A Technical Report: Feasibility Assessment of a Rooftop Solar PV Installation for a Commercial Building

This is a worked technical report produced by Assignment Help Center to illustrate how a distinction-standard undergraduate engineering report is structured, calculated and argued. It is a model answer for study purposes, not a document to be submitted as your own work. All numerical inputs and outputs are illustrative and are chosen to demonstrate method rather than to represent a specific real building.

Executive Summary

This report assesses the technical and economic feasibility of installing a rooftop solar photovoltaic (PV) system on a mid-sized commercial building in central England. The building is assumed to have a flat roof of 1,000 m2, of which 60% (600 m2) is treated as usable for panel deployment after allowing for setbacks, plant, access walkways and inter-row shading. Using an illustrative 430 W monocrystalline module, the roof can accommodate approximately 272 panels, giving an installed capacity of about 117 kWp.

Applying a UK specific yield of 950 kWh per kWp per year, consistent with published irradiance data for the region, the system is estimated to generate approximately 111,100 kWh annually. This corresponds to an implied capacity factor of 10.8%, which is typical for the UK. Assuming 75% of the output is consumed on site (displacing electricity bought at an illustrative 28 p/kWh) and 25% is exported (paid at 5 p/kWh), the annual financial benefit is about £24,700. Against an illustrative capital cost of £111,100 (£950/kWp), the simple payback period is approximately 4.5 years.

The environmental benefit is estimated at 23.0 tonnes of CO2 equivalent avoided per year, using a UK grid emission factor of 0.207 kg CO2e/kWh. Over a 25-year design life, allowing for 0.5% annual degradation, lifetime generation is around 2.62 GWh, avoiding roughly 542 tonnes of CO2e. The assessment concludes that the installation is technically feasible and economically attractive under the stated assumptions, subject to a structural survey, a detailed shading analysis and confirmation of grid connection capacity. All figures should be treated as illustrative and refined through site-specific engineering.

1. Introduction

Rooftop solar PV has become one of the most widely adopted distributed generation technologies in the United Kingdom, driven by falling module prices, rising commercial electricity tariffs and organisational commitments to decarbonisation. For a commercial building with a large, unshaded roof and a substantial daytime electrical load, on-site solar generation can displace a significant fraction of imported grid electricity precisely when consumption is highest, improving both the economics and the emissions profile of the site (Masters, 2013).

This report presents a first-pass feasibility assessment for a hypothetical commercial building. The objective is to establish whether a rooftop PV installation is worth pursuing to detailed design stage, and to quantify the likely capacity, energy yield, cost, payback and carbon savings. The report deliberately uses transparent, hand-checkable calculations so that each assumption can be scrutinised and, where necessary, revised for a real project. It does not replace the detailed structural, electrical and financial studies that a full design would require; rather, it identifies whether those studies are justified.

The commercial case for rooftop PV rests on a coincidence that is unusually favourable in the non-domestic sector: a typical office, warehouse or retail unit draws most of its electrical demand during daylight working hours, which is exactly when a solar array is generating. Every unit generated and consumed on site avoids the full retail tariff, including network, policy and supplier margins, rather than merely the wholesale price. This makes the economics of a well-matched commercial system materially stronger than those of a comparable domestic installation, where much of the output is exported at a low rate because the household is unoccupied during the day. Understanding this relationship is central to interpreting the appraisal that follows.

The scope covers system sizing, annual energy yield, a simple financial appraisal, an estimate of avoided carbon emissions, and a statement of the principal limitations. Half-hourly load matching, inverter selection, cable sizing, protection coordination and planning consent are outside the scope of this introductory assessment.

2. Building and Site Assumptions

The building is assumed to have a rectangular flat roof measuring 40 m by 25 m, giving a gross plan area of 1,000 m2. Flat commercial roofs rarely permit full coverage: space is lost to roof-edge setbacks required for wind uplift and maintenance access, to existing plant such as air-handling units, to walkways, and to the row spacing needed to prevent one row of tilted panels from shading the next. A usable fraction of 60% is therefore adopted, giving 600 m2 available for the array. This is a conservative but defensible planning figure for a first assessment (BRE, 2016).

The site is assumed to be in central England, a location for which published horizontal and in-plane irradiance data are readily available (European Commission, 2023). The array is assumed to be mounted on a ballasted, south-facing frame at a shallow tilt of around 10 degrees, a common arrangement for flat commercial roofs that balances yield against wind loading and row spacing. The roof is assumed to be structurally capable of carrying the additional dead and imposed load; this must be confirmed by a chartered structural engineer before installation.

3. System Sizing and Energy Yield Calculations

3.1 Array capacity

The chosen module is an illustrative monocrystalline PERC panel with dimensions 2.10 m by 1.05 m and a rated output of 430 W at standard test conditions (STC: 1,000 W/m2 irradiance, 25 degrees C cell temperature). The module plan area is:

$$A_{module} = 2.10 \times 1.05 = 2.205\ \text{m}^2$$

The number of modules that fit within the usable roof area is:

$$N = \left\lfloor \frac{A_{usable}}{A_{module}} \right\rfloor = \left\lfloor \frac{600}{2.205} \right\rfloor = 272\ \text{modules}$$

The installed direct-current capacity is therefore:

$$P_{installed} = N \times P_{module} = 272 \times 430 = 116{,}960\ \text{W} \approx 117\ \text{kWp}$$

The module efficiency implied by this specification provides a useful sanity check:

$$\eta_{module} = \frac{P_{module}}{A_{module} \times 1000} = \frac{430}{2.205 \times 1000} = 0.195 = 19.5\%$$

A module efficiency of 19.5% is representative of good-quality commercial monocrystalline panels available in the mid-2020s, confirming that the assumed rating and dimensions are mutually consistent.

3.2 Annual energy yield

The most direct way to estimate annual output is the specific-yield method, in which installed capacity is multiplied by the local specific yield (the annual energy delivered per unit of installed capacity). For a well-oriented system in central England, a specific yield of 950 kWh/kWp/year is representative and lies within the 800-1,000 kWh/kWp range indicated by irradiance databases (European Commission, 2023):

$$E_{annual} = P_{installed} \times Y_{specific} = 116.96 \times 950 \approx 111{,}100\ \text{kWh/year}$$

This result can be cross-checked against the implied capacity factor, defined as the ratio of actual annual generation to the theoretical output if the array ran at full rated power for every hour of the year:

$$CF = \frac{E_{annual}}{P_{installed} \times 8760} = \frac{111{,}100}{116.96 \times 8760} = 0.108 = 10.8\%$$

A capacity factor of about 11% is consistent with published UK solar performance and provides confidence that the specific-yield figure is not optimistic.

A second, independent cross-check uses the irradiance method. Taking an annual in-plane irradiance of 1,100 kWh/m2 for a shallow south-facing surface, a total module area of 600 m2, a module efficiency of 19.5% and a performance ratio of 0.80 (which accounts for inverter losses, temperature effects, soiling, wiring losses and mismatch):

$$E_{annual} = A_{array} \times H_{annual} \times \eta_{module} \times PR = 600 \times 1100 \times 0.195 \times 0.80 \approx 102{,}900\ \text{kWh/year}$$

The two methods agree to within about 7%, which is well within the uncertainty of a feasibility-stage estimate. The specific-yield figure of 111,100 kWh/year is carried forward as the central estimate, with the irradiance result treated as a conservative lower bound.

4. Financial Appraisal

4.1 Capital cost

The turnkey installed cost of commercial rooftop PV in the UK has fallen substantially and, for a system of this scale, an illustrative all-in cost of £950 per kWp is adopted. This covers modules, inverters, mounting, cabling, protection, installation labour and commissioning:

$$CAPEX = P_{installed} \times C_{unit} = 116.96 \times 950 \approx £111{,}100$$

4.2 Annual benefit

The value of the generated electricity depends heavily on how much is consumed on site rather than exported, because self-consumption displaces electricity bought at the full retail tariff, whereas exported energy earns only the lower Smart Export Guarantee rate (Ofgem, 2020). A commercial building with a strong daytime load is assumed to self-consume 75% of the output, with the remaining 25% exported. Using an illustrative import tariff of 28 p/kWh and an export tariff of 5 p/kWh:

$$E_{self} = 111{,}100 \times 0.75 = 83{,}300\ \text{kWh}, \qquad S_{self} = 83{,}300 \times £0.28 \approx £23{,}300$$

$$E_{export} = 111{,}100 \times 0.25 = 27{,}800\ \text{kWh}, \qquad S_{export} = 27{,}800 \times £0.05 \approx £1{,}400$$

$$\text{Total annual benefit} = £23{,}300 + £1{,}400 \approx £24{,}700$$

4.3 Simple payback

The simple payback period, which ignores discounting, maintenance and tariff inflation, is:

$$T_{payback} = \frac{CAPEX}{\text{Annual benefit}} = \frac{111{,}100}{24{,}700} \approx 4.5\ \text{years}$$

A simple payback of roughly four and a half years, against a system design life of 25 years, indicates a strong prima facie economic case. The figure is sensitive to the import tariff and the self-consumption fraction: a higher retail price or greater on-site use shortens the payback, while a lower daytime load lengthens it. To illustrate the sensitivity, if the self-consumption fraction fell from 75% to 50%, a quarter of the output would shift from being valued at 28 p/kWh to just 5 p/kWh, cutting the annual benefit by roughly a fifth and extending the payback to well over five years. Conversely, a sustained rise in commercial electricity prices, which have been volatile in recent years, would shorten it. This asymmetry is why measuring the building’s actual load profile is the single most valuable piece of due diligence before commitment.

A full appraisal would go further than simple payback. It would compute a discounted net present value and internal rate of return using an appropriate cost of capital, incorporate an annual operations and maintenance allowance (typically 1-2% of CAPEX for cleaning, inverter replacement and monitoring), and model both tariff escalation and the gradual decline in output as the modules age. Even after these refinements, a system that returns its capital in under five years and then generates near-free electricity for a further two decades represents a compelling investment, and the simple result is robust enough to justify proceeding to detailed design.

5. Environmental Benefit

Displacing grid electricity with solar generation avoids the carbon emissions associated with that electricity. Using the UK grid emission factor of 0.207 kg CO2e per kWh (DESNZ, 2023), the annual avoided emissions are:

$$CO_{2,annual} = E_{annual} \times EF = 111{,}100 \times 0.207 \approx 23{,}000\ \text{kg} = 23.0\ \text{tonnes CO}_2\text{e/year}$$

Over the 25-year design life, allowing for module degradation of 0.5% per year, the cumulative generation is approximately 2.62 GWh. Holding the emission factor constant for illustration, the lifetime avoided emissions are:

$$CO_{2,lifetime} = 2{,}617{,}000 \times 0.207 / 1000 \approx 542\ \text{tonnes CO}_2\text{e}$$

In practice the avoided emissions per kWh will fall over time as the national grid continues to decarbonise, so the later-year savings would be smaller than this constant-factor estimate suggests. The figure nonetheless conveys the scale of the environmental contribution and supports the building operator’s decarbonisation objectives.

6. Limitations

Several limitations qualify the results and must be resolved before commitment:

1. Structural capacity. The additional dead load of a ballasted array can be significant. A structural survey is essential to confirm the roof can carry the load, especially under combined wind and snow conditions. 2. Shading and orientation. The analysis assumes negligible shading. Nearby buildings, parapets, plant and self-shading between rows can reduce yield materially; a site-specific shading study using a solar pathfinder or 3D model is required. 3. Load matching. The 75% self-consumption assumption is central to the economics but has not been verified against a measured half-hourly load profile. If the building’s daytime demand is lower, more energy is exported at the lower rate and the payback lengthens. 4. Tariff and cost volatility. Electricity prices, export rates and installation costs are all volatile. The single-point figures used here should be replaced with sensitivity ranges. 5. Grid connection. A 117 kWp system may require a formal connection application, and local network constraints could limit export capacity or add cost. 6. Illustrative inputs. Every numerical input is illustrative. Real quotations, a real irradiance dataset for the exact location, and the actual roof geometry must replace these placeholders in any real assessment.

7. Conclusion

Under the stated illustrative assumptions, a rooftop solar PV installation on the commercial building examined here is both technically feasible and economically attractive. A usable roof area of 600 m2 supports an installed capacity of approximately 117 kWp, generating an estimated 111,100 kWh per year at a realistic UK capacity factor of 10.8%. The system offers an annual financial benefit of around £24,700, a simple payback of roughly 4.5 years, and avoided emissions of 23.0 tonnes of CO2e per year, rising to about 542 tonnes over its 25-year life.

The two independent yield methods agree closely, giving confidence in the central estimate. The principal risks are structural capacity, shading and the accuracy of the self-consumption assumption, none of which undermines the headline case but all of which warrant detailed investigation. On the strength of this feasibility assessment, the recommendation is to proceed to a full design study comprising a structural survey, a measured load analysis, a detailed shading assessment and firm supplier quotations.

References

BRE (2016) Solar photovoltaics: Guidance for the built environment. Watford: Building Research Establishment.

DESNZ (2023) Greenhouse gas reporting: conversion factors 2023. London: Department for Energy Security and Net Zero. Available at: https://www.gov.uk/government/publications/greenhouse-gas-reporting-conversion-factors-2023 (Accessed: 18 July 2026).

Duffie, J.A. and Beckman, W.A. (2013) Solar Engineering of Thermal Processes. 4th edn. Hoboken, NJ: John Wiley & Sons.

European Commission (2023) Photovoltaic Geographical Information System (PVGIS). Ispra: Joint Research Centre. Available at: https://re.jrc.ec.europa.eu/pvg_tools/en/ (Accessed: 18 July 2026).

Masters, G.M. (2013) Renewable and Efficient Electric Power Systems. 2nd edn. Hoboken, NJ: John Wiley & Sons.

MCS (2019) MIS 3002: The Solar PV Standard, Issue 4.0. Daventry: Microgeneration Certification Scheme.

Ofgem (2020) The Smart Export Guarantee (SEG). London: Office of Gas and Electricity Markets. Available at: https://www.ofgem.gov.uk/environmental-and-social-schemes/smart-export-guarantee-seg (Accessed: 18 July 2026).