Until recently the European electricity system has been operating as a set of isolated national markets with divergent regulatory norms. Today, the day-ahead markets between South-Western Europe and North-Western Europe are fully coupled, enabling the trading of electricity all the way from Portugal to Finland. Moreover, policy-makers in the power sector are currently preparing the design of what it will be called the Internal Energy Market. Europe's power sector aims for an integrated, more competitive, secure and sustainable power system. Meanwhile, ambitious renewable targets aim for a decarbonization of the electricity sector by 2050. This will lead to a large deployment of renewable technologies into the system, with almost 50% of them being the most intermittent, uncertain and unevenly distributed sources in the continent, wind and solar. The introduction of the projected large amounts of intermittent sources will impact both the functioning of the electricity markets and the operation of the transmission grids. Cross-border congestion profiles are expected to suffer changes, transmission constraints will appear and an effective congestion management approach will be needed within the framework of the market's redesign. Currently, the congestion management mechanism in place in many Member States is based on a redispatch phase after market clearance, which results in inefficiencies and additional rebalancing costs. This congestion management approach falls within the zonal market design. A consistent integration of electricity markets across Europe enabling the access of large capacities of renewable generation would have the potential to maximize overall welfare to all agents. Generators would enter a more competitive market with a lower risk, consumers would benefit from lower electricity prices and transmission system operators would benefit from reduced operation costs of balancing and reserve. Locational marginal pricing, also known as nodal market design, would be able to provide an integrated approach of national and international congestion management, a joint allocation of international transmission rights, the integration of congestion management with day-ahead, intraday and balancing markets and finally a transparent approach to facilitate secure and effective cooperation and information exchange among European system operators. However, a committed high-level support on a European level would be required for its further implementation. The objective of this thesis is to gain a better understanding of the European power market in presence of large amounts of renewable energies and under different power market designs, and find out by how much can the market design and its features affect the provision of cost-efficient electricity, this is the system's variable generation costs of electricity. In order to study the influence of the power market design in the integration of large amounts of renewable energies, an optimization model is used. The model solves a weekly unit commitment problem and the transmission constrained economic dispatch for the day-ahead market of a conceptual network of Europe and from a centralized decision making point of view. The model uses a mixed-integer linear programming (MILP) formulation of the unit commitment and minimizes total variable generation costs of the system. The two market designs studied, nodal market and zonal market, are modeled according to how congestion is managed in each case. The aim is to analyze the impact of the power market design on the power system's variables: total variable generation costs, RES curtailment, energy production by technology, non-served energy and hourly electricity prices while subjected to several scenarios of increasing degree of RES integration. For this, different degrees of future RES scenarios based on ENTSO-E market studies are used. The research shows that in a high renewable scenario the total variable generation costs of the power system when it operates under a zonal power market are around 0,32% higher than under a nodal market. These potential savings under a nodal market could even be larger especially if the large expected projections of renewable sources of generation finally materialize and provided that the required network capacities are delivered effectively on time. Moreover, the degree of curtailment in both nodal and zonal markets rise notably in a high renewable scenario compared to the current situation, up to a weekly curtailment of 7,83% and 8,01%, respectively. Such notable amounts of curtailment could be due to the insufficient development of the transmission network assumed which leads to the incapability of supplying cheap renewable energy across wide regions and instead having to commit or reschedule local and more expensive technologies. On the other hand, costs of unserved energy represent 2,95% and 3,08% of the total system's variable generation costs in the nodal and zonal market, respectively. It is again highlighted the importance of a timely delivery of the network infrastructure investments to gradually integrate the large deployment of renewables in the system. Overall, a nodal market in Europe could have the potential of improving efficiency in the system by reducing variable generation costs by 0,32% compared to a zonal market. Benefits could increase even more if an adequate network expansion plan that takes into account the growth of renewable energies would deliver its investments on a timely manner.