Locator: 51891B.
The Bakken.
WTI: $90.53.
New wells reporting:
- Sunday, October 11, 2026: 17 for the month, 17 for the quarter, 516 for the year,
- 41974, conf, KODA Resources, Amber 2133-1BH,
- Saturday, October 10, 2026: 16 for the month, 16 for the quarter, 515 for the year,
- 42225, conf, Whiting, Paulson 5104 44-13 2B,
- 41922, conf, Hess, GO-Lemire-157-973613H-2,
- Friday, October 9, 2026: 14 for the month, 14 for the quarter, 513 for the year,
- 41914, conf, Devon Energy, Scha 33-34 6H,
RBN Energy: what's driving the gulf coast storage buildout and how much more space is needed? Link here. Archived.
The Gulf Coast gas storage market today is a different animal, marked by steeper prices, an emphasis on high injection and withdrawal rates, and a looming capacity shortfall. How did we get here, which market players are shaping things the most, and how much new gas storage is likely to get built over the next few years as a slew of new gas pipelines, LNG export terminals, and gas-fired power plants come online? In today’s RBN blog, we continue our series on Gulf Coast gas storage.
In Part 1, we said that after a long period of storage-capacity surplus and relatively low storage prices, the Gulf Coast market has been on a tear lately. More than 350 Bcf/d of new storage capacity is currently under development, most of it additional salt cavern space at existing facilities in coastal Texas and Louisiana. This massive buildout, which is expected to continue for at least a few more years, is being driven primarily by the storage needs of new and expanding LNG export facilities, each of which need a place to quickly store large volumes of gas in the event of a liquefaction plant outage.
To a lesser degree, new gas storage capacity is also needed to manage gas flows along the Gulf Coast, which have increased sharply in recent years due to Permian gas production growth and new LNG export, power and industrial demand. Power generators, many tied to planned AI data centers, need backup gas supply if regional gas and power demand soars or traditional supplies are interrupted.
As for the storage-capacity surplus that characterized the Gulf Coast market through most of the 2010s and the very early 2020s, that has been largely contracted for — again, mostly by LNG export terminals — resulting in both higher storage prices and a competition among storage developers to provide the incremental space that will be required.
Lastly, we discussed the differences between salt cavern and depleted reservoir gas storage facilities. Most important by far, salt caverns offer considerably higher gas injection and withdrawal rates — a must-have for LNG export terminals and other customers that may need to “park” large volumes of gas within a short period of time. Also, salt caverns require considerably less “base” or “cushion” gas. (See Part 1 for details.)
Today, we’ll begin with a look at Gulf Coast gas storage prices or, more specifically, the monthly rates that market participants pay storage owners/operators for Firm Storage Services (FSS) — that is, the fixed fee they pay each month under long-term contracts for the right to store X amount of gas at their facilities, whether or not they use it. (Note: In addition to that fee, customers pay volume-based fees for moving gas into and out of storage.)
In the second half of the 2000s, when large amounts of gas storage capacity were being built in anticipation of fast-growing LNG imports (something that never materialized, as it turned out), FSS prices were relatively high — north of 15 cents per dekatherm (dth) per month (blue arrow in Figure 1 below). That price level not only supported the capacity buildout, it also reflected the wide winter-summer spread in gas prices, the high gas price volatility and the hurricane risk that drove the demand for more storage.
