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Coal-to-gas switching seen limiting natural gas storage injections this summer


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Coal-to-gas switching seen limiting natural gas storage injections this summer

Natural gas prices will need to move closer to $3/MMBtu this summer to stave off an increase in coal-to-gas switching that would result in an inadequate rebuilding of the natural gas supply ahead of the next winter heating season, Barclays analysts said.

End-of-March natural gas inventories will total near 1.4 Tcf, or about 17% lower than the five-year average end-of-March level of 1.7 Tcf. To reach an anticipated end-of-October supply of 3.8 Tcf, injections this summer would need to equal 11 Bcf/d, which would be 3 Bcf/d higher than last year and 1 Bcf/d higher than the five-year average, analyst Nicholas Potter said in a March 27 note.

The call on volumes for storage refill, specifically in Appalachia and the Gulf Coast, should provide an outlet for incremental production, which is forecast to grow 7 Bcf/d over the previous summer to 79.5 Bcf/d.

However, the refill rate could be threatened by rising demand. Encouraged by the current natural gas price of $2.70/MMBtu compared with $2.97/MMBtu last year, coal-to-gas switching could boost demand by 700 MMcf/d to 1 Bcf/d, which would add 150 Bcf to 214 Bcf of natural gas demand to the anticipated 300 MMcf/d to 400 MMcf/d already expected for power burn from April through October, Potter said.

Additionally, total exports should rise to an average near 1.8 Bcf/d, and demand for power burn could be boosted another 700 MMcf/d if weather forecasts calling for additional warmth from May through September are correct.

"We see prices having to move closer to $3.00/MMBtu this summer in order to lower these power burn levels and allow adequate storage refills ahead of winter," Potter said.

The Henry Hub cash price is expected to average $3.12/MMBtu over the course of the injection season despite weakness on the natural gas futures curve, as 3 Bcf/d of the expected 7 Bcf/d of production growth is geographically concentrated in the Northeast and Permian while incremental demand growth is largely concentrated on the Gulf Coast.

The 3 Bcf/d of growth will depend on pipeline additions including Rover Pipeline LLC phase II, which will likely be online by early June, and Atlantic Sunrise, which is expected to be online by July, along with late-year projects such as Mountain Valley Pipeline LLC and early 2019 projects such as Atlantic Coast Pipeline LLC. Delays in the start-up of these pipelines would likely curtail production levels from the Northeast relative to current forecasts, Potter said.

"This could potentially set up a situation that presents a more bullish Henry Hub story even in a scenario with growing production," he said.

Canadian production levels have continued to move higher, coming in over 16 Bcf/d in recent months, and with less demand for Canadian storage, higher Canadian exports to the U.S. could prevent some of the potential upside in pricing if domestic gas production becomes pipeline constrained in the Northeast.