Green certificate markets, the risk of over-investment, and the role of long-term contracts
Introduction
EU Directive 2001/77/CE targeted for the first time that a specific percentage of final electricity consumption be sourced from renewable resources,1 and furthermore contemplated a unified EU support mechanism to replace the ad hoc constellation of policies in place in various countries at the time. While the idea of a unified support scheme was subsequently dropped, the measure successfully prompted a considerable research effort to compile case studies of these policies in action, as well as to compare their theoretical merits where case studies were impracticable. A fairly substantial literature now encompasses research on renewable feed-in tariffs (REFITs), tradeable green certificate (TGCs) markets, tendering schemes, and investment subsidies (Butler and Neuhoff, 2004; Fouquet et al., 2005; Schaeffer et al., 1999; van der Linden et al., 2005; Lauber, 2004; Agnolucci, 2007a, Agnolucci, 2007b; Morthorst, 2000; Toke, 2006; Mitchell et al., 2006).
Policy comparison has been complicated by the coexistence of multiple objectives and criteria, relevant in different measures to different interested parties. Among others, these include: (i) the quantity of renewable energy stimulated as a direct result of the policy; (ii) the total cost of the energy produced, relative to the minimum possible cost; (iii) the degree to which investment and ownership in the new industry is controlled by the local population and contributes to local development objectives; (iv) the degree to which a domestic manufacturing industry has been stimulated to supply renewable energy generation equipment.
There is no dispute over the first measure: countries with the greatest percentage adoption of renewables—by an order of magnitude, in fact—attained this status under REFIT regimes (Rickerson and Grace, 2007; Toke, 2006; Lipp, 2007). Nor is it controversial that the tendering system failed almost completely where it was most comprehensively adopted (Mitchell et al., 2006; Agnolucci, 2007a). Furthermore, tendering schemes, TGC markets, and tax incentives (modeled along the lines of the US production tax credit) are widely held to discriminate against local, non-corporate ownership (Rickerson and Grace, 2007; Kildegaard, 2006).
While the case study evidence supports REFITs under the first criterion, it may well be argued that TGCs are a more recent innovation, and cannot be expected to have the same historical track record as a policy that has been in practice, in one form or another, since the 1980s. There are claims for existing successful TGC implementations, (Langniss and Wiser, 2003; Wiser and Barbose, 2008; van der Linden et al., 2005), but most of the attraction here lies in the theoretical potential for this policy to minimize the cost of a given quantity of renewable energy (Schaeffer et al., 1999; Menanteau et al., 2003; van der Linden et al., 2005).
This paper reconsiders the dynamic and static efficiency case for TGCs. We argue that the high ratio of fixed to variable costs of renewable energy projects poses specific risk consequences for certificate prices in a TGC marketplace, and that these risks will necessarily be borne by the demand side of the market. The equilibrium form of contracting, then, is almost certainly long-term, with a price commitment roughly equal to the average fixed costs (AFCs) of the new capacity. Consequently, the two most widely anticipated benefits of TGC markets will not materialize: competition between technology vintages, and efficiency-enhancing liquidity in certificate markets. We extend the analysis to the case where low fixed-cost technologies compete alongside high fixed-cost technologies, and find that in this case long-term contracts will likely disappear, but that technology choice will shift inefficiently toward the low fixed-cost alternative. Finally, we consider evidence from three well-developed TGC markets, in Britain, Sweden, and Texas.
Section snippets
A brief review of REFITs and TGCs
In their most common incarnation, REFITs amount to an unlimited option for qualified renewable energy generators to connect and sell energy into the market, usually at a fixed price but sometimes at a mark-up over the fluctuating wholesale price. The obligation to buy falls on the grid operator, and is ultimately carried by the distribution system operators (DSOs) and their customers.
While REFITs establish prices politically and leave quantities to the market, TGCs do precisely the opposite: a
Certificate prices and over-investment risk
Like investment of any sort, investment in renewable capacity depends on expected risk and reward. The TGC scheme contributes to the expected return by layering a cash flow of certificate revenue on top of the cash flow from energy sales. Understanding the economics therefore requires a theory of the determination of certificate prices.
One approach to thinking about long-run equilibrium in certificate markets appears first in Morthorst (2000), and is employed subsequently in several papers (
Certificate banking
For certain kinds of symmetric risk, the banking of certificates can provide the demand elasticity necessary to level out certificate price fluctuations. Fluctuations in certificate supply due to annual weather and wind variations, for example, can be supposed to average out over the lifetime of an asset. Hence it will be rational for net banking of certificates during high wind-power years, and vice versa.
The kind of risk posed by sub-optimal industry-wide investment, however, is not of this
Long-term contracts: effect (not cause) of a functioning certificate market?
Several authors have discussed the critical role of long-term certificate contracts in successful renewable support schemes (Agnolucci, 2007b; Wiser et al., 2004; van der Linden et al., 2005; Wiser and Pickle, 1998). This literature stresses policies which require or encourage long-term contracts, implicitly identifying the lack of such contracts as the sources of market failure. We argue here that the lack of long-term contracts may rather be the consequence of market failure than the cause
Inclusion of low fixed-cost technologies and price caps
The logic of the preceding section is altered by the inclusion in the TGC scheme of technologies with low fixed and high marginal costs. These include, generally, biofuels used for co-firing of traditional thermal plants, or even outright fuel substitution of landfill or sewage gases for natural gas inputs.
In terms of our diagrams, the effect of certificate eligibility for these newly considered technologies is to render the short-run marginal cost curve significantly more elastic. Fig. 5
Evidence from Sweden, Britain, and the US
Fig. 6 shows the most recent available data, breaking down RES compliance in Britain, Sweden, and Texas, respectively.18 It is clear from these data that Britain and Sweden incorporate a great deal more low capital-intensive energy sources—biomass and landfill gas—than is true in the case of Texas. Sweden and Texas represent extreme examples: in the former
Conclusion
There has been a surge of interest in renewable energy support schemes recently, and in particular in RES/TGC markets. The most commonly cited arguments for this scheme cite: (a) static cost-minimization, arrived at through competition from various eligible technologies in the certificate market; (b) cost stability for obliged parties, resulting from the short-term liquidity guaranteed by the competition discussed in (a); (c) dynamic efficiency via inter-temporal competition between technology
Acknowledgments
The author thanks (without implicating) Paolo Agnolucci, Henrik Klinge Jacobsen, Stina Grenå Jensen, Stephanie Ropenus, and an anonymous referee. The article was written while the author was a Guest Researcher in the Energy Systems Analysis Division at Risø National Laboratory/DTU, in Roskilde, Denmark.
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