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Volatility Returns as Natural Gas Prices Soar During December Bidweek

It was a month of extremes for natural gas markets in November, featuring surging futures and negative spot trades in West Texas as early heating season cold brought volatility back with a vengeance; the NGI Bidweek National Avg. rocketed $1.955 higher to $5.14/MMBtu.

The early heating season gains also put the natural gas markets nearly $2 ahead of last year’s prices, as the December 2017 bidweek average was just $3.12.

After months of mostly range-bound trading where record-level production suppressed futures prices despite large storage deficits, volatility returned to the natural gas markets in a big way during the month of November. The December Nymex contract settled at $3.187 on Oct. 30 only to explode during the first two weeks of November as the first waves of legitimate winter cold hit the Lower 48.

The December contract surged as high as $4.929 on Nov. 14 as anxieties over historically lean stockpiles brought a wave of bullish momentum that caught some by surprise and created a jumpy market where double-digit price moves were a near-daily occurrence for the winter strip.

The big price swings continued during bidweek, including a 45.3-cent surge that saw the December contract roll off the board at $4.715, well above the November contract expiry at $3.185.

The severity of the recent price swings is not surprising, according to EBW Analytics Group CEO Andy Weissman, who pointed to the “potential for wildly different price outcomes this winter depending upon weather.”

Forecasts showing milder trends towards mid-December could drive prices lower, he said.

“However, recent extreme price spikes are bringing additional buyers into the futures market, intent on hedging upside price risk,” according to Weissman. “Further, with storage at multi-year lows,” local distribution companies “are aggressively buying gas in the cash market to avoid further depleting storage this early in the season, pushing cash prices higher. Absent a major further warmer forecast shift, this should sustain support for the January contract at $4.29 or above.”

The strength in day-ahead and futures markets spilled into December bidweek trading, where locations throughout the Lower 48 recorded month/month (m/m) gains of $1.50 or more.

Import-constrained and populated Northeast markets tacked on even larger winter premiums during December bidweek, with Algonquin Citygate jumping $6.885 to $10.57, while Transco Zone 6 NY added $3.530 to $6.72. Further upstream in Appalachia, Dominion South averaged $4.315, up $1.530 m/m.

Storage operators in the Northeast appear to be feeling the pressure created by inventory deficits and have been working to manage balances.

Citing “current and anticipated system conditions,” Dominion Energy Transmission Inc. in a notice last week advised shippers to “monitor contractual storage entitlements” and take steps to reduce any imbalances on the operator’s system.

“Capability for over-withdrawals, short-term loans and park payback activity are expected to be very limited or possibly not available,” Dominion said. These actions could be “subject to allocation or potential penalties if warranted” by an operation flow order.

Columbia Gas Transmission LLC, another major regional storage operator, declared “storage critical days” and imposed penalties for over-withdrawals for certain market areas on Nov. 22 and Nov. 23, citing “weather forecasts, storage levels and increased markets.”

Total Lower 48 working gas in underground storage stood at 3,054 Bcf as of Nov. 23, according to the Energy Information Administration (EIA), down 644 Bcf (17.4%) from a year-ago and 720 Bcf (19.1%) below the five-year average.

Analysts with Tudor, Pickering, Holt & Co. (TPH) said the EIA data for the week ended Nov. 23 indicated the market was about 3.5 Bcf/d oversupplied.

“Though we believe the natural gas market will remain materially oversupplied over the short-term (and medium-term), the past few weeks have illustrated demand’s sensitivity to weather,” the TPH team told clients last week. On the other hand, “supply continues to be robust, as U.S. dry production was reported as roughly 88.4 Bcf/d, or about 1.5 Bcf/d higher than two weeks ago.”

The reported 59 Bcf withdrawal for the week ended Nov. 23 missed well to the bearish side of expectations after a 134 Bcf withdrawal the week before offered a bullish surprise.

Bespoke Weather Services said the bearish pull for the week ended Nov. 23 may have reflected “holiday demand destruction that was under-forecast, and accordingly it is difficult to read all that much into it and declare the market as structurally much looser.

“However, we clearly see the importance of non-linear demand increases in significant periods of cold weather. Storage levels are low enough to still keep a bid at the front of the natural gas strip moving forward and keep us extremely sensitive to any colder forecast revisions, but outside of cold the market does seem loose enough to ease storage concerns some.”

Genscape Inc. analysts Margaret Jones and Eric Fell said the 59 Bcf pull for the week ended Nov. 23 indicates the market was about 4.0 Bcf/d loose versus the five-year average when compared to degree days and normal seasonality. Power generation trends for the week also presented “clear evidence” of gas to coal switching as coal reclaimed a larger share of the power stack, according to the analysts.

Strong physical market prices for the week helped to “push gas from around 55% of thermal generation down to about 50%,” contributing to an estimated 5.4 Bcf/d less gas burn week/week (w/w).

On the supply side, Genscape’s SpringRock daily production estimates as of Friday showed yet another daily record high, with output topping the 87 Bcf/d mark, according to senior natural gas analyst Rick Margolin.

The top-day estimate for Friday was more than 1.22 Bcf/d above the prior week’s average, Margolin said.

“Texas volumes are up around 0.64 Bcf/d on a surge in intrastate interconnect receipts,” while Gulf of Mexico output was showing a 0.35 Bcf/d increase, he said. “Northeast production is up an estimated 0.31 Bcf/d, driven primarily by increased receipts in Northeast Pennsylvania, with Tennessee Gas Pipeline and Transco posting increases of 0.15 Bcf/d and 0.13 Bcf/d respectively.”

Estimates for Permian Basin receipts were also higher w/w by 0.16 Bcf/d, according to Margolin.

It was a glut of gas output from the crude-focused Permian, coupled with limited pipeline takeaway options, that sent West Texas prices plummeting during bidweek even as physical prices soared in other regions. In fact, NGI recorded a handful of zero and negative day-ahead deals in the region late in November -- a first for the United States.

The severe constraints that have left some West Texas sellers willing to pay to get their gas out of the region could last months as the infrastructure buildout catches up with production, according to analysts.

December bidweek action suggests West Texas traders locked in their deals with the expectation that pricing in the region wouldn’t improve any time soon. Waha fell $1.29 m/m to average a measly 16 cents, including trades as low as negative 60 cents. El Paso Permian fared somewhat better, averaging $1.30, including trades as low as 30 cents.

“As the Permian crude oil pipeline build-out has been ‘pulled forward,’ associated gas production is also arriving sooner rather than later...likely the impetus for the recent decline in Permian gas prices,” wrote Raymond James & Associates Inc. analysts led by J.R. Weston and Justin Jenkins.

From 2017-2020, the Raymond James team is forecasting as much as 6 Bcf/d of Permian gas growth, nearly doubling output in three years. That means gas pricing likely will stay lower for longer, a view of many analysts.

Moving gas to western markets, and eventually to California, is competing with renewables. Gas moving north competes with Rockies/Midcontinent supply. Neither of those outlets are “tremendous options” for Permian exploration and production companies, Jenkins and Weston said.

“Putting it simply, because many of these outlets lead to suboptimal gas markets, this means these pipes don't help regional pricing all that much...Our best guess is that Waha prices ‘zipper’ modestly up and right back down with each brownfield pipeline expansion coming online (followed by production gains) in 2018-19.” Smaller capacity additions should provide a bridge until the 2 Bcf/d Gulf Coast Express comes online late next year, followed by other big pipelines into 2020 and beyond.

Further west in Southern California, the volatile SoCal Citygate averaged $13.850, surging $8.030 m/m amid upside risks from ongoing limitations on pipeline imports and restrictions on storage capacity.

SoCal Citygate, already posting substantially higher and more volatile prices so far this winter compared to last year, was set up for even more volatility heading into the first week of December, according to Genscape analyst Joe Bernardi.

Regional demand, including Southern California Gas (SoCalGas), Kern River, El Paso Natural Gas and Mojave, averaged 3.2 Bcf/d in November, about 150 MMcf/d higher year/year.

“More gas-fired power generation has had to move to within the market due to lower power imports from the Pacific Northwest,” Bernardi said. “In addition, outright gas demand has been buoyed by population-weighted daily average temperatures coming in slightly colder than last November. Recent daily average population-weighted temperatures have dipped into the lower 60 degree range versus normal for this time of year at 69 degrees.”

SoCalGas system demand on Friday topped 2.7 Bcf/d for the first time this winter, with regional demand up near 3.6 Bcf/d, also the highest for the winter to date, according to the analyst.

“While SoCalGas system storage inventories are entering the winter in better shape than in the last two winters, restrictions continue to remain in place at the Aliso Canyon storage facility,” Bernardi said. “This will once gain place heightened dependence on import pipelines, though capacity remains restricted on several critical paths.”

With conditions so tight on the utility’s system, SoCalGas on Monday announced that it’s launching a new initiative to encourage customers to conserve natural gas when demand is high this winter. Starting this month, SoCalGas said it will issue “Dial It Down” alerts during periods of cold weather.

“SoCalGas has helped pioneer conservation efforts for decades, and our efforts to date have saved our customers more than $670 million in energy costs and have reduced emissions equal to removing 700,000 cars from the road,” said Dan Rendler, director of customer programs and assistance at SoCalGas. “The new Dial It Down Alerts and our ongoing work to deploy more smart thermostats across our service territory will help promote energy reliability, save customers money, and reduce emissions linked to climate change.”

Elsewhere in the West, restrictions on imports into the Pacific Northwest from British Columbia following an Oct. 9 pipeline explosion on Enbridge Inc.’s Westcoast system have created volatility at Northwest Sumas, a trend that continued during December bidweek.

Northwest Sumas added $4.435 m/m to $17.665, though prices could soon moderate as Enbridge has secured approval from the National Energy Board (NEB) to increase flows through its Huntingdon Delivery Area.

“Westcoast has received approval to restore additional flow capacity at Huntingdon, increasing operational capacity there by roughly 400 MMcf/d” to around 1.4 Bcf/d, Genscape’s Bernardi said. “Additional maintenance scheduled for this week will damper this flow increase somewhat, but this development still represents a significant increase relative to Westcoast’s previous forecasts for winter flow capacity after the explosion.

“...Huntingdon and Station 4B South are the two southbound throughput meters on Westcoast that have had their operational capacities reduced following the explosion...For the past several weeks, Huntingdon capacity has been lower than Station 4B South capacity, but that relationship is expected to flip following this NEB approval for the Huntingdon capacity increase,” Bernardi said. “About 50% of Huntingdon capacity flows into the U.S. at the Sumas border point to Northwest Pipeline.”

On the other side of the border in Canada, Westcoast Station 2 gained C74 cents during bidweek to C$1.27/GJ.

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