An increasingly tight supply/demand picture that began emerging over the past week, in part from much chillier April outlooks, sent natural gas forwards surging during the April 2-7 period. May prices jumped an average 30 cents, and similarly stout double-digit gains were seen through the remainder of summer, according to NGI’s Forward Look.
Prices for next winter and the following summer also posted solid increases, with the momentum seen across the Lower 48 mirroring the behavior in futures trading over the five-day period. The Nymex strip has been on a tear since April 3 as weather outlooks for April trended colder and production growth started to show signs of slowing.
The May Nymex futures contract settled Tuesday at $1.852, up 30 cents from April 2. The balance of summer (May-October) jumped 23 cents to $2.06, and winter 2020-21 (November-March) climbed 9 cents to $2.69.
However, the latest government storage data pointed to an increasingly dismal backdrop for Lower 48 demand and quickly erased a large portion of the gains on Thursday. The Energy Information Administration (EIA) reported a 38 Bcf injection into natural gas storage inventories for the week ending April 3, coming in well above most estimates but besting NGI’s model by only 1 Bcf.
“Demand is getting killed,” said Genscape Inc. senior natural gas analyst Eric Fell, who had called for a 36 Bcf build.
Participating in The Desk’s online energy platform Enelyst.com, Fell said not all of the demand loss resulting from Covid-19 shutdown measures were being captured by flow data. “You’ve got to look past pipeline nominations, although it helps to have infrared monitors on refineries, ethylene crackers, etc.”
Bespoke Weather Services, which had estimated an 18 Bcf injection, said the actual figure provides “a clearer sign that the data we have is not indicating the proper amount of demand destruction that is ongoing with the shutdowns.
“This makes for two very bearish numbers in a row in terms of balances. Using the two-week average balance versus the five-year average shows end-of-season storage at an impossible 4.9 Tcf.”
Ahead of the EIA report, analysts had been predicting an injection between 9 Bcf and 35 Bcf. A Wall Street Journal poll of 12 analysts showed estimates averaging at a 21 Bcf build. A Bloomberg survey arrived at a median build of 24 Bcf, as did a Reuters survey. NGI’s model estimated the injection at 37 Bcf.
The EIA’s 38 Bcf injection compares with last year’s 25 Bcf increase in storage and the five-year average injection of 6 Bcf.
Broken down by region, the South Central region posted a 32 Bcf build, including a 22 Bcf injection into nonsalt facilities and a 9 Bcf build in salts, EIA said. The Pacific region added 6 Bcf, while East facilities held steady with 382 Bcf in inventory. The Midwest withdrew 1 Bcf.
Total working gas in storage as of April 3 stood at 2,024 Bcf, 876 above year-ago levels and 324 Bcf above the five-year average, according to EIA.
For now and the foreseeable future, the market likely will focus on whether a breach of 4 Tcf in storage inventories is likely at the end of October or in early November, according to Mobius Risk Group. From its perspective, eyes should first train on Eastern Canadian and Upper Midwest west storage capacity, as those two regions are likely to be the bellwether for how regional prices and, in turn, North American supply may respond to constrained operating conditions.
“Consider that an Appalachian shale well produces at more than twice the rate of an average U.S. shale well. If the market needs a large supply-side correction in a short period of time, that is how it is best achieved,” the Houston-based firm said.
Western Canadian producers are familiar with this dynamic as they often are the first supply basin to get crunched when North America is deemed to have “excess supply,” according to Mobius. “AECO spot prices and forwards have predominantly traded below $2.00 since early 2018, and the result has caused Western Canadian storage levels to dip back to five-year lows.”
Before the EIA delivered a gut punch to the market, it appeared that the coming cold front and the shape of the curve “could keep a strong tailwind behind near-term contracts,” according to Mobius. However, after a string of increasingly supportive weather forecasts, models finally started to trim demand from April outlooks.
The Global Forecast System lost a couple more heating degree days (HDD) overnight Wednesday, while the European model lost a heftier 11 HDD, NatGasWeather said. Overall, the forecaster said that weather data remained quite cold April 10-19 but was too mild April 20-23.
Also of important consideration, all U.S. natural gas markets were to close Friday for the Good Friday/Easter holiday, “leaving considerable risk of a gap up or down on the Sunday reopen,” NatGasWeather said.
Production figures were starting to show the impact of such low commodity prices, leading to frequent updates to forecasts. Genscape Inc. noted that daily production prints have been posting notable declines and while the firm can pinpoint “a good portion” of the drops to maintenance in certain regions, some of the declines are likely reactions to the rapid collapse of prices.
The firm’s top-day estimate of Lower 48 production on Wednesday showed a 1 Bcf/d-plus day/day drop, having sunk slightly below 91 Bcf/d. While the estimate was likely to get revised higher, “at the moment, it marks the lowest single day of production since early February, when freeze-offs whacked more than 1 Bcf/d offline,” Genscape senior natural gas analyst Rick Margolin said.
Genscape continues to adjust its production models as rigs have actualized substantially lower than the firm’s price-driven forecast had been guiding. The previous two weeks marked the largest observed percentage decline in rig counts since Genscape/Spring Rock began tracking.
“In our most recent weekly update to our production forecasts, we have further reduced our Calendar 2020 gas production outlook by an additional 0.6 Bcf/d versus our mid-March forecast,” Margolin said. “Cal 2021 has been reduced by more than 1.3 Bcf/d from our last forecast.”
Meanwhile, by most published accounts, Saudi-led OPEC and its allies were nearing an agreement to temporarily slash oil production by at least 10 million b/d, thereby ending the price war between Saudi Arabia and non-OPEC heavyweight Russia that has exacerbated the global supply glut since March 6, when the two countries last attempted, and failed, to agree on curtailing output.
A 10 million b/d cut, if true, “is a good first step, but it would still not be enough” to balance the market given the global oversupply of more than 20 million b/d expected for 2Q2020, Rystad Energy analysts said Thursday. They added that “the 10 million b/d figure alone would not make a material difference or reverse the deep contango curve of Brent prices in a meaningful or lasting way” if OPEC-plus cannot convince other major producers to commit to voluntary supply cuts.
Nonetheless, it could save global upstream operators “from a large number of forced production shut-ins over the next couple of months, buying the currently broken oil market precious needed time to adjust to ‘the new normal,’” the Rystad team said.
Tudor, Pickering, Holt & Co. maintains the view that demand will likely dictate near-term pricing, and “supply reductions may ultimately have to match run cuts from a refining standpoint as tank tops start to fill.
“This, to some degree, will help mitigate part of the pressure on physical storage, but it’s important to note that production for the most part will not be structurally lost and as prices recover, we would expect producers to bring back on volumes, somewhat reversing the steep second quarter supply declines.”
With longer-dated tenors along the Nymex gas futures curve sitting around the $2.40 mark through 2025, producers still face the lowest five-year strip in the shale era, according to Mobius. Although the risk factors of weather, Covid-19 and U.S. crude market recovery stand as “wild cards” impacting the balance of the year and 2021 strip, the firm said that natural gas consumers would be wise to consider the prospect of being able to take out winter exposure at less than full-cycle breakevens for most producing basins. Alternatively, collaring exposure with a floor price near $2.00 and ceiling at less than $3.50 could be another attractive solution.
“However, the yin and yang of producer/consumer sentiment has both camps in a conundrum,” Mobius said. “Does the producer accelerate volumetric growth into the peak part of the natural gas curve (2021)? And does the consumer finally get rewarded for looking out to deeper discounts in long-dated tenors?
Another unknown looming over the natural gas market is whether U.S. exports could shut in during the coming months because of the unprecedented slaughtering of demand related to the Covid-19 pandemic. Although China reportedly has granted tax waivers for U.S. liquefied natural gas (LNG) imports and several tankers carrying domestic supplies reportedly were heading for Tianjin, it remained unclear whether the cargoes ultimately would land there as deliveries were not expected until late April or early May.
Markets from coast to coast mounted hefty gains at the front of the forward curve during the April 2-7 period, largely driven by the tighter supply/demand picture. Stronger cash prices because of strong power burns also provided some uplift to forward prices across the country.
Markets out West also strengthened, although increases were a little less pronounced amid more widespread use of renewable energy to meet demand. SoCal Citygate May rose 20 cents from April 2-7 to reach 1.814, while the balance of summer picked up 5 cents to hit $2.51. Nex winter also climbed 5 cents to reach $3.76, while prices for next summer were down 4 cents to $2.90, according to Forward Look.
Meanwhile, an El Paso Natural Gas force majeure set to begin April 14 could affect 559 MMcf/d of westbound flow to Arizona and potentially hamper delivered volumes to Southern California Gas, according to Genscape. Pipeline anomalies discovered downstream of its Cimarron compressor station during routine maintenance require a segment of Line 2000 to be isolated, cutting flows through the Tom Mix compressor station in southeast Arizona to zero, from a prior 30-day average of 559 MMcf/d.
Elsewhere throughout the Lower 48, forward curves in the Midcontinent and downstream of the producing region brushed off some pipeline maintenance occurring over the next couple of weeks. Natural Gas Pipeline Co. of America (NGPL) declared a force majeure that was set to last through April 18 that was affecting flows through Station 105 in Cloud County, KS, and constraining 450 MMcf/d of the entire Amarillo mainline available capacity.
This event falls in between other large-impact tool runs that NGPL began performing on April 1 and are scheduled to last through mid-month, according to Genscape analyst Matthew McDowell. However, “similar events that cut Amarillo mainline capacity have shown that NGPL’s Gulf Coast mainline can compensate for increased market area demand, and Chicago Citygate basis volatility has been muted during recent demand events and supply constrictions due to a diverse supply side.”
Chicago Citygate May prices were up 31 cents from April 2-7, while the balance of summer rose 24 cents to $1.84. Winter climbed 9 cents to $2.72, and next summer moved up 3 cents to $2.23, Forward Look data showed.