Solar Design Terminology: 50 Terms Every Designer Should Know

Global solar PV capacity reached 2,383 GW by the end of 2025, according to IRENA’s Renewable Capacity Statistics 2026. Every one of those gigawatts passed through a design phase where solar design terminology made the difference between a buildable system and a failed inspection. Tilt, string length, inverter size, and protection all depend on a shared vocabulary. When one person says “string voltage” and another hears “system voltage,” the result is usually rework.

This guide covers 50 solar design terms that every designer should know. It is not a software manual. It is a field-focused reference that connects the language of datasheets, simulation reports, permit packages, and client conversations. Whether you are new to solar design or training a team, this list gives you a single source for the terms that shape buildable, bankable systems.

Solar design terminology is the shared language of resource assessment, array geometry, electrical design, components, performance, economics, and safety. Knowing these 50 terms helps designers avoid costly rework, communicate clearly with AHJs and clients, and produce systems that perform as modeled.

In this guide:

• Solar resource and site terms that drive every simulation
• Array geometry and layout terms for usable roof and ground space
• Module and electrical terms from datasheets and IV curves
• System configuration terms for stringing and protection
• Component and equipment terms for inverters, racking, and BOS
• Performance and simulation terms that separate good designs from bad ones
• Economics and contract terms that clients actually ask about
• Codes and safety terms that keep projects compliant
• Common terminology mistakes and how to avoid them

Why Solar Design Terminology Matters in 2026

Solar projects are getting larger and more complex. A 500 kWp commercial roof may have 1,200 panels across ten orientations, multiple inverter types, and a storage adder. A single term misunderstood — Voc, DC:AC ratio, or P90 — can cascade into permit rejection, production shortfall, or a contract dispute.

In 2026, designers also work across borders. A team in India may design for a project in Texas, or a European installer may source modules from Southeast Asia. Standards differ, but the terminology must stay consistent. The 50 terms below give you a baseline that works in NEC, IEC, and emerging markets.

1. Solar Resource and Site Terms

These terms describe the solar energy available at a site and the objects that block it. Get them wrong and every downstream number — yield, payback, system size — inherits the error.

1. Global Horizontal Irradiance (GHI)

GHI is the total solar radiation received on a flat horizontal surface, measured in W/m² at a moment or kWh/m² over time. It is the most common solar resource metric in weather files.

Designers rarely enter GHI manually. Solar design software reads it from a weather dataset and transposes it to the tilt and azimuth of the array. What matters is dataset quality. A site in southern Spain may show 1,800 kWh/m²/year of GHI, while a site in northern Germany may show 950 kWh/m²/year. Using the wrong dataset can shift simulated yield by 10% or more.

2. Plane of Array (POA) Irradiance

POA irradiance is the solar radiation that actually strikes the surface of the panels after accounting for tilt, azimuth, and reflection losses. It is the input that drives energy yield.

A common mistake is citing GHI in a production report when clients need POA. For a 30° south-facing array at mid-latitude, POA is typically 10–15% higher than GHI. Always check that your simulation report references POA, not raw horizontal irradiance.

3. Peak Sun Hours (PSH)

Peak sun hours is the number of hours per day during which solar irradiance averages 1,000 W/m², the standard test condition. A site with 5.0 PSH/day receives the same daily energy as 5 hours at exactly 1,000 W/m².

PSH is useful for quick mental math. A 10 kWp array at 5.0 PSH/day produces roughly 50 kWh/day before losses. It is not a substitute for an hourly simulation, but it is a fast sanity check during early sales conversations.

4. Solar Access

Solar access is the percentage of available sunlight that reaches a specific roof or ground area without obstruction. A roof section with 95% solar access receives almost all the sun available at that location.

Solar access is different from POA. POA measures resource on the panel surface; solar access measures how much of that resource is blocked by trees, buildings, or terrain. A site with high POA but low solar access is still a poor candidate unless obstructions can be removed. Shadow analysis quantifies this before any panels are placed.

5. Horizon Profile

The horizon profile is a 360° map of distant terrain or buildings that block the sun near sunrise and sunset. It is used to calculate far-shading losses.

A mountain ridge to the east or a city skyline to the west can reduce annual yield by 2–8%. Design software uses digital elevation data to build the horizon profile automatically. For sites in valleys or dense urban areas, always review the horizon profile before finalizing yield estimates. See our guide on solar shade analysis for a deeper walkthrough.

6. Albedo

Albedo is the fraction of sunlight reflected by the ground surface, expressed from 0 to 1. Grass is roughly 0.2; a white roof membrane can exceed 0.7.

Albedo controls rear-side irradiance for bifacial panels. Underestimating albedo by 0.2 on a ground-mount bifacial design can cut predicted bifacial gain by 3–6%. For flat commercial roofs with white TPO membranes, albedo is often the largest untapped production lever.

2. Array Geometry and Layout Terms

These terms describe where panels sit and how they relate to each other and the sun. Geometry decisions are usually made once and are expensive to change after permitting.

7. Azimuth

Azimuth is the compass direction an array faces, measured in degrees clockwise from true north. South-facing arrays in the northern hemisphere have an azimuth of 180°.

True south produces the highest annual energy. A deviation of ±15° costs about 1–3% of annual yield. East-west arrays produce less total energy but flatten the daily curve, which helps self-consumption on sites with morning and afternoon loads. Modern solar design software compares multiple azimuths automatically.

8. Tilt Angle

Tilt angle is the angle of the panel surface above horizontal. A panel lying flat has 0° tilt; a vertical wall has 90°.

The tilt that maximizes annual yield roughly equals site latitude. At 48°N, optimal tilt is about 30–35°. At 25°N, it is closer to 15–20°. On flat commercial roofs, low tilt of 5–15° is common because it reduces wind load and inter-row shading while still capturing most of the available energy.

9. Inter-Row Spacing

Inter-row spacing is the distance between rows of panels in a ground-mount or flat-roof array. It controls how much one row shades the row behind it in winter.

Spacing is a tradeoff. Tight rows fit more capacity but increase row-to-row shading. A typical rule is to space rows so the winter shadow is no longer than 2–2.5 times the row height. For detailed guidance, see our article on inter-row spacing for solar panels.

10. Row-to-Row Shading

Row-to-row shading is the loss that occurs when the front row of panels blocks sunlight from reaching the row behind it, especially in early morning and late afternoon.

Even small row-to-row shading can reduce annual yield by 3–8%. Simulation software calculates this loss for every hour of the year based on row height, row spacing, and sun angle. The best designs optimize spacing against land or roof cost rather than minimizing shading alone.

11. Total Solar Resource Fraction (TSRF)

TSRF is a single percentage that combines tilt, azimuth, and shading effects for a specific roof area. A south-facing 30° roof with no shading has a TSRF of 100%.

TSRF is useful for client communication. Telling a homeowner that a roof section has 78% TSRF is clearer than explaining diffuse irradiance. Areas below 60% TSRF are rarely worth installing unless space is extremely limited.

12. Roof Pitch

Roof pitch is the slope of a roof, often expressed as a ratio like 6:12 or as an angle in degrees. A 6:12 pitch equals about 26.6°.

Pitch affects tilt, attachment method, and structural load. Steep roofs increase labor difficulty and safety requirements. Low-slope or flat roofs require racking to achieve useful tilt and often need ballast instead of penetrations. For mounting guidance, see our solar mounting structure design guide.

13. Fixed Tilt

Fixed tilt means the array is mounted at a constant angle and does not move. The vast majority of rooftop and most ground-mount systems are fixed tilt.

Fixed-tilt systems are simpler, cheaper, and lower maintenance than trackers. The design challenge is picking the tilt that balances annual yield, wind load, shading, and structural cost. For flat commercial roofs, fixed tilt is usually 5–15°.

14. Single-Axis Tracker

A single-axis tracker rotates panels along one axis, usually east to west, to follow the sun across the day. It can increase annual energy by 15–25% compared with fixed tilt.

Trackers add cost, mechanical complexity, and maintenance. They are common in utility-scale projects where land is available and energy value is high. They are rarely used on residential rooftops because of wind and structural constraints.

3. Module and Electrical Terms

These terms appear on every module datasheet and inverter spec sheet. They are the building blocks of string sizing, simulation, and code compliance.

15. Standard Test Conditions (STC)

STC is the laboratory condition used to rate panels: 1,000 W/m² irradiance, 25°C cell temperature, and air mass 1.5. A 450 Wp panel is rated at STC.

These conditions align with the test protocols in IEC 61215 and IEC 61730, the core module performance and safety standards. Real panels rarely operate at STC. Summer cell temperatures often reach 60–70°C, and irradiance fluctuates. Designers use STC ratings for procurement and code checks, but simulated output — not nameplate power — should drive yield and financial models.

16. Nominal Operating Cell Temperature (NOCT)

NOCT is the cell temperature a module reaches in open-rack conditions: 800 W/m² irradiance, 20°C ambient air, and 1 m/s wind. It is published on every datasheet.

Software uses NOCT to estimate operating cell temperature from ambient temperature. A module with a NOCT of 42°C runs cooler than one with 47°C and produces more energy in hot climates. When two panels have the same STC rating, the lower-NOCT panel usually wins in warm regions.

17. Temperature Coefficient

The temperature coefficient of Pmax describes how much power drops as cell temperature rises, usually around −0.35 to −0.45%/°C for standard monocrystalline panels.

At 65°C, a panel with a coefficient of −0.40%/°C loses 16% of its STC power. TOPCon and HJT cells have lower coefficients, around −0.25 to −0.30%/°C, which is why they are popular in hot climates. The coefficient feeds directly into hourly simulation models.

18. Open-Circuit Voltage (Voc)

Voc is the maximum voltage a panel produces with no current flowing. It is the highest voltage a string can reach under full irradiance.

Voc rises as temperature falls. A string sized for summer conditions can exceed the inverter maximum input voltage on a cold winter morning. NEC Article 690 requires designers to calculate Voc at the lowest expected ambient temperature. Solar design software runs this check automatically when the correct weather file is loaded.

19. Short-Circuit Current (Isc)

Isc is the current a panel produces when its output terminals are short-circuited. It represents the maximum current the module can deliver under given irradiance.

Isc is used to size overcurrent protection and check inverter current limits. In parallel string configurations, Isc values add. Six strings each with 12 A Isc can feed up to 72 A of fault current into a faulted string, so the OCPD must be sized accordingly.

20. Maximum Power Point (MPP)

Maximum Power Point is the single voltage and current combination at which a panel produces its highest power. It is the “knee” of the IV curve.

The MPP shifts with irradiance and temperature. On a hot afternoon, the MPP voltage drops. Under partial shading, the panel may have multiple local power points. Inverters use MPPT to find and hold the MPP.

21. Maximum Power Point Tracking (MPPT)

MPPT is the inverter algorithm that adjusts operating voltage to keep strings at their maximum power point as conditions change.

Each MPPT input handles one independent electrical zone. A roof with south, east, and west faces needs at least three MPPT inputs — one per orientation. Connecting different orientations to the same MPPT channel drags down production from the best-performing strings. This is one of the most common stringing errors in residential design.

4. System Configuration Terms

These terms describe how panels, inverters, and protection devices connect. Mistakes here create code violations, equipment damage, or lost production.

22. String Configuration

String configuration defines how many panels are connected in series and how many strings connect in parallel. Series connections raise voltage; parallel connections raise current.

Designers must keep string voltage within the inverter window across all temperatures. Too few panels and the string cannot start on hot days. Too many panels and the voltage exceeds the inverter limit on cold mornings. Our guide to solar string design mistakes covers the most common errors.

23. Parallel String

A parallel string is a set of strings connected together before the inverter, increasing current while keeping voltage the same.

Parallel strings need correct overcurrent protection. The fault current from all parallel strings can flow back through a single faulted string. The string fuse or breaker must be rated between the string Isc and the module maximum series fuse rating.

24. Combiner Box

A combiner box is the enclosure where multiple DC strings are combined into a single larger circuit before the inverter. It usually contains string fuses, disconnects, and monitoring hardware.

In commercial systems, combiner boxes reduce cable count and simplify protection. The BOM must list the correct voltage rating, fuse sizes, and surge protection. A 1,000 V combiner box on a 1,500 V system is a dangerous mismatch.

25. DC:AC Ratio (Inverter Loading Ratio)

The DC:AC ratio, also called inverter loading ratio, is total DC module capacity divided by inverter AC capacity. A 10 kWp array on an 8 kW inverter has a ratio of 1.25.

The industry standard range is 1.1–1.35. Higher ratios lower cost per kWh but increase clipping on sunny days. Lower ratios waste inverter capacity. The optimal ratio depends on local irradiance, temperature, and electricity tariff structure. See our guide on solar DC:AC ratio for the full calculation.

26. Inverter Clipping

Inverter clipping happens when DC power exceeds the inverter’s maximum AC output. The inverter limits output and the surplus is lost.

Controlled clipping of 0.5–3% per year is often economically rational. The key is to model it accurately. Clipping only occurs during peak irradiance hours, so the energy lost is usually much smaller than the upfront savings from using a smaller inverter.

27. Voltage Drop

Voltage drop is the loss of voltage as current flows through cables due to resistance. Excessive voltage drop wastes energy and can affect inverter performance.

NEC and IEC recommend keeping DC voltage drop under 1–2%. Voltage drop depends on cable length, cable size, and current. For long runs between array and inverter, upsizing the cable often pays back quickly. Our voltage drop calculator guide walks through the math.

28. Ampacity

Ampacity is the maximum current a conductor can carry safely without exceeding its temperature rating. It depends on conductor size, insulation, ambient temperature, and installation method.

Solar circuits are considered continuous loads, so ampacity must be sized with appropriate safety factors. A cable that is fine for 30 A intermittent duty may overheat at 30 A continuous duty in a hot attic.

29. Overcurrent Protection Device (OCPD)

An OCPD is a fuse or circuit breaker that protects wiring and equipment from overcurrent and short-circuit damage. String fuses and DC disconnect breakers are the most common OCPDs in PV systems.

The OCPD rating must be high enough to avoid nuisance tripping but low enough to protect the module and cable. The maximum rating is listed on the module datasheet as the maximum series fuse rating.

30. Rapid Shutdown

Rapid shutdown is a code requirement that reduces DC voltage in roof conductors to safe levels within seconds after a shutdown signal. NEC 690.12 mandates it for roof-mounted systems in NEC jurisdictions.

Compliance usually requires module-level power electronics such as microinverters or power optimizers, or listed rapid shutdown devices. Standard string inverters on rooftops generally do not meet rapid shutdown requirements without additional equipment.

5. Components and Equipment Terms

These are the physical parts of the system. Specifying the wrong component creates cost, availability, and warranty problems.

31. String Inverter

A string inverter converts the DC output of one or more strings of panels into AC power. It is the most common inverter type for residential and small commercial systems.

String inverters are cost-effective and simple. They work best when all panels share the same orientation and shading profile. They are not ideal for roofs with complex shading or multiple orientations unless paired with optimizers.

32. Microinverter

A microinverter is a small inverter mounted on each panel. It converts DC to AC at the module level.

Microinverters eliminate single points of failure and provide panel-level monitoring. They cost more per watt than string inverters but perform better on complex roofs. They also satisfy rapid shutdown requirements without extra devices.

33. Power Optimizer

A power optimizer is a DC-to-DC converter mounted on each panel that conditions output before sending it to a central inverter.

Optimizers provide panel-level MPPT and monitoring while keeping the cost benefits of string inverters. They are often used on commercial roofs with mixed orientations or partial shading. Optimizer systems still rely on a central inverter.

34. Module-Level Power Electronics (MLPE)

MLPEs are devices — microinverters or power optimizers — that operate at the module level to improve performance, monitoring, or safety.

MLPEs are required for rapid shutdown compliance in many jurisdictions. They also reduce mismatch losses from soiling, degradation, or manufacturing variation. The tradeoff is higher upfront cost and more rooftop electronics.

35. Balance of System (BOS)

Balance of system includes all components except the panels and inverter: racking, cables, combiners, disconnects, monitoring, grounding, and labor.

BOS can account for 30–50% of total project cost. Designers who focus only on module and inverter price miss the biggest levers in BOS optimization, such as cable routing, racking selection, and installation labor.

36. Racking and Mounting

Racking and mounting is the structural hardware that holds panels in place. It includes rails, clamps, flashings, and attachments to the roof or ground.

Racking must handle wind, snow, seismic, and dead loads for the project lifetime. The choice between ballasted, penetrating, and shared-rail systems affects labor cost, roof warranty, and structural requirements.

37. Ballast

Ballast is weight added to a racking system to hold it down without roof penetrations. Concrete blocks are the most common ballast.

Ballasted systems are popular on flat commercial roofs because they avoid leaks. The downside is added weight. A structural engineer must verify that the roof can handle the ballast plus any snow or wind loads.

6. Performance and Simulation Terms

These terms describe how a system performs and how software predicts output. They are the numbers clients, financiers, and regulators care about.

38. Annual Degradation Rate

Annual degradation rate is the percentage by which panel output declines each year. Quality monocrystalline panels typically degrade 0.5–0.7% per year.

Over 25 years, a panel degrading at 0.5%/year retains about 88% of its original output. Lower degradation rates increase lifetime revenue. Premium manufacturers now guarantee 0.25–0.30%/year on some products.

39. Specific Yield

Specific yield is annual energy output in kWh divided by installed DC capacity in kWp. It is expressed in kWh/kWp/year.

Specific yield is the best metric for comparing two designs at the same site. A 10 kWp system producing 12,000 kWh/year has a specific yield of 1,200 kWh/kWp. If your simulation shows 700 kWh/kWp in Madrid or 1,500 kWh/kWp in Oslo, the inputs are almost certainly wrong.

40. Performance Ratio (PR)

Performance ratio is the ratio of actual energy output to the theoretical maximum output if the system operated at STC efficiency for every hour of available irradiance.

Well-designed systems achieve PR values of 75–85%. Below 70% suggests shading, wiring, or design problems. Above 85% is possible in cold, sunny climates. PR is the fastest overall health check for a simulated design.

41. P50 / P90

P50/P90 describes the probability distribution of annual energy yield. P50 is the median; P90 is the yield expected to be met or exceeded in 90% of years.

P90 is typically 5–10% below P50 for rooftop systems. Financiers require P90 for debt sizing because it protects against low-yield weather years. Always tell clients whether your production estimate is P50 or P90.

42. Loss Waterfall

The loss waterfall is a breakdown of every factor that reduces output from theoretical maximum to actual yield. Typical categories include temperature, shading, soiling, wiring, mismatch, inverter efficiency, and availability.

The waterfall shows where the biggest gains are. If shading loss is 8% and temperature loss is 3%, redesigning the layout delivers more value than switching to lower-temperature-coefficient panels.

43. Capacity Factor

Capacity factor is the ratio of actual annual output to the output if the system ran at full rated power for every hour of the year. For solar, typical values are 10–25%.

Capacity factor is driven mainly by site resource. A project in southern Spain might reach 22%; a project in Scotland might reach 11%. For design comparison at the same site, specific yield and PR are more useful than capacity factor.

7. Economics and Contract Terms

These terms explain how projects make money. Designers who understand them can explain tradeoffs to clients and avoid impossible production guarantees.

44. Net Metering

Net metering is a billing arrangement where exported solar electricity is credited against imported grid electricity at the retail rate, usually on a kilowatt-hour basis.

Net metering makes solar economics simple: one kWh exported offsets one kWh imported. Many jurisdictions are moving to net billing, where exports are credited at a lower avoided-cost rate. The difference can change payback by several years.

45. Feed-in Tariff

A feed-in tariff is a fixed payment per kWh for solar electricity exported to the grid, guaranteed for a contract period. It was the main driver of early solar markets in Germany, Spain, and Italy.

Feed-in tariffs reduce revenue uncertainty but are usually lower than retail rates over time. Designers need to model the export fraction carefully because every exported kWh earns the tariff, not the retail rate.

46. Levelized Cost of Energy (LCOE)

LCOE is lifetime project cost divided by lifetime energy output, giving a cost per kWh. It is the standard metric for comparing solar against other generation sources.

In 2025–2026, utility-scale solar LCOE in sunny regions reached €20–35/MWh, according to SolarPower Europe. Residential LCOE is higher because soft costs and customer acquisition make up a larger share of the total.

47. Power Purchase Agreement (PPA)

A PPA is a long-term contract in which a developer sells power to a customer or utility at a fixed price per kWh. The developer owns and operates the system.

PPA pricing depends on simulated yield and degradation. A small error in annual production modeling compounds over a 20-year contract. Accurate simulation is therefore a financial risk exercise, not only a technical one.

48. Investment Tax Credit (ITC)

The Investment Tax Credit is a US federal tax credit for solar projects, currently 30% for projects that begin construction before statutory deadlines. It is one of the largest financial incentives in the US market.

The ITC applies to both residential and commercial systems. Commercial projects can also pair it with MACRS depreciation. Designers in the US must understand these incentives because they affect system sizing and ownership structure decisions.

8. Codes and Safety Terms

These terms keep people safe and keep projects legal. They should appear in every design review and permit submission.

49. Authority Having Jurisdiction (AHJ)

The Authority Having Jurisdiction is the local agency that reviews and approves permits and inspections. It could be a city building department, county, fire district, or utility.

Every AHJ interprets code slightly differently. A design that passes in one county may fail in the next county over. Checking the local checklist, setback requirements, and inspection process before starting design saves weeks of rework.

50. Fire Setback and Pathway

Fire setbacks are clearances between panels and roof edges, ridges, or valleys. Fire pathways are access routes across the roof for firefighters.

Setback rules vary by jurisdiction. In California, Title 24 requires specific pathways and setbacks for residential roofs. Ignoring these rules during layout causes permit rejection and potentially dangerous roof conditions. Always verify local fire code before placing the first panel.

Terminology Mistakes That Cost Real Money

Knowing the terms is the first step. Using them correctly is what separates a profitable design from a rework order. Here are four costly mistakes we see repeatedly.

Confusing kW and kWh

kW is power; kWh is energy. A 10 kW system running for 1 hour at full output produces 10 kWh. Clients often mix these up, and designers sometimes do too. If a proposal says the system will produce “10 kW per year,” it is wrong and confusing.

Treating P50 as a guarantee

P50 means there is a 50% chance the system will produce more and a 50% chance it will produce less. It is not a guarantee. A production guarantee should use P90 or a similarly conservative figure, plus clear assumptions about maintenance and weather.

Ignoring Voc at low temperature

String voltage rises in cold weather. A string that fits the inverter at 25°C can exceed the maximum input voltage at −10°C. The fix is simple: size strings using the site’s record low temperature, not the design temperature. Software does this automatically if the weather file is correct.

Forgetting albedo on bifacial designs

Bifacial gain depends heavily on ground reflectance. Designers who leave the software default at 0.2 for a white TPO roof will understate production and may lose the sale. Updating albedo to match the actual surface is a 30-second change that can shift modeled yield by 5% or more.

How These Terms Work Together

A real design moves through these terms in order. The software loads GHI, DNI, and DHI from a weather file and transposes them into POA. The designer sets azimuth, tilt, and inter-row spacing, then strings panels while checking Voc at minimum temperature and Isc against OCPD ratings. The inverter runs MPPT on each electrical zone. The simulation engine applies temperature coefficients, soiling, shading, and degradation to produce specific yield, PR, and P50/P90. Those outputs feed LCOE, PPA pricing, or net metering savings. Finally, the AHJ reviews setbacks, rapid shutdown, and fire pathways before the system is approved for construction.

No single term tells the whole story. A designer who understands how they connect can spot errors early and explain the design with confidence.

Take Action

Three things to do next:

• Audit your last five designs for the four terminology mistakes above. Fix any string sizing or albedo defaults that do not match the site.
• Standardize the terms your team uses in proposals and permit packages so clients, AHJs, and installers all read the same language.
• If your workflow still jumps between spreadsheets, CAD, and simulation tools, consider a unified solar design platform that keeps terminology consistent from sale to commissioning.

For detailed engineering support or PE-stamped permit designs, our sister company Heaven Designs provides solar design and engineering consultancy across 15+ countries.

Frequently Asked Questions

What is solar design terminology?

Solar design terminology is the shared vocabulary used by designers, installers, engineers, and sales teams to describe solar resource, array geometry, electrical behavior, components, performance, economics, and safety. A common language prevents costly mistakes during design, procurement, and permitting.

Why is solar design terminology important for installers?

Knowing the terms lets installers read datasheets, interpret simulation outputs, and communicate with AHJs and clients without ambiguity. Misunderstanding one term — such as Voc at minimum temperature — can produce an unsafe or non-compliant design.

What is the difference between GHI and POA irradiance?

GHI, or Global Horizontal Irradiance, is the total solar radiation on a flat horizontal surface. POA, or Plane of Array irradiance, is the radiation actually striking the tilted panel surface. POA is what drives energy yield calculations.

What does DC:AC ratio mean in solar design?

DC:AC ratio is the total installed DC module capacity divided by the inverter AC output capacity. A ratio of 1.2 means 1.2 kWp of panels for every 1 kW of inverter. The common range is 1.1–1.35, balancing cost against clipping losses.

What is the difference between string inverters and microinverters?

A string inverter converts DC power from multiple series-connected panels to AC in one central unit. A microinverter mounts on each panel and converts DC to AC at the module level, which helps with shading and panel-level monitoring.

What is P50 vs P90 energy yield?

P50 is the median annual yield the system is equally likely to exceed or fall below. P90 is the yield expected to be met or exceeded in 90% of years. Lenders typically require P90 for project finance because it is more conservative.

What is specific yield and why does it matter?

Specific yield is annual energy output in kWh divided by installed DC capacity in kWp. It strips out system size and lets designers compare layouts at the same site. Typical values range from 900 kWh/kWp in northern Europe to 1,800 kWh/kWp in sunnier climates.

What are the most important safety terms in solar design?

Rapid shutdown, arc fault, ground fault, overcurrent protection, and Authority Having Jurisdiction are the core safety terms. Each relates to keeping firefighters, installers, and occupants safe and keeping the project compliant with local code.