How is imbalance cost calculated? Calculate it for one hour of your plant

A plant sells next-day output in the day-ahead market and corrects it in the intraday market close to delivery. When actual output differs from what was sold, the difference is imbalance. For wind and solar it is never zero; the question is how large it is and at what price it settles.

Imbalance cost does not appear in the sales price but is deducted from revenue every month with the settlement notice. This page explains how it is calculated, the change that took effect in 2026 and how to reduce it, with examples.

What is imbalance

Each participant is responsible, in every settlement period, for the difference between energy traded and energy actually produced or consumed. The settlement period in Türkiye is one hour. Producing more than sold creates positive imbalance; producing less creates negative imbalance.

The system itself is long, short or balanced each hour, as set by the net direction of TEİAŞ instructions in the balancing market. When the system is long, down-regulation pulls the system marginal price (SMF) below PTF; when short, up-regulation pushes SMF above PTF.

How the imbalance price is calculated

The logic is simple: surplus energy is valued at the lower of the two prices and missing energy at the higher one, each with a coefficient. Imbalance is therefore a loss in both directions compared with trading at PTF.

What changed in 2026: coefficients by system direction

Until 1 January 2026, k and l were 3% in every hour. Following the amendment to the Balancing and Settlement Regulation, coefficients are now set in each settlement period by the system’s direction: 6% when a participant deviates with the system and 3% when against it.

The coefficients also apply at both ends of the price range. When PTF and SMF fall below 150 TL/MWh, the shortfall price rests on V and becomes 150 × (1 + k); when PTF or SMF reaches the 4,500 TL/MWh price cap, a shortfall settles above the cap at 4,500 × (1 + k). At the same extremes, the surplus price falls to zero or becomes 4,500 × (1 − l).

Both extremes are explained with examples below in “Low-price hours: the V rule” and “Price-cap hours”.

Coefficients are set by EPDK Board decision and can change. Calculations should use the current decision.

Four scenarios, four prices

A plant can face four situations in the same hour. The table assumes PTF of 2,500 TL/MWh, SMF of 2,000 TL/MWh when the system is long and 3,200 TL/MWh when short.

Figure 1 Cost per MWh of deviation

Surplus, with the system

620

Surplus, against the system

75

Shortfall, with the system

892

Shortfall, against the system

75

In this example, deviating with the system costs eight to twelve times more than deviating against it.

Deviating against the system helps it, so the penalty is just the coefficient. Deviating with the system makes its problem bigger and pays both the PTF–SMF spread and the 6% coefficient. The problem for renewables is that their deviations usually point the same way as the system.

Low-price hours: the V rule

The negative imbalance price formula has a third value besides PTF and SMF: V. The Balancing and Settlement Regulation defines V as a unit price set by Board decision with an initial value of 150 TL/MWh. Because NDF uses the highest of the three, the price of a shortfall never falls below 150 × (1 + k) in any hour.

The rule matters at midday, when solar output is high and PTF drops to zero. Say PTF and SMF are zero, the system is long and a solar plant falls 2 MWh short. Its deviation is against the system, so k is 3%: NDF = 150 × 1.03 = 154.5 TL/MWh. Although PTF is zero, DM = 2 × 154.5 = 309 TL. A plant over-producing in the same hour gets PDF = MIN(0, 0) × 0.94 = 0; surplus earns nothing.

In settlement, the highest SMF of the balancing sub-periods in the hour (SMF_N) is used for negative imbalance and the lowest (SMF_P) for positive imbalance. The calculator works with a single SMF for the hour.

Price-cap hours: settlement above the limit

The highest price allowed in the day-ahead and balancing markets has been 4,500 TL/MWh since 4 April 2026 under EPDK decision 14459. It is the highest price at which you can sell or buy energy in the market. The imbalance price is not bound by this limit: NDF applies (1 + k) to the higher of PTF and SMF. When PTF or SMF is at the cap, a shortfall settles at 4,500 × (1 + k), above the limit itself.

These hours are usually winter and summer evenings with high demand and weak wind or sun. The system is short, so a plant falling short deviates with it. In such an hour, every missing MWh costs 270 TL more than the highest market price.

Example: a wind farm sold 30 MWh for 19:00, the wind stayed weaker than forecast and it produced 24 MWh. PTF and SMF are at 4,500 TL/MWh and the system is short (YAL). EDM = 24 − 30 = −6 MWh. NDF = 4,500 × 1.06 = 4,770 TL/MWh. EDT = −6 × 4,770 = −28,620 TL. DM = −6 × 4,500 − (−28,620) = 1,620 TL and DM % = 1,620 / (24 × 4,500) = 1.5%.

Figure 2 Price of 1 MWh in a price-cap hour

Market sell and buy cap

4,500

Shortfall, against the system

4,635

Shortfall, with the system

4,770

DM % looks low in these hours because the gap between PTF and NDF is only the coefficient. For comparison, in an hour with PTF at 2,500, SMF at 3,000 and the system short, the same 6 MWh shortfall costs 6 × (3,180 − 2,500) = 4,080 TL. The difference in a price-cap hour lies elsewhere: the 4,770 TL paid for each missing MWh is a price no buyer can pay and no seller can receive in the market.

In price-cap hours, closing the gap on the intraday market is therefore 135 to 270 TL per MWh cheaper than leaving it to imbalance, even when the energy is bought at the cap. Updating the position before the evening hours keeps forecast errors from settling at the most expensive price.

Example prices are assumptions. The price cap can change by Board decision; calculations should use the current decision.

Example 1: a sunny noon

A solar plant sold 6 MWh for 12:00 but produced 8 MWh as clouds cleared earlier than forecast. Other plants in the region over-produce at the same time, so the system is long. PTF is 2,200 and SMF 1,800 TL/MWh.

EDM is +2 MWh and PDF = 1,800 × 0.94 = 1,692 TL/MWh. EDT is 3,384 TL against 4,400 TL at PTF; DM is 1,016 TL and DM % = 1,016 / (8 × 2,200) = 5.77%. This is the calculator’s default scenario. Under the previous rule it would have settled at 1,800 × 0.97 = 1,746 TL/MWh, a 908 TL loss.

Example 2: wind dropping early in the evening

A wind farm sold 30 MWh for 20:00 but the wind eased early and it produced 22 MWh. Evening demand is high and the system is short. PTF is 3,100 and SMF 3,800 TL/MWh.

The 8 MWh shortfall is bought at 3,800 × 1.06 = 4,028 TL/MWh. The difference to PTF is 928 TL per MWh, or 7,424 TL in one hour, about 8% of the plant’s sales revenue for that hour.

Prices in examples 1 and 2 are assumptions; real values change hour by hour.

Example 3: portfolio netting

Take two plants in the same hour. A solar plant sold 8 MWh but produced 6; a wind farm sold 5 MWh but produced 7. The system is long, PTF 2,500 and SMF 2,000 TL/MWh.

Figure 3 Imbalance cost of the two plants

Separate settlement

1,390

Portfolio netting

0

Settled separately, the solar plant deviates against the system and pays only 3%; the wind farm deviates with it and pays both the spread and 6%. In one portfolio the deviations cancel and no imbalance arises. Real portfolios never net this neatly, but the netting share grows with portfolio size and diversity.

In balancing groups, from 2026 a participant whose individual imbalance ratio exceeds 5% bears its own imbalance. The Aggregation Regulation makes the aggregator responsible for imbalance and KÜPST at portfolio level.

Imbalance over a month

Hourly costs add up over a month. Take a typical renewable plant: 3,000 MWh a month, 10% average deviation, half surplus and half shortfall, 60% in the system’s direction.

Figure 4 Monthly imbalance cost in the default scenario

Previous rule

131,040

2026 rule

145,080

2026, in a portfolio

101,556

Assumptions: PTF 2,500; SMF 2,000 when long, 3,200 when short; V 150 TL/MWh; KÜPST excluded. In this scenario the 2026 rule raises cost by 10.7%.

KÜPST: the second cost beyond imbalance

On top of energy imbalance, generators pay a deviation charge (KÜPST) for deviations from their final generation plan. Deviations within a tolerance band set by Board decision for each source type are free; deviations beyond it are invoiced separately. As KÜPST is plant- and plan-specific, it is not included in this calculator.

How to reduce imbalance cost

From an investor’s perspective

Feasibility models often assume imbalance as a fixed percentage. The 2026 rule makes that assumption more misleading: cost now depends less on the size of the deviation than on whether it runs with the system. Two plants with the same forecast error can face very different costs depending on their portfolio and timing.

Forecast quality, intraday trading capacity and portfolio structure are therefore direct revenue items. Managing imbalance can have the same effect as raising the sales price by several percentage points.

At Frekans we manage plant imbalance through forecasting, intraday trading and portfolio netting. With your plant’s hourly generation and settlement data we can work out your real imbalance cost and how far it can fall in a portfolio.