Solar Design Software Glossary: 50 Key Terms

Last updated: November 2026

A useful solar design software glossary explains the quantity behind a field, its units and the decision it affects. Similar labels can use different conventions across tools, so comparing two reports starts with their definitions.

SurgePV publishes this post and sells solar design software.

These 50 terms retain the original six categories: resource, components, configuration, simulation, finance and software workflow. For broader engineering vocabulary, use the solar design terminology guide.

Category 1: Solar Resource and Irradiance

These terms define the solar energy input to any simulation. If your irradiance data is wrong, everything downstream is wrong , yield estimates, financial models, and sizing calculations all inherit the error.

1. Global Horizontal Irradiance (GHI)

Global horizontal irradiance (GHI) is the total solar irradiance on a horizontal surface. Irradiance is power per area, commonly W/m²; irradiation is energy accumulated over a period, commonly kWh/m². Keep that distinction visible when moving a weather value into a report.

Check whether the weather file supplies measured or modeled GHI, the time interval and the timestamp convention. The simulation may derive other components depending on available inputs. A regional annual range cannot validate a particular roof. Compare the source period, site representation and quality controls before deciding that one dataset is preferable.

2. Direct Normal Irradiance (DNI)

Direct normal irradiance (DNI) is the direct-beam component received on a plane perpendicular to the sun’s rays. It excludes diffuse sky radiation. Its orientation differs from a horizontal measurement, so DNI cannot simply be added to DHI to obtain GHI.

PVsyst’s irradiation documentation relates horizontal beam irradiance to DNI through solar height. In a design review, check which components are supplied and which are derived. A label saying solar radiation may not identify that distinction. Preserve the units, plane and time basis when exporting data to another tool or comparing different weather providers.

3. Diffuse Horizontal Irradiance (DHI)

Diffuse horizontal irradiance (DHI) is the scattered sky component received by a horizontal surface. Together with the beam component projected onto the horizontal plane, it contributes to GHI. It is not a fixed percentage of global irradiance for every climate or hour.

The treatment of diffuse light matters when transposing radiation to a tilted surface and estimating shading. A simple statement that diffuse light comes from every direction does not mean every orientation receives it equally. Check the model and input data rather than assigning a universal cloudy-climate share or assuming a guaranteed advantage for an east-west array.

4. Plane of Array (POA) Irradiance

Plane-of-array (POA) irradiance is the irradiance on the module plane. A model can calculate it from weather components and orientation, while a suitable sensor can measure it at a site. Specify whether a reported value includes optical effects such as shading or reflection.

Use the correct POA quantity when calculating performance indicators. Comparing a horizontal resource value with an array-plane energy output can create a misleading result. There is no universal percentage uplift from GHI to POA: tilt, azimuth, horizon, diffuse conditions and reflected light all affect the calculation. Record the transposition method and loss boundary.

5. Peak Sun Hours (PSH)

Peak sun hours express daily irradiation as an equivalent duration at a reference irradiance of 1 kW/m². They are not the number of clock hours when the sun is visible. Five peak sun hours represent 5 kWh/m² of irradiation on the stated plane.

As an illustrative loss-free calculation, a 10 kW array exposed to that equivalent resource would correspond to 50 kWh. Actual output requires a performance model and losses. Use peak sun hours for a rough capacity screen, then check hourly or finer data when shading, export timing, storage or demand charges affect the decision.

6. Typical Meteorological Year (TMY)

A typical meteorological year (TMY) combines selected weather periods to represent a typical year according to a stated selection method. It is not a record of one actual calendar year and does not guarantee next year’s weather. Dataset period, variables and time resolution depend on the source.

Record the provider, product, version, location and source years. PVsyst’s weather documentation distinguishes TMY, synthetic and actual-year files. Different weather inputs can explain simulation differences, but so can equipment, geometry, losses and settings. Reconcile those inputs before attributing a disagreement entirely to the TMY source.

7. Albedo

Albedo is the fraction of incident radiation reflected by a surface. It is expressed from zero to one and can vary with surface condition, season and the measurement method. A software default is an assumption, not a site survey.

Albedo matters particularly when modeling rear-side illumination of bifacial modules. Record the surface, expected changes and evidence behind the value. Roof membranes can weather, vegetation can change and snow may be intermittent. Run a justified sensitivity if the value is uncertain; do not assign a fixed bifacial gain from a color description or a generic surface table alone.

8. Soiling Loss

Soiling loss represents the effect of dirt or deposits on solar collection. It may be entered as a loss profile or calculated through a more detailed method, depending on the software. State the period and whether the value refers to irradiance or energy.

Tie the assumption to local observations, cleaning plans or a documented study. Rainfall does not guarantee complete cleaning, and a fixed annual value can hide seasonal effects. Keep soiling separate from permanent degradation and avoid counting it twice in the simulation and financial model. Record whether a cleaning scenario changes both energy and operating cost.

How Irradiance Labels Map to PVsyst

The following mapping comes from PVsyst’s irradiation-model documentation, opened November 2026. It is a product-specific naming example, not a claim that every tool uses these identifiers.

Weather-file definitions are documented separately in PVsyst’s weather-data guide. Record source and timestamp conventions when transferring values.

Category 2: Module and Component Specifications

These terms appear directly in the component library of any design tool. Misreading them , or accepting software defaults without verification , introduces systematic errors into every simulation.

9. Standard Test Conditions (STC)

Standard test conditions (STC) provide a reference for rated module power. PVsyst’s performance-ratio documentation identifies reference irradiance of 1,000 W/m² and cell temperature of 25°C. Use the exact manufacturer datasheet for the full rating conditions and electrical values.

A watt-peak rating is not a promise of continuous field output. Operating temperature, irradiance, spectrum and other effects change production. When comparing modules, distinguish nameplate power from predicted energy and verify the model matches the quoted product. Do not turn an illustrative temperature correction into a performance specification for an unnamed module.

10. Nominal Operating Cell Temperature (NOCT)

Nominal operating cell temperature (NOCT) is a reference thermal characteristic measured under defined conditions. Related datasheets may use nominal module operating temperature or another thermal description. Check the manufacturer’s definition and conditions before comparing the numbers or entering them into software.

Different simulation tools use different thermal models. A NOCT value does not mean every tool uses the same simple cell-temperature equation. Mounting, ventilation, wind and irradiance treatment matter. Record the selected thermal method and its parameters, and compare alternatives on the same basis rather than declaring one module superior from a single thermal value.

11. Temperature Coefficient (Pmax)

The maximum-power temperature coefficient describes how module power changes with cell temperature over the stated model range. It may be expressed as a relative percentage per degree or an absolute power change per degree. Use the exact datasheet and keep its sign and units.

For illustration, an assumed coefficient of negative 0.40% per degree and a 40-degree rise imply a 16% relative reduction under that linear approximation. This is arithmetic, not a claim about a particular cell technology. Use the actual model for production forecasting and do not confuse ambient air temperature with cell temperature.

12. Annual Degradation Rate

Annual degradation describes a change in expected performance over time. The model may use a compounded rate, a linear reduction or a more detailed profile. The selected convention affects lifetime energy and should be explicit in the report.

A product’s warranty floor is not necessarily its expected operating forecast. Record first-year treatment, subsequent-year assumptions and any separate availability or repair effects. Compare the same horizon and starting point across proposals. Avoid using a generic industry percentage as a manufacturer guarantee or assuming that a change in degradation produces a fixed revenue gain regardless of tariffs and capacity.

13. Bifacial Gain

Bifacial gain is the additional output attributed to rear-side collection relative to a defined front-side or monofacial reference. State the denominator and comparison setup. It is different from bifaciality, which characterizes the module’s rear response relative to its front response under specified conditions.

Geometry, albedo, mounting, obstructions and electrical treatment affect the result. Use the exact module parameters and a documented rear-irradiance model. A white roof or elevated array does not guarantee a particular gain. Check how the software represents row shading and nonuniform rear illumination, and retain the assumptions when comparing layout variants.

14. Fill Factor

Fill factor is maximum power divided by open-circuit voltage multiplied by short-circuit current, with all values taken under the same conditions. It describes the shape of the current-voltage curve. It is not the same as module conversion efficiency.

When reviewing a component model, use consistent units and reference conditions. A curve parameter cannot by itself predict annual energy or the behavior of every MPPT controller. Differences in irradiance, temperature, mismatch and model calibration also matter. Avoid assigning a universal commercial-module range or claiming a specific long-term simulation method is more accurate without validation evidence.

15. IV Curve

An I-V curve plots current against voltage for a module or circuit under specified conditions. Open circuit and short circuit are the endpoints; the maximum-power point is where the product of current and voltage is greatest.

Software uses electrical behavior to represent operating points and the effects of configuration or shade. Measured curves need irradiance, temperature and circuit identity to be interpreted. A change in shape can suggest an investigation but is not a conclusive diagnosis by itself. Keep the manufacturer curve, model curve and field measurement distinct, and compare them only after accounting for their different conditions.

16. Open Circuit Voltage (Voc)

Open-circuit voltage (Voc) is the voltage across an unloaded module or circuit under specified conditions. It varies with conditions and is not a fixed lifetime maximum. For a series string, the relevant module voltages combine according to the circuit configuration.

The electrical designer must evaluate the governing cold-condition voltage against equipment limits using the applicable method and exact data. A TMY file’s minimum temperature is not automatically the required design extreme. Keep simulation weather and electrical design temperatures distinct. Record the datasheet coefficient, number of modules and accepted calculation rather than relying on a generic voltage increase.

17. Short Circuit Current (Isc)

Short-circuit current (Isc) is the current measured or modeled when a PV circuit’s terminals are shorted under defined conditions. It is an equipment and circuit input, not a universal maximum under every environmental condition.

Parallel circuits can contribute current, but protection selection requires the complete architecture, equipment ratings and applicable rules. Do not calculate a final fuse or breaker solely by multiplying a datasheet current by a generic factor. Field short-circuit measurements require appropriate instruments and qualified procedures. In the software record, identify the source of the current value and how it is used in the design checks.

Category 3: System Design and Configuration

These are the parameters you set directly in the design tool. Each parameter needs a project-specific basis and equipment check.

18. DC:AC Ratio (Inverter Loading Ratio)

The DC:AC ratio, also called inverter loading ratio, divides installed module DC nameplate power by the stated inverter AC capacity. An illustrative 10 kWp array and 8 kW inverter have a ratio of 1.25. Specify whether the AC denominator is inverter rating, export limit or another boundary.

No single ratio is optimal for every project. Weather, orientation, clipping, inverter limits, tariff and equipment cost affect the choice. Compare variants on annual energy and economics while keeping electrical limits satisfied. A higher ratio is not automatically better, and a lower ratio does not by itself prove wasted capacity.

19. MPPT (Maximum Power Point Tracking)

Maximum power point tracking (MPPT) is the control process that seeks an operating point with high available PV power. An inverter can have one or more independent tracking channels, each with its own supported electrical configuration.

Check how strings are assigned to channels and whether the manufacturer permits the proposed combination. Orientation differences require analysis, but they do not justify a blanket rule that every roof face always needs a separate MPPT. Record voltage ranges, current limits, parallel inputs and any mixed-orientation assumptions. A software allocation should be reviewed against the exact equipment instructions before construction.

20. String Configuration

String configuration describes modules connected in series and strings connected in parallel. Series connections combine voltage; parallel paths combine current according to their electrical behavior. The configuration must fit both the physical layout and equipment operating limits.

Review maximum voltage, operating-voltage range, current limits, string allocation and protective devices. These are project-specific calculations, not only a roof-packing exercise. Distinguish modules per string from the number of strings when reading a software field. If a layout changes, reconcile counts and circuit assignments before accepting an updated energy estimate, bill of materials or electrical drawing.

21. Azimuth

Azimuth describes the direction an array faces, but the numerical convention depends on the tool. A compass convention measures clockwise from north; some software uses a different zero and sign convention. Read the tool documentation before transferring a value.

Keep true north, magnetic north and drawing orientation distinct. If an imported roof appears reversed, verify the coordinate and angle conventions before adjusting losses. The best orientation depends on site resource, shade, available roof area and the value of energy at different times. Do not assign universal yield penalties to a fixed angular deviation or promise that south always maximizes project value.

22. Tilt Angle

Tilt is the angle of the module plane relative to horizontal: zero degrees is horizontal and ninety degrees is vertical. On a sloped roof, the modeled tilt may follow the roof or a separate mounting arrangement. Record which geometry the value describes.

Optimize within the project’s structural, access, shading and equipment constraints. Latitude can help an early screen but is not a complete design rule. Compare annual and seasonal energy, row spacing and usable capacity together. A layout with a higher per-module yield may fit fewer modules or have different construction costs, so the preferred tilt depends on the decision.

23. Inverter Clipping

Inverter clipping occurs when available PV power cannot be converted into additional AC output because a relevant inverter limit is reached. The model should identify the specific limit and the energy effect. Power clipping, voltage constraints and grid curtailment are different mechanisms.

Review the time series and loss diagram instead of accepting one annual percentage without context. Clipping can occur whenever the relevant conditions arise, not only at summer midday. Compare the additional module cost and useful shoulder-hour generation with lost output. No universal acceptable clipping percentage replaces the project’s equipment limits and economic analysis.

24. Voltage Drop

Voltage drop is the voltage difference caused by current flowing through circuit impedance. Cable losses also convert electrical energy to heat. The appropriate calculation depends on AC or DC topology, conductor properties, length, temperature and operating conditions.

For a simple two-wire resistive DC circuit, the return path must be included. More complex circuits need the applicable method. Ask the designer to check the standard and project specification for limits; this glossary does not attribute an unverified percentage to IEC or NEC. Keep design voltage drop, annual energy loss and thermal ampacity checks separate in the output.

25. Overcurrent Protection Device (OCPD)

An overcurrent protection device (OCPD) interrupts excessive current under its intended conditions. Fuses and circuit breakers are examples. Device selection needs the circuit duty, voltage, fault capability, conductor protection and equipment instructions, not just a nominal current number.

A disconnect is not automatically an overcurrent protective device. Check the exact product function and rating. When software produces a protection schedule, retain the calculation basis and have a qualified reviewer verify the result. Equipment substitution, a changed parallel-string count or a different connection method can require the protection review to be repeated.

26. Rapid Shutdown

Rapid shutdown refers to a PV safety function required for certain installations under the applicable electrical rules. The governing edition, system architecture and listed equipment determine what must occur and how it is verified. Check the standard for the actual boundaries and values.

Do not reduce compliance to a blanket requirement for one type of optimizer or microinverter. Use a supported system design and retain the manufacturer’s instructions and approval evidence. A software warning can support review, but it cannot replace the professional assessment, required field verification or authority decision. Keep the final shutdown arrangement consistent with the drawings and labels.

Category 4: Simulation and Performance Metrics

These are the outputs that determine whether your design is good. Understanding what each number means , and what drives it , is the difference between using software as a black box and using it as a real design tool.

27. Specific Yield

Specific yield divides energy output by installed DC capacity over a stated period. Annual values are commonly expressed in kWh/kWp/year. Define the energy boundary and capacity basis so comparisons use the same denominator and losses.

Illustrative example: 11,000 kWh from 10 kWp and 110,000 kWh from 100 kWp both equal 1,100 kWh/kWp. Equal specific yield does not mean equal total energy, cost or project value. A layout with lower specific yield can still deliver more useful energy from the available site. Compare weather, orientation, export limits and economic scope before selecting the better design.

28. Performance Ratio (PR)

Performance ratio (PR) compares energy delivered at a defined boundary with a reference energy based on array-plane irradiation and installed nominal power. PVsyst’s documentation explains that the numerator changes with system type, including self-consumption and storage treatment.

Use a consistent energy boundary, period and irradiation definition. PR is not obtained by simply adding all percentage losses, since loss stages may use different bases. A single universal good-PR band cannot diagnose every system. Investigate changes in the model, temperature, optical losses, availability and meter boundary before interpreting a high or low result as design quality.

The chart repeats the values in term 27. Its larger bar shows more energy, not a higher specific yield or a better financial return. PVsyst’s PR definition explains why PR is a different measure.

29. Capacity Factor

Capacity factor divides energy generated during a period by rated power multiplied by the number of hours in that period. State whether the rating is DC or AC. The same energy output can produce different capacity factors when the denominator changes.

For a non-leap year, the period contains 8,760 hours. Use the actual period for measured data or a leap-year series. Capacity factor reflects resource and operation as well as design. It is not interchangeable with module efficiency or performance ratio. When comparing reports, reconcile the rating, outage treatment and reporting boundary before comparing percentages.

30. P50 / P90 Energy Yield

P50 and P90 are exceedance estimates under a stated uncertainty model. P50 is the median estimate; P90 is a value the modeled outcome has a 90% probability of exceeding. The period and uncertainty basis must accompany the label.

PVsyst’s documentation says these calculations require uncertainty parameters beyond the simulation itself. A low scenario is not automatically P90, and a TMY run is not a complete independent uncertainty assessment. Do not subtract a generic percentage from P50. Review weather variability, model uncertainty and their treatment, and distinguish a single-year outcome from a multi-year average.

PVsyst’s P50/P90 documentation explains the additional uncertainty inputs and interpretation, checked November 2026.

31. Loss Analysis (Loss Waterfall)

A loss waterfall follows energy through modeled stages and shows the effects assigned to each stage. It helps explain how the selected resource and equipment become energy at the report’s output boundary. Some stages can contain gains as well as losses.

Check the base used for each percentage before adding or comparing numbers. A loss already included in the simulation should not be subtracted again in the financial model. When considering a redesign, rerun the changed configuration rather than assuming the full value of one displayed loss can be recovered without affecting other stages, capacity or cost.

32. 8760-Hour Simulation

An 8,760-hour simulation represents one non-leap year in hourly intervals. The input might be a TMY, an actual-year file or another documented series. Hourly simulation is not the only possible resolution; some questions require finer intervals.

Match the simulation step to the decision. Demand billing, controls and short-lived clipping can be sensitive to time resolution. Preserve timezone, timestamp position, daylight-saving treatment and missing-data rules when exporting results. Do not claim that every lender requires the same interval or that every monthly model has a fixed error. Validate the method against the intended use and evidence.

33. Anti-Islanding

Anti-islanding protection addresses unintended operation of generation with a disconnected portion of the utility network. Intentional backup operation is a separate architecture with approved isolation and controls. An inverter can support one mode without proving the other is permitted.

Use the utility’s applicable requirements and exact equipment certification and settings. A generic software checkbox or product family name cannot establish acceptance for every jurisdiction. Record the approved operating mode and any export restrictions. If storage or a transfer device is added later, review the protection and interconnection arrangement again rather than assuming the original approval covers all changes.

34. Total Solar Resource Fraction (TSRF)

Total solar resource fraction (TSRF) combines orientation and shading effects relative to a defined reference resource. The reference plane, period and calculation convention must be identified by the tool or report. A particular tilt and direction are not a universal 100% reference everywhere.

Use TSRF to compare roof areas only when the method and reference match. It does not by itself prove a roof area is financially worthwhile. Equipment, usable capacity, construction cost and tariff still matter. Ask how near shade, horizon and orientation enter the result, and avoid using a generic threshold as an automatic exclusion rule.

35. Soiling Degradation Modeling

Time-varying soiling modeling represents how deposits and cleaning change losses over the modeled period. It is distinct from irreversible equipment degradation. A tool may use monthly values, a more detailed accumulation model or an externally supplied profile.

Document rainfall treatment, cleaning assumptions and evidence for the profile. Compare the extra energy from a cleaning plan with its cost and access requirements. Do not assert that one additional cleaning recovers a fixed share of annual production at every site. SurgePV supports energy-yield and financial modeling, but that scope alone does not prove a specific automated soiling-model feature.

Category 5: Financial and Business Terms

Solar design software increasingly includes financial modeling alongside yield simulation. These terms define the economic outputs that clients and investors actually make decisions from.

36. LCOE (Levelized Cost of Energy)

Levelized cost of energy (LCOE) compares lifetime costs with lifetime energy on a defined calculation basis. A discounted form divides the present value of costs by the present value of energy. Identify the horizon, discounting convention and included cost items.

LCOE is not the same as bill savings or project return. Electricity has different value depending on delivery time, export terms and customer demand. Financing, tax and residual-value treatment can also differ across methods. When comparing two reports, reconcile those conventions before concluding that the lower number is the better investment or a direct substitute for the retail tariff.

37. Payback Period

Simple payback divides initial cost by a representative annual net benefit. An illustrative €12,000 investment with a constant €1,800 annual net benefit has simple payback of about 6.7 years. This ratio does not capture every change in later cash flows.

Modeled break-even sums the annual cash flows, while discounted payback applies a chosen discount rate first. Repairs, degradation, tariff changes and financing can alter the timing. State the method in a proposal and keep ongoing costs after break-even visible. Do not describe electricity as free after payback or assume every cash-flow pattern produces the same relationship between metrics.

38. Net Present Value (NPV)

Net present value (NPV) sums cash flows discounted to a reference date, including the initial outlay and later costs or receipts. A positive NPV means the modeled cash flows exceed the return represented by the chosen discount rate under those assumptions.

Use net cash flow, not only energy savings, in the calculation. Keep nominal cash flows with a nominal discount rate or real cash flows with a consistent real rate. Show sensitivities for uncertain energy prices, costs and production. There is no fixed percentage change in NPV from changing the discount rate; it depends on the cash-flow timing and magnitude.

39. MACRS Depreciation

MACRS means Modified Accelerated Cost Recovery System, a US tax depreciation framework. The applicable method, recovery period, convention, basis and special deductions depend on the property and taxpayer’s circumstances. It is not a flat cash rebate for every solar installation.

The IRS Publication 946 explains depreciation methods and their conditions. Have a tax adviser identify the rules for the actual asset, acquisition and placed-in-service dates. Do not hard-code a universal first-year percentage or combine depreciation and credits into an unsupported recovery claim. Show tax timing separately from operating energy benefits and document any basis adjustments.

IRS Publication 946, How To Depreciate Property is the source for the depreciation framework, opened November 2026. Obtain project-specific tax advice before assigning a schedule.

40. Power Purchase Agreement (PPA)

A power purchase agreement (PPA) is a contract for electricity with defined pricing, delivery, term and responsibilities. Ownership and operating arrangements depend on the transaction. Read the actual agreement rather than assuming every PPA has the same duration or escalator.

Model delivered or eligible energy at the contract’s specified boundary. Include curtailment, settlement, escalation, taxes and other terms where applicable. A customer’s avoided bill and the seller’s revenue are different calculations. A software report does not itself make the agreement bankable or guarantee lender acceptance; the project’s technical, legal and commercial review defines the reliance requirements.

41. Escalator Rate

An escalator changes a price over time according to a contract or modeling assumption. A PPA escalator can be contractual, while retail electricity escalation in a savings model may be an uncertain forecast. Label the two differently.

For illustration, €0.30/kWh increasing by 3% for 20 annual changes becomes about €0.542/kWh. If year 1 uses the starting rate, year 20 contains only 19 changes. Make the timing convention explicit and run a flat-rate case. Apply separate assumptions to imports, exports and other charges when their terms differ; historical increases do not guarantee future prices.

42. Demand Charge

A demand charge bills a defined measure of power demand rather than only energy consumed. The tariff specifies the measurement interval, time window, ratchet or other rules. A single universal interval or percentage of the bill is not a safe assumption.

Model the customer’s load and generation at a resolution appropriate to the tariff. Reducing annual kWh does not guarantee reducing the billing peak. Storage may change the result, but dispatch, reserve and equipment limits matter. Verify the modeling capability of the chosen tool and retain the tariff logic; SurgePV’s broad financial-modeling scope is not proof of a particular demand-charge algorithm.

43. Yield Ratio (kWh/kWp)

A yield ratio expressed in kWh/kWp is a specific-yield quantity over a stated period. Define its energy boundary and whether the period is annual. Similar labels in different tools should be reconciled before moving a value into a revenue model.

Illustrative arithmetic: 200 kWp multiplied by an assumed 1,000 kWh/kWp produces 200,000 kWh. Valuing every kWh at an assumed €0.22 gives €44,000 gross benefit. That is not a forecast for Munich or a complete savings model. Separate direct use, exports, curtailment and costs before interpreting the number as customer value.

Category 6: Software Features and Workflow

These terms describe the tools inside design platforms , functions whose exact scope must be checked in the chosen product.

44. LiDAR Roof Modeling

LiDAR uses light-based distance measurements to create spatial data such as a point cloud. A roof model derived from that data depends on survey coverage, resolution, processing, age and the objects visible to the sensor. It is not automatically a complete site survey.

Check coordinate system, roof edges, obstructions and changes since capture. Verify dimensions that control installation, structure or access. Do not assign a universal measurement accuracy or claim that site visits are unnecessary. Tool availability and dataset coverage differ. SurgePV’s documented 3D roof-modeling scope does not alone establish a particular LiDAR source or integration.

45. Auto-Stringing

Auto-stringing is a software function that proposes or creates module-to-string assignments according to its configured rules. The feature’s actual scope depends on the product. It should not be assumed to search every possible configuration or certify electrical compliance.

Review module count, inverter inputs, operating limits, orientation grouping and cable routing. Confirm which temperatures and equipment parameters drive the checks. Compare the output with the intended field arrangement, and repeat the review after equipment or layout changes. Ask a vendor to demonstrate the required workflow on your project rather than relying on the feature name alone.

46. Bill of Materials (BOM)

A bill of materials (BOM) lists equipment and quantities for a defined scope. It can include modules, inverters, mounting, wiring and other balance-of-system items, but the actual coverage must be stated. A generated list is not automatically a complete procurement package.

Reconcile quantities with the accepted layout and electrical design. Identify allowances, spares, accessories and items omitted from the model. SurgePV supports bill-of-materials output, but specific procurement-system integrations require separate evidence. Keep exact model identifiers and revision history so a substitution cannot silently change the quote, installation requirements or handover documents.

47. Single-Line Diagram (SLD)

A single-line diagram (SLD) is a simplified electrical representation of the system and its major equipment and connections. It uses a compact drawing convention to show circuit relationships without depicting every physical conductor in detail.

The required content depends on design stage, authority and utility requirements. Verify equipment, protection, ratings, connection points and notes against the calculations and actual design. Some tools assist with diagrams; do not assume every platform automatically creates an approved plan. A generated drawing still needs the required professional review and must be updated when the installed configuration changes.

48. Permit Package (Plan Set)

A permit package is the set of drawings and documents required for a particular approval application. Its contents depend on the jurisdiction, project type and scope of work. Building, electrical, fire and utility submissions can have different requirements.

Use the authority’s current checklist and accepted design basis. Identify structural calculations, equipment evidence, professional responsibility and application forms where required. Software can support document preparation, but no generic preparation-time claim proves suitability. Ask who checks the package, answers comments and updates revisions. A submitted package is not the same as an approved permit or authorization to operate.

49. Shade Report

A shade report describes modeled or measured shading for a stated site, layout and period. It should identify geometry, obstructions, horizon, method and relevant loss outputs. Distinguish irradiance shading from the electrical effect on the configured array.

Check whether vegetation, future obstacles or uncertain measurements are included. Use the report to compare layout choices while retaining capacity, access and equipment constraints. A shaded roof section is not automatically uneconomic, and a colorful map is not evidence of survey accuracy. SurgePV supports shading analysis; review the exact report and its assumptions before using it in a customer proposal.

50. Proposal Generation

Proposal generation turns project information into a customer-facing document. The scope can include layout, equipment, energy assumptions, costs and commercial terms, depending on the tool and configuration. SurgePV’s documented product scope includes proposal generation.

Check that figures refer to the same design revision and that estimates are distinguished from contractual guarantees. A generated document can still contain wrong inputs or stale terms. Verify finance, incentives, exclusions and ownership conditions before sending it. Do not infer interactive financing comparisons, automatic tariff updates or specific integrations from a general proposal feature claim.

How These Terms Connect in a Design Workflow

Keep the resource, electrical design, energy model and financial model linked by named inputs and versions. They answer related questions, but one output does not automatically validate the next stage.

1. Resource: Record location, weather source, period, resolution and irradiation components. Save the original file and any conversion settings. A TMY is a model input with a defined purpose, not a measured prediction of the coming year.
2. Configuration: Establish geometry, module and inverter models, strings and connection limits. Have the responsible designer check electrical extremes and equipment instructions separately from typical-year production inputs.
3. Shading: Record horizon, near objects, layout and the electrical shading method. Check imported coordinates and the source date so a detailed-looking model does not conceal outdated site information.
4. Simulation: Run the accepted baseline and preserve its loss boundaries. Reconcile energy totals, specific yield and PR with the same capacity and output point. Investigate differences before changing assumptions to improve the headline result.
5. Uncertainty: Build probability estimates only where the method and evidence support them. Keep ordinary sensitivities labeled as scenarios. A changed weather input is not automatically an independent P90 assessment.
6. Finance: Value direct use, exports and other eligible receipts under their actual terms. Include investment, operations, replacement, financing and tax effects where applicable. P50 and P90 belong to the energy uncertainty assessment, not to a generic tax calculation.
7. Documents: Check that the BOM, drawings and proposal refer to the accepted design revision. Identify the professional and authority reviews required before procurement or construction. Automatic document production does not make those reviews unnecessary.

Read an Output Without Overclaiming

Start with the question the report is intended to answer. A layout comparison, equipment decision and lender energy assessment can require different evidence. Write that purpose beside the revision so an early screening result is not reused as a final guarantee.

Then identify the units and boundary of each headline quantity. Kilowatts describe power, kilowatt-hours describe energy and kWh/kWp normalizes energy by capacity. A financial value adds a tariff and time basis. If the report does not state those conventions, request them before comparing its numbers.

Check the input provenance. Mark each item as measured, manufacturer-published, authority-approved or assumed. A precise-looking decimal does not make an assumption measured. Retain the source document and date for equipment, weather, rates and policy inputs.

Finally, ask which result would change the decision. A small improvement in specific yield may be outweighed by lower installed capacity or a higher price. A high PR may coexist with a poor tariff or a difficult roof. Evaluate technical fit and commercial value together while keeping their calculations distinct.

Where to Go From Here

Use this glossary as a reference beside a project, then open the governing equipment, software or authority documentation for the actual value. For related definitions, the SurgePV glossary provides individual entries; the design principles guide connects them to a wider workflow.

Bring a sample design to a SurgePV demonstration to review its documented 3D roof modeling, layout, shading, energy-yield, financial and proposal capabilities. This glossary’s generic software terms are not a claim that every named feature is included in SurgePV.

Frequently Asked Questions

What is the most important solar design software term?

Start with the units and boundary of the quantity you are using. Energy, power, specific yield and performance ratio answer different questions. No single metric proves a design is technically or financially suitable.

What is the difference between GHI, DNI and DHI?

GHI is total horizontal irradiance, DHI is its diffuse horizontal component, and DNI is direct irradiance on a plane normal to the sun. DNI must be projected onto the horizontal plane before combining it with DHI. Keep irradiance and accumulated irradiation units distinct.

What does DC:AC ratio mean in solar design?

DC:AC ratio divides installed module DC nameplate power by the stated AC capacity. A 10 kWp array with an 8 kW inverter has a ratio of 1.25. The preferred ratio depends on equipment limits, energy and economics.

What is the difference between P50 and P90?

P50 and P90 are energy exceedance estimates under a stated uncertainty model. P50 is the median; P90 has a 90% modeled probability of being exceeded for the defined period. They require more than assigning labels to optimistic and pessimistic scenarios.

How is performance ratio calculated?

PR compares delivered energy with reference energy based on array-plane irradiation and nominal installed power. Use consistent units, period and energy boundaries. Check the tool’s treatment of self-consumption, storage and bifacial irradiation.

What is specific yield in solar software?

Specific yield is energy output divided by installed DC capacity over a stated period. It helps normalize systems of different sizes, but higher specific yield alone does not prove higher total energy or economic value. Compare the same weather and output boundary.