Same price, different mix
The day-ahead market clearing price (PTF) averaged 2,742.43 TL/MWh in September 2026: 5.7% below August and only 0.5% above September 2025. In dollars the picture is different: the average was 56.6 $/MWh, 14.6% lower than a year earlier. In euros it was 49.0 €/MWh, against 56.5 €/MWh a year ago.
The flat lira price hides a large shift underneath. Output from reservoir hydro was 2.8 times its level a year earlier, and gas fell from 24.6% to 10.6% of licensed generation. Midday hours stayed cheap while the evening price rose, widening the gap within the day. This report summarises the month’s figures, the imbalance picture for August, the latest month with settlement data, and what they mean for solar, wind and battery investors.
Thirteen months of prices: lira and dollar
September stayed within the recovery that began in July. In the first half of 2026 cheap supply had pushed the PTF to very low levels: the April average was 921 TL/MWh and the May average 591 TL/MWh. Since July the monthly average has moved in a 2,700–2,900 TL/MWh band.
In dollar terms the recovery is weaker. The PTF was 66.2 $/MWh in September 2025, fell as low as 13.1 $/MWh in May 2026, recovered to 61.0 $/MWh in August and was 56.6 $/MWh in September. The lira price is unchanged on a year ago while the dollar price is 14.6% lower because the lira value of the dollar rose by about 18% over the same period. For an investor carrying dollar-denominated debt or equipment costs, this is the series that matters.
Within the month the price moved across a wide range. On Sunday 20 September the PTF was zero for four hours between 10:00 and 14:00. On 12, 21 and 24 September a total of seven hours cleared at the 4,500 TL/MWh price cap. Daily averages ranged from 1,424 TL/MWh on Sunday 27 September to 3,328 TL/MWh on 1 September.
How prices are distributed
An average says nothing about how the hours are spread. In September 2025, 52.6% of hours fell between 3,000 and 3,500 TL/MWh, with the price cap at 3,400 TL/MWh. When the cap rose to 4,500 TL/MWh on 4 April 2026, the distribution opened upwards: in September 2026, 23.2% of hours cleared above 3,500 TL/MWh. At the low end, 6.1% of hours were below 1,000 TL/MWh, against 6.5% a year earlier and 1.4% two years earlier.
The first nine months make 2026 stand out more clearly. There were 4 zero-price hours in 2024 and 41 in 2025, but 395 in 2026, of which 391 came between February and June. Hours above twice the monthly average, absent in the first nine months of 2024 and 2025, reached 404 in 2026: with spring averages so low, evening hours sat far above them.
At the top end the picture is reversed. The price cap has changed from period to period: 2,700 TL/MWh in the first half of 2024, 3,000 from 1 July 2024, 3,400 from 5 April 2025 and 4,500 since 4 April 2026. Counting each hour against the cap in force that day, the PTF cleared at the cap in 736 hours of January–September 2024, 686 in 2025 and 369 in 2026. Of the 2026 hours, 315 came before the cap rose in April; since then only 54 hours in six months have hit it, against 157 in July 2025 alone. With the higher cap, scarcity hours are priced in the 3,500–4,500 TL/MWh range instead of being clipped at the limit; the upper tail in the distribution chart is the result.
The daily price spread is the gap between the highest and lowest hourly PTF of each day.
Water in, gas out
Licensed plants generated 27.7 TWh in September, 4.2% more than a year earlier. The total changed little, but the order of sources did. Reservoir hydro became the largest source at 7.0 TWh, against 2.5 TWh a year earlier. Gas-fired output fell from 6.5 TWh to 2.9 TWh, less than half.
Real-time generation data covers licensed plants only; unlicensed generation, mostly solar, is not included. Realised generation including unlicensed plants is published a month later; the full picture for August is in the “August settlement” section below.
The retreat of gas did not lower the average price, because the PTF is the price of the most expensive megawatt needed to meet demand in each hour. At the latest tariff published by BOTAŞ, the state gas company (4 April 2026; 1.692 TL/kWh), and 50–55% efficiency, a gas plant’s fuel cost is 3,080–3,380 TL/MWh. In September the average PTF between 18:00 and 21:00 was 3,875 TL/MWh. Evening prices clearing above this cost show that the last plant dispatched at the peak is still gas-fired.
Illustrative calculation. Fuel cost is BOTAŞ’s tariff for power generation divided by plant efficiency; operating and network charges are excluded.
Trade changed direction too. Türkiye was a net exporter of 618 GWh in September, against 76 GWh of net imports a year earlier. Real-time consumption rose 3.4% to 30.6 TWh.
Cheap midday, expensive evening
The daily profile shows the year’s clearest change. Dividing each hour’s average by the monthly average sharpens the shape: in September 2026 the average PTF at 12:00 was 47% of the monthly average and at 19:00 it was 152%. In 2024 the same hours were at 62% and 123%. The midday trough had already deepened in 2025 (45%); what is new in 2026 is the higher evening peak.
In September the average PTF was 2,068 TL/MWh between 10:00 and 16:00 and 3,676 TL/MWh between 18:00 and 22:00: a gap of 1,608 TL/MWh, against 1,280 TL/MWh in September 2025. The gap between each day’s highest and lowest PTF averaged 2,965 TL/MWh. Over the first nine months this daily spread averaged 2,841 TL/MWh, 49% above 2025 and 85% above 2024, and it exceeded the same month of 2025 in every month of 2026.
The average price is where it was a year ago; what changed is its shape through the day.
What it means for assets
Weighting the hourly PTF by licensed solar output gives an average captured price of 2,199 TL/MWh for a solar plant in September: 80.2% of the average PTF. Over thirteen months this ratio fell to 33% in April and 22% in May, then returned to a 74–81% range from July. For wind it stayed within 90–110% over the same period; because wind also produces in the evening, it is not affected by the change in the price shape.
For a battery the measure is the gap between the day’s expensive and cheap hours. The gap between the two most expensive and the two cheapest hours of the day averaged 2,706 TL/MWh in September, against 1,950 TL/MWh a year earlier. A 1 MW / 2 MWh battery cycling once a day in the day-ahead market (GÖP) alone would have earned a gross margin of about 148 thousand TL/MW in the month, against 102 thousand TL/MW in September 2025.
Illustrative calculation. Battery margin: charge in the two cheapest hours and discharge in the two most expensive each day, 85% round-trip efficiency; imbalance, operating and network charges excluded.
Ancillary services and imbalance prices
The secondary frequency control (SFK) capacity price averaged 2,937 TL/MW·h in September, against 1,632 TL/MW·h a year earlier. A plant providing 1 MW of reserve in every hour of the month would have received about 2.11 million TL in capacity payments. In primary frequency control (PFK) the price was 827 TL/MW·h, close to a year earlier.
That is about 14 times the battery margin, but the pool is small: in September the average hourly SFK reserve was 1,020 MW and the PFK reserve 430 MW. With reserve needs fixed, every new participant pushes the price down.
SFK revenue assumes 1 MW of reserve paid at the capacity price in every hour of the month; energy payments, performance conditions and outages excluded.
In SFK, 1 MW shows 14 times the revenue of GÖP arbitrage; but the pool is around 1,000 MW.
In balancing, the system was in surplus more often: it was long in 312 hours of September and short in 378, against 228 and 472 a year earlier. Up-regulation instructions (YAL) totalled 274 GWh, 36% below a year earlier, and down-regulation instructions (YAT) 219 GWh, 14% above. The system marginal price (SMF), the balancing market price, averaged 2,507 TL/MWh, 235 TL/MWh below the PTF.
In the median hour the SMF equals the PTF, but the tails are widening. In September 2026 the SMF was at least 1,700 TL/MWh below the PTF in the lowest 10% of hours and at least 912 TL/MWh above it in the highest 10%. A year earlier these thresholds were −995 and +588 TL/MWh. At the imbalance prices published by EPİAŞ, a surplus MWh cost 588 TL/MWh against the PTF in the average hour and a short MWh 411 TL/MWh, against 324 and 258 TL/MWh in September 2025.
August settlement
Imbalance volumes, realised generation and unlicensed generation are published with settlement, about a month later. This section covers August, the latest month with complete data; September will follow in next month’s report.
Total system imbalance in August was 1.77 TWh: 0.80 TWh positive and 0.97 TWh negative. The extra cost that participants bore against the PTF because of these imbalances was 1.05 billion TL. The volume-weighted average cost was 591.6 TL/MWh, 77% above a year earlier and 20% of the average PTF.
Positive imbalance cost = PTF − positive imbalance price; negative imbalance cost = negative imbalance price − PTF. Hourly costs are weighted by the system-wide imbalance volumes published by EPİAŞ.
The heat map shows where in the month the cost was concentrated. By hour, the highest averages were at 15:00 (751 TL/MWh) and 18:00 (711 TL/MWh), the lowest at 05:00–06:00 (412–423 TL/MWh). Among days of the week Saturday stands out at 735 TL/MWh, against 420 TL/MWh on Wednesday. The median hourly cost was 479 TL/MWh, and it exceeded 1,086 TL/MWh in 10% of hours. Positive imbalance is skewed: its median is 108 TL/MWh, but the costliest 10% of hours are above 1,444 TL/MWh.
Realised generation (UEVM, the settlement-based injection data) includes unlicensed plants and completes the picture. Solar’s share of generation in August was 14.1%, about four times the 3.5% visible in real-time data. Of solar output, 3.95 TWh came from unlicensed plants; hourly solar output peaked at 20,552 MWh (August 2025: 17,903 MWh). Reservoir hydro’s share rose from 11.3% to 22.6% while gas fell from 24.3% to 10.8%.
Weighted by the output profile of all solar plants, the captured price in August was 2,274 TL/MWh, 78.2% of the average PTF; the licensed profile alone gave 81.1%. The difference comes from unlicensed output being more concentrated in the midday hours, when prices are lowest. A year earlier the same ratio was 84.7%.
The realised unit cost of YEKDEM, Türkiye’s renewable support mechanism, has also been published for August: 395.30 TL/MWh, after 486.31 TL/MWh in July. Both months came in far above EPDK’s April forecast: 2.6 times in July and 1.8 times in August. In a fixed-price supply contract that priced YEKDEM at the forecast, the difference comes straight out of the margin.
Looking ahead to October
The average PTF over the first seven days of October was 2,341 TL/MWh; on the weekend of 3–4 October the daily average fell to around 1,600 TL/MWh. On the electricity futures market (VEP), the daily indicative price of the October baseload contract stayed at 2,858.65 TL/MWh throughout September.
The USD/TRY rate is the 30 September 2026 settlement price of the USDTRY future on Borsa İstanbul’s derivatives market (VİOP) expiring on the last business day of the delivery month; for 2027 the average of the January–December 2027 contracts is used. The indicative prices of the November and December electricity contracts did not change during September, pointing to limited trading on VEP. USD/TRY futures, by contrast, are deep: the November contract traded 4.0 billion TL on 30 September.
The curve says two things. Prices are expected to rise to 3,200–3,600 TL/MWh in the winter months. The April 2027 contract at 1,105 TL/MWh shows the market pricing another spring of cheap supply, similar to 2026.
USD/TRY futures price the same months between 51.48 (November 2026) and 57.99 (April 2027). At these rates VEP prices are worth 62–67 $/MWh in the winter months, 19 $/MWh in April 2027 and 51 $/MWh on average for 2027. September’s realised average was 56.6 $/MWh. In dollar terms, the market expects prices above September’s level for the winter and below it for 2027 as a whole.
Cost references did not change in September: the GÖP price cap has been 4,500 TL/MWh since 4 April 2026, and the YEKDEM cost forecast EPDK updated in April is 330.66 TL/MWh for September and 332.82 TL/MWh for October. During the month EPDK granted Kuvvet Enerji a 49-year generation licence for a solar-plus-storage project in Karaçoban, Erzurum (Board Decision 14842-12), and the decision on the transmission surcharge for 2027 (14864) was published in the Official Gazette on 16 September.
For investors
The lesson of September is that the average price is not enough. The PTF is unchanged in lira on a year ago but 15% lower in dollars; a solar plant captured 80% of the average, and the cost of imbalance rose 77% in a year. The same average price means very different revenue for two assets with different output profiles and forecast quality.
The widening gap between evening and midday raises the value of storage added to solar, and SFK prices show a larger revenue line for batteries than GÖP. Whether either lasts will depend on hydrology, the battery capacity that gets built and reserve needs. We will track these variables in this report every month.
At Frekans we calculate these indicators every month, plant by plant, for the plants we manage and update bidding and storage strategy accordingly. For projects at the investment stage we build the revenue model not on the average price but on the hourly price shape, the dollar equivalent and the cost of imbalance.
