The volume of natural gas in storage and the flow of gas into and out of it are among the most closely watched indicators in the U.S. gas market. That makes sense, given that these numbers provide important weekly insights into the supply-demand balance, gas price trends, the impact of LNG exports, and any number of other market drivers. However, what’s often ignored by those not involved in the day-to-day physical gas market are the mechanics and economics of storage itself. Who uses gas storage, and for what purposes? What are the value drivers for a storage facility? Why are there different types of gas storage contracts? How much does storage cost, and what do storage rates reflect? Today, we explore these and other questions.
As we said in Part 1, in the decades leading up to the early 2000s, the U.S. gas market underwent a series of fundamental changes, each spurring the development of new storage capacity. First, starting in the 1910s, ’20s, and ‘30s, a number of depleted gas reservoirs were converted to storage facilities — initially in the Northeast, but then in other regions (yellow dots in Figure 1 map and yellow slice of pie chart to left). In the late 1940s and ’50s, another approach — “aquifer storage” — was introduced as an option for regions (primarily the Midwest) that needed gas storage capacity but lacked a sufficient number of depleted gas fields. Aquifer storage (red squares in map and red slice in pie chart to left) had an advantage over depleted-reservoir storage, namely that gas can typically be injected into and withdrawn from it more quickly. However, a disadvantage of aquifer storage is that it needs to be completely empty at the end of the heating season each year, or it can lose gas. The primary purpose of both types of storage facilities was — and is — to help balance seasonal swings in gas demand.
In the 1990s, the gas market was turned on its head with the issuance of FERC Order 636 (along with its predecessor rulemakings going back to Order 436), which among a whole range of market transformations had huge implications for gas storage. Until then, gas pipeline companies were the primary buyers and sellers of natural gas — that’s right, they were transporting gas and marketing it all at once. And they — and a number of local distribution companies — were the ones who paid for the development of most gas storage facilities. Those pipelines then delivered gas to gas distribution companies and electric generators, along with other customers, and the infrastructure cost was baked into “bundled” regulated pipeline rates as state regulators or FERC saw fair, generally defined as “just and reasonable.” With Order 636, interstate pipeline companies were prohibited from buying the gas they deliver (see Part 2 of Different Strokes for more), taking the cost of gas out of pipeline rates and leaving just transportation and storage rates to be regulated under the basic bread-and-butter cost-of-service model. Pipelines kept most of their storage, but it became a separate regulated service for them, with some storage allocated to the transmission side of their businesses for balancing. For storage that pipelines did spin off — and for the developers of new storage — the Energy Policy Act of 2005 provided that if a storage owner could show lack of market power, its rates could be “market-based.”
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