The most common mistake in solar power feasibility is to ignore the power plant type as "roof / land". 5.1c (same metering point) vs 5.1h (separate metering) is not just meter placement: the upstream and downstream distribution charge base can shift the ROI by tens of points. If the energy item (offset / net consumption / surplus) and the money item (withdrawal DB discount, outgoing DB cost) are not modeled together during the hourly clearing period, the report will either be inflated or miss the realistic income. This article clarifies two rules compatible with the product account and provides a feasibility checklist.
50% discount
5.1c traction
Offset × draw DB
solo sale
5.1c yield
There is no DB in offset
no discount
5.1h traction
Standard discrete measurement
genre mix
Feasibility risk
ROI swells/collapses
What are 5.1c and 5.1h?
| Genre | measurement | typical facility | critical in feasibility |
|---|---|---|---|
| 5.1c | Same measuring point (bidirectional) | Roof Solar | Traction 50% + yield only sales |
| 5.1h | Separate measurement (production / consumption) | Land solar power plant, separate meter | No traction discount; giving base is wide |
| domestic consumption | No sales / self consumption | No sales scenario | Sales revenue is not calculated |
Consumption before clearing at the same metering point is often clarified by the formula T = A + (B − C) (A draw, B production meter feed, C bidirectional feed). The details of the formula are in our Hourly Settlement 2026 guide; Type selection and form fields are summarized in our GES feasibility report guide. The focus of this article is the distribution fee difference.
5.1c distribution economics: two rules
When production and consumption are at the same measurement point, two distribution effects occur after hourly (or line-by-line) netting. The first is the traction direction: a 50% discount is applied to the traction distribution fee in the part equal to the offsetting energy - that is, the intersection of production and consumption in that slice. Secondly, the giving aspect: offsetting = the giving distribution is not paid on the part of production that meets the consumption; Output DB is calculated only on excess kWh (sold to the grid).
| Direction | base | What happens? |
|---|---|---|
| Draw (consumption subscriber) | Offset kWh | 50% delivery discount (savings) |
| Supply (production / supply to the grid) | kWh sold only | There is no transfer DB in the part up to the offset |
| surplus | Production − offset (within limit) | Veriş DB + sales revenue |
Example: production 100 kWh, consumption 80 kWh
The figures below are exemplary (not the actual EMRA unit price). The aim is to show the base: offset 80 kWh, sale 20 kWh.
| pencil | 5.1c | 5.1h (standard) |
|---|---|---|
| offset | 80 kWh | 80 kWh |
| Sales (surplus) | 20 kWh | 20 kWh |
| Traction DB discount | 80 × traction DB × 50% | None (0) |
| Issue DB base | 20 kWh (sales only) | Generally net production / delivery (offsetting + sales band) |
| Feasibility effect | Traction savings + low delivery costs | No traction savings; delivery cost is higher |
- Assuming traction DB = 1.00 TL/kWh, 5.1c savings ≈ 80 × 1.00 × 0.5 = 40 TL (that slice).
- Assuming delivery DB = 0.66 TL/kWh, 5.1c delivery cost ≈ 20 × 0.66 = 13.2 TL.
- In the same slice, traction discount at 5.1h is 0; If the output base approaches the 100 kWh band, the cost is ~66 TL — the type mix distorts the ROI.
- Actual units vary by subscriber group and term plan; Enter the inflow and outflow DB separately in the model.
What's different in 5.1h?
In standard 5.1h (separate measurement), the 50% distribution discount due to offset in the draw direction is not applied. Output distribution is based on net production / energy base delivered to the grid — typically gross production on the product side minus generation meter internal consumption; may include tax base offset + sales band. Result: at the same kWh profile the distribution cost of 5.1h is higher than 5.1c, while the draw savings line is zero. Modeling rooftop SPP assuming 5.1h ignores distribution savings; Mistaking land 5.1h for 5.1c produces an imaginary 50% discount.
Feasibility checklist
- Plant type: 5.1c / 5.1h / internal consumption — identical to field measurement.
- Hourly (or at least peak daytime) consumption–production profile; The monthly total is not enough.
- The traction distribution unit (consumption subscriber) and the output distribution unit are on separate lines.
- In scenario 5.1c: offset × draw DB × 50% + sale × give DB.
- In 5.1h scenario: no traction reduction; Do not exaggerate/understate the giving base.
- Paid production limit (2×) and surplus sales — in our unlicensed solar energy sales guide.
- In the USD guaranteed portfolio that has completed 10 years, the LÜ-1→LÜ-2 transaction fee is written separately - do not get confused here.
- Set-off tariff difference for eligible consumers: Hourly Set-Off Roadmap for Eligible Consumers.
ENOPTIMAL — type is correct, distribution is visible
ENOPTIMAL Solar Power Plant Feasibility Report Application Form takes the power plant type (5.1h / 5.1c / domestic consumption) as a mandatory input; The wrong type will distort the sales and offset projection. Post-commissioning offset module shows hourly offset, traction distribution savings and delivery cost in the same flow — in 5.1c, the delivery base is kWh sold. You can run the scenario and get a PDF/Word report from the form on our SPP optimization analysis page; Verify feasibility with real profile in our SPP production monitoring module in operation.
Conclusion
As long as the production meets the consumption at the same measurement point (5.1c), there is a 50% discount in the offsetting part in the traction distribution; No distribution is paid for that portion - the delivery is recorded in the DB only as surplus. There is no draft discount in discrete metering (standard 5.1h); The giving base is wider. Choosing the wrong type in feasibility will disrupt distribution economics and turnaround time. The right model: hourly offset + correct type + separate off/out units — then field validation with ENOPTIMAL.