A step-by-step framework for running a bankable solar feasibility study — from site assessment and system sizing to CAPEX, tariff structuring, IRR, and risk. Built for developers and investors who need decisions, not white papers.
Why a Feasibility Study Matters
Most solar projects do not fail because the technology is wrong. They fail because someone skipped a question early — a tariff assumption, an offtaker risk, a grid constraint, a tax line — and the consequences only surfaced two years later when the model stopped balancing.
A solar feasibility study is the structured way to ask those questions before you commit capital. Done well, it tells you three things: whether the project can be built, whether it can be financed, and whether it will actually return what the spreadsheet promises.
This guide walks through the six core sections of a bankable feasibility study, in the order an experienced developer would build them.
1. Site Assessment
Everything starts with the site. Before any financial model, you need to know what you are dealing with physically.
The basics:
- Solar resource. GHI and tilted-plane irradiation from a credible source (Solargis, Meteonorm, or NASA POWER as a free baseline). Annual yield is the headline, but seasonality and inter-annual variability matter for cash flow stability. - Available area. Usable hectares after setbacks, shading, slope, and exclusion zones. A 10 MWp ground-mount needs roughly 12–18 hectares depending on row spacing and tracker choice. - Soil and topography. Ground-bearing capacity drives mounting structure cost. Slopes above 5–8% start adding meaningfully to civils. - Access and logistics. How modules and transformers physically reach the site. In emerging markets this is often the silent killer of CAPEX assumptions.
2. Technical System Design
Once the site is understood, the system design follows. The feasibility-stage design does not need to be construction-ready — it needs to be defensible enough to size CAPEX and yield.
Key decisions:
- DC capacity (kWp) and AC capacity (kVA). The DC/AC ratio (typically 1.1–1.4) directly affects yield and inverter clipping. - Module choice. Mono PERC vs. TOPCon vs. bifacial. Bifacial gains 5–15% on high-albedo ground but adds racking complexity. - Inverter topology. Central vs. string. Central is cheaper per watt but exposes more capacity to single-point failure. - Mounting. Fixed-tilt, single-axis tracker, or rooftop. Trackers add 8–15% yield in good resource zones but also add OPEX. - Battery sizing (if hybrid). Power (MW) and energy (MWh) sized to the load profile or arbitrage opportunity, not to a round number.
3. Grid Integration and Permitting
A perfectly designed system that cannot connect to the grid is worth zero. Grid integration deserves its own workstream, not a footnote.
Cover at minimum:
- Point of connection. Distance to the nearest substation with available capacity, and the cost of any line extension or upgrade. - Available headroom. What the utility will actually let you inject, in MW and at what voltage level. - Permitting timeline. Environmental, land-use, generation licence, grid connection agreement. In most emerging markets, permitting is the longest item on the critical path — not construction. - Curtailment risk. Especially relevant in markets with growing renewables penetration and weak transmission.
4. Financial Analysis
This is where most feasibility studies become useful or useless. A bankable financial model needs to address both sides of the cash flow.
CAPEX
Build the CAPEX bottom-up, by category:
- Modules - Inverters and transformers - Mounting and trackers - BoS (cabling, combiner boxes, monitoring) - Civils and access roads - Grid connection and substation works - EPC margin and contingency - Soft costs (development, legal, advisory, financing fees)
A common mistake is to use a single $/Wp benchmark. Benchmarks are useful for sanity-checking — not for sizing equity.
OPEX
Recurring costs over the project life:
- O&M contract (typically $8–$20/kWp/year for utility-scale) - Land lease or rates - Insurance - Asset management and reporting - Inverter replacement reserve (year 10–12) - Battery augmentation reserve (for hybrid projects)
Revenue
For a PPA project, revenue is tariff × generation, both escalated. The key questions: