After the oil shocks, energy policies have focused on the reduction of energy dependence and exhaustible resource conservation including a component of R&D and promotion of renewables justified by the social gains associated to these collective goods and the remedies to the market failure in the capture of intertemporal externalites of technological learnings. After 1990, renewables promotion policies received the backing of climate change activists based on the rationale of reducing carbon externalities. In the electricity sector, renewable energy sources of electricity (RES-E) have received particular attention in the OECD countries with special support policies mostly based on long term production subsidies, despite the launching of carbon pricing policies based on emissions trading systems, and sometimes on carbon taxes. The design of RES-E promotion policy is central to the current European enegy debate and has been questioned in a number of academic works (see for instance Menanteau et al., 2003; Palmer and Burtraw, 2005; Klessmann et al., 2008).
Today, RES-E support mechanisms--feed-in tariffs (FIT), fixed premiums (FIP), (1) auctioning for fixed-price contracts, certificate obligations--strongly influence the investment choices of electricity producers. While investments in conventional electricity production technologies are mostly driven by anticipations of their market revenues on day-ahead markets, (2) which present important price-risk and volume-risk, the future incomes of RES-E projects are ensured by specific mechanisms which guarantee long term revenues and so, are estimated with a low level of risk. This leads to two investment regimes: (1) one based on anticipations of market prices, sums of discounted net hourly revenues and criteria of risk management and (2) an out-of-market regime based on these long-term arrangements providing both a production subsidy to non-commercially mature technologies and risk transfer to consumers via the levy financing the cost overruns of the RES-E promotion policy.
Regarding the literature about the impacts of out-of-market RES-E entries on the electricity market, it mainly focuses on the effects on the market prices, residual load curve and generation mix. More recently, academic works also focus on defining an optimal system for a set of characteristics of variable generation technologies and on the market value of a MWh generated by RES taking into account their integration costs. Firstly, the increasing RES-E capacity significantly alters market functioning by increasing price volatility and lowering average prices, thus endangering the profitability of new investments in complementary thermal technologies for mid-load and peak-load. Indeed, two merit order effects are classicaly described in the literature : (1) a high level of entry by RES-E producers decreases the average market price by reducing the net demand addressed to thermal power plants (Sensfu[beta] et al., 2008) and (2) this entrance contributes also to reduce hourly production of thermal units by pushing them out of the merit order more and more frequently. These two effects not only make new investment in thermal units much more risky and threaten coverage of investment cost but also make some of the existing thermal capacities obsolete. Moreover, with sufficient RES-E capacities, hourly market prices are significantly reduced during periods of wind or sun thus a lower market value of RES-E output (Green and Vasilakos, 2011; Hirth, 2013). Secondly, the residual part of the generation system has to adapt itself in the long term to these artificial entries which reshape the residual load (Holtinen, 2005; Nicolosi & Fursch, 2009; Bush-nell, 2010). To facilitate the optimal adaptation of non-RES capacities, result of RES-E promotion policies should be certain at a forward horizon while in practice, it is intrinsically uncertain due to the use of a price-instrument (FIT or FIP) rather than a quantity-instrument (obligation of green certificates, etc.). Thirdly, RES-E variability strongly alters short-term mechanisms such as operating reserves. Indeed, system costs (including plant-level and grid-level costs) resulting from the variability of wind power and photovoltaic increase more than linearly with the cumulative RES-E capacity (Keppler and Cometto, 2013). However, given the difficulties encountered with current RES-E supports, it is time to challenge their existence. The dilemma is between implementing support mechanisms which guarantee long term revenues to RES-E producers or implementing a regulated carbon price to internalize environmental damages. In the new guidelines on state aids in environmental protection and energy adopted in April 2014 (European Commission, 2014), the European Commission supports the integration of renewable technologies into the electricity market by exposing generators to hourly market prices, by the promotion of feed-in premiums instead of feed-in tariffs and by auctioning contracts for getting this premium and inciting entrants to reveal their costs. In the same trend, different European states have redefined the form of their support for RES-E (electricity market reform in the United Kingdom; Spanish reform; reform of the Renewable Energies Act in Germany; French consultation on RES-E support schemes in 2014, etc.).
Yet, theoretical arguments in favour of carbon price to trigger entries in RES-E generation without support mechanisms as soon as we are close to the commercial competitiveness are gaining in audience (Crampes, 2014). On the broader level of reducing C[O.sub.2] emissions, it is also argued that carbon pricing (through carbon tax or cap and trade system) is the best option to mitigate climate change (Gollier and Tirole, 2015). Concerning the electricity sector, Fisher and Newell (2008) use a long term modelling of the electricity market with perfect information to assess the efficiency of different types of energy and climate policies and show that the carbon price is the most efficient option compared to various other types of RES-E support. But, the use of a simplistic representation of electricity markets and cost functions of low carbon technologies leads to an underestimation of the carbon price equivalent to the RES-E supports which are compared with.
In this article, we consider that wind power (3) entries are triggered by its profitability compared to investment in dispatchable thermal units under the incentive of higher hourly electricity market prices which include a high and stable carbon price. The market-based development of wind power is assessed using the Simulator of Investment Decisions in the Electricity Sector (SIDES) which is a System Dynamics (SD) model of an electricity market (see Sterman (2000) for details on System Dynamics). The method allows to endogenously reproduce three important effects of wind power development: (1) the negative correlation between hourly wind power production and hourly price in opposition to dispatchable plants; (2) the gradual decrease of the average annual price with the development of new RES-E capacities, both of which make fixed costs recovery more difficult and (3) the feedback loop consisting in the "self-cannibalisation" of wind power competitiveness by its own development and leading to an endogenous limit of wind power capacities. This latter effect does not exist in the case of out-of-market entries of wind power (under the incentive of feed-in tariff or feed-in premium).
In the following approach, endogenous evolution of the technology mix is simulated by the formalisation of investment decision-making based on a long-term anticipation of hourly market prices and hourly net revenues (the so-called "infra-marginal rents") that each new plant could generate on the energy market during pay-back period. The model considers an energy-only market without any additional RES-E support mechanisms, but with a credible carbon price constant over a 20-year period rather than an uncertain carbon price signal (as that which emanated from the EU-ETS during its three first phases). In that sense, wind power is invested in under the same regime of other thermal power plants. The carbon price is supposed to be known and constant so that issues raised by its uncertain level are evacuated. The development of wind power when the carbon price is sufficiently high exacerbates capacity adequacy issues. One answer, which is not represented in the SIDES model is to implement a capacity mechanism with capacity credit allocation differentiated by technologies. In such a case RES-E units with variable production are inevitably penalized by their low capacity credit and consequently their development is reduced (Cepeda and Finon 2013).
Finally this study also adresses the argument that with the present cost-price of MWh produced by the last state-of-the-art wind power technology the carbon price needed to reach competitiveness of wind power is quite low (for instance in the range of [euro]30 to [euro]40 per ton of C[O.sub.2] as in IEA and NEA (2010)). In fact as our purpose is to take into account the market value of wind power output the SD simulations presented herein suggest that the carbon price needed for wind power development is much higher than the one estimated by a comparison of levelized costs of electricity (LCOEs). In section 2 which follows the SIDES (Simulator of Investment Decisions in the Electricity Sector) model is described. Section 3 details the results of the simulations for different levels of carbon price in two policy contexts: one without opened nuclear option and one with the nuclear technology acting as a low carbon competitor of wind power. Then the results are discussed and compared to the simple cost-price approach of wind power competitiveness in section 4. Finally, section 5 concludes and offers suggestions for further work.
Carbon Price instead of Support Schemes: Wind Power Investments by the Electricity Market.
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