Co-firing Coal with Biomass under Mandatory Obligation for Renewable Electricity: Implication for the Electricity Mix.

AuthorBertrand, Vincent

    In the last few years, co-firing coal with biomass has become very popular in the European power sector, where firms have to comply with stringent policies to reduce C[O.sub.2] emissions and increase their output of renewable electricity. Co-firing provides short-term opportunities for increasing the share of renewable energy sources (RESs) and reducing C[O.sub.2] emissions in a very cost effective way through conventional technologies that are not subject to problems of intermittency and that do not require additional investments.

    In addition to exemption from surrendering C[O.sub.2] allowances under the European Union Emission Trading Scheme (EU ETS) when burning biomass (equivalent to a zero emission factor), several European states have implemented arrangements to include co-firing in their support schemes for renewable electricity (e.g. Poland, UK, Denmark, Netherlands), which raised concerns about the consequences for the contribution from coal to the electricity mix (even through co-firing with biomass) and the resulting C[O.sub.2] emissions. As recently pointed out in debates on energy agreements in the Dutch parliament, it may seem strange that some coal plants are set to close down due to environmental regulation while the same units can receive subsidies when co-firing biomass. This raises questions about the actual incentives to invest in traditional RES technologies (e.g. wind, solar, dedicated biomass units) to meet European targets and the consequences for future energy mixes.

    In the same way as for natural gas, co-firing has often been pointed to by practitioners from the energy industry as a transitional technology, which may limit the C[O.sub.2] emissions from existing power fleets in the short run, before deployment of a true energy transition in the long run, with a carbon-free power sector. However, whereas co-firing reduces the carbon intensity of coal plants (compared with the classical configuration when coal is the only input), it still generates C[O.sub.2] emissions. Hence, if coal is maintained and co-firing diverts investments away from traditional RES, it is to be expected that C[O.sub.2] emissions from electricity will be higher in the long run (compared with a more radical energy transition in which pure renewables dominate the fleet of power plants). Accordingly, any policy that promotes co-firing as a renewable may result in higher C[O.sub.2] emissions in the long run, if it gives incentive to use coal plants under co-firing instead of investing in the RES carbon-free technologies. In this context, this paper aims to investigate what would happen if co-firing, which is thought of as a transitory option by some (but also receives support from renewable schemes in some countries, see section 2), is continued and becomes a long-term solution. (1) We focus on European countries with simulations for France and Germany. However, beyond the case of Europe and other developed countries, we believe this paper may help to understand what could happen in developing and emerging countries if co-firing is used to develop RESs. Given the high share of coal in the generation mixes of these countries, this may be a big question in the future. This paper provides some insights that may help to anticipate this issue.

    The question of the consequences of promoting co-firing as renewable electricity has attracted little attention in the economic literature. To date, to the best of our knowledge, the only contribution comes from Lintunen and Kangas (2010) who provides a theoretical model to analyze the effect of co-firing in a stylized and simplified power system. The authors consider profit maximizing power producers that optimize production and investment decisions so as to meet static power demand. Investments in renewables are modeled as demand for new wind turbines (the only renewable technology in the analysis) that can increase the production capacity with the aim of meeting the static power demand at the lowest cost. Results show that promoting co-firing as a renewable decreases investments in pure renewable technology, whereas the C[O.sub.2] intensity of electricity is not significantly impacted. However, although Lintunen and Kangas (2010) illustrate their results through a numerical application with parameters reflecting the Finnish power sector, they fail to provide comprehensive estimations of investment decisions over a complete power system management including elements such as a dynamic time horizon, the decommissioning of old capacities, or increasing demand for power. Notably, their modeling approach with a simplified power system cannot be used to investigate the consequences for long-term C[O.sub.2] emissions when the electricity mix is continuously modified by policies promoting co-firing against pure renewables and carbon-free technologies. Considering a more detailed treatment of power systems through simulations with a dynamic time horizon is likely to produce more significant effects when co-firing steadily displaces traditional RES technologies over time, resulting in a power plant fleet that is more carbon intensive in the end. This is the starting point of our analysis, which extends the previous contribution by Lintunen and Kangas (2010).

    Compared with previous work, this paper uses a simulation approach to analyze the consequences for the electricity mix when co-firing is recognized as renewable electricity. We use the Green Electricity Simulate (GES) model, which is a simulation model for electricity designed to focus on biomass-based electricity and co-firing in European countries (Bertrand and Le Cadre, 2015). In order to assess the effect of promoting co-firing as a renewable option, we run the model with and without co-firing in the set of RES technologies that are accounted for to meet the RES targets. Our simulations rely on a detailed representation of the power system, which can be used to derive more general results taking into account elements such as a dynamic time horizon, the decommissioning of old capacities, rising demand for power or increasing renewable targets. This extends the study by Lintunen and Kangas (2010).

    As an illustration, we provide simulations for France and Germany, which offer good cases of study for our analysis because they have large coal capacities (even in France where the coal capacity is not negligible in volume with respect to other European countries, see Table 3) and because no support scheme for co-firing has been implemented in these countries so far. Hence, France and Germany provide relevant counterfactuals with which to investigate the consequences of implementing such provisions that recognize co-firing as renewable electricity. The case of France is also interesting regarding the effect of nuclear reduction that may greatly impact the electricity mix in this country. Whereas French electricity has historically been highly dependent on nuclear power, a law on "energy transition" was passed in 2015, which aimed at reducing the share of nuclear power by 2025. (2) Although the full application remains uncertain, such a reduction of French nuclear power combined with the RES targets is likely to be offset by some RES power plants, to which co-firing may contribute if counted as a renewable. This is something of interest for our study. (3)

    Results confirm that recognizing co-firing as an RES would jeopardize investments in traditional RESs, which would be largely ousted in favor of increased generation from existing coal power stations under co-firing plus some new investment in coal. The additional coal investments are more substantial in France because French coal capacities are lower than German capacities, thus limiting the scope for using existing coal plants to meet the RES targets through co-firing. The additional French coal capacities may reach 18 GW when the model is implemented with exogenous decommissioning of old nuclear power plants. Comparatively, the maximal additional coal capacity in Germany is close to 14 GW when co-firing is included in the set of RES, which corresponds to a progression of about 27% for coal in 2030 compared with the initial capacity, whereas the same progression is more than 243% in France when old nuclear power stations are decommissioned (107% when nuclear plants are prolonged), with almost 26 GW of coal accounting for 20% of the 2030 French capacity mix. Hence, including co-firing in RESs may more radically change the French capacity mix, in which coal may change status and become an important source of French electricity output.

    Regarding C[O.sub.2] emissions, results indicate that recognizing co-firing as an RES generates sharp increases because of reduced traditional RESs (carbon-free) and more coal in electricity. This effect is more significant in Germany than in France due to its much greater coal capacities. Moreover, in the case of France, the magnitude of the carbon increase depends largely on the share of nuclear power, with fewer increases when old nuclear power stations are prolonged. Finally, we show that including co-firing in the set of RESs reduces the overall costs associated with managing the power system, because this allows compliance with the RES constraint through a conventional and low-cost option that does not require additional investments. When balancing this cost saving against the increased social cost from higher C[O.sub.2] emissions, results show that the cost saving may be dominated by the increased carbon cost with a high carbon valuation around 100 Euros per tC[O.sub.2]. An exception comes from France when the service life of ageing nuclear power stations is prolonged. In this case, the cost saving is very high and the increased C[O.sub.2] emissions are slight (because massive cheap and carbon-free nuclear power continues to be used for base-load generation) with the result that the cost saving always dominates the...

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