Optimal long term hydro scheduling linked to average electricity market prices

Traditionally, the Icelandic, island, hydro-based power system has been scheduled and planned based on local, isolated demand of two types: General Demand (GD) and the flat, now dominating Energy Intensive Industry (EII) demand. Thus a local load profile determines the scheduled operation, perhaps causing underutilization of resources, and water spillage. This limited flexibility is built into an isolated system, but interruptible EII contracts have served to increase the utilization to better meet the variable resource inflow (Water, geothermal steam). However, an access to a larger market would mitigate and change radically this limitation. Therefore a model based estimate of possible benefits is all important, when considering a UK-Iceland HVDC submarine link. This paper compares the optimal scheduling of a test system based on the Iceland system, with and without an external submarine link to a larger electricity market. A model HYDW1 uses linear programming (LP) and CPLEX to simulate weekly operations, using an official long term load forecast. This test system uses historical weekly averaged UK electricity spot prices and assumes a submarine link with preliminary cost estimates. The results quantify the benefits of trading flexible water power in a spot market, in terms of energy sales and operations costs by better utilizing the installed capacity, water flow and reservoirs. Finally, conclusions are drawn on expanding the weekly HYDW1 model to encompass a short term extension to enhance the future planning framework.