States since 1992, struck the Florida Panhandle in 2018 and cut power demand by up to 3.2 Bcf/d, with impacts lasting almost a week.
“As hurricanes hit further westward in the Gulf, they tend to affect more production and less demand relative to those making landfall further east,” said Genscape analyst Cory Madden.
Last year, Barry, a Cat 1, ran into Louisiana and cut 2.2 Bcf/d of offshore production at its peak. “This year, with LNG exports and production shut-ins at all-time highs, hurricane impacts should make for very dynamic market activity,” Madden said.
Much like futures, spot gas prices across the country traded both sides of even on Friday, as there is little change in the current weather pattern expected through the Memorial Day weekend.
NatGasWeather forecasts mild temperatures across the northern United States and only slightly cool weather in the Northwest. In fact, only Texas and the Southwest were expected to generate more demand over the next several days, with highs of 80s to 90s portending increased cooling demand, the firm said.
The holiday weekend effect took hold across most markets, with the sharpest declines seen in West Texas, although even those were not extreme. El Paso Permian prices for gas delivered through Tuesday averaged $1.435, down 11.5 cents day/day. Other markets across the Lone Star State shifted around a nickel or so lower on the day.
Similarly, small losses were seen throughout the Midcontinent and Midwest, while some points in Louisiana and the Southeast picked up a couple of cents. Transco Zone 5 spot gas climbed 2.5 cents to average $1.710 for gas delivered over the three-day period.
East Coast markets were up across the region amid relatively strong power burns amid the low gas price environment. Tennessee Zone 4 Marcellus jumped 5.5 cents to $1.160, while farther downstream, Transco Zone 6 non-NY picked up 1.0 cents to $1.285.
On the pipeline front, from Tuesday through Thursday (May 26-28), East Tennessee Pipeline is scheduled to conduct an outage on its Rural Retreat, VA, compressor, restricting capacity through the compressor and the Patriot and Roanoke Laterals.
However, Genscape analyst Josh Garcia noted that the restrictions are far above normal flows and as such were not expected to be impactful. “However, East Tennessee’s interconnect with Transco at Cascade Creek will have to net zero.”
East Tennessee has delivered as much as 150 MMcf/d to Transcontinental Gas Pipe Line (aka Transco) and received as much as 81 MMcf/d from Transco at this interconnect over the last 30 days, according to Genscape. If necessary, East Tennessee can source alternate supply from Tennessee Gas Pipeline, Texas Eastern Transmission or Southern Natural Gas Pipeline Co. much farther upstream, “and Transco has ample means of sourcing alternative supply,” Garcia said.
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