RES in Cyprus: who produces, who sells, who sets the price

Dr Andreas Procopiou In Cyprus’ public debate on energy, the lack of well documented information is widespread. Here we always back our claims with official data, because energy literacy is not a luxury, it is a prerequisite, especially for those who make policy decisions. Data never takes a side. Only those who choose to ignore it do. The topic is especially timely these days, as proposals are circulating to revise solar energy sale agreements as a way of lowering electricity bills. Before evaluating such proposals, one needs to know exactly what the “solar” share of the generation mix represents, how much of it is actually sold somewhere, and how much is sold nowhere at all. The official chart, as we all see it The transmission system operator (TSO) publishes the island’s real time electricity demand together with the generation mix: conventional generation, wind and a single yellow profile representing all distributed photovoltaic (PV) generation. To show what that profile is made up of, since its composition is not visible, we present below two versions of the same chart for the same two days in 2026: first as the TSO publishes it today, with PV shown as one single block, and then the same chart broken down by PV category, based on data from the Distribution System Operator (DSO). Let’s first look at how it is published today: 10 May 2026 (low demand, 11,037 MWh): conventional 67.3%, wind 6.6%, PV 24.1%. 25 August 2026 (high demand, 23,551 MWh): conventional 73.0%, wind 0.9% (a typical summer lull), PV 24.9%. Roughly a quarter of daily demand is covered by solar on both days, but the chart does not show exactly where that quarter comes from. What makes up the yellow profile of solar generation The Distribution System Operator (DSO) has published PV generation data for the distribution system since the Competitive Electricity Market began operating, split into three main categories: Utility scale commercial PV parks (controlled): fully remotely controlled via a SCADA system. Small scale and residential, controlled: small scale systems under net billing and net metering, with Ripple or IoT remote control. Residential, uncontrolled: rooftop self consumption with no remote control system, typically under net metering. The chart below shows the same two days, with PV split into these three categories: Distribution of PV generation by category, as a share of total demand: Utility scale commercial PV parks – 3.9% on 10 May, 9.8% on 25 August Small scale and residential, controlled – 11.9% on 10 May, 11.9% on 25 August Residential, uncontrolled – 8.8% on 10 May, 3.7% on 25 August Who actually produces more On both days, the small scale segment (residential and small scale controlled combined) far outpaces the utility scale commercial parks: 10 May: parks 3.9%, small scale total 20.7%. 25 August: parks 9.8%, small scale total 15.6%. Sample total, roughly 310 days: small scale 74.5% of all PV energy delivered, versus 25.5% from utility scale parks. More than 102,000 small, scattered systems on the roofs of homes and businesses (99,854 net metering and 2,343 net billing, according to the ministry’s official installed capacity data) make up most of the yellow curve in the TSO’s chart. 254 utility scale installations take part in the market. Why the ratio shifts: curtailment The share of utility scale parks rises sharply on the high demand day, from 3.9% to 9.8%, while the share of uncontrolled residential systems shrinks, from 8.8% to 3.7%. The second shift is not due to curtailment, since these residential systems are barely curtailed at all: their output stays nearly constant across the two days, 972 MWh and 876 MWh respectively. When total demand is low, they therefore take up a larger share of it, and when demand is high, a smaller one, simply because the denominator changes. The rise in the parks’ share, by contrast, reflects how the system is managed: when demand is low and sunshine is high, someone has to be curtailed. The smaller and more local a producer is, the less exposed it is to curtailment. The burden of balancing the system falls almost entirely on the large parks. Who sets the price in the market Utility scale commercial parks: participate in the wholesale electricity market (Day Ahead Market) and sell at market price. Small scale: settled bilaterally with EAC, outside the wholesale market. Under net metering, energy is directly offset, cheap solar at midday for expensive conventional power at night, while under net billing EAC credits the surplus energy exported to the grid at a fixed 11 cents/kWh. In both cases the energy reduces midday demand, but it stays outside the Competitive Market and never enters the mechanism that sets the marginal price. The largest share of Cyprus’s PV generation, the part that dominates the yellow curve, is largely invisible to market pricing. It affects the price only indirectly, by reducing the demand that has to be met from more expensive sources at midday, but it does not set any price itself. The Ministry’s Energy Service official installed capacity data (April 2026) show installed capacity by category and its operating regime: Net metering, around 44.7% of installed capacity (471.51 MW): exchanges cheap solar energy at midday for expensive conventional power in the evening with EAC Supply, with no price in the market sense. Net billing, around 15.0% (158.27 MW): surplus energy exported to the grid is settled with EAC Supply at a fixed, regulated price of 11 cents/kWh. Feed in tariff, 76.28 MW of solar and 157.50 MW of wind installed capacity: EAC Supply buys it at the same fixed price, 11 cents/kWh. This price is not arbitrary. It is set out in CERA’s Fuel Cost Adjustment Calculation Methodology, as amended by Regulatory Decision No. 112/2023 (11 April 2023): when EAC Generation’s Avoided Cost exceeds 11 cents/kWh, the RES purchase price equals the average purchase price for the 2013–2022 decade, that is exactly 11 cents/kWh. In addition, under CERA Regulatory Decision 01/2021 (KDP 359/2021, paragraph 7.74), EAC Supply is explicitly barred from entering bilateral wholesale purchase contracts, with the sole exception of energy from RES stations under national grant schemes, priced at exactly 11 cents/kWh. Wholesale market, PV (325.65 MW from independent producers and 20.00 MW from EAC Generation), plus 12.00 MW of wind from independent producers: PV had a volume weighted average sale price of 14.48 cents/kWh for the period 1 October 2025 to 21 August 2026, far cheaper than conventional generation. Back to the public debate The TSO’s official chart correctly shows how much solar energy enters the system, but not where it comes from or how each category is settled. This detail changes significantly how we should read, and discuss, every proposal for solar energy “agreements”: before deciding whether they should be revised, it is worth first knowing how many actually exist, who manages them, and what share of production they account for. Dr Andreas Procopiou is a former senior research fellow in Smart Grids at the University of Melbourne and researcher at Électricité de France R&D in France. The views expressed are personal