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Looking at Storage:

If You Build It, Will They Come?

May 12, 2016 | By Callie Kolbe

The Energy Information Administration (EIA) says that 13 companies have a combined total of 23 proposed underground storage projects for 2016-2018 across the lower 48 States. Combined, these projects would add 170 billion cubic feet (Bcf) of working gas storage capacity and nearly 6 Bcf per day (Bcf/d) of withdrawal deliverability. These increases would be spread across eight states, with Louisiana home to 54% of the increased deliverability.

However, as with other projects in the natural gas industry, low prices and an evolving market environment have called into question whether all of these projects will be built.

This week’s Get the Point reviews these proposed storage projects and discusses why many of the projects have been delayed or have been put on hold. 

First, we start with a quick overview of currently active U.S. underground gas storage facilities. The EIA 191 form collects information on working and base gas in reservoirs, injection rates, withdrawal rates and location of reservoirs from operators of all underground natural gas storage fields on a monthly basis; from this EPA, publishes annual data.

Figure 1 reflects the most recent data published by EIA in March 2016 for the year 2015. The data includes a total of 385 active storage reservoirs across the Lower 48 with a combined working gas capacity of 4.6 trillion cubic feet (Tcf). Of this, 3.7 Tcf is from depleted fields, 0.45 Tcf from aquifers and 0.49 Tcf from salt caverns. 

Figure1: Lower 48 Active

There are two key capacity measures for natural gas storage: how much gas can be stored and used (known as working capacity and measured in Bcf); and how fast the gas can be used, or maximum deliverability (measured in  Bcf/d). Maximum deliverability rates can vary widely as depicted in Figure 2. The areas of the country with the most prolific deliverability capacity are found near large population centers like Chicago or Houston, as well as near accessible  supply basins along the Gulf Coast.

Figure 2: Maximum Withdrawal Rates across the Lower 48

figure2map

 

Figure 3 indicates the geographic breakdown of new proposed storage projects and deliverability additions. The regional distribution of these pending projects shows the majority of additional capacity is proposed for the Gulf Coast, with Louisiana accounting for over half of the additional deliverability.

In addition, 21 out of the 23 proposed projects are specific to high-deliverability salt-dome formations; this reflects the market’s interest in meeting peak demand for the power sector or flexibility to deliver gas to liquefied natural gas (LNG) export centers. Salt dome natural gas storage generally has higher flexibility, with the ability to turn (or ratchet) flows from injection to withdrawal on a more frequent basis than a depleted field or aquifer. This allows storage holders the ability to take advantage of short-term swings in market prices as regional supply, demand and pipeline constraints dictate.

If all of these projects were to be completed, the result would be nearly a 4% increase in Lower 48 working gas storage capacity from 4.6 Tcf available today. However, the more important consequence of the buildout would be the additional withdrawal capacity into the market, which would result in nearly a 5% increase in peak winter deliverability across the Lower 48 and an additional 19% in Louisiana alone. 

figure3

All but three of the proposed projects have been authorized to begin construction by FERC since 2012. However, almost all of those projects have been delayed or put on hold, pushing back each  project’s initially proposed in-service date.

For example, the proposed 8 Bcf of working capacity Picacho Peak project in Arizona is indefinitely on hold by MultiFuels. The salt-dome project, originally certified in 2011, was strategically located near five potential natural gas-fired power plants. But as market conditions changed in the area, the economics of the storage facility have been called into doubt. 

Sempra Energy’s Mississippi Hub Storage Expansion, which was anticipated to bring its fourth cavern into service this year and add 9 Bcf of working capacity to the state, was abandoned late last year. The salt-dome project was originally certified in 2007, and its purpose had evolved to serve LNG export demand in the Gulf Coast. Again, however, the market has changed considerably, in this case because LNG demand is emerging more slowly than anticipated.

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Other storage projects like Merchant Energy’s Tallulah Gas Storage project in Louisiana have had to jump through regulatory and environmental hoops. Last year, Merchant Energy filed a request for a three-year extension on the project in part as a result of a lacking a permit from the Louisiana Department of Environmental Quality.

Future storage projects may also have additional uncertainty as construction costs will likely increase as a result of increased scrutiny on storage safety following the SoCal Gas leak at the Aliso Canyon facility near Los Angeles. Just last month, the Obama Administration created an interagency task force aimed at making natural gas storage facilities safer. The slow movement towards completing new storage capacity begs the question whether the right market signals are even in place to encourage capacity buildout.

The need for storage capacity first requires a projection of future supply and demand of gas to determine if enough working capacity is available. That said, an understanding of the full pipeline transmission system and its capacity limitations is also needed in order to estimate deliverability options. But figuring out the transmission system’s limitations depends on whether or not the project developer believes that a permanent increase in natural gas demand will show up, and for which use. If demand comes from power generation, where will the additional gas supply and storage be needed? If it’s LNG, the location of storage needs is likely to be different than for power. Within the category of LNG exports, questions remain about which export facilities will be operating (the Gulf, the Pacific Northwest or the Mid-Atlantic), and to what capacity?

Additionally, a glut of supply from high deliverability and highly efficient shale gas formations over the past 8 years has dulled the need for storage facilities and blunted the volatility that provides many storage facilities their intrinsic value – the delta between the price of gas injected and what price it can sell for once its withdrawn. This is especially true regarding the development of depleted reservoir and aquifer storage, which can only turn seasonally and is realtively limited in its flexibility compared to salt-dome storage. 

In any of these situations, the Catch-22 is that price signals that might give operators the confidence to move forward with their planned capacity may come too little too late. Stay tuned to our Get the Point series as we monitor storage development, storage inventory levels and the supply and demand factors that impact infrastructure build out in the future.   

 

 

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