Woefully low prices in West Texas headlined natural gas spot price action during the week ended March 22, with generally mild temperatures resulting in small adjustments for much of the Lower 48; the NGI Weekly Spot Gas National Avg. tumbled 22.5 cents to $2.535/MMBtu.
The question of the week for West Texas spot prices might have been, “How low can they go?” Given a glut of production and a lack of pipeline capacity, the region has had the recipe for depressed prices for some time now. Toss in shoulder season conditions and a force majeure further restricting takeaway capacity out of the Permian Basin, and you get the negative prices recorded during the week.
Waha seemed to get the worst of it, even posting a negative daily average at one point. Waha’s weekly average plummeted $1.340 to just 19.5 cents. El Paso Permian similarly fell $1.210 to 35.5 cents.
The deep discounts in West Texas may have had some spillover impact outside of the Permian, as a few Rockies locations near the Colorado/New Mexico border traded lower compared to other points in the region. Transwestern San Juan dropped 89.0 cents on the week to $1.685.
Elsewhere, a spring storm late in the week along the East Coast had a limited impact on spot prices. On the week, Algonquin Citygate shed 6.0 cents to $3.030.
Meanwhile, natural gas futures capped off the week on a down note Friday, dropping to the bottom of the recent trading range amid an underwhelming demand outlook in the near-term. The April Nymex futures contract fell 6.8 cents to settle at $2.753 after trading as low as $2.721. Week/week the front month slid 3.3 cents after opening Monday at $2.786.
The selling Friday continued a general downtrend for natural gas going back to earlier in the week, Powerhouse Executive Vice President David Thompson told NGI. But the broader range from $2.75-2.90 that has contained price action for weeks ultimately held, with April settling right up against $2.75 support, he noted.
“This will be the big question over the weekend, to see whether $2.75 holds,” Thompson said.
Traders attempting to play the recent range might see prices at $2.75 as an opportunity to enter long positions, he said.
“If people are saying it’s this range from $2.75-2.90, and it’s just there until we get a better idea of summer demand,” then there could be traders ready to “buy at the bottom of the range,” Thompson said. “If you think the market is locked in the range, then that would be the trading strategy that some would employ.”
Despite Friday’s sell-off, the macro picture offers some encouraging signs for the bulls. Societe Generale said in a note to clients earlier in the week that it had shifted its stance on natural gas from “bearish/neutral” in 2019 to “neutral/bullish.” Why?
“Constructive weather this quarter has helped boost the 1Q2019 storage withdrawal pace to average nearly 5 Bcf/d stronger than 1Q2018, almost putting 1Q2019 in the top three withdrawal quarters in our history set (nearly tied with 1Q2015, behind only 1Q2013 and 1Q2014),” Societe analyst Breanne Dougherty wrote. “This stronger withdrawal pace to start 2019 has lowered the 2019 storage trajectory significantly.
“Furthermore, we see upside to our 2019 demand forecast tied to both power generation” and liquefied natural gas (LNG) exports, Dougherty said. “The bearish offset could of course be production outperformance, but we see this bearish risk as weighted heavily to November and December, which still leaves the next seven months vulnerable to tightened fundamental optics.”
Along similar lines, analysts with Jefferies LLC pegged end-season inventories at around 1.1 Tcf, which they said would count as the second lowest level in the last decade, trailing only the 0.8 Tcf in the ground in 2014.
“However, the supply/demand setup in 2014 was quite different versus 2019. Production grew rapidly through the summer, adding around 3.4 Bcf/d (plus 5%) of supply between and March and October to reach 70 Bcf/d for the first time, while demand over the same time period was up just around 1.1 Bcf/d year/year, which allowed storage to refill to around 3.5 Tcf by October 2014,” the Jefferies team said.
By contrast, in 2019 many gas-heavy exploration and production companies are slowing growth to generate free cash flow, Permian Basin associated gas growth could be limited until new takeaway comes online in the second half of the year, and current production levels lag below 2018 highs, the analysts said.
“On the demand side, year/year summer weather may be a tough comp, but LNG exports alone could add 2-3 Bcf/d year/year demand growth during refill season,” according to the Jefferies team. “While summer 2019 gas is trading near $3,” based on recent pricing along the 2020/2021 summer strips in the neighborhood of $2.65 “we continue to see more risk to the upside than the downside.”
The Energy Information Administration (EIA) on Thursday reported an on-target 47 Bcf weekly withdrawal from U.S. natural gas stocks, and the recently range-bound futures market found little reason for any sudden moves in response.
Thursday’s EIA report, covering the period ended March 15, also included a small bearish revision to the prior week’s data. Due to a 4 Bcf revision to South Central region nonsalt stocks, the net withdrawal for the week ended March 8 was actually 200 Bcf, not 204 Bcf as originally reported, EIA said.
As for the week ended March 15, the 47 Bcf withdrawal largely validated the market consensus leading up to the report, as major surveys and Intercontinental Exchange futures had landed on a pull in the 48-50 Bcf range. NGI’s model predicted a 44 Bcf withdrawal.
Last year, EIA recorded an 87 Bcf withdrawal, and the five-year average is a withdrawal of 56 Bcf.
During a discussion on energy-focused social media platform Enelyst, Genscape Inc. analyst Eric Fell described the 47 Bcf figure as “much looser” than the five-year average when factoring in weather-driven demand during the report period.
According to Fell’s calculations, “There were 14 more degree days than the five-year average, but the draw was lower than the five-year by 7 Bcf...Year-to-date stats have been loose versus weather by a little less than 2 Bcf/d. This is despite freeze-offs that have averaged close to 1 Bcf/d and hydro coming in near five-year minimums.”
While analysts see looseness in the market on a weather-adjusted basis, inventories remain at a deficit to historical norms. Total Lower 48 working gas in underground storage stood at 1,143 Bcf as of March 15, 315 Bcf (21.6%) below year-ago levels and 556 Bcf (32.7%) below the five-year average, according to EIA.
By region, the Midwest saw the largest pull week/week at 19 Bcf, while the East withdrew 17 Bcf. In the Mountain region, 4 Bcf was withdrawn, while 6 Bcf was pulled from Pacific stockpiles. In the South Central, EIA reported a net 2 Bcf withdrawal for the period, with a 6 Bcf injection into salt stocks offset by an 8 Bcf pull from nonsalt.
The 47 Bcf withdrawal for the week implies the market was 1.6 Bcf/d looser year/year adjusting for weather, according to analysts with Raymond James & Associates Inc. The Raymond James team said the market has averaged 2.7 Bcf/d looser year/year over the past four weeks.
Analysts with Tudor, Pickering, Holt & Co. (TPH) viewed the market as about 2.0 Bcf/d oversupplied for the report period, which they said is a shift the previous four weeks when the market was “slightly undersupplied.”
Meanwhile, heading into Friday’s trading, market observers appeared somewhat perplexed by a sharp and sudden nearly 10-cent drop in prices Thursday evening, when the April contract went from just above $2.810 to as low as $2.721 in a matter of minutes.
Thompson said the sharp drop late Thursday was odd, noting that it corresponded with an unusually large trading volume for the time of night. Generally, a market participant would avoid trading a large number of contracts during periods of low liquidity “if your goal is not to move price.”
Physical prices Friday pointed to difficult headwinds for sellers, as shoulder season temperatures served to limit buyer interest in three-day deals for most of the Lower 48.
NatGasWeather saw no major changes in the latest midday data Friday, describing the pattern for the two-week outlook period as neutral overall, showing near to slightly lighter than normal demand. The forecaster was looking for slightly stronger national demand Friday and into Saturday as a system bringing rain and snow was expected to exit the Northeast.
After a short break late in the weekend “across the Great Lakes and East, a chilly late season weather system will arrive Tuesday to Wednesday with lows of teens to 30s, and likely just cold enough to result in a small draw on the week instead of what once looked like the first build of the year,” NatGasWeather said. “A warm break is still expected across the Great Lakes and East” late in the upcoming week and into the weekend. Here the data has been “milder trending with highs of 60s to near 70 degrees, resulting in national demand dropping below normal.
“It remains active across the western and central U.S. with areas of showers, but relatively mild with highs of 40s to 60s. The southern U.S. will be exceptionally comfortable into the foreseeable future with highs of upper 60s to 80s for very light demand.”
A spring storm bringing heavy rains up the East Coast was expected to deliver snow across parts of the Northeast into the weekend, according to the National Weather Service.
The prospect of some heavy precipitation appeared to support higher spot prices at a few New England locations, although gains were modest. Algonquin Citygate added 8.5 cents to $3.035.
However, the broader trend across the Lower 48 Friday was decidedly downward. In the Midwest, Chicago Citygate shed 3.0 cents to $2.640. Down in Texas, Katy dropped 6.5 cents to $2.725. Benchmark Henry Hub fell 4.0 cents to $2.750.
Another factor negatively impacting demand Friday, Cheniere Energy Inc.’s Sabine Pass LNG terminal was reportedly seeing a decline in deliveries. Early Friday, Genscape Inc. said its infrared cameras detected a shutdown at Sabine’s Train 2.
“Genscape proprietary observations have historically been able to detect resumption of operations at U.S. LNG terminals ahead of nominations,” the firm said. A day earlier, Genscape reported a 617 MMcf/d day/day drop in pipeline deliveries to Sabine from the Kinder Morgan Louisiana and Creole Trail pipelines.
NGI’s U.S. LNG Export Tracker for Friday showed a day/day drop of 554,848 Dth/d in deliveries to domestic export facilities.
West Texas prices rebounded somewhat Friday on average, but a number of locations continued to post trades in the negatives. After posting a negative average Thursday, Waha picked up 30.0 cents on the day to finish back on the positive side of the ledger at 28.5 cents.
El Paso Natural Gas (EPNG) posted an update Friday on a force majeure event related to outages at two of its compressor stations in southern New Mexico, an event that has been linked to some of the recent downward pressure on West Texas prices.
EPNG said Unit 1C at its Lordsburg compressor is expected to return to service April 5, while Unit 1C at its Florida compressor is expected back online April 8.
“The available capacity through the L2000 constraint remains at 384,700 Dth/d pending the return to service” of the two compressor units, EPNG told shippers. That’s a 200,000 Dth/d drop in operational capacity through the L2000 constraint, the pipeline has said.
Analysts at Jefferies, pointing to recent Waha forward basis prices trading at a more than $2 discount to Nymex, said they “expect little relief on Waha basis until gas pipelines to the Gulf enter service in late 2019.”
TPH analysts offered a similarly bearish outlook on Permian natural gas prices Friday.
“Though near-term market concerns have faded on an expectation of less stringent flaring regulations, the dramatic swing in spot differentials highlights continued tightness in the Permian natural gas market,” the TPH team said.
“The updated U.S. production outlook sees little improvement for Permian natural gas takeaway dynamics as about 2.0 Bcf/d of annual residue gas growth maintains pressure on infrastructure despite greenfield capacity adds of 4.0 Bcf/d from Kinder Morgan’s Gulf Coast Express and Permian Highway projects over the next two years, indicating the natural gas problem (or midstream opportunity) isn’t going away soon.”