New England, the land of Ben & Jerry’s, clam chowder, deflated footballs and expensive natural gas. Because of a lack of pipeline infrastructure to bring molecules into the area, the region has been plagued by muted demand, high prices and policies aimed at ensuring residents stay warm in the winter and that the lights turn on. Recently, BTU Analytics started looking at demand dynamics in Maine, New Hampshire, Vermont, Rhode Island, Massachusetts and Connecticut in an attempt to quantify how much gas our friends in the Northeast would use if pipeline infrastructure was not a bottleneck.
First up in our analysis is residential and commercial demand. If we look at consumption per degree by state, it is clear that the region uses far less natural gas than New York which is just to the south and significantly less than a state like Minnesota which receives similarly cold winters. If we assume the New England states consumed gas at the same rate as Minnesota, an additional 470 MMcf/d of gas would need to flow into the region.
The second demand sector in our analysis is power burn. ISO New England notes the fuel accounts for almost half of the electricity produced in the region. As the chart below highlights, gas consumption in the winter notes a decline and the coal and ‘other’ categories (fuel oil) come in to pick up the slack. As a recent ISO-New England report noted, the average price of natural gas at power plants, “which set the wholesale electricity price in 70% of the hours in 2014”, rose from $6.97/MMBtu in 2013 to $7.99/MMBtu in 2014.
The chart below shows coal and fuels oil’s contribution to the generation stack on gas burn equivalent for both the summer and winter. If we assume that gas is not constrained in the summer then coal and ‘other fuels’ are running for reliability and transmission reasons in the summer. Thus we take only the difference between winter and summer demand to estimate constraint driven power burn loss. Combined, coal and fuel oil accounted for 200 MMcf/d of demand.
Additionally, there are three planned gas fired power plants in the region, all expected to be online by 2018. At a 50% utilization rate, these three facilities could provide about 150 MMcf/d of incremental demand. If we combine all of these factors and distribute the demand based on historical monthly consumption trends, New England could add roughly 750 MMcf/d of demand with a peak of 1.4 Bcf/d in the winter.
While the potential for increased demand looms large in New England, barriers exist. Check back next week for additional analysis on the latent demand situation in New England and to get our commentary via email when its published sign up here.