- April Nymex futures settle at $2.755, up 0.2 cents; May up 0.7 cents to $2.774
- “Natural gas pricing is positioned to open the week on shaky footing as flow data shows LNG feed gas down about 1.5 Bcf/d, while production is up about 1.0 Bcf/d”: TPH
- Region-wide negative average spot prices in West Texas
- “I’ve never seen wholesale price negativity like this before,” says NGI’s Rau
Natural gas futures finished close to even Monday as traders mulled looser balances on the one hand and a supportive storage deficit on the other. In the spot market, West Texas discounts shattered historical precedent as prices averaged well into negatives region-wide; the NGI Spot Gas National Avg. climbed 1.5 cents to $2.445/MMBtu.
The April Nymex futures contract -- set to expire Wednesday -- settled 0.2 cents higher at $2.755. The May contract settled at $2.774, up 0.7 cents after trading as low as $2.720 and as high as $2.786. Further along the strip, June settled at $2.825, up 0.4 cents.
After a major test -- the front month went as low as $2.706 Monday morning -- the April contract ultimately finished just above the lower boundary of the roughly $2.750-$2.900 range that has contained the market over the past month.
Bespoke Weather Services said storage deficits and colder trends from recent model runs provided support as prices were able to rebound from the early sell-off Monday
“Heading into expiry, we feel that prompt month prices likely remain stuck in the $2.70-2.80 range given the battle we have between the downward pressure of weak balances and support offered by the storage deficit, combined with a weather pattern that, while not all that cold, is not decidedly bearish compared to normal,” Bespoke said.
Selling early Monday accompanied analyst reports on looser balances in the market, including a recent drop-off in liquefied natural gas (LNG) export demand and an uptick in production.
“Natural gas pricing is positioned to open the week on shaky footing as flow data shows LNG feed gas down about 1.5 Bcf/d, while production is up about 1.0 Bcf/d,” analysts with Tudor, Pickering, Holt & Co. (TPH) said in a note to clients Monday.
The TPH team said the drop in LNG feed gas demand appears driven by a reduction in flows to Cheniere Energy Inc.’s Sabine Pass LNG terminal, adding that some volatility is expected with ongoing commissioning activities for Sabine’s Train 5.
“Working against LNG at the moment is extremely weak global pricing, with Asian markets falling to sub-$5 pricing. If pricing remains weak there is potential for extended maintenance to occur over the summer and/or a delayed ramp up of new projects scheduled to come online,” according to TPH. “With LNG shouldering the bulk of U.S. demand growth this year, softness in the global market could prove to be a headwind for U.S. gas pricing.”
On the supply side, associated gas out of Texas, the Midcontinent and the Rockies appears to be driving gains in production heading into the week, according to TPH.
Genscape Inc. similarly pointed to weak pricing overseas to help explain the drop in deliveries to Sabine Pass. Pipeline deliveries to the terminal as of early Monday remained down 2.4 Bcf/d, according to the firm.
“Genscape’s LNG team has been alerting clients of the possibility the shutdowns might be one of the terminal’s first demonstrations of reacting to weak economics,” senior natural gas analyst Rick Margolin said. “In recent weeks, Asian and European LNG prices have plummeted below the $5 mark, which -- when factoring in transport costs -- appears to put shipments from the U.S. out of the money.
“In addition, the shutdown comes without any known planned maintenance on upstream pipelines,” although he noted that Creole Trail has a planned maintenance for Monday, “but the declines started last week when nominations fell before our proprietary observations detected physical shutdowns.”
Turning to the spot market, after some modest gains in the region Friday, West Texas physical prices plunged to new lows Monday. Nearly every location NGI reports in the region posted a negative average, and by some margin.
The entire West Texas region on average traded at negative 43.0 cents on the day. Waha averaged negative 64.0 cents after dropping 92.5 cents day/day. El Paso Permian plunged 53.0 cents to negative 31.5 cents. Transwestern tumbled 99.0 cents to average negative 56.5 cents on the day.
Associated gas growth has outpaced the available takeaway capacity in the Permian Basin, leaving some producers in the crude-focused play willing to pay to unload their gas.
An ongoing force majeure on El Paso Natural Gas (EPNG) in southern New Mexico, impacting westbound flows through its L2000 constraint, appears to have exacerbated the congestion. The affected units at EPNG’s Lordsburg and Florida compressors are expected back online early next month, according to the pipeline.
In the recent past, other producing regions have seen supply gluts and pipeline constraints crush prices. Just last year, in Western Canada producers selling into NOVA/AECO C had to deal with negative prices. According to Daily GPI historical data, NOVA/AECO C averaged negative C1 cent/GJ for the May 4, 2018, trade date after going as low as negative C13 cents. Before that, prices at the location traded as low as negative C29 cents during the Sept. 26, 2017, trade date.
While stronger basis in the Marcellus/Utica shale region more recently suggests the pipeline buildout has started to catch up with output there, Appalachian producers for years saw crushing basis differentials as the midstream sector rushed to keep up with the basin’s burgeoning output. On Sept. 30, 2016, NGI’s Dominion South index averaged just 29 cents and saw trades as low as 10 cents.
But these past examples don’t compare to the extreme discounts recorded in West Texas in recent months -- and especially Monday. It was already an unprecedented situation in terms of the willingness West Texas sellers have shown to withstand negative pricing. NGI has recorded negative West Texas spot prices on various occasions going back to last year. But even with that in mind, Monday marked a new nadir for Permian natural gas discounts.
“I’ve never seen wholesale price negativity like this before,” said NGI’s Patrick Rau, director of strategy and research. “Prices got down to a quarter of a cent in the Marcellus once, and were certainly depressed for long stretches of time, but I don’t recall those ever going negative. Even within Appalachia, there were certain pockets of relative price strength. But in West Texas, outside of the El Paso-Plains Pool, it’s pretty bad.
“AECO has gone negative a few times, and has also suffered from relatively weaker prices for long stretches, but not like we are seeing in the Permian.”
That Permian producers aren’t drilling for gas in the first place likely helps explain their tolerance for negative prices.
“The Permian is driven almost entirely by liquids pricing, mainly crude oil, and natural gas is the associated (and oftentimes unwanted) byproduct,” Rau said. “You can’t just flare it all, so if you want to produce the oil, you’ve got to produce the gas. And producers are wanting to produce more oil now that both absolute and relative crude prices in the Permian are higher than they were in the latter stages of 2018. Both the absolute price of WTI and the relative price (Midland Cushing spread) have increased since late 2018.”
Even after deducting the costs of negative natural gas prices, recent crude prices likely leave many Permian producers in the money, according to Rau.
“Permian producers are now receiving mid to upper $50s/bbl for their in-basin production. If they have to sell gas at, say, negative $2.00, that’s $12 on a crude oil equivalent basis, which would make the net proceeds of their oil closer to the $40-45 range,” he said. “But that is still in the money for many Permian producers, as a significant portion of that acreage has breakeven prices below $40. My guess is Permian natural gas prices probably cannot get significantly more negative before they start reaching a pain point on the realized crude oil sales price.
“It’ll be interesting to see if utilities and the like start to scoop up this gas and put it into storage at an increased pace. This might set up the South Central storage region to replenish storage much more quickly than normal, everything else being equal.”
Outside of West Texas, physical prices in the Gulf Coast, Southeast, Midwest and Midcontinent generally saw moderate day/day adjustments, with shoulder season conditions taking hold for much of the Lower 48.
“A chilly late-season weather system will sweep across the northeastern U.S. Tuesday to Wednesday with lows in the teens to 30s for a minor surge in national demand,” NatGasWeather said. “A warm break remains on track to build across the East Thursday through Saturday, with highs reaching the 50s and 60s over the Northeast and 70s and 80s over the Mid-Atlantic coast and Southeast for a swing back to lighter national demand.”
Prices in the Northeast saw modest gains as forecasters called for spring chills in the region. Tenn Zone 6 200L jumped 35.5 cents to $3.380, while Iroquois, Waddington added 12.0 cents to $2.950. Further upstream, Texas Eastern M-3, Delivery gained 3.5 cents to $2.700.
From Tuesday through Thursday (March 26-28), cleaner runs on Texas Eastern Transmission’s (Tetco) 36-inch diameter Line 27 between the Bechtelsville and Lambertville stations are expected to impact about 730 MMcf/d of capacity in the pipeline’s M3 zone, according to Genscape analyst Josh Garcia.
“These cleaner runs will limit capacity through Bechtelsville to 2,230 MMcf/d for the duration of the run, 735 MMcf/d below normal levels,” Garcia said. “Although flows through the location have only averaged 1,840 MMcf/d over the last two weeks due to abnormally warm weather in the Northeast, there is potential for bullish pressure on M3 cash prices during this event.
“Current flows are right at the maintenance operating capacity, and pending forecast revisions, Northeast temperatures are expected to be much colder than average on March 26 and 27,” the analyst said. “...Last week’s Bechtelsville maintenance did not materialize, but this event is more likely to go through, as the previous one was only tentatively scheduled.”
“Bearish headwinds for summer gas burns in California continue building as snowpack levels in the Sierras continue climbing,” Genscape’s Margolin said. “As of last Thursday, California statewide average snowpack is up 156% of normal for this date. Current snowpack levels are at their second highest for this time of year in the past 10, trailing only Spring 2017.
“In the summer following the record-high Spring 2017 snowpack, hydro generation topped 92 average GWh/d, while gas burns dropped 17% below the prior five-year average, resulting in an estimated 390 MMcf/d of lower gas demand.”