Twenty-four months of North Macedonian day-ahead data show midday prices falling and evening prices rising. The gap has more than doubled. This changes what a new solar plant is worth.

Between August 2024 and July 2026, the average baseload price on the North Macedonian day-ahead market was 108.31 EUR/MWh. That figure tells you very little about what a solar plant actually earned.

Solar plants do not sell at the baseload price. They sell during daylight hours, and daylight hours are precisely when solar output suppresses the price. Over the same twenty-four months, the average price during the 09:00–20:00 band was 100.91 EUR/MWh. During the 21:00–24:00 evening band it was 140.57 EUR/MWh.

That is a 39.66 EUR/MWh gap between when solar produces and when the market pays most.

The gap is widening

The twenty-four month average conceals a trend. Over the most recent twelve months, the daytime band averaged 88.20 EUR/MWh and the evening band 135.63 — a spread of 47.43 EUR/MWh.

Narrow the window further, to the high-irradiation months of March through July 2026, and the picture becomes stark: 63.36 EUR/MWh during the day, 153.96 in the evening. A spread of 90.60 EUR/MWh.

The same period a year earlier tells the story directly. Between April and July 2025, the daytime band averaged 66.15 EUR/MWh. In 2026 it was 60.30 — down nearly nine percent. Evening prices moved the other way, from 146.88 to 158.55.

Two years ago the pattern was inverted. In November 2024, daytime prices averaged 201.50 EUR/MWh against 145.69 in the evening. Winter still behaves that way; summer no longer does.

Why this is structural

This is not a weather effect or a one-off market disruption. It is the arithmetic of solar penetration.

Every megawatt of solar added to the system produces at the same hours as every existing megawatt. Supply rises where supply was already rising, and the merit order clears at a lower price. The more solar the system carries, the less each additional megawatt-hour of solar is worth.

The process is well documented in Germany, Spain and California. It is now visible in Southeast Europe, and the region's solar buildout has barely started.

What this means for new projects

Three consequences follow.

A yield figure is not a revenue figure. A financial model that multiplies annual production by an average market price will overstate revenue. The correct input is the capture price — the production-weighted average of the hours the plant actually generates. In this market, over the past twelve months, that figure sits close to 78 EUR/MWh, against a baseload average of 100.

Storage economics are improving, not fixed. A battery earns the spread. When the spread was 40 EUR/MWh, storage struggled to justify its capital cost. At 90 EUR/MWh during the months when solar plants produce most, the calculation changes. Projects should be modelled against the trend, not against last year's average.

Connection capacity is worth more than nameplate capacity. If daytime output is worth progressively less, the value of a connection point shifts toward the hours when it can deliver something else. A connection that can export in the evening is worth more than one that can only export at noon.

What we take from it

We model capture prices, not baseload averages. We size storage against the observed spread in the specific market, not against a regional assumption. And we state the trend explicitly in every projection we present, because a model built on today's spread will be wrong in three years — in a direction that favours flexibility.

Data: MEMO day-ahead market monthly reports, August 2024 – July 2026.