According to IEA, for the very first time, on 28 August 2023, the United States met more than of half of its electricity demand from natural gas. It encapsulated a summer during which gas-fired electricity generation grew dramatically. In just the past two years, its share of the power mix rose from 40 to 45 percent for the summer months of July and August.
A confluence of factors, including a significant drop in the price of natural gas, coal plant retirements, low output from wind and hydropower, and high cooling demand in some regions caused the share of gas to increase. By contrast, the share of coal-fired generation declined from 23 to 17 percent over the same period.
The record share of natural gas in the power mix continues the long term trend toward gas caused by the shale revolution. It comes alongside federal and state level environmental policies that pose significant risks to coal in the United States power sector.
Recent strong growth in domestic gas production combined with above-average storage levels after the 2022-2023 winter season caused prices to decline by 60% through Q1-3 2023 at Henry Hub. The steepest declines in natural gas prices were recorded in gas producing areas, including Texas, Louisiana, and the East Coast, as the region benefitted from a particularly mild Q1 2023. The price swing sparked a switch coal to gas-fired generation in the power sector.
The average utilisation of coal-fired generation in the United States declined from 48.5% in the first seven months of 2022 to 39.8% in the same period in 2023, while the capacity factor of gas-fired generation increased from 54.6% to 57.7% in the same period.
Coal-to-gas switching was particularly noticeable in regions with wholesale markets, where competition between resources is based on short-run marginal cost economics. We estimate that coal became more competitive in 2021 and 2022, particularly in the Midwest (MISO) and Central (SPP) regions due to the jump in gas prices. During 2023 gas became more competitive again as its price fell.
In the Central region, coal-fired generation, which is predominantly procured on long-term contracts, remains comparatively lower due to lower coal prices. Despite this, coal-fired generation was down about 20% in the first three quarters of 2023 in the Central region and gas-fired generation was up by about 15%, as lower gas prices allowed some of the more efficient gas-fired units to displace older and less efficient coal plants.
There is also evidence that market type is a factor driving the switch between coal and gas. For instance, natural gas is replacing coal at faster rates in regions with liberalised markets than in regions with vertically integrated utilities. Coal output increased by 7% in regions with vertically integrated utilities during July and August 2023 compared to last year, while decreasing by 15% in regions with liberalised markets. Gas generation is up 5% between 2019 and 2023 in regions with vertically integrated utilities while it is up 22% in regions with liberalised markets.
Potomac Economics, the independent market monitor for the Midcontinent ISO (MISO)2, studied the economic impact of regulated utilities using must-run designations to commit units at rates much higher than merchant, or competitive, suppliers, in the MISO region, including at times when fuel and electricity prices suggest that running coal plants is unprofitable. In the period from 2017-2020, Potomac estimates that 24% of must-run starts by regulated utilities were unprofitable, compared to only 9% by merchant (competitive) suppliers. While this rate declined to 9% by regulated utilities in 2022, merchant plants had no unprofitable starts in the same period.
Some utilities have claimed that must-run designations are necessary because MISO commitment and dispatch parameters are ill-suited to the operations of coal plants, which can have high startup and shut down costs, fixed fuel contracts (take or pay) and less flexible ramping rates. However, some utilities have changed this practice. For example, Xcel Energy in Minnesota switched to economic dispatch and seasonal operation of its two remaining coal units in 2020 after stakeholders raised concerns about the practice during its integrated resource planning process.
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.
Over this summer, US coal power plants were required to change the way they operate. For instance, on the fourth week of August – when natural gas for power reached its zenith, only about 80 GW were used for baseload compared to about 95 GW last year on the same week. 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.
This highlights the necessity for power plants originally designed for baseload operation to transform their functions to address new flexibility requirements. As a result of their more intermittent use, power plant operators now face new challenges including handling increased stress on components and turbine shells, as well as dealing with corrosion of turbine parts. These challenges can lead to higher outage rates or premature end-of-life, which may occur before their intended operational lifespan.
Operating flexibly, in load-following or cycling mode, in response to economic conditions also reduces plant efficiency. An EPRI study shows an efficiency penalty of around 40% (14 000 Btu/kWh v 10 000 Btu/kWh) when plants are operating near minimum load condition compared to baseload operation, which adds between USD 3 to12/MWh to the operating cost of the unit at current coal prices.
Strong renewable capacity additions (9 GW for wind and 18 GW for solar PV year-on-year) were not enough to compensate for coal retirements and high demand, letting natural gas fill the gap. In addition, wind, now the leading source of renewable energy in the US, underperformed in the summer – the average capacity factor of 26% was near its lows of the past five years.
But while carbon pricing is a factor in driving emissions downward in the states participating in the Regional Greenhouse Gas Initiative (RGGI), its impact is minor compared to other economic and policy factors. Whether or not the price of carbon is strengthened, the trajectory of coal and gas generation, and emissions, in the United States will depend to a large extent on how the following policies and measures develop in the coming years:
- Renewable incentives – federal tax credits and state-level programmes have driven widespread adoption of renewable energy and their deployment will displace fossil fuel generation when available due to having low or zero marginal costs.
- Environmental regulations – the federal government has passed measures targeting reductions in SO2, NOx, mercury, toxic metals, and coal ash that raise the cost of burning coal, either through the need to purchase allowances or install control equipment.
- Electricity grid development – the electricity grid will need to be expanded to successfully integrate renewable energy sources, particularly wind and solar, and avoid curtailment as they grow as a share of the energy mix.
- Power market design – the design of price setting mechanisms, including the level of price caps and adequacy payments, will affect the generation mix by valuing attributes of power generation that can vary across types.
