Even as the United States faces years of structural natural gas demand growth ahead, particularly in the form of liquefied natural gas and Mexican exports, the continued exploitation of shale resources will limit the need for more gas storage development, analysts say.
In 2006, FERC allowed new storage developers to charge market-based rates with the idea of encouraging the development of new storage capacity. The Federal Energy Regulatory Commission specifically noted the need for more capacity as demand had increased by 24% over the prior 20 years, while storage capacity had grown by only around 1.5%, according to PointLogic’s Callie Kolbe, manager of energy analysis.
Since 2006, more than 675 Bcf of working capacity has been added to the Lower 48 states. Much of the growth has come from high-deliverability salt cavern storage, which was supported by the need for flexibility as the market expanded. Post-2013, however, storage capacity increases have largely come from existing field reclassifications and expansions, Kolbe said.
Meanwhile, unconventional development of shale and tight gas resources over the last decade dramatically changed the landscape, effectively leading to rampant onshore production, steep declines in offshore production and lower gas prices. These and other market changes in turn appear to have reduced the importance of storage as a supply source.
“If you look at the Marcellus, production is happening right where the storage fields are,” said RBN Energy’s Rick Smead, managing director of advisory services. “Each year, we’ve added more production deliverability than total deliverability of storage. So taking into account the existing storage fields, you’re basically doubling capacity.”
Pipelines Upending Load Swings
With decades’ worth of technically recoverable resources in the Appalachian Basin alone, and growing demand in what was once the epicenter of U.S. supply, the manner in which gas is transported has also changed. Multi-directional pipes have made storage less critical because there is so much flexibility, Smead said.
“Storage used to carry you on a forward haul. You can now meet a lot of load swings with pipeline flexibility,” he said.
Genscape Inc.’s Eric Fell, senior natural gas analyst, said while storage was also designed to handle supply shocks, a lot of those concerns are not as pronounced in a post-shale revolution world.
“Although both supply and demand have grown a lot, the seasonality of demand hasn’t changed very much,” he said. “Supply shocks are less of a concern today versus 10 years ago when a much larger percentage of our supply stack was offshore (hurricane risk) and LNG imports.”
And during times of high demand and thus higher gas prices, the market now has the ability to absorb large shocks with price-driven switching between gas and coal in the power stack. Before 2009, fuel switching between gas and oil was the norm and was much smaller in scale than gas versus coal is today, Fell said.
“Given large declines in offshore production and the market’s ability to absorb price and supply shocks via large-scale coal versus gas switching, the need for storage capacity has arguably declined compared to 10 years ago, even though the overall size of the market is much larger today.”
In fact, Fell said FERC’s ruling in 2006 led to a storage overbuild that remains largely underutilized. A noteworthy example is Tres Palacios Gas Storage LLC (TPGS), which in 2013 asked FERC for authorization to abandon up to 22.9 Bcf of working capacity at its three-cavern storage facility in the Texas counties of Matagorda, Colorado and Wharton. TPGS said the market didn’t want the capacity and an abandonment would cut its cavern lease payments to Riverway Storage Holdings LLC and Underground Services Markham. FERC denied the request in March 2015.
In 2016, FERC also vacated a certificate for the proposed Tallulah Gas Storage Project, a salt cavern facility planned for Madison Parish, LA. The project was certificated in 2011 to be placed in service by March 2015. A three-year in-service extension was sought in November 2014, and a one-year extension was granted in February 2015 to March 18, 2016. No further extension was sought.
Today, based on data provided by the Energy Information Administration (EIA), “we’re not cycling a very high percentage of working gas,” said underground gas storage consultant Douglas Elenbaas of Michigan-based EI Energy. “We’re not doing deep withdrawals.”
Record-Breaking Storage Levels
Indeed, storage inventories at the end of the traditional withdrawal season set record highs in 2012 and again in 2016, according to the EIA. Heading into the 2015-2016 winter season, inventories were already at a record high of 4,009 Bcf on Nov. 20, 2015. In the previous five winters, the total withdrawal from the end of October through the end of March averaged 2,176 Bcf. During the 2015-2016 winter, weekly withdrawals were often smaller than the five-year average level, and the total withdrawal was only 1,475 Bcf, the EIA said.
A more granular look at storage data by ICF International LLC for the U.S. Department of Energy (DOE) in 2016 revealed that the maximum inventory level reached has surpassed 80% for all regions except the Mountain region, which has seen a maximum inventory level of just 52%.
Peak storage deliverability occurred during the winter of 2013-2014 for all regions. The regions with the highest peak storage deliverability utilization are the Mountain and Pacific regions at about 80% during mid-December 2013. The East, Midwest and South Central regions had peak-day withdrawals at a more modest level of 46%, 68% and 46%, respectively, during the first half of January 2014. Despite cold weather, maximum storage withdrawals in January 2014 were well below maximum deliverability capabilities because of relatively low inventory levels and pipeline constraints, ICF said.
Unconventional Gas Creating Flatter Prices
Meanwhile, another byproduct of the shale revolution has been a relative flattening of gas prices over the last few years. Price signals to incentivize gas storage development (summer-winter spreads and price spread volatility) have been crushed to the point where people have mostly stopped trying to develop new facilities, Genscape’s Fell said.
ICF analysts echo those sentiments, saying “low price levels and low price volatility have, at least temporarily but dramatically, diminished the value of storage facilities as a tool to mitigate price risks. As a result, almost all pending new storage projects and capacity expansions have been delayed or canceled.”
The issue of lower price volatility has impacted the demand for U.S. storage for a number of years now. In February 2014, Boardwalk Pipeline Partners slashed their quarterly distribution by 81% to $0.10 per unit, in no small part because of what CEO Stanley Horton described as “substantial market headwinds” facing their storage business.
“Since forward price curves are backwardated, market conditions currently do not provide opportunities to park gas,” Horton explained at the time. Boardwalk’s cash flows from operations have improved since early 2014, but its quarterly distribution still remains at $0.10 per unit.
$4 Gas? Not Until 2030 At The Earliest
A look at the New York Mercantile Exchange (Nymex) futures curve on Wednesday (Oct. 17) shows winter prices for November 2017-March 2018 averaging $3.16 and the summer 2018 (April-October) strip averaging less than 25 cents lower at $2.99. The winter 2018-2019, meanwhile, sat just 20 cents above the summer 2018 strip. In fact, $4 gas isn’t seen in the entire futures strip through 2029.
The futures curve was vastly different back in 2006. A look at historical Nymex data shows November 2005-March 2006 futures averaging $10.39, compared to the summer 2006 strip, which averaged at a $4.07 discount at $6.32. The winter 2006-2007 strip averaged $7.15.
“High price levels, large price differentials between summer and winter or extreme price volatility provide opportunities for storage capacity owners to profit from the price movements using the flexibility of storage capacity, creating market incentives for sustained storage developments,” ICF analysts said in their 2016 report. “However, expected seasonal spreads observed in the Nymex natural gas futures market have been in constant decline in recent years, as a result of robust growth of shale production outpacing growth in gas demand.”
In addition to discouraging storage development, the lack of gas market volatility has also created a starkly different environment compared to a decade ago in which storage operators contract their services. Long gone are the days of 10-year deals and high rates of return. Now, customers want short-cycle, low-rate contracts that offer flexibility.
“People that are purchasing storage are not going to opt for 10-year contracts; they want one- to five-year contracts, which makes it difficult for the operator,” El Energy’s Elenbaas said. “Returns aren’t as certain as they’ve been in the past. Gas pricing is not consistent with the past.”
Better Days Ahead
Some storage operators, however, are optimistic that there are brighter days ahead for gas storage. During a second quarter earnings call in July, Boardwalk’s Horton said the company was “bullish” that storage was going to pick up. Whether it’s electric utility plants or industrial load or LNG load, the occasional variability in that load will lend itself to the need for storage, he said.
Boardwalk owns gas storage facilities comprised of 14 underground storage fields in four states with an aggregate working gas capacity of approximately 205 Bcf.
“We have a lot of storage and quite frankly, we don’t really need right now to expand our storage to handle some additional re-contracting,” Horton said during the call.
Boardwalk holds a lot of “financial storage, a lot of power” that can easily be converted over into operational storage with longer-term contracts, Horton added. “So I think our storage position right now is good. We’ve got the ability to put new caverns at our petrol facility. I think we’ve got the ability to leach five additional caverns there. We’ve got the ability to add caverns in our Boardwalk Louisiana Midstream areas, and those could be natural gas caverns if the demand materializes there.”
For now, though, where storage is for the next couple years, Boardwalk has plenty of capacity to to handle demand, Horton said. “But I do think that the operational storage is going to be more valuable, and we’re going to see more demand for that,” he added.
Improving Gulf Coast Utilization
With exports to Mexico averaging around 5 Bcf/d and expected to grow through at least the next few years, and U.S. LNG exports accelerating at lightning speed since launching in mid-2016, one could argue the need for more storage in the South Central region.
In the latest International Energy Outlook 2017, the EIA said world gas trade, by pipeline and by LNG shipments, is poised to increase. In the United States, LNG exports are projected to account for more than 60% of total domestic gas exports by 2040.
Mexican pipeline imports from the United States, which have more than quadrupled since 2009, are also expected to continue increasing over the next several years. By 2018, the United States is expected to become a net gas exporter on an average annual basis, as pipeline exports to Mexico and LNG export volumes grow, the EIA said.
Meanwhile, power generation growth in the region is also set to drive demand. “The one place that could put a strain on storage is power generation, especially with renewables,” RBN’s Smead said. “That could cause volatility. If gas tends to be more baseload, then that would reduce the use existing storage for renewables.”
Still, under a base-case scenario outlined by the Department of Energy’s Office of Energy Policy and Systems Analysis, ICF analysts said that given planned pipeline expansions, gas infrastructure, including storage, is sufficient to meet the needed increase in supplies. The base case called for gas demand for power generation growing at more than 4% per year in the South Atlantic region, which would increase the daily demand to 7.5 Bcf/d from 6.5 Bcf/d by 2035.
ICF analysts, however, said the South Central region could benefit from improved utilization of upstream storage facilities in the Gulf Coast to help meet the need for intra-day flexibility and the intermittent and instantaneous demand from the power sector. Expected LNG exports in the region could also lead to improved utilization of the storage facilities in the Gulf Coast as LNG suppliers need to support potential supply disruptions, they said.
Energy Ventures Analysis analyst Henan Xu agreed that better utilization of existing storage in the Gulf Coast would prove beneficial in the new era of LNG exports. “The South Central region has a lot of storage that can flip directions and is pretty flexible,” Xu said.
While the market could see some fluctuations during maintenance events, those typically last a few days to two weeks, Xu said.
LNG Facilities Creating Storage
Meanwhile, the LNG facilities have storage on site, Elenbaas said. “That is, in a way, a new type of storage coming into the market. As opposed to trying to develop new storage, you can build these tanks,” he said. “The ships alone can hold a lot of gas, so that’s storage as well.”
Smead said he wholeheartedly agreed there is no need for additional storage development in the United States, but said it was critical for storage operators to maintain the integrity of the existing facilities.
“Existing storage needs to stay healthy,” Smead said. “That means recognizing the integrity and maintaining level of capacity.”
Southern California Gas’ Aliso Canyon underground storage facility, the state’s largest, is a prime example of how poor oversight may lead to major disruptions in the gas market. A gas well at the facility sprung a leak back in October 2015 that continued for four months. The California Division of Oil, Gas and Geothermal Resources at the time suspended injections at the facility, but it cleared the way for it to resume operations at a fraction of its design capacity in July.
Non-Salt Storage Eyed As Growth Engines
As noted, most of the new storage capacity coming online in recent years resulted from reclassifications and expansions. Interestingly, EIA data show that in 2016, all eight storage expansions were in the South Central region. The largest expansion was near Houston at the Kinder Morgan Inc. (KMI) Tejas West Clear Lake facility, which expanded by more than 16 Bcf.
Salt fields are mostly in the South Central region, PointLogic’s Kolbe said.
Capacity-wise, the salt fields over the past few years have peaked with a maximum demonstrated capacity at about 91% of total design working capacity. The rest of the South Central region is made up of the non-salt fields.
Non-salt fields started in 2017 with a 23 Bcf, or 2%, boost to design working capacity, according to the EIA. Most of the increase came from two fields: the Tejas West Clear Lake field and Oneok Inc.’s Haskell/Booch field in Oklahoma, which converted 4 Bcf of base gas into working gas.
“I would say that over the next few years, the non-salt fields in the South Central region will be the ones to watch,” Kolbe said. “They will have to balance winter peak demand with increasing demand coming from LNG exports.”
Genscape’s Fell agreed that growth in LNG exports will likely create more seasonality and volatility of demand, and may indeed lead to the need for more storage down the road, but said the market is currently overbuilt and would “first need to chew through the excess storage capacity that we already have.”
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