Natural gas working storage capacity was up slightly from November 2015 to November 2016, led by growth in the South Central region, where several facilities reached new five-year maximum levels, the U.S. Energy Information Administration said.
The agency measures storage capacity annually in November using two distinct measures: the demonstrated maximum working gas volume, which represents the sum of peak volumes reported by the 385 active storage facilities in the Lower 48, regardless of when the individual peaks occurred over the most recent five-year period; and design capacity, which is the sum of the 385 active storage fields' working gas design capacity, as of November 2016, as reported on survey Form EIA-191, the Monthly Underground Natural Gas Storage Report. Design capacity is based on physical characteristics of the reservoir, installed equipment and operating procedures particular to the site and is often certified by federal or state regulators.
An update of underground natural gas working storage capacity released April 3 showed that with the exception of the South Central salt sub-region, which grew by nearly 3%, and the East region, which fell by less than 1%, storage capacity grew by about 1% in most regions from the previous period in both maximum working gas levels and design capacity.
The 2016 injection season began with record-high start-of-season natural gas storage levels and ended the titular injection season on Oct. 31, 2016, with an end-of-month record of 3,987 Bcf that grew to an all-time high in November 2016. Growth occurred despite Southern California Gas Co.'s Aliso Canyon storage field being shut in from normal storage operation because of a major leak late 2015. In addition, total U.S. natural gas production was down slightly in 2016 compared to 2015, but Northeast production was up.
The high storage volumes applied downward pressure on natural gas spot prices. The average Henry Hub spot price in 2016 was $2.52/MMBtu, 10 cents lower than in 2015 and the lowest average annual spot price since 1999.
For the third consecutive year, no new underground storage facilities began operation and relatively few existing storage facilities were expanded.
"In recent years, wintertime prices have spiked less than in previous winters, and have been lower in the futures market, making it more difficult for storage operators to take advantage of price differentials," the EIA said.
In addition, while production was down slightly year on year, it was 24% higher than in 2010, reducing the reliance on storage as a source of supply. Dry gas production in the Marcellus and Utica together accounted for about 49% of all U.S. shale gas production, according to February figures, bringing production closer to several large market centers in the Northeast and Midwest. Further, overall energy intensity was lower because of increased efficiency and southwestward population migration, which the EIA said may be moderating demand for heating.
Total demonstrated maximum working gas volume rose by 0.7%, or 31 Bcf, to 4,373 Bcf, driven largely by the South Central region, which expanded by 20 Bcf, while total design capacity grew by 0.7%, or 21 Bcf, between November 2015 and November 2016 to 4,688 Bcf.
The south central region expanded its demonstrated peak by 20 Bcf, largely attributed to several facilities in the salt subregion reaching new five-year maximum levels that increased the subregion's demonstrated peak to 448 Bcf, up 12 Bcf, or 2.7%, compared to the previous period. By contrast, the East region showed a slightly lower demonstrated peak of 989 Bcf, or 3 Bcf lower than the prior period's demonstrated peak, based on storage volumes between December 2010 and November 2015. The decreases were spread across many different facilities in the region, whose previous maximum levels occurred before December 2011.
As in demonstrated capacity, the south central region showed an increased design capacity of 35 Bcf, or 2.3%, while the capacity of most storage regions was relatively unchanged between the two periods. The East region decreased by 0.4%, or 4 Bcf, and the Midwest, mountain and Pacific regions all showed no significant change. Most of the south central region increases were attributable to the south central nonsalt subregion, which expanded by 23 Bcf, or 2.2%, from November 2015 to November 2016. These gains were attributed to a more than 16 Bcf working gas capacity expansion at Kinder Morgan Tejas Pipeline LLC's West Clear Lake field, and a conversion of base gas to working gas at ONEOK Inc.'s Haskell/Booch field, which added 4 Bcf to the regional total. Several other incremental expansions occurred throughout the region.
With the exception of the South Central region, most of the storage regions had relatively stable capacity year on year. The South Central region capacity increased by 35 Bcf, or 2.3%, with 23 Bcf, or 2.2%, of that growth in the nonsalt subregion, and 12 Bcf, or 2.5%, of growth in the salt subregion. Elsewhere, East region capacity decreased by 0.4%, or 4 Bcf, and the Midwest, mountain and Pacific regions all showed no significant change.
A total of three facilities in the East and Midwest regions became inactive in 2016, which collectively removed less than 1 Bcf from the design capacity total, while two facilities resumed storage activity, adding more than 8 Bcf of storage capacity.
Although no new storage facilities were added in the review period, increases in working gas design capacity came from expansions of eight facilities in the South Central region by 1 Bcf or more between November 2015 and November 2016, and the restoration of 8 Bcf of capacity at Bridgeline Holdings LP's Napoleonville facility. The Atmos Energy Corp.'s Liberty South/Squirrel field in Kansas was also restored to service, adding 0.4 Bcf of working gas capacity.