Comparison of Incentive Policies for Renewable Energy in an Oligopolistic Market with Price-Responsive Demand.

• Author: de Arce, Miguel Perez

1. INTRODUCTION

   Due to the great concern worldwide about reducing carbon dioxide (C[O.sub.2]) emissions, different policies have been implemented to incentivize the development of renewable energy (RE) sources, such as wind, solar and geothermal, among others. In 2009, power and heat generation from conventional sources was responsible for 41% of the C[O.sub.2] emissions worldwide (IEA, 2011a). In 2009, 3% of the electricity generation came from non-hydraulic renewable energy sources (IEA, 2011b). According to the International Energy Agency (2011b), this percentage could reach 15% by the year 2035, through the implementation of annual subsidies of 180 billion dollars.

   Among the policies that seek to accelerate the reduction of C[O.sub.2] emissions through the integration of RE, the most commonly used are: carbon taxes, feed-in tariffs, premium payments, quota systems, auctions and cap and trade systems (Wiser et al., 2007; Fouquet and Johansson, 2008; Barroso et al., 2010; Olimpio et al., 2011; Kitzing et al., 2012; Tukenmez and Demireli, 2012; Fouquet, 2013; Hinrichs-Rahlwes, 2013). A carbon tax policy, such as the one proposed by Green et al. (2007), seeks to impose an additional cost on thermal generators, so as to disincentivize C[O.sub.2] emissions, notwithstanding the fact that, in some situations, this might not occur, as pointed out by Downward (2010).

   Among the incentive policies using subsidy mechanisms to encourage the development of RE, one may distinguish two particular types: feed-in tariff and premium payments (Mitchell, 1995; Lesser and Su, 2008; Couture et al., 2010; Schallenberg-Rodriguez and Haas, 2012; Al-Amir and Abu-Hijleh, 2013; Uran and Krajcar, 2013; Cherrington et al., 2013). The first type consists of fixed tariffs determined for each unit of RE generated while the second type consists of a fixed payment that is additional to the retail price of electricity per each unit of renewable energy produced. Some policies using subsidies for RE specify a maximum installed capacity per technology that is subject to the subsidy.

   A large percentage of European countries have adopted these types of policies (Germany, Denmark and Spain among others), as it is mentioned in Couture and Gagnon (2010), Farrell (2009), and in Menanteau et al. (2003). In Germany, feed-in tariffs started in the 1980s and were consolidated at the end of the 1990s (Lipp, 2007). This policy has led to a rapid growth of the share of RE in electricity consumption in Germany, from 3.4% in 1990 to 25.4% for 2013 (Germany Federal Ministry of Economy and Energy, 2013); with political support being one of the key factors for the success in its implementation (Wiistenhagen and Bilharz, 2006). According to the International Energy Agency (2011c), the share of RE in global electricity production was 16% in 2009 and 16.5% in 2010.

   On the other hand, the quota obligation system (or simply quota system) places an obligation, generally on electricity suppliers, to generate a specified fraction of their electricity from RE sources (Amundsen and Mortensen, 2001; Berry and Jaccard, 2001; Fischer, 2010; Palmer and Burtraw, 2005; Woodman and Mitchell, 2011). This mechanism is also known as Renewable Portfolio Standards (RPS) in the United States, Renewable Electricity Standards (RES) in India, Renewables Obligations (RO) in the United Kingdom and Renewable Energy Targets in Australia. Governments usually set a minimum percentage of electricity to be generated through RE, applied over the total amount of electric power sold during a period (Menanteau et al., 2003). The additional cost is generally transferred to the end consumers. The quota system is usually complemented with tradable certificates, like the Tradable Green Certificates (TGCs) in Europe or the Renewable Energy Credits/Certificates (RECs) in the U.S. (Munoz et al., 2013). These certificates of RE generation are traded in the market by firms that must comply with the RE quota (the quota system establishes penalties for those firms not complying with the RE quota; IPCC, 2011). Mitchell et al. (2006) argue that the main risks faced by generators within a quota system are related to the retail price level, the energy volume and the balance of energy.

   A cap-and-trade policy, like the one described by Green et al. (2007), seeks to incentivize the reduction of carbon emissions through a system of transactions of permits for such emissions. Through this type of policy it is possible to lay down emission limits that generate credits for companies that are below such a limit, allowing for the existence of a market for trading these credits. Limpaitoon et al. (2011) present a comprehensive model of a cap-and-trade policy, identifying interesting results related to the congestion in the transmission system and the reduction of social welfare. Cap-and-trade policy is not modeled in the present work, but it can be considered a similar policy as carbon tax.

   Some authors have compared incentive policies for encouraging RE (Butler and Neuhoff, 2008; Barroso et al., 2010; Fischer, 2010; Asano, 2013; Verma and Kumar, 2013; Oak et al., 2014). However, those studies make some oversimplifications like ignoring transmission constraints in the power network and disregarding the possibility that generation firms act as oligopolistic firms, exercising market power. On one hand, significant transmission investments are needed to integrate RE, and these investments interact with generation expansion decisions as well (Felder, 2011; Joskow and Tirole, 2005; Kahn, 2010; Martin and Rice, 2012; Mills et al., 2011; Morales et al., 2012; Munoz et al., 2012; Olson et al., 2009; Pozo et al., 2013a; Pozo et al., 2013b; Sauma and Oren, 2007; Sauma and Oren, 2006; Schaber et al., 2012; Schumacher et al., 2009).

   On the other hand, although most countries have implemented several policies to promote competition in the electric generation sector (Arango and Larsen, 2011; Sioshansi and Pfaffenberger, 2006), there is still evidence of market power in some markets (Yenita and Kirschen, 2012). Some countries having oligopolistic market structures in the power sector are Finland (Pineau et al., 2011; Pineau and Murto, 2003), Singapore (Chang, 2007; Chang, 2004), India (Kumar and Thampy, 2011), Iran (Hossein and Monsef, 2010), Poland (Kaminski, 2012), Italy (Guerci and Sapio, 2011), England and Wales (Belsnes et al., 2011), Spain (Rious et al., 2008), Germany (Rious et al., 2008), United States of America (Belsnes et al., 2011; Limpaitoon et al. 2011; Yu et al., 2001), United Kingdom (Maiorano et al., 1999; Thomas, 2005), and some Nordic countries (Juselius and Stenbacka, 2011; Hellmer and Warell, 2009). This fact highlights the relevance of considering the exercise of market power in modeling power markets (Mare et al., 2013; Oh and Thomas, 2013; Banal-Estafiol andRuperez, 2011; Sandsmark and Tennbakk, 2010; Percebois, 2008; Thomas, 2005; Wolfram, 1999). Furthermore, some authors have studied the impact of considering market power in the RE penetration (Kazempour and Zareipour, 2014) and in the resulting C[O.sub.2] emissions (Linares et al., 2008).

   Our work contributes to the literature by comparing different incentive policies for encouraging RE, considering both transmission constraints in the power network and the possibility that generation firms act as oligopolistic firms. In addition, results under each policy are compared when considering different market structures (oligopoly and perfect competition) and when considering different methods to recover the subsidy costs (no direct recovery from the government and recovery through a customers' pay back scheme).

   The rest of the paper is structured as follows. Section 2 presents the base power-market model. Section 3 shows the model formulation for the different RE incentive schemes analyzed. A case study is used in Section 4 for comparing RE policies under different criteria. In particular, we study nodal prices, RE penetration differences, the network congestion effect, the cost effectiveness in reducing C[O.sub.2] emissions, and social welfare, under different market structures and under different assumptions about who bears the cost of the subsidies. Section 5 concludes.

2. BASE POWER-MARKET MODEL

   In order to study the RE incentive policies, we model the electricity market using game theory, analogously to Downward (2010). Our objective is to analyze the behavior and interaction of power generation firms, which are able to generate through both conventional and RE sources.

   A simplified radial (two-node) power network is modeled, assuming generation firms compete a la Cournot. In this Cournot game, each player (generation firm) has some degree of market power. As in Downward (2010), we assume constant marginal costs and linear price-responsive demand functions.

   The power network considered in this work is shown in Figure 1. There are two nodes linked by a transmission line with capacity K. The flow through the transmission line is designated by f. In each node i, there is a generation firm, which can produce power from a RE source at a levelized cost of [c.sup.r.sub.i] and/or from a conventional source at a levelized cost of [C.sup.c.sub.i]. (1) The total amount of energy injected into node i is [q.sub.i], which corresponds to the sum of the conventional ([q.sup.c.sub.i]) and renewable ([q.sup.r.sub.i]) power generation in node i.

   At each node, we consider an inverse demand curve, given by [p.sub.i]([y.sub.i]) = [a.sub.i] - [b.sub.i] * [y.sub.i], where [a.sub.i] and [b.sub.i] are both strictly positive constants, [y.sub.i] is the power demand satisfied at node i, and [p.sub.i] is the price at node i.

   We consider that the generation firm located at node 1 owns two power plants: a (conventional) coal power plant and a (renewable) wind power plant. Maximum generation capacities are [K.sup.c.sub.1] and [K.sup.r.sub.1], respectively. In turn, the generation...