What a long-term generation plan would have changed in July 2021

01 · The problem

Most generation and supply companies build an integrated resource plan (IRP) for the next 5, 10 or more years. The EAC has stayed with older practices instead, and the cost shows up in the price of electricity and in carbon costs.

To make the cost of planning decisions visible, the question was simple: what would the same month have cost with a planned portfolio?

02 · What was done

1. Base case: July 2021 as it ran. About 11% of the EAC’s load was first covered by PV and wind; the rest came from the internal combustion engines at Dhekelia (102 MW), the combined-cycle units at Vasilikos (440 MW) and, for part of the peak, the gas turbines.
2. Optimised case: optimisation to find the ideal generation portfolio, with a large share of July generation from PV and energy storage, and the rest from a mix of wind and conventional generation.
3. Both cases used the same inputs: 632 GWh of generation, a mixed fuel cost of €510.42 per tonne and a carbon price of €55 per tonne of CO₂.

03 · What it showed

In the model, planning and optimisation would have cut the cost of generating electricity by €22.8 million in July 2021 alone.

Generation cost excluding carbon fell from €72m to €57.5m, a 20% reduction. The carbon cost roughly halved because PV supplied much more of the month.

These are model results for one month under a counterfactual portfolio, not a saving anyone realised.

04 · What it means

A long-term plan is not paperwork. In a fuel-heavy island system, the portfolio choice moves the cost per kWh by a quarter.

The same kind of model can be checked against what happens later. In 2020 a model of the Cyprus load curve projected an evening ramp of about 100 MW per hour with 500 MW of solar and about 140 MW per hour with 750 MW, and a serious problem around 2029. By 2026 the DSO data showed curtailment was already the norm: the direction was right and the timing came earlier than projected.