Ahead of the S&P Global Platts Global Power Markets conference in Las Vegas, April 8-10, 2019, The Barrel presents a series of articles on the global and US electricity sectors. Here, Morris Greenberg explores the drivers behind US coal generation retirements in recent years. April 2, 2019
The aging US coal fleet is being squeezed from all sides, with policy, cheap domestic gas supply and developments in clean energy generation all contributing to fast-paced closures.
S&P Global Platts Analytics data show that since peaking at 317 GW at the end of 2011, US generating capacity with coal as the primary fuel fell by 73 GW, or 23%, due to retirement of 61 GW and primary fuel conversion – mainly to natural gas – of 16 GW. This was offset by additions of 4 GW.
Most of the additions were made early on in this eight-year period. Coal-fired generation has fallen even more steeply than capacity, with a decline of 33.5% between calendar years 2011 and 2018. The drop reflects a reduction in average capacity factor (utilization rate) from 62% to 52%.
While capacity factors have stabilized during the past three years, announced plans for retirement of around 20 GW and conversion of around 5 GW indicate that, without some form of policy support, capacity declines will continue.
Indeed, the announcements may only reflect the tip of an iceberg that includes many more GW of capacity at risk. To get a better handle on that number, it is useful to review first the economics of retirement and then factors that have driven the restructuring observed to date. These factors are: an aging coal fleet; stagnating demand; low natural gas prices; environmental regulation; and finally, cost declines and policy support for clean energy.
The decision to permanently retire a merchant coal unit, or really any merchant unit, is made by comparing the present value of future revenues from sale of energy, capacity and ancillary services to the present value of costs including fuel, non fuel variable operating and maintenance expense, fixed operating and maintenance expense, and required capital spending. For regulated units, the relevant measure is the present value of revenue requirements. The calculations are similar if replacement energy and capacity is acquired from the market. There are several factors that play into this calculation and have driven the restructuring seen in the US market in recent years.
Of the 317 GW of operable capacity in 2011, 125 GW exceeded 40 years of age and 50 GW exceeded 50 years. Older units are less efficient, require higher spending per unit of capacity to maintain availability, and tend to face higher capital requirements for environmental retrofits, leaving them more vulnerable to changes in market conditions.
Stagnating power demand
A combination of improving energy efficiency among consumers combined with rising behind-the-meter generation has led to stagnating demand, leaving US retail electricity sales virtually unchanged from 2011 to 2017. Weak demand depresses energy and capacity prices for all generation, but coal units were exposed due to the factors that follow.
Lower natural gas prices
Low natural gas prices have had a major impact on the erosion of US coal-fired capacity. The direct impact is the conversion of existing capacity from coal to gas. But there is also an indirect impact, as lower electric energy and capacity prices reduce the value of coal capacity and may boost operating costs due to operational changes.
Since 2011, rising gas supply associated with shale gas development has allowed US consumption of gas for power generation to increase by 38%, from 21 Bcf/d to 29 Bcf/d and accommodated higher net exports with no upward pressure on prices.
Accounting for permitting, financing and engineering, the development cycle for gas capacity ranges from about two years for fuel conversions, to five years for greenfield development. As a result, while gas prices have an immediate impact on energy prices, the impact on capacity prices and decisions to build or retire plants occurs with a lag of that duration.
A three-year moving average of Gulf Coast gas prices lagged by two years peaked in late 2010 near $8/MMBtu, fell to the $3.50 range in 2015-17, and to the low $3 range in 2018. It will fall below $3/MMBtu this spring and likely remain there for several years. That means gas markets will remain a drag on coal unit economics for years to come.
Coal units must comply with air, water and solid waste emissions standards. Air emissions include sulfur dioxide, nitrogen oxide, particulates, mercury and other air toxics, and carbon dioxide. Water standards cover plant effluents as well as cooling water intake structures and temperature impacts. Coal combustion residuals are also regulated.
The Mercury and Air Toxics rule, which took effect in April 2015, was the most important regulation to impact coal capacity during the 2011-18 period, driving units facing high compliance costs to retire. In some cases, units that remained in service faced increased costs associated with operating emissions controls or purchasing coal additives to improve mercury capture.
While the Obama administration’s Clean Power Plan proposed in 2014 was never implemented, the potential for future carbon regulations must be considered in a decision to retire or maintain coal capacity, particularly if capital infusions are required. In addition, while the federal regulatory role is currently limited, carbon emissions caps are in effect in California and the Northeast, through the Regional Greenhouse Gas Initiative (RGGI), and several other states have emission reduction targets.
Cost declines and policy support for clean energy
A combination of falling costs and state, as well as federal, policy has led to rapid growth in US wind and solar generation. Solar PV costs have declined from about $4,000/kW-AC in 2011 to about $1,200/kW-AC at present. During the same period, onshore wind costs fell from over $2,000/kW to about $1,500/kW. In addition, the cost of battery storage that can help integrate intermittent renewables, particularly solar, has fallen dramatically.
States have played a role in renewables growth primarily through renewable portfolio standards (RPS), which mandate a certain proportion of renewables in the energy mix. Twenty-nine states and the District of Columbia currently have mandatory RPS. Qualifying technologies vary from state to state – though solar and wind qualify everywhere – and percentage requirements vary over a wide range. Based on current law, renewable generation to meet RPS requirements of load serving entities – that is, companies that provide power on a retail basis, mainly utilities but also unregulated marketers – will more than double between 2018 and 2030. Corporations in pursuit of sustainability goals have also stepped up their purchases of renewable energy, signing deals for over 6 GW of capacity in 2018 alone.
State support for merchant nuclear units challenged by weak margins may come at the expense of coal capacity. Unlike intermittent renewables, nuclear units provide significant capacity value – meaning they can provide energy whenever needed. New York and Illinois are already providing support, with New Jersey and Connecticut also moving down this path. Pennsylvania, home to 10 GW of nuclear capacity, may follow.
The federal role in promoting renewables has mainly been through tax credits, including production tax credits (PTC) for onshore wind and investment tax credits (ITC) for solar. Under legislation enacted in late 2015, wind projects starting construction in 2016 are eligible for a PTC of $23/MWh for 10 years; the value of the credit steps down for projects started in subsequent years and is phased out for projects begun after 2019.
The ITC is 30% for projects started by the end of 2019 and then steps down over the following two years with the residential credit expiring for projects begun after 2021 while the ITC for non-residential systems falls to 10%.
The cost of wind generation (including ROI) from projects qualifying for the full PTC in areas with high average wind speeds is in the $15-20/MWh range, competitive with the variable cost of coal and gas generation. The cost of solar PV qualifying for the full ITC in areas with high insolation is in the $25/MWh range. Variable production costs are lower, and producers are often willing to sell at negative prices to capture tax credits (in the case of wind) and renewable energy credits (used for RPS compliance).
Due to lower variable production costs, rising renewables generation will displace both coal and gas generation and result in lower energy prices. In addition, more extensive cycling of dispatchable generation to balance supply and demand will result in higher operating costs.
Despite its impacts on energy prices and operating costs, growth in renewables output by itself has not been a major driver of coal retirements because the resources do not provide much capacity value, and lost energy revenues can be partially recouped in capacity markets. That may change, however, with additional investment and the ability of battery storage to add capacity value. According to the American Wind Energy Association, there are 35 GW of wind capacity in advanced development and the Solar Energy Industry Association report 27 GW of solar projects with signed PPAs and another 37 GW announced.
While this discussion has been focused on US developments, the same factors apply elsewhere in the world as well, though their relative importance may vary. Europe, for example, is expected to see a significant reduction in coal-fired generating capacity during the next two decades. Slow demand growth, policy support for renewables, and explicit coal shutdown plans play a role. As a gas importer, gas prices tend to be higher in Europe, but the impact is offset by carbon allowance prices that boost the effective cost of burning coal relative to gas.
In Asia, the picture for coal is a little brighter thanks to high gas prices, faster load growth and looser environmental regulations. However, renewables are making inroads, particularly in China, causing growth in coal to slow.
Read more articles in this series:
Morris Greenberg, Senior manager, S&P Global Platts Analytics
Morris Greenberg is senior manager, North American electric power, at S&P Global Platts Analytics. Morris has been instrumental in the development of electric power market coverage during the past two decades. He currently oversees development of the electric power market forecasts and covers the WECC markets in written reports and presentations. Prior to joining S&P Global Analytics, he covered oil and gas markets for Lehman Brothers commodity brokerage and proprietary trading desks.