This article appears as published in Foster Report No. 3251
With record natural gas demand expected this summer due to increased exports and industrial consumption, robust production and healthy gas storage levels should keep prices in check, the Natural Gas Supply Association (NGSA) said May 30 in its summer outlook.
Production is forecast to reach an all-time high of 89.4 Bcf/d, which, when combined with imports from Canada and other sources, result in a total summer supply level of 94.2 Bcf/d. Those are compared with summer 2018 figures of production at 82.6 Bcf/d and total supply at 88.1 Bcf/d.
The production gains include elevated output in the Permian Basin and Marcellus, Utica, and Haynesville Shale plays, as gas associated with oil production plays a bigger role in the supply picture. Associated gas production has not responded to lower oil prices as it has in the past, and oil prices have recovered recently amid OPEC’s agreement to cut production and continued sanctions on Iran. “As a result, the recent concerns over the potential for a pullback from associated gas production have largely dissipated,” according to the report.
Summer weather is forecast to be normal, with the number of cooling degree days at the 10-year average, compared with the summer of 2018, which was the fourth-hottest on record. The forecast for cooler temperatures this summer – 14% lower on average than last summer — results in relatively flat demand in the residential and commercial customer sector and less power generation burning of natural gas.
The biggest demand push stems from increased pipeline exports to Mexico and more LNG exports as several projects are expected to begin service during the summer, NGSA noted. Liquefaction trains at the Corpus Christi and Freeport LNG projects in Texas, Cameron LNG project in Louisiana, and Elba Island project in Georgia are expected to add 2.3 Bcf/d of new export capacity by the end of the summer.
Pipeline exports to Mexico are projected to reach 5.5 Bcf/d from the 4.7 Bcf/d level of last summer, as Mexico increases use of natural gas to serve electric generation and manufacturing needs, NGSA said.
NGSA does not forecast prices, but said its examination of all factors, using published data from the Energy Information Administration and assessments from Energy Ventures Analysis, shows neutral pressure on prices relative to last summer, when Henry Hub prices averaged $2.92/MMBtu.
The slight dip in power generation use of gas is attributed to less economic switching by generation owners, even as the number of gas-fired generators climbs. Those “structural changes” of 6 GW of combined-cycle gas turbine additions during 2018 add about 5.3 Bcf/d of power burn demand this coming summer, compared with 3.4 Bcf/d of power burn last summer.
A slight gain in industrial gas demand is attributed to higher capacity utilization in the sector and new industrial projects that use natural gas as a feedstock, such as fertilizer and methanol plants. About 80 major natural gas–intensive industrial projects have been or will be completed between 2015 and 2023, representing 3.7 Bcf/d of new demand for that time period, according to the report.
“The picture that has emerged for the upcoming summer is one of remarkable growth in demand that is matched by record-setting production,” said Jenny Fordham, senior vice president at NGSA. “The abundant supply of natural gas is great news for consumers, with diverse market outlets that support and sustain production,” Fordham said in a statement.
In the supply picture, NGSA expects growth of 6.8 Bcf/d compared with the summer of 2018, which was a record growth year that more than tripled the previous year’s growth.
Besides the shale gains and associated production in the Permian, Gulf of Mexico production has rebounded following the start-up of eight major deepwater projects during 2018 that more than offset declines from existing Gulf of Mexico wells.
Onshore production has producers working to counter the production declines from shale wells added in 2018. NGSA noted that production from shale wells can decline between 30% and 70% during the first year of production, depending on the location, and the Marcellus wells added in 2018 are poised to experience declining output in 2019. With the number of rigs at similar levels to the summer of 2018, production is unlikely to grow as fast as last year as output declines from wells that began production in 2018.
Gas storage injections during the summer are expected to be “hearty,” averaging about 85 Bcf/week to make up for the deficit that at the end of March had the national inventory 505 Bcf below the five-year average. ”These are sizeable injections, but not unprecedented, since industry refilled storage at an average rate of 89 Bcf per week in 2014,” Fordham said.
The high storage injection rate also is the result of production gains and increased pipeline takeaway capacity that is enabling more gas to move to markets, NGSA noted. The group forecast the injection-season ending level of 3,745 Bcf, which is very close to the five-year average at that time of year.
By Tom Tiernan TTiernan@fosterreport.com