Just when the natural gas market had all but written off any prospects for significant early-season cold, weather models made an abrupt shift over the weekend, signaling more intense, frigid air for the United States over the next two weeks. Some of the sharpest gains over a two-day span sent December and January prices up more than 20 cents on average for the Oct. 24-30 period, according to NGI’s Forward Look.
The majority of markets across the country followed in line with Nymex futures, which surged nearly 15 cents on Monday as weather models trended colder for the coming weekend and next week. The gains occurred in the face of another new production high and added to the typical volatility that arises ahead of futures contract expiration.
The November Nymex contract rolled off the board Tuesday at $2.597, up about 28 cents from Oct. 24. The December contract jumped about 22.5 cents to $2.691, and the balance of winter (December-March) shot up around 20 cents to $2.702.
“The November natural gas contact ripped higher into final settlement, posting two of the three largest daily gains in 2019,” EBW Analytics Group said. “Back-to-back gains of 14.6 cents on Monday and 15.1 cents on Tuesday carried the November contract 29.7 cents higher into expiration early this week, decisively swinging momentum in favor of bulls.”
The rapid price escalation is a sign that winter has arrived in the natural gas market. Weather models continue to move colder and any hint of getting out of the cold regime just keeps getting pushed back further out in time. This is keeping confidence low for Bespoke Weather Services, which said that although both the American and European weather models tease a possible change in pattern at the very end of their outlooks, “until it progresses forward in the forecast, it is not going to be trusted.
“Our read on the pattern signals does suggest it happens, but the delay and the stronger cold in front of it has been the dominating theme since last week. Strongest cold remains in the central United States more often than not, but penetrates into the East and South enough to keep demand above normal there as well.”
With a solid two weeks of above-normal demand, the latest government storage data may have signaled the last significant injection of the refill season. The Energy Information Administration (EIA) reported an 89 Bcf injection into storage inventories for the week ending Oct. 25.
The reported build was on the high end of expectations and easily surpassed both last year’s 49 Bcf injection and the 65 Bcf five-year average. Ahead of the report, estimates ranged widely from a 66 Bcf injection to a 94 Bcf injection, although most projections clustered around a mid-80 Bcf build.
“Things are starting to get interesting now that winter is here,” said Het Shah, managing director of industry chat platform Enelyst.com.
Shah pointed to pipeline freeze-offs that are already occurring as much of the central United States is blanketed by Arctic air. That is “even more important now that we have a ton of wet gas.”
Residential/commercial demand is also soaring, and liquefied natural gas feed gas deliveries also have continued to come in near record highs, he said.
Broken down by region, the South Central added 44 Bcf into storage stocks, including a 25 Bcf build into salt facilities and a 19 Bcf injection into nonsalts, according to EIA. Midwest inventories grew by 26 Bcf, while East stocks rose by 15 Bcf.
Total working gas in storage as of Oct. 25 was 3,695 Bcf, 559 Bcf above last year and 52 Bcf above the five-year average, EIA said.
The next two storage weeks, ending Nov. 7 and Nov. 14, are expected to yield around 40 gas-heating degree days and more than 50 Bcf of above-normal demand, according to EBW.
“Fundamentally, this incremental demand creates a bullish 51 Bcf decline in the year/year storage surplus over the two storage weeks,” the firm said. “Psychologically, it can help reset market expectations and increase bullish hopes for a cold winter ahead.”
However, storage inventories could continue to swell regardless, according to Goldman Sachs. U.S. gas production has grown on average 1.6 Bcf/d since Oct. 18 versus Oct. 1-17, with most of that growth driven by Appalachia.
“We believe this jump may have been driven by an attempt to allocate production growth in the winter period, which presents the best upside potential for prices, especially given the context of a very well-supplied summer expected next year,” Goldman Sachs analysts said.
As a result, they now see year-end Appalachia production 1 Bcf/d higher than previous expectations, which ultimately increases the firm’s overall Lower 48 production expectations for winter 2019-2020 and Calendar Year 2020 by 1 Bcf/d and 420 MMcf/d, respectively. This revised forecast also now includes more seasonality to the expected Appalachia production path, with higher levels in winter months and lower levels in summer.
Interestingly, the impact of the colder forecasts on prices has extended beyond winter contracts, with the whole Nymex gas forward curve having moved higher, likely exacerbated by the extreme short positioning seen in the market in recent weeks, according to Goldman Sachs.
These net-loosening revisions to its balance reinforce its view that Cal2020 and Cal2021 Nymex gas prices need to remain low to disincentivize Appalachia production growth to keep inventories manageable. Accordingly, the firm maintains its Cal2020 and Cal2021 price forecast at $2.50, in line with current forward prices at $2.50 and $2.47, respectively.
Several producers throughout Appalachia have already reduced spending and could make further cuts given the generally bearish outlook for natural gas. EQT Corp. on Thursday indicated it would slash capital expenditures by approximately $525 million in 2020 as its new management team aims to transform the company into “a modern, digitally-enabled, efficient and values-driven natural gas producer.”
Super independent Apache Corp. cited the low oil and gas price environment in its decision to drop rigs in the Alpine High prospect of the Permian Basin and defer some fourth-quarter completions into 2020. “These changes, combined with a reduced production outlook for a recent multi-well pad, has resulted in a 5% decrease in fourth quarter Alpine High production guidance,” CEO John Christmann said.
It’s still early in the third quarter earnings season, and 2020 budgets are still being ironed out. However, during times of low/falling prices, producers have traditionally found themselves in the classic game theory scenario called the “Prisoner’s Dilemma,” NGI’s market analyst Nate Harrison said.
The purpose of the game is to illustrate that when the two prisoners act in mutual self interest, neither achieves the optimum outcome, he explained. However, since they aren’t able to cooperate, the choice they make is always one of self-interest.
“Similarly, during times of low prices, producers need to decide whether to cut back production, or to continue to produce,” Harrison said. “The optimal solution would be that all producers cut back and achieve the increased prices and hopefully return on investment (ROI) brought on by the reduction in supply. However, since a given producer cannot expect such cooperation from its peers, it usually chooses to act in its own self-interest and continue to produce, even if the prices are low.”
While some would argue that producers are far more focused on ROI, and that capital discipline is now the name of the game, “ultimately, these producers will be judged by how they perform against their peer group or benchmark index,” Harrison said.
While most forwards markets across the United States posted solid gains across the curve during the Oct. 24-30 period, pricing hubs in the Rockies and California posted much smaller increases as storage inventories appear relatively healthy and the threat from long-standing maintenance constraints has decreased in recent weeks.
In Southern California, the return of both L235-2 and L4000 at reduced pressure last week after months of delays indicated that winter supply straits might be less dire than previously expected, according to Genscape Inc. Since that announcement on Oct. 22, SoCal Citygate basis prices for winter 2019-2020 have dropped during each consecutive trading day, moving from $1.26 down to $1.05 per NGI data.
As for fixed prices, SoCal Citygate December sat Wednesday at $4.067 after holding steady throughout the week, according to Forward Look. January rose just 2 cents to $4.031 and the balance of winter (December-March) tacked on 4 cents to $2.687. Summer prices were up 2 cents to $2.66.
The California Public Utility Commission’s withdrawal rules for Aliso Canyon are also intended to make it easier to withdraw from that storage field this winter than in previous years, Genscape said. Meanwhile, total Southern California Gas storage inventory levels are within 3 Bcf of their highest beginning-of-winter level since the Aliso Canyon leak was discovered in October 2015.
“Only 2018’s end-of-October inventory was higher than the current mark, with 2016 and 2017 levels both well below that,” Genscape natural gas analyst Joseph Bernardi said.
In the Rockies, Northwest Sumas was the lone pricing hub across North American to post a loss at the front of the curve. December plunged 24 cents from Oct. 24-30 to reach $3.571, while January tumbled 20 cents to $3.445. The balance of winter was down 9 cents to $3.142, but next summer was up a penny to $1.71, Forward Look data show.
The dramatic declines follow an Oct. 24 notice by Westcoast Transmission that showed its southbound flow ramping up considerably in November. Northwest Pipeline’s (NWPL) Jackson Prairie storage inventory is at its normal, full, beginning-of-winter level, just above 24 Bcf, according to Genscape.
“Earlier this summer, these inventories increased rapidly, setting multi-year records for inventory through the summer. NWPL was also able to complete planned maintenance that required a shut-in of the facility for two and a half weeks starting on Oct. 1,” Bernardi said.
On the flip side, Permian Basin prices bounced back with a vengeance after coming under intense pressure from pipeline constraints following the quick filling of Gulf Coast Express. After falling to around $1.12 on Oct. 23, the El Paso Permian December contract shot up 44 cents to reach $1.683 as of Wednesday, according to Forward Look. January jumped 36 cents to $1.911, while the balance of winter picked up 33 cents to hit $1.587. Summer prices averaged just 83 cents despite picking up 14 cents.
In the Northeast, New England pricing hubs posted substantial increases across the curve amid scheduled pipeline work in the region. Algonquin Citygate December shot up 50 cents to $6.627, and January rose 38 cents to $8.916. The balance of winter finished the week 40 cents higher at $7.426, and Summer 2020 was 9 cents higher at $2.45.
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