Natural gas covered almost half of the United States’ electricity demand this summer amid significantly lower gas prices, coal plant retirements, low output from wind and hydropower and high cooling demand. According to the International Energy Agency (IEA), the steepest price drop occurred in gas producing regions – like Texas and Louisiana – accelerating the coal-to-gas switch.
In July and August, the share of the cleaner-burning fuel in the US power mix rose from 40 percent to 45 percent in July and August. In contrast, the share of coal contracted from 23 percent to 17 percent over the same period. Accordingly, the average utilisation of coal-fired generation fell from 48.5 percent to 39.8 percent in the first seven months of the year, while the capacity factor of gas-fired generation increased from 54.6 percent to 57.7 percent.
Low gas price trigger switch from coal
Prices dropped by 60 percent all through the first three quarters of 2023 at the US benchmark Henry Hub. Regional gas prices were even lower, notably in the large shale gas producing regions which also benefited from a particularly mild winter. The substantial price swing sparked a fuel switch from coal to gas. IEA analyst noted the “switching was particularly noticeable in regions with wholesale markets, where competition between resources is based on short-run marginal cost economics.”
In Midwest (MISO) and Central (SPP) regions, coal had become more competitive in 2021 and 2022 due to a jump in gas prices. But gas became much more competitive again also in these regions this year as its price fell, analysts pointed out. In contrast, coal-burn remained dominant in the Central as the coal to fuel power stations is here predominantly procured on attractive long-term contracts, IEA figures show. Still, more efficient gas-fired units managed to displace older coal plants.
Operational challenges for ageing coal fleet
The age of assets is also decisive: “With an average age of 43 years compared to 22 years for their natural gas counterparts and almost an entire fleet of more than 30 years of age, coal plants are faced with new challenges,” analyst said, referring to their ways to operate.
For instance, in the fourth week of August – when natural gas for power reached its zenith – just some 80 GW were used for baseload compared to about 95 GW last year in the same week, IEA figures show. “With coal plants running at about 125 GW on the peak for both years, this meant that the coal capacity used for peaking went from about 30 GW to 45 GW in just a year,” analysts commented.
Operating a power plant flexibly, in load-following or cycling mode, in response to economic conditions also reduces plant efficiency. A study by the Electric Power Research Institute (EPRI) shows there is an efficiency penalty of around 40 percent (14,000 Btu/kWh v 10,000 Btu/kWh) when plants are running near minimum load condition compared to baseload operation. This adds between $3 to $12 oer MWh to the operating cost of the unit at current coal prices.
Liberalised markets switch faster
Market type is impacting the speed of fuel switch. Evidence gathered by the IEA shows natural gas is replacing coal at faster rates in regions with liberalised markets than in regions with vertically integrated utilities. In fact, gas generation was up 5 percent between 2019 and 2023 in regions with vertically integrated utilities while it soared 22 percent in regions with liberalised markets.
Regulated utilities use ‘must-run designation’ to dispatch power units at rates much higher than merchant, or competitive, supplier – also at times when fuel and electricity prices suggest that running coal plants is unprofitable. Between 2017 and 2022, Potomac Economics that 24 percent of must-run starts by regulated utilities were unprofitable, compared with only 9 percent by merchant suppliers. Though this rate fell to 9 percent percentby regulated utilities in 2022, merchant plants had no unprofitable starts that year.
Proponents say must-run designations are necessary because MISO commitment and dispatch parameters are ill-suited to the operations of coal plants, which can have high start-up and shut down costs, fixed fuel contracts (take or pay) and less flexible ramping rates. But some utilities in MISO, e.g. Xcel Energy in Minnesota, change this practise by running their two remaining coal units in a more economic, seasonal operation.
