☀ IST PVSolar Simulator V9.0.0 — Help & User Guide

Introduction & Features — Why IST PVSolar Simulator V9.0.0

IST PVSolar Simulator V9.0.0 is a professional, browser-based photovoltaic yield-assessment and bankability platform. It pairs a full 8,760-step (hourly) / 35,040-step (15-min sub-hourly) time-series engine with a fast monthly engine, and follows the same physics used by many other simulator, SAM and PVGIS — Perez (1990) transposition, a real single-/two-diode I–V solver, the Faiman cell-temperature model and a Bifacial Radiance view-factor rear-irradiance model — while staying entirely in the browser with no install.

Key advantages

🎯 Quick Tour Guide — Step-by-Step Walkthrough

Open Help → Quick Tour in the menu bar to launch the interactive overlay. A yellow highlight box plus a pointing arrowhead marks the exact card each step describes, and the tour switches tabs automatically.

1. Title bar — version & standards banner.
2. Tab 1 · Project Information — mandatory: Project Name, Client Name, Client Address, Project Type, Prepared By.
3. Tab 1 · Site Location — enter Lat/Lon → Lookup Location fills name, state, country, altitude; opens Google Maps.
4. Tab 1 · Import Hourly TMY — default years 2005–2024; Import PVGIS TMY or NASA Hourly TMY.
5. Tab 1 · Site Condition — far-horizon shading allowance (default 0.5%).
6. Tab 2 · Tilt & Azimuth — Auto-Optimize Tilt; Azimuth 0° (NH); Module Height & Gap; Row Spacing Calc; bifacial sheds model.
7. Tab 3 · PV Module Selection — manufacturer, model, approx. plant size.
8. Tab 3 · Inverter Selection — manufacturer, model, Vmp/Imp vs MPPT range.
9. Tab 4 · Thermal & Other Parameters — check Uc, Uv, uncertainty inputs.
10. Tab 5 · Add Sub-array — modules/string, strings/MPPT, MPPT/inverter, no. of inverters; make all checks OK; Add; review summary.
11. Tab 6 · Economic Evaluation — Include-in-Report tick; CAPEX, OPEX, financing.
12. Tab 7 · Simulation Engine — resolution & cell model; Run; PR/Yf advice; Generate Report.
13. Tab 6 · Hourly Perez Engine — Run Monte-Carlo financial risk.
14. Tab 4 · PVSolar Loss Table — values refresh after a run.
15. File menu — Save Project → .pro; reuse via Upload Project.
16. Database tab — add module & inverter specifications.

Design Workflow — Recommended Order

1. Tab 1 — project & client details, Lat/Lon & lookup, monthly resource (manual entry), and TMY import — PVGIS TMY or NASA Hourly TMY — for bankable runs, design temperatures, far-horizon shading.
2. Tab 2 — tilt (Auto-Optimize), azimuth, module height/gap → row spacing; bifacial sheds geometry if applicable; review monthly POA.
3. Tab 3 — select module & inverter; verify string-voltage window.
4. Tab 4 — thermal coefficients, uncertainty, loss table.
5. Tab 5 — string configuration; pass all electrical checks; add ≥ 1 sub-array.
6. Tab 6 — CAPEX/OPEX/financing/tariff (optional in report).
7. Tab 7 — choose resolution + cell model, Run, read PR/Yf advice, Generate Report.

Standards & Codes Reference — Updated 2026

International (IEC) & scientific models

Indian (BIS / CEA / MNRE) — current 2025–26

Tab 1 — Project & Site Information

Project Information mandatory*

Required fields (gate to later tabs & report): Project Name, Client Name, Client Address, Project Type, Prepared By. Optional: Engineer/Organization, Date, Ref No.

Site Location & Lookup

Enter Latitude (°N) and Longitude (°E) in decimal degrees, then click 📍 Lookup Location — a reverse-geocode fetches location name, state/country and altitude (m) and fills the fields below; an Open in Google Maps link is provided. Design temperatures (entered manually, or carried in from an imported TMY):

Monthly Resource & Hourly TMY Import

The 12-row Monthly Weather table (GHI, DNI, DHI, Temp, Wind) is the base resource. Populate it manually, or import a measured hourly TMY whose monthly summary fills it automatically. For bankable runs, import one of:

• 🛰 NASA Hourly TMY — typical-year hourly built from NASA POWER hourly climatology (06:00–18:00 LST, 365 days).
• 🇪🇺 PVGIS TMY — true ISO 15927-4 Typical Meteorological Year with measured beam-normal DNI.

Site Condition — Far-Horizon Shading Allowance

Select a far-horizon (distant obstruction) shading-loss factor representative of the site. Default 0.5% (open site). This is distinct from row-to-row near-shading, which the engine computes geometrically.

Tab 2 — Orientation Setting & POA Calculation focus

Tilt & Azimuth Settings

⚡ Auto-Optimize Tilt sweeps 0–60° (1° steps) and selects the tilt with maximum annual H_POA (computed at due-south). The Orientation Loss vs Optimum panel shows the % deviation of your chosen tilt/azimuth from the optimum.

Module Height and Gap combine into the collector slant length used by the row-spacing tool: L = 2·H + gap (two-module table). With the defaults, L = 2×1.05 + 0.02 = 2.12 m.

POA transposition method

POA (Plane-of-Array) transposition is required because solar resource data is usually available on a horizontal surface, while PV modules are installed at a tilt and azimuth. The transposition model converts horizontal irradiance into the irradiance actually received by the PV modules.

Monthly POA uses a daily-integrated Liu-Jordan beam ratio (Rb) + full Perez (1990) anisotropic diffuse model; the hourly/sub-hourly engine uses the same Perez (1990) anisotropic diffuse instantaneously. Both share identical beam and ground terms:

Ground albedo ρ default 0.2 (green/typical). The monthly POA table and chart, and the bifacial gain table, are produced here.

🪟 Unlimited Sheds 2D Model — Bifacial Rear-Irradiance Geometry

If a bifacial module is selected (Bifacial Factor ɸ > 0), expand this section to model the front and rear POA with the Bifacial Radiance view-factor model (G_rear = G_ground × albedo × VF_{ground→rear}). Select ground type (albedo), set mounting height and pitch, and the live preview shows bifacial gain %, POA front and POA back. The simulation uses the same model per-month (monthly) and per-step (hourly).

Tab 2 — Solar Row Spacing Calculator (Shadow-Free Pitch Design) focus

Open the calculator with the orange Row Spacing Calc button. It sizes the row-to-row pitch so the array is shadow-free during the chosen window, and reports the design trade-offs.

Inputs & defaults

Method — full-year shadow-free pitch

For each season — Winter (Dec 21), Equinox (Mar 20), Summer (Jun 21) — the tool sweeps the window in 15-min steps (local apparent solar time, so noon = solar noon) and finds the worst-case minimum altitude. Each season shows a calculated suggested pitch and an editable "Use pitch". The Full-year shadow-free pitch is the largest of the three (★ winter governs in the NH) and is what Apply to Tab 2 writes.

Performance metrics at the chosen pitch

Three synchronized views (Side, 3D, Front) animate the sun and live shadow; the 3D view shows a metrics HUD plus albedo & rear-glow cues.

Tab 3 — System Parameters (Module & Inverter)

PV Module Selection

Narrow the list with the Manufacturer, Technology and Pmax (Wp) filters (they combine and cascade — each filter only offers values valid for the ones above it), then choose the Module; STC parameters auto-fill: Pmax, Voc, Isc, Vmp, Imp, TC_Pmax, TC_Voc, TC_Isc, NOCT, Rs, Rsh, bifaciality ɸ, area, length. Enter the approximate Plant Size for quick string sizing.

Year of the Project Life (right after Approx. Modules Needed) defaults to 25 years and auto-updates the moment you select a module — it's set to whichever is higher: 25, or that module's warranty period (N years). The field's maximum input range is capped at the same figure, so project life can't be pushed past the module's own warranty term for a 25+ year warrantied module. This value is mirrored into Tab 6's Project Life (Years) field (either field can be edited — they stay in sync both ways) and drives every downstream financial calculation: LCOE, NPV, IRR, DSCR, the Full Cash-Flow Calculation table, and the Bankability Assessment Report.

Inverter Selection

Narrow the list with the Manufacturer, Type and AC Power (kW) filters (combining and cascading), then choose the Inverter; rated AC power, max DC voltage, MPPT min/max voltage, max DC current and efficiency populate. Check module Vmp/Imp against the inverter MPPT voltage & current range.

String Voltage Design Check

Tab 4 — Thermal & Other Parameters · Loss Calculation focus

Thermal & uncertainty parameters (defaults)

Thermal behavior of PV modules

In this PV Simulation, the thermal behavior of PV modules is modeled using the Faiman thermal model.

Uc and Uv describe how well your specific racking/mounting hardware dissipates heat — how much the module rises above ambient for a given irradiance and wind speed. That's a property of the physical structure (open-rack vs. roof-mount vs. BIPV, rear ventilation gap, etc.).

Is it consirded wind-speed in simulation?
Yes it's genuinely considered — real per-hour wind speed is fully wired into the actual Tcell calculation. Here's the complete chain, real per-hour wind is fully wired into the actual cell temperature verified directly in the simulation, Every one of your 8760 hours gets its own Tcell computed from that hour's actual GPOA, ambient temperature, and wind speed together with your chosen Uc/Uv.

How does NOCT fit into this?
NOCT → T_cell → (T_cell − 25°C) × TC_Pmax% → DC power derate. NOCT itself never appears directly in the % loss; it only sets how hot the cell gets for a given irradiance, and the temperature coefficient converts that ΔT into a power loss. NOCT is only used combined with the temperature coefficient.

PVSolar Loss Table (defaults, signed: − loss / + gain)

Inverter Auxiliary/Night Consumption is "AC auxiliary loss": most inverters keep control electronics, communications, and anti-islanding monitoring powered even when not converting, drawing a small amount from the grid at night and during dawn/dusk standby. Set Standby Power (W) and Night Consump (W) on the inverter record (Tab 3) — both default to blank/0 (no-op, fully backward compatible) unless entered. Requires Hourly or Sub-hourly resolution (Tab 7); the Monthly engine doesn't have a per-timestep day/night distinction to hang this off of.

Site-Level Auxiliaries (new card above the Loss Table, Tab 4) adds PVsyst's second, independent auxiliary-loss source — its plant-level "Auxiliaries" dialog, distinct from the inverter's own intrinsic Standby/Night draw above. Four fields, all optional and default to 0 (no effect): a Constant Draw (kW) gated by an Activation Threshold (kW AC output) — e.g. PVsyst's own example, a fixed 72 kW load that only switches on once the plant exceeds 100 kW output; a Proportional Draw (W per kW AC output) — e.g. cooling load scaling with inverter heat output; and its own fixed Night Draw (kW), separate from the inverter's Night Consump, since site equipment (SCADA, lighting, security) keeps running overnight regardless of the inverter's own state — this same night value is also used as the plant's idle-daytime baseline (dawn/dusk zero-output steps). Both sources combine into the same single Inverter Auxiliary/Night Consumption Loss row after a run — mirroring PVsyst's own combined "Aux_Lss" reporting (plant auxiliaries + the inverter's own "IL_Night").

Avoiding double counting: some inverter manufacturers already fold fan/cooling self-consumption into their published efficiency curve. If that's the case for your selected inverter, check "Standby/Night consumption already included in efficiency curve" next to the Standby Power / Night Consump fields (Tab 3) — this skips the inverter's own separate draw while still applying any Site-Level Auxiliaries configured above, mirroring PVsyst's own opt-in checkbox for its inverter-level "Auxiliary consumption" (OND) field.

Typical magnitude by plant scale (rule-of-thumb starting points)

Activation Threshold (kW AC output): usually left at 0 (meaning the constant draw applies whenever there's any output at all) unless you specifically know a piece of equipment (e.g. a large cooling fan bank) only kicks in past a certain generation level — example uses a threshold precisely for that case (72 kW load activating only above 100 kW plant output on a large utility plant).

Proportional Draw (W per kW AC output): this represents load that scales with how hard the plant is working — typically 0.5–3 W/kW for cooling/ventilation systems in switchgear or transformer rooms on larger plants. Small/medium systems usually don't have this at all — leave at 0.

The Sankey loss diagram and Clipping Loss chart update live; ILR (DC/AC) best practice for India is 1.1–1.3.

IAM Loss (Incidence Angle)

Hourly/Sub-hourly mode = real per-timestep AOI-driven Martin-Ruiz calculation, responsive to your actual tilt/azimuth/location and glass coefficient. Run Hourly or Sub-hourly resolution whenever IAM accuracy matters (which is essentially always for a bankable yield estimate) — that's the one meaningful lever in this simulation for IAM accuracy.

Recommended AC Ohmic Loss Values

Typical DC Ohmic Loss by Project Size

PV Module LID (Light-Induced Degradation) Loss in Simulation

Spectral Loss

Hourly/Sub-hourly resolution: Used a real per-timestep calculation using the First Solar / Lee-Panchula (2016) 2D model coefficients and the same Gueymard Pw-from-RH fallback. Always computing it means the model responds correctly to your specific site's altitude, humidity, and technology, rather than requiring the user to remember to turn on an extra toggle. For humid tropical sites, high-altitude sites, or CdTe/thin-film technology — where spectral shift is more pronounced — this is a genuine accuracy advantage over a design where most users never enable the correction at all.

If you're optimizing for the most physically complete standalone estimate, leaving it on is reasonable — just don't treat the resulting number as more "true" than PVsyst's, since both ultimately rest on the same unvalidated First Solar coefficients.

Soiling Loss (%) Consideration

Recommended Bankable Design Soiling Loss Values

Typical Auxiliary Consumption Loss (%)

Module Efficiency

Module Efficiency — not actually a "loss" in the calculation chain. DC power comes from Pmax, TC_Pmax, and irradiance/temperature, not from efficiency × area. So there's no "module efficiency loss" line in the loss table.

Module Mismatch Loss

Module Mismatch Loss or Modules and strings Mismatch loss - The bypass-diode/shading-driven MPP loss is a different row in Near-Shading electrical loss in this simulation.

By default this is implemented as a flat, editable % in the loss table — no I-V-curve-based computation behind it, a static assumption like other simulation default mode. Tab 6 now offers an optional upgrade — see Module Aging & Age-Driven Mismatch below — which replaces this flat number with a dedicated Monte-Carlo calculation that grows across the project's lifetime table, when enabled.

Module Aging & Age-Driven Mismatch (Tab 6, PVsyst-style)

Degradation now uses a linear accumulation model, evaluated at the mid-point of each project year (e.g. Year 10's degradation is evaluated at 9.5 elapsed years, not 10) — matching PVsyst's own documented convention, and matching the industry-standard practice of treating degradation as roughly linear over time (real-world degradation studies report linear median rates), rather than this app's previous compounding/geometric-decay curve.

Each project year's degraded module is now physically reconstructed rather than treated as a single flat power scalar: the year's total power loss is split between the current channel (Isc/Imp) and the voltage channel (Voc/Vmp) via an Imp Degradation Sharing fraction (default 80%, PVsyst v8's own default — current-related degradation mechanisms, e.g. LID and cell cracking, are generally faster than voltage-related ones per published studies), then the single-/two-diode reference parameters are re-derived from that degraded nameplate — the same "elaboration of a degraded module" PVsyst performs internally. Requires the single-/two-diode PV model (Tab 7); the linear Pmax×temp-coefficient model has no I-V curve to reconstruct from.

Dedicated Monte-Carlo module-mismatch model (optional — enabled by setting the Isc/Voc Dispersion RMS fields above 0, Tab 6): individual modules don't all degrade at exactly the same rate, so their Isc/Voc dispersion naturally widens over the plant's life even as the population mean keeps falling uniformly. This runs genuine random sampling of per-module Isc/Voc offsets across a representative 20-module string, solves each string's ACTUAL series-connected operating point (common current, module voltages summed, via the same Newton V(I) solver validated for the bypass-diode substring model), and compares the dispersed string's realised MPP against the "no dispersion" ideal to get an expected mismatch loss % — once per project year, using a single fixed set of random draws scaled by that year's growing dispersion (so the resulting curve is smooth and monotonic in age, not independently re-sampled noise each year). The two dispersion inputs represent the population spread expected by the end of the project life (e.g. entering "2%" means ~2% RMS Isc spread by the final year), scaled down proportionally for earlier years and combined in quadrature with a small fixed manufacturing/binning tolerance (1.0%, does not grow). Leaving both dispersion fields at 0 keeps the previous flat "Module Mismatch Loss" table row unchanged — fully backward compatible.

Combined display (Tab 4 preview-a-specific-year control): when the Monte-Carlo mismatch model is active, previewing a project year folds that year's mismatch % into a single combined figure shown in the Module Aging/Degradation Loss row, rather than showing degradation and mismatch as two separate rows — the underlying energy calculation already applies both effects correctly regardless of this; only the Tab 4 display is combined. The separate "Module Mismatch Loss" row is shown as 0% at the same time, so its effect isn't counted twice visually. The combination is a proper compounding of the two loss fractions (1 − capacity_fraction × (1 − mismatch_fraction)), not a simple sum, so it will read very slightly lower than adding the two percentages by hand.

Tab 5 — Sub-array Design (String Configuration) focus

The selected module & inverter spec cards appear at the top. Configure a sub-array and watch the Live Electrical Check update as you type — add the unit only when all checks read OK.

Inputs

Computed quantities

Live safety checks (✅ / ⚠️)

1. Voc_max @ T_min ≤ Inverter Vdc_max
2. Vmp_max @ T_winter ≤ MPPT V_max
3. Vmp_min @ T_summer ≥ MPPT V_min
4. Array Current/MPPT (Imp × Str/MPPT) ≤ inverter MPPT max input current
5. Total DC Current/Inv (Imp × Str/MPPT × MPPT) ≤ inverter max DC input current

ILR is shown alongside these for reference but is not itself a pass/fail check — see the recommended band below.

Click + Add Sub-array. You need at least one sub-array to run a simulation. The Total System Summary aggregates DC kWp, AC kW, ILR, total modules and strings across all sub-arrays. Mixed sub-arrays (different tilt/inverter) are supported by adding multiple units.

Typical behavior as ILR (Inverter Loading Ratio) or DC/AC Pnom Ratio increases

Why annual energy increases: Adding more DC modules allows the inverter to operate closer to its rated AC power for more hours of the year, especially during mornings, evenings, winter, and cloudy conditions. Therefore: Total annual AC energy (kWh) generally increases. However, inverter clipping also increases around solar noon on high-irradiance days.

Tab 6 — Economic Evaluation & Bankability focus

Tick Include in Report (top-right) to add the economics & financial-risk pages to the PDF; leave unchecked to skip them.

Inputs & defaults

Financial formulas

The Year-by-Year Projection table lists energy, tariff, revenue, OPEX, depreciation, tax, net saving (after-tax), cumulative cash-flow and degraded PR for each year; lifetime revenue is the column total. LCOE stays a pre-tax cost metric (standard practice, for comparability across financing structures) — tax and depreciation only enter the cash-flow-based metrics (NPV, IRR, Payback, ROI, DSCR, Equity IRR).

Bankability Perspective — Live Metrics & Full Cash-Flow Calculation

Shown once Calculate Economics has run. Four cards report Project IRR (unlevered), Equity IRR (levered — nets annual debt service against the own-fund outflow), Minimum DSCR (over the loan tenure), and Simple Payback, each rated Poor/Marginal/Good/Excellent (or the DSCR-specific Poor–Strong scale) against standard project-finance thresholds.

Below the cards, the Full Cash-Flow Calculation table lists every year of the project life (Year, Energy at P90, Revenue, OPEX, Depreciation, Tax, Net Operating Cash Flow — after-tax, Debt Service, DSCR, Equity Cash Flow, Cumulative Equity Cash Flow) — a genuine year-by-year recalculation, not a summary. Net Operating CF is Net Profit After Tax + Depreciation add-back, per the Tax & Depreciation settings. Debt Service and DSCR are shown only while the loan is outstanding (Years 1–Loan Tenure); the payback year is highlighted. The Overall Bankability Verdict (Highly Bankable / Bankable / Marginally Bankable / Weak) is the average of the four card ratings, followed by numbered recommendations for improving any weak metric.

Financial Due Diligence — Technology Assessment & Global Bankability Inputs

The 🔎 Financial Due Diligence sub-tab's Technology Assessment card captures PV Module, Inverter, BOS, EPC and O&M assessment notes and criteria (BNEF Tier 1 status, product maturity, warranty terms, contract type, performance ratio guarantee, delay liquidated damages, defects liability period, insurance, change order mechanism, and Parent Company Guarantee) — these drive the auto-derived risk ratings shown in the Bankability Assessment Report's Technology and Developer/EPC sections.

Below it, the 🌐 Legal, Insurance, Country Risk & Fiscal — Global Bankability Inputs card covers the additional due-diligence content international lenders, DFIs and ECAs typically expect: Offtaker Credit Rating & Payment Security Mechanism; Land Title, Grid Code Compliance, Local Content and Force Majeure allocation; Operational-phase Insurance Program (All-Risk+BI, Third-Party Liability, Natural Catastrophe cover); Sovereign/Political Risk and Currency/FX mismatch; and Environmental & Social Action Plan (ESAP) target date/owner plus Depreciation Method, Tax Incentives and Import Duty treatment. All of these feed directly into the Bankability Assessment Report's Legal, Insurance/Country-Risk, ESAP and Fiscal sections and the consolidated Conditions Precedent table.

Bankability Perspective & Monte-Carlo (Hourly Perez Engine)

The 📈 Hourly Perez Engine card drives a NumPy Monte-Carlo on the exported 8,760-step AC series. Click 🎲 Run Monte-Carlo to sample energy (systematic ⊕ inter-annual), degradation, tariff & OPEX escalation and report the P10/P50/P90 distribution of:

• Project NPV, Equity IRR (levered), LCOE,
• Minimum DSCR (EBITDA / level debt-service annuity), discounted payback.

Tab 7 — Simulation Engine focus

Simulation Resolution & PV Cell Model

Per-step energy chain (hourly)

Results

KPIs: DC kWp, E_AC (MWh/yr), PR (%), Yf (kWh/kWp); monthly table; Eac/Earray/GPOA chart; P50/P75/P90/P95 probability & CDF; 25-year grid-injection & revenue forecast; PR-vs-year; CO₂ savings.

The selected solar resource: exact sun position, Perez (1990) POA transposition, Martin-Ruiz IAM, air-mass spectral correction, Faiman cell-temperature model, row-to-row self-shading, and true inverter clipping.

Read the 💡 How to Improve Performance Ratio (PR) advice and the 🎯 Specific Yield (Yf) Rating Check, then click Generate Report.

🔥 Cell-temperature (thermal) effect dominating over irradiance

May be in June July August GPOA (kWh/m²/month) minimum but PR maximum, Why this happens:

• June–August is monsoon season in this weather profile — heavy cloud cover cuts direct beam radiation drastically (DNI drops from ~6.1 kWh/m² in April to just 1.5–2.0 in Jun/Jul/Aug), so GPOA bottoms out.
• PR is defined as E_AC ÷ (H_POA × Pnom) — it deliberately normalizes out how much sunlight was available. It measures how efficiently the system converts whatever irradiance it got, not how much energy it made.
• Cell temperature is driven mostly by irradiance itself, not just ambient air temp — less sunlight means less panel self-heating. Combined with monsoon's much higher wind speed (5.4–6.2 m/s vs 2.8–3.8 m/s pre-monsoon) providing extra convective cooling, cell temperature drops nearly 10°C below the hot, sunny months (35–38°C vs 46–48°C).
• Since modules lose power as they heat above the 25°C STC reference (via the module's negative temperature coefficient), less heating = less thermal derating = higher PR — even though there's far less energy being produced in absolute terms.

So the pattern makes physical sense: highest energy months (Apr/May) run hottest and post the lowest PR; lowest energy months (Jun–Aug) run coolest and post the highest PR. This is standard, expected PV fleet behavior and actually a good sign the temperature model (Faiman cell-temp + power temperature coefficient) is behaving correctly — a flat or irradiance-correlated PR curve would be the sign of something wrong, not this inverse relationship.

🔌 Protection & Cable Schedule

After every simulation run, Tab 7 displays a Protection & Cable Schedule table below the Performance Ratio chart. This table lists indicative electrical protection and cable specifications calculated automatically from your module, inverter, and sub-array design — providing a ready engineering reference for detailed system design.

Schematic electrical diagram of the PV system from DC array to grid connection point. Cable sizes and protection ratings are indicative design values calculated per IEC 60364-7-712, IEC 60269-6 (gPV string fuses), and CEA (Measures relating to Safety and Electricity Supply) Regulations 2010. Final specifications to be confirmed by a licensed electrical engineer before installation.

Calculation Formulas & Basis

Solar PV Cell Model: Single-Diode (5-Parameter De Soto Model)

The Single-Diode 5-Parameter De Soto Model is one of the most widely used mathematical models for photovoltaic (PV) cell and module simulation. It calculates cell performance across varying irradiance and temperature using manufacturer datasheet values.
Typical Use: for Engineering & bankable simulations

IAM Coefficient (Martin–Ruiz ar)

The Martin–Ruiz IAM coefficient (ar) is a single empirical parameter used in the Martin–Ruiz Incidence Angle Modifier (IAM) model to describe the reduction in transmittance of solar radiation through the module glass as the angle of incidence increases.
Standard glass PV module: Default value 0.16

Uncertainty Model in PV Simulation & Bankability Reports

For bankable PV energy yield assessments, the total uncertainty is not taken from a single value. It is calculated by combining several independent uncertainty sources using the Root Sum Square (RSS) method.
The simulator collects four independent uncertainty inputs (defaults shown, all user-editable in the UI as iav, unc_data, unc_model, unc_component):

1. Interannual variability (IAV) — default ±5%. Year-to-year weather variation. This is the only one that varies per simulated year. IAV is real weather spread, not a model error, so it is excluded from the accuracy-vs-measured figure below.
2. Resource / data uncertainty — data-source-aware: ±5% for satellite climatology or weather synthesized from monthly means, automatically ±2.5% when a measured hourly TMY (PVGIS ISO 15927-4 / NASA POWER) is loaded. This is the dominant lever on annual-yield error vs measured.
3. Model (transposition + PV) — default ±1.5%. Both engines use the full Perez (1990) transposition plus the pvlib-validated single-diode (De Soto) model and the Bifacial Radiance view-factor rear model, so the transposition+conversion model error is ~1.5%.
4. Component (tolerance / soiling / degradation) — default ±2%. Hardware and field effects: module power tolerance, soiling estimate, degradation-rate estimate.

σ_total = √(IAV² + Data² + Model² + Component²) (used for P50→P90)

Annual yield error vs measured = σ_systematic = √(Data² + Model² + Component²), i.e. σ_total without IAV. With satellite/synthetic input this is ≈±5–8%; with a measured hourly TMY it tightens to ≈±2–4% — the simulator reach ±2–4% only when validated against measured resource. The simulator reports this automatically (sigma_systematic_pct); it does not assert a tighter band than the input data justifies.

How they're used differently in the Monte-Carlo

That energy then feeds revenue → NPV, equity IRR, LCOE, and DSCR across thousands of trials, producing the P10/P50/P90 distributions and the P(NPV>0) / P(DSCR≥1.30) probabilities.
So in short: IAV is the per-year noise; data + model + component are the once-per-project systematic bias; the RSS of all four is σ_total, which sets the P75/P90/P95 energy band. A fallback exists too — if no breakdown is supplied, the code uses a single lumped sigma_total_pct (default 7.62%) instead.
One thing worth noting: in the P-value table all four are RSS'd together into σ_total, but in the Monte-Carlo the IAV is deliberately separated out as per-year noise. That's an intentional modeling choice, not an inconsistency — though it does mean the MC's effective year-1 spread and the static P90 won't be numerically identical. If you want, I can trace a single numerical example through both paths to show the difference.

Databases — Module, Inverter, Settings & Bankability Bands

The Database tab is organised into 5 sub-tabs:

The PV Module and Inverter sub-tabs manage the panel.JSON and inverter.JSON libraries used in Tab 3.

• Add new specification — enter a module's STC parameters (Pmax, Voc, Isc, Vmp, Imp, temp-coeffs, NOCT, Rs, Rsh, bifaciality, area, length) or an inverter's specs (Pac, Vdc_max, MPPT range, Idc_max, efficiency) and save.
• Edit / delete existing records.
• Import / export the JSON databases; records persist in browser localStorage.

🌍 Country wise Bankability Bands

An editable table covering all 20 supported currencies, giving a typical utility-scale ground-mount CAPEX/Wp benchmark range (Low / High) for each market, expressed in that currency's own units — not a fixed USD figure, since installed costs vary materially by country (labour, land, import duties, local EPC competition). This table is the single source the Bankability Assessment Report reads from (Section 5.2 CAPEX benchmark and the Project Bankability verdict), so edits here are reflected there immediately. Use ↺ Reset to Defaults to restore the built-in indicative values.

📋 Default Parameters

A scrollable, 90-row reference table of every default/fallback value the simulation engine uses when a field is left blank or not overridden — grouped by category (Site/Location, Orientation, Weather, System Losses, Row Spacing/Shading, Single-Axis Tracker, Bifacial Settings, Financial/Economic, Uncertainty).

No Need for .PAN and .OND Files

Unlike many conventional PV simulation software packages that require proprietary PV module (.PAN) and inverter (.OND) files, IST PVSolar Simulator eliminates this limitation.
Many PV module and inverter manufacturers do not provide downloadable .PAN and .OND files, making it difficult and time-consuming to evaluate different equipment in traditional simulation software.
With IST PVSolar Simulator, users can directly create a complete PV module or inverter model using the manufacturer's PDF datasheet.
Key Benefits

1. No dependency on proprietary .PAN or .OND files.
2. Supports virtually any commercially available PV module and inverter.
3. Easy entry of electrical specifications from manufacturer datasheets.
4. Quickly build a customized equipment database.
5. Compare multiple manufacturers without waiting for simulation files.
6. Ideal for feasibility studies, EPC design, technical due diligence, and bankable energy yield assessments.
7. Reduces engineering time and increases flexibility during equipment selection.

Users simply enter the required electrical parameters from the manufacturer's datasheet, and the software automatically creates the simulation model. Once created, the PV module and inverter are saved in the project database and can be reused in future simulations.
This feature makes IST PVSolar Simulator one of the most flexible and user-friendly PV design and energy simulation platforms, enabling engineers to simulate projects using their preferred equipment—even when official simulation files are unavailable.

Menu Bar & Project Files

The top menu bar has three dropdowns. On large displays the right-side status text and the standards line are shown; on mobile they are hidden to keep the header clean.

🔬 Research Tab — Overview & Workflow advanced

The Research tab is an advanced post-processing layer that sits on top of a completed simulation. It reads the simulation results, the Tab 5 sub-array designs and the selected module/inverter, then renders engineering diagnostics, statistical analysis and machine-learning studies. Nothing here changes the design — it only characterises the plant you have already built.

Prerequisite — run a simulation first

Open Tab 7 and run a simulation, then click Refresh Analysis in the Research tab. Several panels need a time-series run:

Sub-tabs

Exports

Tables export to CSV/JSON; every chart has a ⬇ Download .PNG link beneath it (see Chart Watermark & PNG). Aligned hourly SCADA data exports as scada_aligned_hourly.csv.

🏗 Per-Design Diagnostics & IEC 61724 Accounting

1. Per-Design (sub-array) table

One row per Tab 5 sub-array (U1, U2 …) reporting string-sizing margins against the inverter window and energy apportioned by DC share.

2. IEC 61724-1 yield & loss accounting

3. Weather-corrected performance

Energy-weighted mean cell temperature and PR corrected to 25 °C, separating the thermal component from the rest of the loss chain so designs at different sites can be compared on equal terms.

4. Operating-point distributions hourly

🎚 Sensitivity Analysis (Tornado)

Ranks how strongly annual AC energy responds to each design/site parameter, perturbed independently about the current design point. Runs on the fast monthly engine for responsiveness.

Parameters swept

🎲 Uncertainty Analysis — P50 / P75 / P90 / P95

Combines six independent 1σ uncertainty sources by root-sum-square (RSS) into a total uncertainty, then converts it to exceedance percentiles — the bankability band lenders size debt against.

The six sources (1σ, % of annual yield)

Outputs

Variance contribution chart shows each source as a share of total variance (σ², not σ — that is why a slightly larger σ dominates disproportionately). The Annual-energy probability distribution is an assumed-normal curve about P50 with the percentile markers dashed in. The table lists z, the (1 − z·σ) factor, MWh, kWh, specific yield and % of P50.

🤖 AI & Machine Learning Application hourly

Lightweight, fully transparent models trained client-side on the simulated hourly dataset — no external library and no data leaves the page. The core is ordinary least squares (OLS) via the normal equations with ridge stabilisation; features are scaled (POA/1000, T_cell/100) for good conditioning. Because they learn the simulator's own physics, they are for methodology research and teaching — field use needs real monitored data.

Models

🌡 Module / Thermal Model Characterisation hourly

Calibrates four standard cell-temperature models against the simulator's own hourly T_cell series (treated as truth), then ranks them on temperature accuracy and on the energy error they would cause.

Accuracy metrics

Faiman/NOCT/Ross slopes are recovered by linear OLS (e.g. Faiman linearises as G/(T_cell−T_amb) = U0 + U1·WS). The comparison view ranks models by T_cell RMSE (🏆 = best) and shows the energy error each induces; a ±1 °C mean offset is roughly ±|γ_Pmax|% energy.

🔌 Inverter Characterisation hourly

Characterises five inverter behaviours from the hourly series.

🌑 Shading Characterisation hourly

Derives hourly row-to-row self-shading factors from the simulated geometry using five models, then reports annual and monthly losses and two sample weeks.

Outputs

Annual shading loss by model, monthly shading loss, and the time-based shading factor for a sample winter week and a sample summer week (when low winter sun angles make row shading worst). Full 8,760-step factors are available via Export Hourly CSV.

⚡ Bifacial Characterisation

Explores the rear-side gain predicted by the simplified view-factor model used by the engine, as a function of ground albedo, mounting height and surface type.

Studies

📡 SCADA Benchmarking needs measured data

Validates the simulated energy against uploaded measured operational data (hourly SCADA), aligning the two series by timestamp and reporting standard validation statistics overall, by month, by irradiance band and by hour-of-day.

Charts

🖼 Chart Watermark & PNG Export new

Centre watermark on every chart

Every chart across the app — server-rendered (POA, Eac, probability, grid, life, PR, Sankey, finance, clipping) and client-rendered (all Research charts, Monte-Carlo, satellite-tracker charts) — carries a faint light-gray box at its centre reading IST PVSolar / Simulator. On-screen it is drawn at 9 px bold; the link is size-guarded so small UI icons never receive it.

⬇ Download .PNG (Research tab)

Beneath each Research chart is a Download .PNG link. It rasterises that chart on a white background at 2× resolution and saves it. The exported PNG re-stamps the watermark at 12 px for print legibility.

POA Transposition — Formulas & Method

Monthly engine: daily-integrated Liu-Jordan beam ratio + full Perez (1990) diffuse. Hourly engine: Perez (1990) anisotropic (instantaneous).

Defaults: albedo ρ = 0.2. Extraterrestrial I0 via Spencer series; air mass via Kasten-Young.

Cell Temperature — Faiman & NOCT

Defaults: Uc = 25 W/m²K, Uv = 6.84 W/m²K per m/s (pvlib/NREL Faiman). Use Uc = 29, Uv = 0 only when no reliable wind data. The hourly engine evaluates Tcell every step on broadband POA-global irradiance; the monthly engine energy-weights an intra-day profile so the kWh see the hot midday hours (ambient peak ~15:00).

Diode I–V Model — Single- & Two-Diode

The default single-diode (De Soto 5-parameter) model solves a real I–V curve at every operating point; a two-diode option adds a recombination term. Reference parameters are extracted from the datasheet (Isc, Voc, Vmp, Imp, Rs, Rsh) and translated to operating G, Tcell.

A performance grid Pmp(G,T)/Pmax is precomputed per module and bilinearly interpolated per step (=1 at STC). The linear model uses the datasheet Pmax temperature coefficient only.

Energy Chain

DC-loss product excludes physically-modelled rows (thermal, clipping, bifacial, inverter, AC-ohmic) to avoid double counting.

PR & Yield

The PR denominator uses unshaded front POA, so near-shading correctly shows up as a lower PR. Typical Indian utility PR 75–82% (measured TMY); specific yield 1,400–1,700 kWh/kWp/yr.

Probability Analysis — P50 / P75 / P90 / P95

Defaults: IAV 5%, data 5%, model 2%, component 2% → σ_total ≈ 7.62%. P90 is the conservative figure lenders use.

Bifacial — Infinite-Sheds View Factors

Front POA uses Perez (1990) + Martin-Ruiz IAM + row self-shading; rear POA uses the Bifacial Radiance view-factor model — G_rear = G_ground × albedo × VF_{ground→rear}, with the sunlit/row-shaded ground split and a GCR-aware rear→ground view factor.

Inputs: tilt, azimuth, GCR, mounting height, pitch, albedo, bifaciality ɸ, sun position. The monthly engine evaluates a representative noon gain per month; the hourly engine evaluates per step and energy-weights the annual gain.

Financial Formulas

CO₂ & Environmental

Uses the conservative P90 energy. Default grid emission factor 0.82 kg/kWh (CEA CO₂ Baseline Database v20, 2023–24).

Electrical Design Checks

Row Spacing Geometry

Worst case is the winter solstice in the NH. Metrics: GCR, front-side shading %, bifacial gain %, ground-reflected albedo capture %.

Solar Resource & Data

Report Generation

Project → Generate Report (or the Tab 7 button) builds an 8-page A4 PDF: cover & project info, site & resource, system design, loss waterfall, monthly & annual results, P50/P90, 25-year forecast, CO₂; plus economics & Monte-Carlo bankability pages when Include in Report is ticked in Tab 6. Use the browser Print / Save as PDF dialog. Run a simulation first so the report carries live results.

Industry Best Practices

• ILR (DC/AC) 1.1–1.3 for Indian irradiance; higher raises clipping.
• Tilt ≈ latitude for annual energy; lower for summer-biased loads; use Auto-Optimize.
• Row spacing: design to the full-year (winter) shadow-free pitch; check the GCR vs bifacial-gain trade-off.
• Bankable runs: import a measured TMY and use Hourly/Sub-hourly with the single-diode model.
• Soiling/cleaning: schedule per MNRE norms (pre-/post-monsoon, winter fog).
• Certification: ALMM List-I modules, BIS-QCO inverters.

Troubleshooting

References & Default Values

Key engine defaults

Scientific references

• Perez R. et al. (1990), Solar Energy 44(5) — anisotropic diffuse model.
• Hay J.E. & Davies J.A. (1980); Liu B.Y.H. & Jordan R.C. (1960) — diffuse/daily ratio.
• Faiman D. (2008), Prog. Photovolt. — module operating temperature.
• De Soto W. et al. (2006), Solar Energy 80 — 5-parameter model.
• Martín N. & Ruiz J.M. (2001) — angular losses (IAM).
• pvlib python — transposition & single-diode references; NREL bifacial_radiance — rear view-factor reference.
• NASA POWER (MERRA-2); PVGIS (ISO 15927-4 TMY); CEA CO₂ Baseline DB 2023–24.

Glossary