Power plants are major consumers of natural gas. We take a look at key development trends within the Electric Power sector (EP sector) and provide an outlook on natural gas storage.
Over the past seven years, natural gas consumption in the EP sector has increased by almost 46%. The growth rate had its ups and downs due to fluctuations in weather-related demand for electricity (cooling degree days) and constant changes in fuel economics, but the general long-term trend has been positive. On a 12-month average basis, natural gas usage in the EP sector now accounts for almost 36.3% of total natural gas demand in the United States.
Rising consumption by power plants and utilities is partly driven by structural factors (such as a growing number of natural gas-fired plants) and partly by fuel and environmental economics, which puts natural gas in a more favorable position versus its closest substitute, coal.
Total natural gas-fired nameplate capacity has increased by 12% since 2010. Some 8 GW of net summer capacity was added in 2016 alone. It is estimated that total stock of natural gas-fired generators now exceeds the stock of coal-fired power plants by 167 GW. In 2010, the difference was less than 74 GW. New capacity additions only partly explain the rising share of natural gas generation. Another reason is that the pace of retirements of coal power plants has been several times greater than that of natural gas power plants.
According to EIA, the stock of natural gas generators would grow by another 25.1 GW by 2019, whereas the stock of coal generators will decline by 7.4 GW over the same period. Therefore, structural changes in demand will continue to spur natural gas consumption in the EP sector in 2017 and 2018.
On February 28, 2017, EIA reported that the EP sector consumed 668.8 bcf of natural gas in December 2016, which was 13.3% less than in the same month of 2015. However, year-to-date consumption was up 3.2%.
Natural Gas Consumption in the Electric Power Sector (Mmcf)
Average NG-Coal Spread (cents per kWh)
Source: EIA, NOAA, ICE, CME, GeckoiCapital calculations; *HDD - heating degree day
Relative consumption (on a per heating degree day basis) was much weaker than last year. This should not be surprising, since December 2015 was much warmer, and natural gas, therefore, was a lot cheaper. However, despite the fact that the average cost of natural gas (relative to coal) for electricity generation has since gone up by 0.843 cents per kWh (i.e., more than doubled), consumption per heating degree day in December 2016 was only 37% weaker than in December 2015. In other words, the decline in consumption was disproportionately smaller relative to the unfavorable effect from fuel cost economics.
The relationship between natural gas consumption in the EP sector on the one hand and NG-Coal spread on the other is very strong, but not immediate. It is made possible thanks to the so-called "coal-to-gas switching effect", which is a displacement of coal-fired generation by natural gas-fired generation due to short-term fuel price competition. Coal-to-gas switching has a positive impact on total natural gas demand. It occurs because of lower natural gas prices relative to coal. The lower the spread, the stronger is the impact of coal-to-gas switching and the higher is the consumption of natural gas in the EP sector.
Source: EIA, ICE, CME, GeckoiCapital calculations
However, the cost of fuel is not the only factor determining the economics of fuel switching. Other important factors include the cost of switching itself (technical cost), taxes, and the cost of extra emissions produced by burning a dirtier fuel (this factor may become less relevant under the Trump administration). In addition, utilities will not switch fuels if it is beneficial for just one day. They will look at the cost of either fuel over a medium to longer time frame to determine which fuel is more beneficial on a BTU basis.
It is important to remember, however, that this substitution effect is particularly important during summer.
Source: EIA, NOAA, ICE, CME, GeckoiCapital calculations; *CDD - cooling degree day
Notice that last summer, consumption in the EP sector increased even as the NG-Coal spread stayed relatively unchanged (in fact, it was actually higher by $0.015 cents per kWh, which normally should discourage natural gas usage).
Last summer, the most bullish (versus history) storage report was for the week ending July 29. The "injection" for that particular week was 60 bcf smaller than the 5-year average. In reality, it was not even an injection, but a 6 bcf draw. It was, of course, expected, but no less unprecedented. The 30-day average NG-Coal spread at that time stood at around 1.09 cents per kWh. Last Friday, it was 0.83 cents per kWh. If we are to avoid draws from storage this summer, the spread should rise, and that means either natural gas prices need to increase or coal prices need to fall.
Source: EIA, ICE, CME, GeckoiCapital calculations (print screen is from GeckoiCapital website)
Our long-term storage forecast models include the fuel-switching element, but this season, it is particularly crucial. With the latest natural gas and coal forward curves, we project just 3,342 bcf in storage by the end of October 2017. The market expects 3,700 bcf (according to ICE settlement reports). We update our forecast on a daily basis, but over the past two weeks, it has not been moving closer towards market expectations. The current forward curve is too favorable for natural gas power burn this summer - prices need to rise further to eliminate potential extra consumption in the EP sector. Indeed, the latest figures reveal that gas usage already hit a one-month high in Pennsylvania-New Jersey-Maryland Interconnection (PJM) and in Midcontinent Independent System (MISO) last week, and in PJM in particular, natural gas overtook coal as the second preferred fuel after nuclear.
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