CEEPR Working Paper 2021-013, September 2021

The costs of replacing dispatchable power sources based on fossil fuels with intermittent renewable power sources remain controversial. The life-cycle cost of renewables, in particular wind and solar power, is known to have fallen substantially over time (Jansen et al., 2020; Steffen et al., 2020; Rubin et al., 2015). Once deployed, these power sources also have effective priority in the marketplace due to their zero short-run production cost. In contrast, the life-cycle cost of traditional dispatchable generation sources tends to increase due to lower capacity utilization as these facilities are increasingly relegated to delivering output during hours when intermittent renewables are not available (Bushnell & Novan, 2021; Kök et al., 2020).

While all of these cost effects favor renewable power, countervailing effects emerge on the revenue side (Millstein et al., 2021; Das et al., 2020). First, renewables increasingly experience a “cannibalization” effect in jurisdictions where significant additions of wind or solar power capacity cause market prices to fall during hours when renewable sources are at peak capacity (López Prol et al., 2020, Hirth, 2013). A second effect favoring the value generated by dispatchable energy sources is the price premium they earn at times of limited supply capacity due to the intermittency of renewables (Antweiler & Muesgens, 2021).

This paper provides an integrated assessment of the cost and value dynamics of solar photovoltaic (PV), onshore wind, and natural gas combined-cycle (NGCC) power plants in the context of the wholesale electricity markets in Texas and California. Our empirical findings are based on a novel metric termed the Levelized Profit Margin (LPM). This metric is shown to capture the relevant unit economics in terms of dollars per kilowatt-hour (kWh) for assessing the competitiveness of alternative power generation technologies. Key to the calculation of this profit margin is that the average market price for electricity in a particular year and jurisdiction is adjusted by a technology-specific factor that captures the covariance between real-time fluctuations in electricity prices and optimized capacity utilization rates. The economic profitability of a power generation facility thus hinges on a weighted average of the future technology-adjusted unit revenues to exceed the life-cycle cost of energy generation. A dynamic LPM analysis thus integrates the countervailing competitive effects due to technological improvements, shifts in capacity utilization, cannibalization, and the dispatchability price premium.

Our findings indicate that for the most part new capacity investments in both renewables or natural gas plants undertaken during the years 2012-2019 are thus far not on track to become economically profitable. This finding may reflect that new investments were based on criteria that extend beyond expected net present values, such as renewable portfolio standards in California or the presence of “impact investors”, such as technology firms investing in renewable energy projects (Borenstein, 2012; Comello et al., 2021).

At the same time, our results indicate that the estimated LPMs of new wind and solar energy projects have improved considerably and, by 2019, approached or exceeded the break-even value of zero. This finding is primarily due to substantial reductions in the life-cycle costs of these power sources. In California, the LPM improvements of solar PV have been partially offset by a tangible cannibalization effect (Woo et al., 2011, 2016). In contrast, solar PV has achieved a growing price premium in Texas, a state where solar power today still has a relatively modest market share.

For NGCC power plants in California, we find that falling capacity utilization rates have been counterbalanced by increasing dispatchability price premia. These two countervailing trends have resulted in steady but distinctly negative LPMs. In Texas, by contrast, profit margins for NGCC plants have improved due to higher utilization rates at times of higher power prices. This finding is consistent with the general observation that in Texas natural gas and wind power have gradually replaced coal-fired generation (Fell & Kaffine, 2018).



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Further Reading: CEEPR WP 2021-013

About The Authors

Gunther Glenk is an Assistant Professor for Business at the University of Mannheim and a Climate Fellow at Harvard Business School. His research examines questions related to corporate transitions toward zero net emissions. Specific topics include the economics and management of corporate carbon emissions, decarbonization and sustainable energy technologies, and incentives for climate action. Recent work has focused on the competitiveness of clean energy technologies, such as energy storage, renewable hydrogen, and electric mobility. Professor Glenk received his B.Sc., M.Sc., and Doctorate in Management and Technology from the Technical University of Munich.

Stefan Reichelstein is the William R. Timken Professor of Accounting, Emeritus at Stanford Business School, and director of the Mannheim Institute for Sustainable Energy Studies (MISES). His research focuses on cost and profitability analysis, decentralization, internal pricing, and performance measurement. His research projects span analytical models, empirical work, and field studies. Insights from his research have been applied by a range of corporations and government agencies. In recent years, he has also studied the cost competitiveness of low-carbon energy solutions with a particular focus on solar PV and carbon capture by fossil fuel power plants. Professor Reichelstein received his Ph.D. from the Kellogg School of Management at Northwestern University in 1984. Prior to that, he completed his undergraduate studies in economics at the University of Bonn in Germany.