Coal-Biomass Co-firing within Renewable Portfolio Standards: Strategic Adoption by Heterogeneous Firms and Emissions Implications.

• Date: 01 September 2023
• Author: Valqui, Brayam

1. INTRODUCTION

   The electric power sector is in the process of a major transition in its composition of fuels, technologies, and regulatory environment, and this transition is likely to accelerate in the next few decades. Changes in the relative shares of different energy sources are being driven by a variety of factors, including economic factors, such as low natural gas prices, and environmental regulation, such as renewable portfolio standards. In the U.S., electric power generation from coal fell from 1756 million MWh in 2009 to 965 million MWh in 2019 (EIA, 2021). At the same time, generation from solar energy in the U.S. grew from 0.9 million MWh to 72 million MWh and non-solar and non-hydro renewable generation grew from 143 to 368 million MWh over the same time period. With efforts to reduce greenhouse gas emissions from electricity in the coming decades, these trends are likely to continue. A recent analysis of potential C[O.sub.2] mitigation options in the U.S. electric sector projects further reductions in coal generation under a range of carbon emissions policies (Young and Bistline, 2018).

   A widely used regulatory instrument for influencing energy technology and emissions is the renewable portfolio standard (RPS). sometimes called a renewable energy standard (RES). As of 2021, 28 states in the U.S. have mandatory RPS legislation, and another 3 states have voluntary RPS legislation (NCSL, 2021). The details of the RPS vary widely across jurisdictions in several key dimensions, including which technologies are eligible, which entities are affected, and whether cost caps on electricity prices are included. One other key difference across RPS implementations is whether there are quantity requirements for specific technologies--known as 'carve-outs'. More than 20 states have specific carve-out provisions for individual technologies (NCSL, 2021).

   There are many potential objectives behind RPS legislation, including job creation, market creation, reduction of technology costs, and greenhouse gas emissions reductions (Young and Bistline, 2018). There has been extensive economic analysis of the impacts of RPS in the past decades. Many studies have investigated the impact of RPS on electricity prices (e.g., Fischer, 2010; Fischer and Newell, 2008; Nogee et al., 2007; Wiser and Bolinger, 2007). Other studies have explored the distributional impacts of RPS design on member states of the EU (Landis and Heindl, 2019), individual U.S. states (Perez et al., 2016), or households by income level (Bohringer et al., 2017). Young and Bistline (2018) applied the US-REGEN model to compare a range of RPS to technology-neutral emissions policies that target equivalent reductions and showed that technology targets approximately double the cost of emissions reductions. Fleten et al. (2018) used a Bayesian multilevel model to investigate the incentives for upgrade investments in hydroelectric sources from RPS.

   Although most RPS legislation and analyses focus on wind and solar energy as the primary targets, biomass co-firing with coal in power production has received attention by some as a candidate for support under renewable energy incentives. In particular, at least three states in the U.S. (NCSL, 2021) and several EU members states, including Denmark, The Netherlands, and Poland (Bertrand. 2019), have made biomass co-firing eligible under RPS and in some cases can receive targeted subsidies as well. As of 2012, there were 86 coal-fired power plants with some degree of biomass co-firing in the U.S. (Aguilar et al., 2012). Biomass co-firing has been promoted as a way to prolong the life of existing coal-fired power plants in light of the rapid retirement trends described above and the associated employment and regional economic impacts (e.g., Tillman., 2000; Stutzman et al., 2020). Biomass co-firing is also seen as a way to develop markets for biomass fuels for the electric sector (Baxter, 2005). The use of renewable energy targets and incentives to support biomass co-firing has been justified based on arguments that carbon emissions would be decreased, relative to coal generation without biomass (e.g., Tillman.. 2000: Demirbas. 2003: De and Assadi, 2009; Lintunen and Kangas, 2010).

   Much of the academic and technical literature has focused on the technical feasibility, engineering costs, or resource availability of coal biomass co-firing (e.g., Tillman., 2000; Demirbas, 2003; Goerndt et al., 2013; Liu et al., 2014). Some economic analyses have focused on a single representative power plant (e.g., Nasiri and Zaccour, 2009; Tan et al., 2017). All of the engineering-based and micro-level analyses cited above conclude that coal biomass co-firing would reduce carbon emissions relative to a coal plant without biomass. In contrast, regional economic analyses that consider an entire power system have reached conflicting conclusions about the emissions impact. Lintunen and Kangas (2010) simulated the Finnish power system and explored the relative impacts of a subsidy for renewable energy that included biomass co-firing compared to a subsidy that covered all technologies except biomass co-firing, both in the context of a carbon price. Their study finds benefits in terms of reduced [CO.sub.2] emissions. Similarly, Liu et al. (2014) simulated the potential for co-firing coal plants in Missouri, and found that emissions can be reduced, but this outcome depends on the presence of other emissions policies, such as a carbon tax or a cap, as well as subsidies for the technology. In contrast, the study by Bertrand (2019) simulated the power systems of Germany and France with renewable energy standards that did or did not include coal biomass co-firing under the standard. Their results showed that C[O.sub.2] emissions increase when biomass co-firing is eligible under the RES. Their model focused on long-term investment and found that the mechanism for increased emissions is a crowding out of investment in wind and solar by the coal-biomass investments.

   Given the conflicting findings among studies, we focus on the question of whether allowing coal-biomass co-firing under an RPS target would increase or decrease C[O.sub.2] emissions. Our contribution is to include two critical features of electricity markets that are absent from previous studies. First, we explicitly consider that the adoption decision by any coal plant to retrofit with biomass co-firing is voluntary, and therefore subject to strategic considerations by each firm. In contrast, many previous studies use engineering technical efficiency as the criterion for selecting which units will be retrofitted with co-firing and assume that all units are converted to co-firing if technically efficient (e.g., Tillman., 2000; Demirbas, 2003; Goerndt et al., 2013; Johnston and Kooten, 2015). Other studies have used cost minimization models to represent electricity markets (e.g., Lintunen and Kangas, 2010; Liu et al., 2014; Bertrand, 2019). Although cost minimization is a useful proxy for a perfectly competitive electricity market, the prevalence of strategic bidding behavior in electricity markets is well-established (e.g., Gabriel et al., 2012; Hobbs, 2001; Ventosa et al., 2005). The fundamental economic idea of marginal cost pricing in electricity market design (e.g., Joskow and Schmalensee, 1983; Schweppe, 1988; Wilson, 2002) provides the mechanism by which strategic bidding can create market power and increase profits (e.g., Bushnell and Oren, 1994; Borenstein and Bushnell, 1999; Hobbs, 2001). Specifically, because system operators generally schedule units from lowest to highest marginal cost (the "merit order"), large deviations between generator bids and their true marginal cost are a potential means to attempt to exercise market power. Much of the academic and regulatory attention to this issue has focused on mitigating market power in how generators bid into energy markets, and many markets use market monitors or other means to mitigate market power in electricity markets.

   Aside from bidding behavior, firms' investment decisions can also affect their own profits and the profits of the other generators. If those investments change the marginal cost of an existing unit or introduce new units, this will affect the dispatch order among units and may affect the prices as well (e.g., Ehrenmann and Smeers, 2011; Wogrin et al., 2012; Kazempour et al., 2013). Unlike bidding in day-ahead or real-time markets, there are fewer mechanisms to mitigate market power in investments. In addition to conventional sources of electricity, recent analyses have investigated the role of investment in renewable generation in the exercise of market power (e.g., Traber and Kemfert, 2009, Green and Vasilakos, 2010; Tanaka and Chen, 2013). Given the potential for strategic behavior in electricity markets, we study the impacts of coal biomass co-firing when adoption by each profit maximizing firm is voluntary. Because all sources of electricity compete on the basis of marginal cost, one cannot assume that production from coal-biomass necessarily displaces conventional coal; the displaced generation must be determined endogenously by simulating market clearing in a competitive electricity market.

   The second contribution of our study is to explicitly represent the intertemporal variability in power systems and the relative flexibility across technologies. It has long been known in the engineering literature that a physically realistic representation of power system dynamics must account for the chronological patterns of demand and intermittent renewable generation and for the constraints of each generation technology in terms of its feasible intertemporal operations (e.g., Lu and Shahidehpour, 2005; Wu et al., 2007; Poncelet et al., 2020). More recently, the importance of these dynamics has been demonstrated in economic analyses (e.g., Merrick, 2016; Bistline, 2017). For example, a coal-fired power...