The mild winter of 2019-2020 has seen lackluster storage withdrawals and a building storage surplus which will leave the US natural gas market long in summer 2020. While LNG exports continue to put up solid year-over-year gains of an incremental 4.0 Bcf/d, the question going into summer 2020 is, can coal-to-gas switching be a big enough demand lever to help balance the natural gas market. BTU Analytics estimates current total US coal-to-gas switching potential to be as much as 12.0 Bcfe/d. However, at this point the remaining coal fleet is entrenched at either very low breakeven points for economic switching, or regulatory, reliability, and other factors limit the ability to displace generation. This suggests the total switching potential may be substantially lower than total coal generation would otherwise imply.
US coal-fired electric generation has been on a decade long decline driven primarily by competition from shale gas. As shown in the table above, regions like New England have seen coal generation drop by 96%, when comparing 2009 to 2019 generation levels. On a go forward basis, coal-to-gas switching is going to need to come from regions with higher volumes of coal burn and potentially regions that have not seen declines as aggressive as New England. The two largest remaining coal generation regions are the Midwest and Appalachia which make up over 48% of the US coal generation markets combined. However, these two regions have seen generation decline by 49% and 37% respectively since 2009. But not all regional markets are the same. For example, the Southeast is mostly comprised of regulated utilities, so a less competitive coal plant may remain in the dispatch curve versus a similar plant in a competitive ISO dispatch market in PJM or MISO. For this reason, the Southeast is unlikely to provide as large a volume of coal-to-gas switching gains in summer 2020 versus coal burn in PJM or MISO.
BTU Analytics’ coal-to-gas switching model shows the natural gas equivalency of total coal burn at different gas price levels through October 2019, as shown above. For example, at a gas price of $2.00-$2.49, there is up to 6.0 Bcfe/d of coal-to-gas burn potential on an economic basis. This compares to nearly 13.2 Bcfe/d of coal-to-gas switching potential at the same price band in 2015. Indicating that the combination of natural gas and renewables switching have eroded 50% of the potential demand when prices are between $2.00-$2.49 since 2015.
This reduction in potential demand is not surprising. As we look at historical prices, we can see that Henry Hub, Dominion South, and Chicago pricing have been trading in this band for much of the last 5 years. In the summer of 2019, Henry Hub averaged $2.39 per MMBtu and Dominion South averaged $1.90 per MMBtu. This means that some coal plants in the Southeast, Appalachia and Midwest remained generating in a $2.00-$2.49 price level despite seeing gas prices in summer 2019 that would dictate, on purely an economic basis, that these coal plants should not dispatch.
How much coal-to-gas switching can occur in summer 2020 considering that Henry Hub and Dominion South futures curves are at $2.06 and $1.58 per MMBtu respectively? Shown above is the incremental increases in potential at various price levels for the Midwest and Appalachia. If cash gas prices are weak in summer 2020, in the Midwest and Appalachia we can see that there is up to an incremental 2.5 Bcfe/d and 2.2 Bcfe/d of switching potential at the $1.50 to $1.99 and $2.00 to $2.49 levels respectively. Actual switching is likely going to come in at only a portion of these volumes. The takeaway is coal-to-gas switching may act to help balance the gas market in summer 2020, but more demand or curtailed supply will need to be found considering the potential mounting storage surplus. To follow BTU Analytics’ supply-demand models, request more information on the Henry Hub Outlook.