November 2019, Vol. 246, No. 11


Winter Is Coming, And the Gas Storage Outlook Appears Secure

By Richard Nemec, Contributing Editor   


As rhythm and blues singer Richard “Dimples” Fields matter-of-factly proclaimed in the 1980s, “If it ain’t one thing, it’s another.”  For the natural gas storage industry, that succinctly summarizes its last five years following the global oil and gas price declines. 

While underground stored supplies have carried the industry through some severe regional cold snaps, controversy and questions about storage arose in late 2015 during a four-month methane leak from a compromised storage well at Southern California Gas Co.’s Aliso Canyon facility at the northern edge of Los Angeles. It was the largest gas leak ever, according to the Sempra Energy gas-only utility, the nation’s largest gas distributor.     

It took up to a billion dollars to cover the costs, including the services of the famous well firefighting firm, Houston-based Boots and Coots Inc., and temporary living accommodations for thousands of nearby residents who had to abandon their homes for most of the first half of 2016.

The 3,200-acre storage field in an abandoned oilfield, the state’s largest, has been closed or operating on a restricted basis ever since. Consequently, the 86 Bcf capacity field, along with storage facilities generally have been subjected to tighter scrutiny. Locally, residents and organizations have advocated that state regulators permanently close the Aliso Canyon facility.

In the midst of a national outlook for strong storage supplies and reliability predictions for the coming winter, Aliso Canyon is the local exception. For safety concerns, regulators have imposed a ceiling on its storage volumes at about one-third of its working capacity.

And the winter supply-demand situation is further complicated by the fact that SoCalGas has two major transmission pipelines for out-of-state supplies that have been out of service for several years and are still being repaired in the fall of 2019.

One line operates at lower pressures due to a rupture in 2017 of a nearby line. System pipeline capacity has been knocked down by more than 800 MMcf/d, and the gas-only utility’s daily maximum send-out has dropped from 4.5 Bcf/d to 3.56 Bcf/d.

For the industry, the stigma of the Aliso incident, which turned out to be caused by a preventable groundwater-induced microbial corrosion in a seven-inch diameter storage well casing, public ridicule has eased with time, and newer positive examples of underground gas storage have emerged in places like along the Columbia River in Oregon, northwest of Portland.

There, the local gas distribution operator, NW Natural, has partnered with the local electric utility, Portland General Electric, to expand the Mist storage facility to provide exclusive on-demand storage service 24/7 for PGE’s nearby gas-fired power generation plants.  

“North Mist is an excellent example of storage working collaboratively with the power generation sector,” said Randy Friedman, senior gas supply director for NW Natural. 

The $132 million project is dedicated to PGE’s nearby gas-fired generation plants, which are linked by a new 13-mile, 16-inch diameter transmission pipeline between the storage facility and power generation units.

The old storage field’s 16 Bcf of working capacity is primarily dedicated to serving core customers, while the added 2.5 Bcf of capacity is dedicated to the electric utility under a 30-year contract. After completing critical engineering, construction and testing work in 2018, NW Natural senior executives view Mist as having a valuable location, enabling the utility to provide “high value with long-term contracts,” 

Officials at both NW Natural and PGE talk positively about the added storage. Friedman said it has operated as expected, and the electric folks are “definitely using it.” Engineers at PGE echoed the same assessment, adding that the dedicated space gives the electric utility “the flexibility to continue adding renewable resources to the system.” A growing buzzword in the upcoming gas storage cycle seems to be “flexibility.”

As Friedman mentions, most storage is still operated by local utility distribution companies, or similar companies needing it for their operations’ balancing supply/demand. In the past 10 years, storage hasn’t been of much value to arbitragers, but in the Pacific Northwest, there was an event that strained the system last winter when an Enbridge Partners supply transmission pipeline ruptured in British Columbia.

“It restricted supplies all through the winter and reminded even that group [arbitragers] that storage can be extremely valuable,” Friedman noted.

These sorts of positive-negative storage scenarios can be found in other areas of the country as U.S. natural gas production keeps growing with an eye on global developments that impact both demand and supplies, and eventually the need for more or less storage. 

Natural gas storage tanks and oil tanks at an oil refinery.
Natural gas storage tanks and oil tanks at an oil refinery.

Seasonal Forecasts

As the coming gas storage season was nearing in late September, the U.S. Energy Information Administration’s (EIA) monthly national energy review showed consumption and production flat or increased, while coal, nuclear, and renewables were decreasing.

Overall energy consumption was down 1%, while production was up 8%. At the same time major gas industry stakeholders were meeting in Washington, D.C., to review the final new underground storage regulations from the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA).

Earlier projections from EIA on 2019-2020 gas storage were bullish, placing overall storage levels above the five-year average and headed for more than 3 Tcf of stored supplies before the snow starts flying.

By the end of October, EIA was projecting storage totals to be above 3.7 Tcf, putting the total 16% higher than the same time the previous year, and slightly above the U.S. five-year average.

Storage totals in mid-summer were only 2.7 Tcf, but that was 13% higher than the previous year, while lagging 4% below the five-year (2014-18) average. Last August, EIA analysts said, “storage injections will outpace the previous five-year average and inventories will rise to more than 3.7 Tcf.”

Supply/demand was the equivalent of an opaque stew in which the individual ingredients were not clearly differentiated or understood. It looks edible, but how long will it remain an integrated whole?

In late September, EIA calculations showed overall U.S. energy consumption was down about 1% for the first six months of 2019 compared to the same period the previous year measured by Btu, but during the same period natural gas consumption was up 3%, petroleum was flat and everything else was down, including coal consumption at 11% lower.

Over the same six months, overall energy production was up 8%, led by petroleum up 15% and dry natural gas up by 12%, Coal production, nuclear and renewables were down 1%-3%.

So, what does this bode for storage? Following EIA’s outlook for natural gas next year, storage could benefit from rising prices, production and a dry gas comeback. Henry Hub spot prices averaged $2.37/MMBtu in late summer, according to EIA, which lowered its forecast for the second half of 2019 to $2.36/MMBtu.

With prospects for “subdued” hub prices and accelerated injection rates in storage coming out of summer, Standard & Poor’s (S&P) Global’s Insight was betting “underground storage sites [were] likely to continue to fill at an average or above-average pace – at least, until rising temperatures and exports draw down on the supply glut” that pooled during the summer.

S&P points to “regional dynamics” as influencing storage, which is certainly true in the Southeast where the Gulf Coast is busy dealing with the increase in liquefied natural gas (LNG) exports and pipeline exports into Mexico.

And “regional” impacts can be found elsewhere, such as the Northeast, according to S&P: “Since the beginning of 2019’s injection season, Northeast storage facilities have posted substantial weekly inventory builds, largely erasing running inventory deficits relative to historical averages. The trend has been aided both by strong regional production and weak seasonal demand and comes in spite of dismal seasonal spreads – the differential that traditionally provides the price signal to inject now and withdraw later.”

Proponents of storage going into winter had to put aside the general analytical observation that was bearish all summer in 2019. Incidents and injection volumes were causing analysts to stress in the middle of summer when rising volumes continued. EIA reports again added to group consternation over a 65 Bcf weekly injection figure in mid-summer when a host of smart analytical organizations had predicted totals between 50 Bcf and 57 Bcf.

Concerns were heightened in late July when there was a fatal explosion on the Texas Eastern Transmission (Tetco) pipeline system in Kentucky, causing Tetco to cut the gas flows on its north-to-south 30-inch pipeline south of Danville, Ky.

At this time period, EIA reported: the Midwest injected 27 Bcf week/week, while the East injected 22 Bcf. Further west, the Mountain region refilled 5 Bcf, while the Pacific recorded a 1 Bcf withdrawal. In the South Central, a 16 Bcf weekly injection into non-salt stocks was partially offset by a 3 Bcf withdrawal from salt.

At that time overall U.S. gas storage was 14.5% higher than it had been at the same time in 2018, although then it still lagged the five-year average storage levels by 4.5%, which subsequently was more than made up.

Storage Outlook

“Natural gas storage is an incredible energy source compared to electric storage in batteries; gas far exceeds in capacity what batteries can store,” said Mike Adamo, a gas storage engineer and senior program manager at the Gas Technology Institute (GTI). “Storage is something that is going to be used far into the future, so I don’t see a lot changing with it. There are not a lot of technology changes coming, but storage will continue to play an important role for a long time.”

Adamo sees storage as “essential” for pipeline operations. He sees the anti-fossil fuel drive across the West as ignoring the common understanding from a few years ago that gas was the “bridge fuel” to a zero or low-carbon environment. He notes that the longer-term movement to more of a hydrogen economy would depend on the gas storage and pipeline infrastructure.

NW Natural’s Friedman agrees with Adamo, noting that despite shrinking commodity prices and narrowing of price bases, an offsetting trend is “the increasing need for energy storage assets to balance renewables growth on the electric grid.” He thinks that “until batteries take a quantum leap forward in cost/efficiency, gas-fired generation is the likely balancing tool, meaning increased use of gas storage.” It offers the long-sought “flexibility” to respond quickly to renewables fluctuations, he said.

The American Gas Association (AGA) in late summer measured the pulse on overall winter preparedness among 105 of its members, which include most of the major local gas utility suppliers and storage operators. More than 95% of the members indicated they were relying on the use of underground gas storage, according to Richard Meyer, AGA’s managing director for energy analysis.

“Overall, we see a strong picture for U.S. gas supplies, of which storage is an important and integral part,” Meyer said. “This year the projections for storage have outpaced the five-year average. What we see for the outlook is largely relatively strong inventories headed into the winter.”

Storage levels in mid-September were 15% higher than a year earlier, and the projections have stuck with the prediction that it will outpace the five-year average going into this winter.

“I think the renewables in the electric generation sector have had an impact on gas storage,” Meyer said. “I don’t have any comprehensive national data, but when you look at examples like the North Mist storage expansion project [NW Natural Corp.], it was developed to give no-notice gas storage services to the local electric utility [Portland General Electric Corp.].”

Specifically, the added storage was to support gas-fired generation that could further support the integration of more renewables into the power mix. “There is an evolution ongoing with some of these assets,” Meyer said. “Depending on the company and location, the role of underground storage is very important in terms of meeting peak day, peak month and even peak-hour loads.”

Two factors that the experts like Meyer say always make a difference are commodity prices and technology, if not in storage directly, in the upstream and downstream sectors. Lower commodity prices do matter, Meyer and others in the industry agree, but for LDCs and regulators how storage is used is less of a concern.

“If you’re a local distribution company and your primary concern is to provide adequate supplies on a peak day, much of the planning around those peak days is not going to be sensitive to price considerations [compared to reliability issues],” Meyer said.

In thinking about the technology sector that has transformed production and transportation a great deal, Friedman observed the power-to-gas (P2G) and renewable natural gas (RNG) technologies “have the potential to change the discussion around fossil fuels [with climate change advocates] and the integration of the U.S. natural gas system with the electric grid.”

While acknowledging that GTI currently is not engaged in a lot of projects tied to gas storage, since Aliso Canyon, the gas research organization has been involved with several industry players looking at the risks inherent in storage and how they are best dealt with.

“We’ve developed methodologies for looking at risk and complying with national industry standards [American Petroleum Institute #1-171], so operators can better understand their storage assets,” said GTI’s Adamo.

Adamo thinks North America still contains potential new gas storage sites although he hesitates to name the potential locations. Generally, he thinks depleted hydrocarbon wells will continue to be prime sources for storage.

“Aquifers and salt dome caverns are always in demand for fast-in/fast-out storage,” he contends. “Companies traditionally have used the salt caverns, but I’m not sure of where the sites are that may have the potential to grow.”

The AGA survey indicated that a small number, only 6%, of the LDC respondents were either expanding or building new storage. Nearly a quarter of the LDCs are considering propane-air or peak-shaving facilities as opposed to more underground storage.

Richard Nemec is P&GJ’s regular contributor based in Los Angeles. He can be reached at


For more information on the changing environment for gas storage in the EU, read EU Storage Operators Brace for 'Flexible' Services Era

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