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Towards a Rational Bioenergy Policy Concept

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Concepts and Instruments for a Rational Bioenergy Policy

Part of the book series: Lecture Notes in Energy ((LNEN,volume 55))

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Abstract

This chapter derives recommendations for bioenergy policy, applying the theory-based analytical framework developed in Chap. 3 to the German case study. The focus is on recommendations for a rational bioenergy policy concept, which encompasses the definition of a system of consistent policy aims; the choice of allocative principles which determine what allocation mechanism is used primarily to implement aims; and the identification of suitable instrument types. Given the conflicting nature of policy aims, the establishment of a complete and coherent system of policy aims is found to be of particular importance. Also, requirements concerning the operationalisation of aims are discussed. In contrast to neoclassical recommendations, a theoretical case is established for a bioenergy mix combining governance structures comparatively close to markets, which leave technology choices to market actors, with more hierarchical interventions. Based on the analysis of what allocative principles are recommendable for different allocative challenges, perspectives for the further development of the German policy mix are discussed. Moreover, to demonstrate the applicability of the study’s analytical framework to more specific questions of instrument choice and design, recommendations for the bioelectricity sector are developed in greater detail. Three design elements are identified as particularly important: the choice between price, quantity and hybrid instruments; the design of a mechanism for technology differentiation; and the design of an adjustment mechanism. Based on a comparative analysis of institutional alternatives, recommendations are derived.

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Notes

  1. 1.

    While the EU-RED’s transport sector target is in principle technology-neutral, the absence of feasible RES alternatives makes it implicitly a biofuel-specific target (see 4.1.2.2).

  2. 2.

    In the longer term, electromobility may make a sizable contribution, but in this case, its GHG mitigation potential and even its classification as an RES technology depend on the source of electricity used, and therefore on the achievement of RES targets in the electricity sector.

  3. 3.

    The Combined Heat and Power Law (Kraft-Wärme-Kopplungsgesetz, KWKG) sets targets for an increase in the share of electricity from CHP (section 1 (1) KWKG), complementing RES and energy efficiency targets (see 4.1.1).

  4. 4.

    Parts of this section have been published in abridged form in Purkus et al. (2015).

  5. 5.

    An exception are perennial feedstocks such as SRC, where sizable upfront investments are required and land is tied up for several years; at the same time, the scope of applications is as of yet narrowly defined.

  6. 6.

    An abridged version of this section has been used in Purkus et al. (2015).

  7. 7.

    Price risks arise from imperfect knowledge about price developments in the electricity market, volume risks from imperfect information about the volumes of electricity that can be sold.

  8. 8.

    For technologies at a very early stage of development, R&D support may prove more appropriate than diffusion support.

  9. 9.

    Similarly, a uniform remuneration level not only for all bioelectricity technologies but for all RES technologies minimises overall private costs of RES generation in a static perspective.

  10. 10.

    In 2013, bioelectricity production received a remuneration sum of 4.06 billion euros under the FIT scheme, amounting to 29.65 % of total FIT payments, and 2.10 billion euros or 35.27 % of the payments under the market premium scheme (including flexibility premium payments) (50Hertz et al. 2014). In terms of electricity produced, bioenergy was responsible for 19,551,739 MWh or 34.96 % of the total amount of electricity remunerated under the FIT, and 16,644,366 MWh or 25.36 % of the total amount of electricity remunerated under the market premium scheme (ibid.).

  11. 11.

    However, the EEG surcharge’s share in consumer spending depends on income, and tends to be higher for low income households (Bardt and Niehues 2013: 215; Neuhoff et al. 2013: 46 f.)

  12. 12.

    For PV, a breathing cap had already been implemented in the “PV Novelle 2012”.

  13. 13.

    For the EEG 2009 and EEG 2012, these are: ≤150 kWel, ≤500 kWel, ≤5 MWel, ≤20 MWel of rated average annual capacity. In the EEG 2014, the demarcation was changed to ≤150 kWel, ≤750 kWel, ≤5 MWel, ≤20 MWel (see Tables 4.5 and 4.6).

  14. 14.

    In particular, this applies to plants between 150 kWel and 5 MWel. Plants above 5 MWel were not able to benefit from the EEG 2012s substrate tariff classes I and II or the biogas processing bonus, so that the EEG 2014 resulted only in a small reduction in remuneration (cf. Tables 4.5 and 4.6).

  15. 15.

    Competition is further limited through the exclusion of certain feedstocks such as scrap wood from remuneration (cf. 4.2.3.2).

  16. 16.

    Moreover, bioliquids have to adhere to sustainability requirements according to the biomass electricity sustainability ordinance (BioSt-NachV); however, since plants using bioliquids have been excluded from funding since the EEG 2012, this differentiation mechanism is neglected here.

  17. 17.

    In earlier versions of the EEG, cogeneration with associated GHG benefits was incentivised with a CHP bonus (section 27 (4) No. 3 EEG 2009; section 8 (3) EEG 2004).

  18. 18.

    Technical requirements for the minimisation of emissions leakage are retained, but these could in principle also be implemented as a requirement for the approval of installations according to emissions law (i.e. the BImSchG).

  19. 19.

    In 2012, 300 new biogas plants became operational, compared to 1300 in 2011 (Scheftelowitz et al. 2014: 18). Assuming a continuation of the EEG 2012s conditions, new biomass plants (incl. biogas, biomethane and solid biomass plants) were expected to account for an annual increase of about 90–150 MWel in installed capacity from 2014 onwards (ibid.: 47). However, in 2012 and 2013 a significant additional increase in installed capacity originated with an extension of existing plants, which could benefit from older versions of the EEG; this has reduced the effectiveness of the EEG 2012s steering of bioenergy expansion, but can be addressed through a more precise definition of the terms plant and start-up date (Scheftelowitz et al. 2014: 122 ff.).

  20. 20.

    A temporary fall back remains possible, e.g. if direct marketing intermediaries exit the market; but in this case, reference prices are reduced by 20 % (section 38 EEG 2014).

  21. 21.

    The flexibility premium, however, is dependent on participation in the MPS, so the option of monthly changes between schemes is primarily attractive for plants that do not receive it.

  22. 22.

    Yet another option would be a feed-in premium which would be paid, not for a certain period, but for a fixed contingent of electricity produced (SRU 2013: 94 ff.). In this case, producers would have to recover costs in a smaller number of full load hours than is the case with a feed-in premium without a contingent, and would therefore require a higher premium; if the size of the contingent is sufficiently limited, this option is structurally similar to a capacity premium (Kopp et al. 2013: 29; Bode 2014: 155; EEX and EPEX Spot 2014: 6). Therefore, it is not discussed separately in the following sections.

  23. 23.

    An exception would be competitive bidding schemes where, after a successful bid, remuneration is not paid over a plant’s estimated depreciation period, but only for a considerably shorter period. Here, existing plants would have to continue to compete in tenders, providing high incentive intensity to reduce costs. However, planning security would be very low, on a level comparable to quota schemes with green certificate trading. To facilitate comparability, it is assumed here that remuneration periods will continue to be aligned with depreciation periods in a competitive bidding scheme.

  24. 24.

    Hölder (2015) discusses price caps as a means of differentiating between different technologies and plant types (e.g. depreciated plants and new plants). In principle, an extension to different size classes would be possible.

  25. 25.

    At the same time, it would be more efficient to provide indirect incentives for small-scale slurry biogas plants by increasing the costs of GHG emissions in the agricultural sector.

  26. 26.

    However, the majority of currently operational bioelectricity plants are receiving remuneration based on earlier versions of the EEG. Extending sustainability standards to these plants may be associated with high political costs and legal difficulties.

  27. 27.

    In the UK sustainability standards for bioelectricity, for example, fuels falling in the waste category are largely exempt from reporting requirements regarding land criteria, the timber standard or GHG criteria; for processing residues, producers need to report only on emissions associated with collection processes, and non-woody residues are also exempt from reporting on the performance against land criteria or the timber standard (Ofgem 2014: 16).

  28. 28.

    This role could be filled by intermediate actors, comparable to direct marketing intermediaries—this would, however, further increase the transaction costs of the scheme.

  29. 29.

    Differences in external costs and benefits even apply to plants using waste and residues—for example, the extraction of woody residues can negatively impact biodiversity (Giuntoli et al. 2014), while the fermentation of bio-degradable waste is associated with additional benefits of waste disposal.

  30. 30.

    For processing biogas to biomethane, the EEG 2012 retains a bonus, which was only abolished with the EEG 2014. However, this bonus could also lead to steering errors, given that electricity generation from biomethane is associated with higher GHG emissions than biogas CHP production (Thrän et al. 2011b: 72 f.). For equivalent uses, the direct use of biogas would therefore be more beneficial. Rather than supporting biomethane production through a bonus, it would be advantageous if higher costs were compensated by higher value utilisation options, such as transport sector applications or electricity production in peak load hours. Moreover, a bonus distorts competition with other RES-based flexibility options (e.g. power to gas, storage technologies using RES electricity).

  31. 31.

    So far, receiving support under both EEG and KWKG is not possible. In the KWKG, the cogeneration of heat and electricity is supported through remuneration for a contingent of kWh. Combining this form of remuneration with a capacity premium according to the EEG would have the added advantage that the competitiveness of bioelectricity cogeneration plants in the electricity market’s merit order would be increased compared to fossil fuel plants, without the need to provide an additional fixed FIP (cf. Sect. 5.4.3.2, Leprich et al. 2013: 63 f.).

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    Alexandra Purkus

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Purkus, A. (2016). Towards a Rational Bioenergy Policy Concept. In: Concepts and Instruments for a Rational Bioenergy Policy. Lecture Notes in Energy, vol 55. Springer, Cham. https://doi.org/10.1007/978-3-319-31135-7_5

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