Design, Calculation and EPC Budget Framework for Rooftop Solar Selling 100% to a Factory

Legal framework and grid connection procedures for rooftop systems selling to the grid

Rooftop PV systems selling to EVN must meet connection conditions up to 35 kV, be installed on building roofs and complete bi‑directional meter acceptance before signing the PPA according to Decision 13/2020 and Circular 18/2020. ^[2][9]

Scope of application includes rooftop PV systems connected to networks with nominal voltage not exceeding 35 kV, with maximum capacity limits as set by relevant regulatory documents. In site surveys, the utility inspects the proposed POI, the substation’s ability to absorb exported power and the operational safety plan.

Typical connection agreement application documents include the main technical and legal items below.

• Technical documents: single‑line diagram (1‑line), connection scheme, inverter and distribution board technical data.
• Legal documents: ownership papers or a valid authorization of the project owner’s representative.
• Operation and acceptance plan: operating procedures, safety measures and post‑installation acceptance schedule.
• Note: EVN may allow certain documents to be supplemented after acceptance per internal guidance; verify this when submitting the application.

The practical connection procedure usually follows: (1) submit the connection agreement application to the utility; (2) perform site survey and agree on connection conditions; (3) system acceptance, install and record the bi‑directional meter reading; (4) sign the PPA or register generation for payment.

Regarding processing times, Circular 18/2020 specifies administrative timelines for application processing and contract signing, with reference to dates around 31/08/2020; however some provisions have partially expired or been amended, so always check consolidated texts before submission.

On metering and payment, the principle is installation of a bi‑directional meter supplied by the utility and locking readings at acceptance; the start of payment follows terms in Decision 13/2020 and the PPA template in Circular 18/2020.

Special cases, such as connecting at low voltage versus medium/transformer levels, require attention to phase limits and total accepted power at the substation; in the field, if the substation cannot absorb the export, the utility will refuse or request a power relief plan.

Interim conclusion: before implementation, conduct a site survey, confirm substation export capability, prepare full technical and legal documentation, and verify the consolidated text of Circular 18/2020 to ensure connection procedures and PPA clauses are applicable.

Formula to convert kWp to realistic AC output and variables to measure

P_AC for design is commonly calculated as: P_AC = kWp × PR × η_inv × (1 − losses_total). This approach converts nominal kWp to useful AC power by applying system performance and subtracting groups of losses that are relevant for design and acceptance. ^[8][0]

kWp is the module peak power under STC (1000 W/m², 25°C, AM1.5). Performance Ratio (PR) is the ratio of actual energy yield to nominal energy and aggregates many system and climatic factors; in practice PR is estimated from operational data or by using region PVout values to calculate expected yield.

Inverter efficiency (η_inv) is the DC→AC conversion efficiency at operating power and should be chosen as an average across the typical loading range (e.g. efficiency at 25–75% of P_rated). During site survey measure inverter efficiency at representative load levels and note clipping behavior if DC/AC ratio is too high; clipping directly reduces instantaneous P_AC during strong sun.

Losses grouped as “losses_total” to consider include:

• Soiling (dust and fouling) and cleaning frequency depending on operating environment.
• Mismatch between modules, DC cabling losses and MPPT mismatch.
• Inverter clipping due to oversizing (DC/AC ratio) and transformer/tap change losses.
• AC cabling and distribution system losses.
• Thermal losses due to cell temperature, plus availability/curtailment from downtime.
• Degradation over years (account separately for long‑term simulations).

Thermal losses should be separated: use the module temperature coefficient (°C⁻¹) or NOCT reference to estimate power reduction with cell temperature. In site surveys measure cell temperature at peak and use local meteorological data or PVout values published by EVN to adjust expected yield.

Regarding degradation, in practice projects include an annual percentage in long‑term simulations; typical reference values are around 0.5–1%/year and should be treated separately from base PR when doing life‑cycle simulations. During operations monitoring, tracking soiling and inverter performance updates PR and allows adjusting cleaning schedules or DC/AC ratio if needed.

Key decisions at sizing stage: select PR and η_inv based on field data or regional PVout, determine an acceptable DC/AC ratio based on tolerable clipping, and decide whether to include degradation in equipment sizing or only in long‑term energy analysis. Operational warning: do not fold degradation into base PR if the goal is to size for peak/day performance; perform field surveys to collect irradiance, temperature and soiling data before fixing P_AC for transformer sizing.

Transformer selection process — formulas, voltage steps and decision criteria

Select transformer rating starting from the inverter AC power using S_tr ≈ P_AC / cosφ_design; this is the basic formula to determine trafo kVA. ^[1][10]

When calculating P_AC, start with DC source power multiplied by inverter efficiency (P_AC = P_DC × η_inv) and then subtract cable losses, power factor correction losses and inverter limits. In site surveys measure cable lengths, inverter limits and harmonic levels to establish realistic losses before choosing S_tr.

In the field note that inverter output 800 V usually refers to the DC‑link voltage before the inverter; do not use 800 V as transformer winding voltage. For transformers use the AC rated voltage and the AC power after the inverter, and apply a safety factor (typically 1.05–1.25) for temporary overload margins.

Choosing medium voltage or staying LV depends on substation power, distance to the grid and connection limits; typically when substation rating exceeds ~500–1000 kVA consider medium voltage (≥6–10 kV). Design must analyze transformer no‑load and copper losses (P0 and Pcu) and percentage impedance Z% to assess voltage drop, short‑circuit capability and harmonic compatibility.

• Field survey criteria: total AC power at POI, cable lengths, point connection limits, existing harmonic levels.
• Pros/cons of distributed substations: many small substations reduce MV/LV losses but increase number of connection points; central substations reduce transformer count but require larger transformers and possibly OLTC for voltage regulation.
• Maintenance checks: winding temperature, tap position, peak current and harmonic filtering to prevent transformer overheating.

For a 10 MWp rooftop scenario you can distribute many distribution substations (e.g. 10–40 substations of 250–1,000 kVA) or a few central substations (1–3 substations 2,500–4,000 kVA) depending on grid structure and site layout. Final decision requires site survey to measure real power, EVN connection limits and harmonic assessment before selecting transformer type, Z% and whether OLTC is needed.

EPC budget framework for a 10,000 kWp rooftop: cost components and influencing variables

The EPC budget framework for a 10,000 kWp rooftop must separate CAPEX and OPEX and identify technical variables to survey on site for estimation. ^[1][13]

Main CAPEX groups and major construction items include:

• PV modules — largely influenced by $/Wp and module efficiency.
• Inverters and AC/DC cabinets — selected by kW/unit, warranty period and efficiency at local operating temperatures.
• Mounting system, anchors/foundations, wind bracing — roof type and structural characteristics determine foundation work and materials.
• Transformers/substations, bi‑directional meters and control equipment — depend on step‑up needs and connection voltage.
• AC/DC cables, junction accessories, surge protection and grounding.
• Transport, unloading and rooftop handling (safe working at height).

Construction and procedural costs should be separated into: mechanical installation, electrical works, testing & commissioning, as‑built documentation, inspection and HSE. In site surveys measure distance to the substation/POI to estimate cable length and potential need to upgrade the utility substation, as this is a major cost driver.

Differentiate technical and financial contingencies: equipment contingency (usually 5–10%), contingency for design changes and legal risks, and a buffer for material price fluctuations. Annual OPEX should list O&M, insurance, remote monitoring and planned replacements such as inverter replacement after 10–15 years or sensor/meter replacement when required.

Major cost variables to verify on site include: module price ($/Wp), inverter price per kW/unit, actual system performance ratio, roof type and foundation scope, transformer/substation needs, and cable distance to the POI. For EVN connection clarify the substation’s ability to absorb exported power, connection voltage level and the potential cost of upgrading the substation or lines.

Quotation breakup principle: separate equipment price (FOB/CIF), transport & handling, installation & labor, HSE costs, legal/permit fees, taxes and financing costs. During site survey collect: official vendor quotes for major equipment, local labor rates for rooftop installation, and actual foundation/mounting proposals to fix quantities.

Decision warning: you cannot finalise a reliable investment cost without roof structure survey and confirmation of EVN connection capability; require detailed vendor quotations and site survey minutes to avoid large estimation errors. Next step is compiling equipment quotes and site survey results to produce an EPC phased cost breakdown and estimate investment per VND/Wp.

On‑site pre‑energization procedure: commissioning checklist & EVN paperwork

Before energization complete the acceptance test pack to confirm electrical safety, grid compatibility and metering readiness before coordinating energization with EVN. ^[10][12]

Technically, standard commissioning tests include insulation and grounding checks, load tests, inverter functional tests and protection function verification. During maintenance or site survey pay special attention to inverter functions: power injection, cosφ/reactive power control (Q), power limiting and anti‑islanding; check DC/AC switching and emergency isolation. Also perform protection coordination tests, set relay timing and verify signals compatible with the distribution substation or distribution dispatch.

1. Check rooftop working safety: anchor points, temporary guardrails, anti‑slip measures and rescue plan.
2. Measure insulation and grounding: earth resistance and insulation tests at inverters and DC/AC cables.
3. Inverter operation tests: power injection, power limit, Q control, anti‑islanding verification.
4. Load testing and observe voltage fluctuation, flicker and power factor under real operating conditions.
5. Metering check and sealing: meter location must be adjacent to POI, seals/passwords per metering regulations.
6. Protection coordination testing and relay tests with the utility, adjust timing and trip thresholds.

Below are the basic documents to prepare and submit to the utility/EVN prior to acceptance and energization.

Classification by capacity (typically <100 kW, 100 kW–1 MW, ≥1 MW) affects acceptance, metering and possible dispatch connection; field survey is needed to determine the applicable group. During on‑site acceptance the energization minutes must list tests performed, results, defects/remedial actions and safe operation conditions. Operational cautions: ensure fire safety arrangements for DC/AC areas and inverter/BESS zones (if present), and verify meter sealing before handing over to the utility.

Light conclusion: after completing tests and compiling documents, register acceptance with the utility, perform on‑site acceptance together with the power company/utility and finalise the acceptance minutes so EVN can proceed with energization and, if conditions are met, sign the PPA template under Circular 18/2020.