Abstract
In the last decades, the weight of renewable energies sources (RES-E) in the electricity generation mix of most European countries has considerably increased, constituting an important contribution to the transition towards a low-carbon economy. Until very recently, RES-E were supported by favorable investment mechanisms specially designed to endorse investment in RES-E. More recently, as RES-E are becoming increasingly more competitive (especially wind and solar photovoltaic), RES-E are starting to be remunerated according to market mechanisms. This has generated a lively debate on the economic pros and cons of dispatching RES-E in the market. This paper contributes to this debate by developing a game theoretical model in the context of which we analyze how the inclusion of RES-E in the electricity wholesale market affects equilibrium outcomes under demand and supply uncertainty. Then, we examine how the inclusion of RES-E in the electricity wholesale market impacts firms' incentives to invest in conventional energy sources, characterizing the optimal investment under demand and supply uncertainty. We find that, when RES-E capacity and asymmetry in firms' marginal production costs are sufficiently high, RES-E producers may strategically reduce the market price, in order to evict the less efficient conventional source in that period. Although, in the short-run, this strategy may actually favor energy consumers (since prices are lower), the expectations of inactivity periods (regardless of whether they arise for strategic or market reasons) may negatively affect investment in back-up capacity, possibly leading to an increase in future prices (since less back-up capacity is available). Finally, we provide an analytical characterization of optimal investment levels in conventional energy sources under demand and supply uncertainty.

Abstract
We merge the two-sided markets duopoly model of Armstrong (2006) with the nested vertical and horizontal differentiation model of Gabszewicz and Wauthy (2012), which consists of a linear city with different consumer densities on the left and on the right side of the city. In equilibrium, the high-quality platform sells at a higher price and captures a greater market share than the low-quality platform, despite the indifferent consumer being closer to the high-quality platform. The difference between market shares is lower than socially optimal. A perturbation that introduces a negligible difference between the consumer density on the left and on the right side of the city may disrupt existence of equilibrium in the model of Armstrong (2006).

Abstract
In the last decades, the weight of renewable energies sources (RES) in the electricity generation mix of most European countries has considerably increased. The implementation of these policies has been relying on different supporting schemes such as: the existence of a price premium for RES (feed-in tariffs); the assignment of priority access to renewable sources over conventional sources when entering the electricity network; and subsidizing investments in RE. While these incentives have certainly played a very important role in launching renewable energy production in Europe, more recently, both scholars and practitioners are claiming that RE generation should now be exposed to market incentives in order to promote economic efficiency. However, the inclusion of RE in the market may significantly affect equilibrium outcomes arising in electricity wholesale markets. Recent empirical studies, e.g. Puller (2007), point that the inclusion of RES in the market reduces average electricity prices at the cost of increasing price volatility (merit of order effect). Such outcomes can be explained by the intermittent nature of RES together with the asymmetry on generation marginal costs between RES and non-renewable energy sources (with the former being quite low for most of the available RES). However, the inclusion of RES in the wholesale electricity market may also yield strategic effects, as firms may strategically manipulate renewable energy production in order to have greater market power. In this paper, we provide an overview of the investment challenges following the introduction of market-based mechanisms for renewable production. The next step of this research project will be the development of a theoretical model, building on Milstein and Tishler (2011) in order to address the regulatory challenges related to capacity investment in a market with uncertain demand in which two firms offer two different electricity generation technologies, respectively using renewable and non-renewable energy sources. The renewable energy production is assumed to have an intermittent nature.

Abstract
The aim of this paper is to compare the electricity market design currently adopted in Portugal and in Brazil. We shed light on the differences and similarities between the two models regarding their rationale and risks. In particular, we highlight their differences regarding the organization of the wholesale and the retail activities: while the Portuguese model builds upon the pillars of competitive generation and retail, the Brazilian model is based on a centralized auction-contracting mechanism in the wholesale market and on captive consumption in the downstream market. We assess the advantages and disadvantages of each model by reviewing the theoretical and empirical literature on the benefits and limitations of retail choice and the literature on the pros and cons of electricity markets (in Portugal) versus contracts markets (in Brazil). The first approach yields competition in the market, whereas the second one fosters competition for electricity supply. We characterize the most stringent flaws in each model and we conclude that there is room for regulatory innovation in both models. The Portuguese model needs to be adjusted to create the necessary incentives to invest in the capacity that is needed to achieve the country's environmental and supply security goals. The Brazilian model already privileges investment incentives but it needs to be redesigned in order to account for the excessive risk allocated to distributors, which are quite vulnerable to exogenous shocks (e.g. hydrological shocks or demand-side macroeconomic shocks).

Abstract
In this paper, we develop a theoretical model that enriches the literature on the pros and cons of ownership unbundling vis-A -vis lighter unbundling frameworks in the natural gas markets. For each regulatory framework, we compute equilibrium outcomes when an incumbent firm and a new entrant compete A la Cournot in the final gas market. We find that the entrant's contracting conditions in the upstream market and the transmission tariff are key determinants of the market structure in the downstream gas market (both with ownership and with legal unbundling). We also study how the regulator must optimally set transmission tariffs in each of the two unbundling regimes. We conclude that welfare maximizing tariffs often require free access to the transmission network (in both regulatoy regimes). However, when the regulator aims at promoting the break-even of the regulated transmission system operator, the first-best tariff is unfeasible in both regimes. Hence, we study a more realistic set-up, in which the regulator's action is constrained by the break-even of the regulated firm (the transmission system operator). In this set-up, we find that, for a given transmission tariff, final prices in the downstream market are always higher with ownership unbundling than with legal unbundling.

Abstract