Natural gas futures capped the week in positive territory, but the weight of bloating storage inventories and U.S. export concerns were on full display. The July Nymex gas futures contract hit a $1.763/MMBtu intraday low and traded in the red throughout most of Friday’s session before settling the day at $1.849, up 2.2 cents from Thursday’s close. August was up 2.1 cents to $1.940.
Spot gas, which traded Friday for gas delivery on Monday, continued to slide further. With losses becoming more pronounced than on Thursday, NGI’s Spot Gas National Avg. dropped 11.0 cents to $1.495.
Coming off two straight days of declines for futures, continued warming in the latest weather models snapped the losing streak at the start of Friday’s session. However, the momentum didn’t last as traders continued to digest the latest government storage data.
The Energy Information Administration (EIA) on Thursday said that inventories for the week ending May 22 grew by 109 Bcf, which essentially kept the surplus to year-ago levels intact but expanded the overhang to the five-year average by some 16 Bcf.
Genscape Inc. senior natural gas analyst Eric Fell, who had projected a 103 Bcf injection, said when compared to degree days and normal seasonality, the EIA figure appeared loose by around 1 Bcf/d versus the prior five-year average. However, the 109 Bcf injection was more than 7 Bcf/d tighter than the all-time record loose number from the storage week ending April 16, according to Genscape.
“Steep production declines are driving tighter supply/demand balances, with average weekly production down nearly 7 Bcf/d compared to the week of April 16 (86.2 Bcf/d versus 93 Bcf/d), and off nearly 3 Bcf/d week/week,” Fell said.
The rapid pace of production decreases have been driven by a combination of shut-in oil/associated gas, a curtailment of about 1 Bcf/d by EQT Corp. in the Northeast and structural declines driven by the accelerated reduction in rig counts/new well completions, according to the analyst.
West Texas Intermediate crude oil prices are now back above $30/bbl and “have rebounded back to levels where a number of producers have stated they would bring back shut in oil production; this suggests that we could see a quicker rebound in associated gas than many are currently assuming, including us.”
Tudor, Pickering, Holt & Co. (TPH) analysts agreed. The firm’s pipeline flow data has not yet show any “meaningful” return of associated volumes, but the team expects “a significant share of the estimated 2-3 Bcf/d currently shut-in could return in June.”
As for the EIA’s latest storage report, the TPH analysts said the 109 Bcf figure likely represented the floor on demand, which they peg at 77.5 Bcf/d, with gains from power expected to offset losses in the residential/commercial sector moving into summer. They expect at least one more 100-plus Bcf build, and potentially as many as three, before cooling demand tightens the market in late June.
Data for the May 26-29 work week, said TPH analysts, showed supply/demand balances “largely unchanged,” and they issued a preliminary estimate of an 106 Bcf injection for the next EIA report, which would be in line with the five-year average. From there, analysts see production and liquefied natural gas (LNG) utilization being the key variables to watch.
“LNG has surprised so far this week, recovering to an average of 6.2 Bcf/d (around 62% utilization), but we expect this will be short lived given June cancellations and maintenance at Cove Point, which is scheduled to begin next week,” said the TPH team.
The analysts could be correct. Bloomberg reported that a cargo reloaded in Belgium was expected to be delivered to Cheniere Energy Inc.’s Sabine Pass LNG terminal in Louisiana on June 12 for import. While Cheniere had not commented on the import, the cargo eventually could be reexported as it would end up in storage tanks and reduce the company’s liquefaction production requirements, according to one source familiar with the terminal’s operations. This would reduce the need to source feed gas from within the Lower 48.
Though LNG imports into the United States are not uncommon, they typically occur during the winter, often to supply the pipeline-constrained New England region. However, with U.S. gas prices tracking above global benchmarks, the economics make sense.
BTU Analytics LLC brought the issue of summer imports to light last week, noting that while spreads between international prices and Henry Hub may not move high enough to incentivize shipments from Australia or Qatar, they could convince shippers that are closer to take advantage of higher U.S. prices. Still, BTU analyst Connor McLean said summer imports “would be unexpected to say the least.”
Whether the United States takes in any additional cargoes throughout the summer is unclear, especially as European prices were tracking below Henry Hub through October, but Energy Aspects sees September as “an inflection point for cargo cancellations from U.S. facilities.”
This theory is predicated on the Japan Korea Marker (JKM) September contract now representing an open U.S. export arbitrage for companies that can consider their shipping costs as sunk. By September, the firm sees oil-indexed LNG potentially starting to compete with coal in South Korea, driving up the country’s aggregate demand for LNG.
“There will also be year/year LNG demand growth in Asian markets as they recover from lockdowns, given the affordability of the fuel,” said Energy Aspects analyst James Waddell. “U.S. and other cargo cancellations earlier in the summer should tighten the global balance.” September is also the point on the JKM curve when floating storage starts making commercial sense, according to Waddell, allowing U.S. exports to be loaded for delayed delivery. “The deferred delivery of long-term contract cargoes to Pacific buyers in 2H20 is a threat to JKM prices offering a U.S. export arbitrage.”
With no shortage of headwinds facing the futures market, prices remained firmly in the red for the bulk of Friday’s session. Even after the latest Baker Hughes Co. rig data was released, which showed the total U.S. rig count now down nearly 500 units since mid-March, the small bump was not enough to move the July contract into positive territory.
However, some aggressive buying emerged in the last half hour of trading, “perhaps with folks simply not wanting to go into the weekend short given that we are seeing demand creep back,” according to Bespoke Weather. The firm said that demand could get a boost if the hotter weather pattern sticks around as it suspects it will this summer.
“Data will be increasingly important moving forward,” said Bespoke. “We still need to see more tightening to lower the risk of filling storage.”
Spot gas prices continued to fall Friday as generally mild springtime weather conditions were expected to continue across the country. There were some exceptions, namely in the West, but the overall pattern remained “mostly comfortable,” according to NatGasWeather.
A cooler-trending weather system was on track to sweep across the Northeast late in the weekend, although it’s much too late in the season to drive any meaningful heating demand, the forecaster said. Meanwhile, upper high pressure is expected to strengthen over the central United States, the South and Southeast as the week progresses, resulting in warm highs of upper 80s to lower 90s. However, the northern and eastern part of the country “will be quite comfortable,” including the important corridor from Chicago to New York City, the firm said.
Given the lackluster weather demand, Northeast markets softened across the region, but most notably in New England, where Iroquois Zone 2 gas for Monday’s delivery plunged 27.0 cents to $1.300.
Farther upstream, the biggest mover in Appalachia was Tenn Zone 4 200L, which tumbled 15.5 cents to $1.350.
Cash markets across the Southeast were down between 10.0 and 20.0 cents, similar to the decreases seen across Louisiana. Prices across the Midcontinent and Midwest slipped mostly around 10.0 cents or so, while in Texas, Houston Ship Channel spot gas fell 13.5 cents to $1.605.
On the West Coast, SoCal Citygate cash plummeted 41.0 cents to $1.805 for Monday’s gas delivery despite a maintenance event getting underway Monday on Southern California Gas (SoCalGas) that is expected to disrupt about 150 MMcf/d of flowing supply at the California-Arizona border.
SoCalGas is performing planned maintenance on its L235-2, one of the lines that went down in a force majeure incident in the fall of 2017. Work on this line for the past two and a half years has cut SoCalGas import capacity considerably through its Northern Zone within the Needles/Topock Area Zone, according to Genscape.
“For most of 2018 and 2019, flows were limited to 270-300 MMcf/d, but capacity increased to around 450 MMcf/d this past November,” analyst Joseph Bernardi said. “Now, flows will again be limited to 270 MMcf/d for what SoCalGas plans to be a two-month maintenance event.”
Compensatory flows will likely come via the SoCalGas interconnect with the Kern and Mojave systems at Kramer Junction, according to Bernardi. Not only has SoCalGas posted that extra capacity will be available here during the period of changed flow dynamics during the L235-2 maintenance, but there also is recent evidence for Kramer Junction propping up the imports on the SoCalGas Northern Zone, the analyst said.
That could be why, despite the heat that’s suffocating the region, prices across the state dropped Friday.
Meanwhile, construction appeared on track for the El Paso Natural Gas (EPNG) South Mainline Expansion project to meet the target July 1 in-service date, according to Genscape analyst Colette Breshears. The latest construction report filed by the pipeline on May 19 showed compressor construction completion at more than 80% and pipeline work at 100% complete.
The project, which adds the Dragoon, NM, and Red Mountain, AZ, compressor stations, as well as a 17-mile pipeline loop in Texas, would increase throughput out of the Permian Basin along the EPNG mainline by 182 MDth/d.
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