The losses continued for natural gas forward prices during the Sept. 10-16 period, with cooling weather and increasing storage concerns pouring salt in the wound left by the lingering shutdown of the Cameron liquefied natural gas (LNG) export terminal.
October natural gas fell an average 7.0 cents, while November tumbled a more substantial 14.0 cents on average, according to NGI’s Forward Look. Prices for the full winter strip (November-March) were down 8.0 cents, and a smaller decline of only 2.0 cents on average was seen for summer 2021.
“The natural gas market is currently pricing in a worst-case scenario for the return of Cameron LNG,” said EBW Analytics Group.
The restart timing of the Cameron LNG facility remains unclear since power first must be restored to the terminal following Hurricane Laura. Unlike most U.S. export facilities, Cameron relies on an outside utility for its power needs, rather than having on-site electric generation. Entergy Corp. has worked feverishly to get electricity back up and running to the hundreds of thousands of customers that had their power knocked out as the Category 4 storm crashed ashore Lake Charles, LA, on Aug. 27.
In a Wednesday update, the utility said power was made available to nearly 90% of the essential customers in southwest Louisiana that can safely accept it, including most hospitals and water and waste treatment plants. Once essential services are restored, Entergy then would prioritize work to restore the greatest number of customers at one time.
As of 3 p.m. Sept. 16, more than 56,000 customers have been restored in the Calcasieu and Cameron parishes, down from a peak of around 93,000 outages. Over the course of the storm and restoration, the company has restored 414,243 individual outages in Louisiana.
“The company anticipates that most customers in southwest Louisiana will receive service by Sept. 23, and the remaining customers who can safely accept power will be back on by Sept. 30,” Entergy said.
At a minimum, expectations are for the Cameron export facility to remain down through October, which would keep U.S. LNG capacity utilization around current levels, according to Tudor, Pickering, Holt & Co. (TPH) analysts. The TPH team pegs current U.S. LNG utilization at around 90%, averaging 7.4 Bcf/d this week, without any contribution from the roughly 2 Bcf/d Cameron facility.
“However, despite the extended Cameron outage, current feed gas demand is still exceeding our expectations for September, and current volumes are in line with our October forecast of 7.5 Bcf/d,” TPH analysts said. “Therefore, from a macro perspective, the extended outage has little impact on end-of-season storage balances, with potential bullish upside if Cameron resumes operations in early October.”
TPH’s end-of-season storage balance currently sits at 4.1 Tcf and the firm sees “little residual risk” around breaching capacity, which it said should result in front-month pricing lifting to take some of the $1/MMBtu contango out of the curve.
‘Enjoy The Show’
That theory, however, may be a bit more difficult to achieve after the latest round of government storage data.
The Energy Information Administration (EIA) on Thursday reported that inventories during the week ending Sept. 11 jumped by a whopping 89 Bcf, lifting total working gas in storage to 3,614 Bcf. This is 535 Bcf than year-ago storage levels and 421 Bcf above the five-year average.
Participants on The Desk’s online energy platform Enelyst were anticipating a high-side storage build, with estimates ahead of the report ranging from a 68 Bcf build to an 85 Bcf injection. NGI’s model predicted an 84 Bcf injection. However, analysts were stunned when the EIA figure hit the screen.
“This is the classic problem of natural gas: prices affect balance,” said NatGasWeather analyst Andrea Paltrinieri. “We needed LNG to avoid the catastrophe.”
Enelysts participants agreed that the front of the Nymex gas futures curve had been priced a bit too high in recent weeks. This has been evident in the sell-off over the past week that has occurred despite higher LNG feed gas demand coming from the Sabine Pass LNG terminal, which also had shut down ahead of Laura’s landfall.
“The bullish case for winter is still there, but I think we now see clearly why it was silly to allow the front to participate in the rally, taking October over $2.60,” said Bespoke Weather Services analyst Brian Lovern.
Regional storage balances were concerning to some analysts, especially in the South Central region, where a massive 33 Bcf was injected during the reference week, according to EIA. Nonsalts added 19 Bcf into storage, while salts added 14 Bcf.
“Now let the operational flow orders begin for long imbalances for a while,” said Huntsville Utilities natural gas scheduler Donnie Sharp.
Enelysts participants also noted the storms currently churning in the Gulf of Mexico. Though most were not expected to impact the U.S. onshore, the cooler temperatures resulting from the weather systems were seen lowering demand.
“There is nowhere to take gas with LNG off so much,” said one participant.
Enelyst Managing Director Het Shah agreed that it would be difficult to continue injecting with inventories sitting so high already. “Cash is going to get smoked in so many places.”
However, Genscape Inc. senior natural gas analyst Eric Fell said he believes that salt inventories would continue since spreads between the October Nymex contract and winter months are so wide. “They will inject until they get closer to 90%.”
Elsewhere across the Lower 48, Midwest inventories rose by 30 Bcf, according to the EIA, while East stocks grew by 20 Bcf. The Mountain region added 5 Bcf, and the Pacific added 2 Bcf.
“Storage containment doesn’t happen every year. Enjoy the show while it lasts, folks,” Fell said.
The October Nymex gas futures contract, which had fallen about 6.0 cents from Sept. 10-16 to reach $2.267, got whacked in a big way Thursday following the EIA storage report. The prompt month plummeted to an intraday low of $2.003 before going on to settle at $2.042, off 22.5 cents from Wednesday’s close.
Low Demand Portend Shut-Ins
As it stands now, weather models are showing a generally warm pattern in the northern half of the nation heading into the final third of the month, while the South is largely void of any heat relative to normal, according to Bespoke. At this point in the year, this becomes a “very low demand regime” by way of reduced early-season heating degrees days in the north and a lack of material cooling degree days in the South.
“This is still the type of pattern we expect to hold into October as well, keeping demand rather low as we head into the fall season,” Lovern said.
EBW analysts see cooling degree days falling to only 28 next week, but rising early-season heating demand could narrow demand losses to only 2.0 Bcf/d week/week. However, in the Northeast, the low-demand outlook could lead to more shut-in production, the firm said, adding to the 1.0-plus Bcf/d of publicly announced shut-ins by EQT Corp. and CNX Resources Corp.
“While the near-term weather may be priced into the market, the potential for additional shut-ins is not,” EBW analysts said. “Instead, should production appear to be falling, it could help lift Nymex futures contracts.”
Over the next month and a half, a more bullish sentiment should return to the market, according to EBW, with a strong likelihood of rising LNG demand, falling production and the market refocusing on the supportive winter storage trajectory. Cooler weather could further amplify any rally, “but there is a risk of low spot prices and persistent 2020 storage containment fears further deferring likely gains,” it said.
Northeast forward markets barely batted an eyelash at the newest round of supply cuts in Appalachia, with prices across the region and in downstream markets plunging in response to the mild fall outlook.
At Dominion South, the October and November contracts each dropped 18.0 cents from Sept. 10-16 to reach $1.018 and $1.902, respectively, according to Forward Look. Winter prices were off 8.0 cents on average to 2.570, while the summer 2021 strip was down 3.0 cents.
Texas Eastern M-3 October slid 17.0 cents to $1.176, November fell 20.0 cents to $2.391 and the full winter strip slid 11.0 cents to $4.060. Summer was down only 3.0 cents to $2.380.
Similar price patterns were seen on other pipelines across Appalachia.
In the Northeast, Transco Zone 6 non-NY October prices were down 20.0 cents from Sept. 10-16 to reach $1.100, and November was down 21.0 cents to $2.402, Forward Look showed. Winter pricing slipped 11.0 cents to $3.900, while summer 2021 lost 2.0 cents to hit $2.400.
During EQT’s second quarter earnings call in July, management noted that it had returned to sales the 1.4 Bcfe/d it took offline in May in response to the oil market downturn and Covid-19 pandemic. However, additional curtailments were possible, they said, though minimum volume commitments (MVC) it has on pipelines needed to be considered.
Based on Wood Mackenzie’s model, it seems that the MVC level, which would act as a “production floor,” is likely close to 3.1-3.2 Bcfe/d given that EQT’s production levels have never breached this threshold during the past two curtailment events.
“Dipping below that level, assuming it is their MVC, would spur additional costs and penalties, which is the opposite of EQT’s cost reduction mantra and would eat into some of the arbitrage” that management noted on the call, said Wood Mackenzie analyst Brandon Lee.
There doesn’t appear to be much improvement for in-basin pricing for October based on Tetco M3 forwards either, so it would make logical sense for EQT to bring these volumes back sometime in early November, Lee said, as Tetco M3 prices at that time are currently around $2.40.
“In the near term, EQT will likely need to revise their 2020 fiscal year production guidance lower during 3Q2020 earnings, but the strategy makes fiscal sense as they are able to reduce costs, specifically production/workover costs, in the weaker-priced shoulder season while increasing their molecules’ exposure to the more premium winter pricing,” Lee said.
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