We’ve reached a coal cost crossover with renewables – now what?
A new analysis released today from Energy Innovation and Vibrant Clean Energy (VCE) indicates we’ve reached a coal cost “crossover” in the United States. Due to recent rapidly declining wind and solar costs, the combined fuel, maintenance, and other going-forward costs of most existing coal plant generation is now more expensive than the all-in costs of new wind or solar projects.
The analysis is simple, but compelling. Similar to pioneering analysis in Colorado, our analysis compared going-forward operating costs of coal plants to the levelized cost of energy (LCOE) for new wind and solar within 35 miles of the plant. The analysis raises substantial questions for policymakers and utility stakeholders across the U.S.:
- Would replacing existing coal with new wind or solar immediately result in cost savings for customers?
- What are the financial implications of billions in uneconomic assets on utility books?
- To what extent can local renewable resources also replace tax revenues, jobs, and provide economic development to coal plant communities?
- What institutional and regulatory barriers are preventing the retirement of these uneconomic assets?
The analysis suggests local decision-makers should consider plans for smoothly shutting down these uneconomic plants—assessing options for reliably replacing that electricity. Ultimately, this report begins a longer conversation about the most cost-effective coal replacement, which may include combinations of local or remote wind, solar, transmission, storage, and demand response.
To determine which coal plants are facing this cost crossover with renewables, Energy Innovation partnered with VCE to compile a national dataset of coal, wind, and solar costs. For simplicity, the modeling compares each coal plant’s marginal cost of energy (MCOE) to the lowest LCOE of a wind or solar resource within 35 miles of that coal plant. Restricting replacement to local resources makes this analysis conservative, considering most coal, wind, and solar all travel from more remote locations to load centers via transmission.
VCE leveraged its uniquely granular data on wind speed and solar irradiance, creating high-resolution maps of 2018 wind and solar LCOE. These were used as the basis for comparing coal plants with local wind and solar, taking federal tax credits into account.
2025 LCOE figures were based on costs in the National Renewable Energy Laboratory (NREL) Annual Technology Baseline low cost case.
Coal MCOE data were extracted from different publicly available sources, including Energy Information Administration generator data and FERC Form 1 utility filings. Because such data can be inaccurate and inconsistent, there is unavoidable uncertainty around the exact MCOE of each coal plant.
Our research finds that in 2018, 211 gigawatts (GW) of existing (end of 2017) U.S. coal capacity, or 74 percent of the national fleet, were at risk from local wind or solar that could provide the same amount of electricity at a lower cost. By 2025, at-risk coal increases to 246 GW – nearly the entire U.S. fleet.
Furthermore, 94 GW of existing U.S. coal capacity was deemed “substantially at-risk” from new local wind and solar in 2018, meaning these renewables could undercut ongoing costs of existing coal by at least 25 percent. By 2025, substantially at-risk coal increases to 140 GW – almost half the U.S. fleet – even as federal renewable energy tax credits phase out. Even given uncertainties in publicly available coal cost data, the tier of coal plants “substantially at-risk” could, with high confidence, be replaced with renewable energy at an immediate cost savings.
|MW||RE Cost||Wind (2018)||Solar (2018)||Wind (2025)||Solar (2025)||Combined (2018)||Combined (2025)|
|Coal substantially at risk||>25% less than coal||49,165||69,117||75,778||111,077||93,812||140,073|
|Coal at risk||0-25% less than coal||118,085||178,871||167,201||229,001||210,842||246,306|
|Coal potentially at risk||0-25% more than coal||168,563||107,777||119,447||57,647||75,806||40,342|
|Coal deemed safe||>25% more than coal||101,792||49,620||46,289||15,706||21,608||7,866|
The VCE dataset reveals the going-forward costs for the vast majority of coal plants fall between $33 – 111 / megawatt-hours (MWh). 2018 solar costs are more tightly clustered, between $28 – 52 / MWh, while wind costs vary more widely from $13 – 88 / MWh based on locational resource quality, with a high number of very costly outliers in windless regions.
Putting the findings in context
The cost crossover between new renewables and existing coal is just one important part of shutting down obsolete coal plants – replacing uneconomic plants with new wind and solar energy is much more complex in practice. This report acts as a conversation primer for stakeholders and policymakers where the math points to cheaper options that could replace coal plants at a savings to customers now. Any decision on how to proceed will require further modeling of grid needs and reliability services, as well as the cost of potential renewable replacements outside of the 35-mile maximum radius considered in this report.
The first step for merchant owners, utilities, regulators, and other stakeholders is taking a hard look at coal retirement. For regulated utility assets, integrated resource plans (IRP) and other long-term planning analytical efforts should always include coal retirement scenarios. Indiana utility NIPSCO has shown how smart analysis can flip planning directions: Their most recent planning effort recommended replacing all their coal in the next decade with renewable energy, including wind and solar, along with battery storage. Consumer advocates elsewhere should be asking whether coal plants receiving state-regulated cost recovery but operating in transparent, competitive regional energy markets should be allowed to run at loss to the detriment of consumers’ pocketbooks.
Consumer advocates faced with utility inertia, environmental advocates concerned about unpriced coal externalities, and advanced energy solutions providers eager to open opportunities can push back against reliability or dispatchability arguments simply by comparing economics. The cost of any single coal plant compared with a combination of local (or distant but easily accessible) renewables and complementary demand-side and storage resources, or virtual power plants (VPP), can make a powerful case. If a VPP drop-in replacement also proves more economic than an at-risk coal plant, it can provide an estimate of the minimum savings available from coal plant retirement.
A more holistic approach leveraging other existing assets on the grid can prove to be even cheaper for integrating low-cost renewables. For example, a VCE study showed how Colorado could replace all its aging coal plants with a mix of wind, solar, natural gas, and storage to save the state’s electric customers more than $250 million annually without affecting reliability. This example is especially notable in the context of the coal cost crossover analysis, because Colorado appears on the tail end of states with coal plants at risk from renewables within 35 miles.
In fact, our cost crossover analysis flags fewer Western plants as at-risk than the reality. High-quality wind resources in the $15 – 25 / MWh range are often accessible through existing and new large transmission projects in the West, and the hyper-local nature of this analysis leaves these options on the table. Understanding the geographic dimensions of renewable costs – the opportunities visible in our maps – and proper modeling are therefore key to planning analysis and decision-making.
Different approaches in different markets
Depending on the market, it may be particularly important to consider not just at the MCOE of a given coal plant, but also at the remaining balance of long-term costs. This is especially true for coal plants in vertically integrated jurisdictions, which dominate the Southeast and West, and in hybrid setups where coal plants participate in wholesale markets but long-term costs are covered by ratepayers (e.g. many states in Southwest Power Pool and Midcontinent Independent System Operator). Customers are on the hook for these costs; if an at-risk coal plant retires but is not paid off, significant incremental savings await ratepayers, especially if the remaining amortization balance can be refinanced at a lower cost than typical utility rates of return.
In restructured markets, particularly PJM Interconnection and ERCOT, market design matters. ERCOT has already seen a rapid movement away from coal, as the energy-only market design has allowed new gas and wind to force out high-MCOE coal plants while maintaining reliability. But in PJM, capacity market revenues are keeping these “zombie” coal plants around. The swath of red circles in the Ohio Valley signal that those market institutions, not just economics, are creating artificial barriers to coal exit and renewable entry.
Starting the conversation
Stakeholders are beginning to break through on coal retirement arguments by showing coal can be replaced by new wind and solar at immediate savings, but it hasn’t been easy. Leadership from the Sierra Club and others in the Northwest led Pacificorp to analyze and ultimately release an analysis deeming half of its coal plants were uneconomic compared to new renewables. In Colorado, a consortium of NGOs analyzed coal versus renewables economics, providing a strong case for proposed legislation that finances a faster transition away from these assets. NIPSCO’s integrated resource planning process is following a similar track.
In each case, quantitative analysis of these coal plants compared to new options formed the basis of a larger retirement conversations. Similar analysis can be a starting point to identifying the most at-risk plants, though more in-depth examination of coal plant numbers, particularly with utility assistance, can facilitate a more transparent, inclusive dialogue. In a separate set of reports, APP experts Ron Lehr and Mike O’Boyle lay out a more comprehensive suite of options to balance consumer, community, environmental, and utility concerns through this financial transition.