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Community opposition has caused delays in renewable energy investments. The literature suggests that increasing setback distances, decreasing scale and increasing self-sufficiency among others may increase community acceptance of energy infrastructures. We perform an analysis of the evolution of the Irish power system under these policies by constraining the maximum onshore renewable generation installation at each transmission node, accounting for network and spatial effects. We also consider the impacts of uncertainty in storage costs. An unconstrained renewable development portfolio is marginally cheaper than a constrained one. However, there are substantial differences in the final generation expansion portfolios and spatial allocations. The network reinforcement requirements are also greater under the unconstrained approach. Lower storage costs only slightly mitigate the costs of capacity constraints but significantly alter the spatial distribution of generation investments. The differential in costs between the unconstrained and constrained cases increases non-linearly with renewable generation targets. Future work will consider transmission as well as generation investments. • Power system impacts of constrained vs unconstrained renewable developments analysed. • Constrained case: higher setback distance and self-sufficiency, and decreased scale. • An unconstrained renewable portfolio is marginally cheaper than a constrained one. • Lower storage costs slightly mitigate cost of capacity constraints. • Cost differential between portfolios increases non-linearly with RES targets. [ABSTRACT FROM AUTHOR]

Electricity generation capacity expansion is driven by both economic and socio-political realities. Policy makers determine public infrastructural decisions, such as climate and renewable targets, and transmission infrastructure, and the optimal generation capacity expansion follows. Policy makers therefore require planning models that can determine the optimal generation capacity mix in the long run under various scenarios, including policy choices. This work presents a planning model based on linearised alternating current optimal power flow which determines optimal generation capacity expansion and operation, in a least-cost manner, given global and local technical constraints, as well as policy decisions. We apply the model to a test case of the island of Ireland, which has two weakly interconnected systems, high renewable generation targets and low storage and interconnection. We determine the optimal generation expansion and operation out to 2030 considering the effects of increased multi-area interconnection, existing fossil fuel generation phase-out and increased renewable generation targets and carbon prices. Our results find that costs and emissions are driven primarily by the decommissioning of old inefficient generation units. High renewable targets, on the other hand, render increased carbon prices relatively ineffective in reducing system emissions. Furthermore, high renewable generation targets crowd out low-carbon power generation options such as carbon capture and storage (CCS). The strategic north-south interconnection has little effect on renewable energy source installations required to achieve renewable power generation targets but does impact on security of supply and the congestion level across the island. • A decision support model for medium to long-term generation expansion planning. • Insights from an Irish study on optimal generation expansion mix under various policy scenarios. • Effects of multi-area interconnection, fossil fuel phase-out, RES-E targets and carbon prices. • Costs and emissions driven primarily by decommissioning of old inefficient generation units. • High renewable targets render increased carbon prices ineffective in reducing emissions. [ABSTRACT FROM AUTHOR]