How to Read PVSyst Array Losses: 6 Points｜Explaining Where Energy Is Lost

Table of Contents

• What the PVSyst array loss item indicates

• The flow of energy production you should know before reading array losses

• Reading 1: Check losses that occur when converting irradiance to module-plane irradiance

• Reading 2: Confirm output reduction due to temperature

• Reading 3: Confirm low-irradiance characteristics and module quality losses

• Reading 4: Look at mismatch losses and the impact of string configuration

• Reading 5: Confirm DC wiring losses and voltage drop

• Reading 6: See the reduction of effective irradiance due to shading, soiling, and reflection

• Items easily confused when reading array losses

• Procedure for checking array losses in practice

• Design and construction focal points to improve array losses

• Summary

What the PVSyst array loss item indicates

When checking PVSyst results, many practitioners first look at annual energy production and PR. However, when trying to find why production is lower than expected, simply looking at the final values is insufficient. It is necessary to trace at which stages and by how much energy is being reduced. Reading array losses is important in that process.

Array losses are organized mainly around losses occurring on the photovoltaic module side, that is, on the DC side. This item is used to interpret the reductions that occur from the moment solar irradiance strikes the module plane, the module generates DC power, and that power passes through strings, combiner boxes, and DC wiring to the power conversion equipment. Simply put, it is where you look to see how much is being lost near the point where sunlight is converted into electricity.

Losses in PV systems can broadly be divided into irradiance-side losses, module-side losses, DC-circuit losses, post-conversion AC losses, and transformer/transmission losses. Among these, array losses are closely related to the efficiency from irradiance arriving at the module plane to being extracted as DC power. Therefore, design conditions, panel layout, azimuth, tilt angle, shading, temperature, soiling, wiring length, and string configuration — in other words, site design validity — tend to be reflected in this area.

The purpose of correctly reading array losses is not simply to evaluate whether the loss rate is large or small. It is important to distinguish whether a loss is something unavoidable due to natural conditions, something that can be improved by design, or something that changes significantly depending on input assumptions. For example, temperature loss is influenced by regional ambient temperature and racking conditions but also by ventilation and mounting methods. DC wiring loss depends on cable length, conductor cross-section, and current, so there is room for improvement by reviewing the design.

Array losses are also important for explaining PR. PR is used as an indicator of how much effective generation was achieved compared to ideal irradiance, but low PR has multiple causes. Irradiance data, temperature conditions, shading, soiling, reflection, DC losses, AC losses, and curtailment interact. Among them, array losses are likely to be pointed out in design reviews or third-party report comparisons because they relate to site layout and module conditions.

In practice, judging array losses solely by whether they are “large or small” can lead to incorrect conclusions. You need to consider the region, mounting method, module type, tilt angle, snow and soiling conditions, presence of shading, string design, and DC cable lengths together. The same loss rate can mean different things for a plant installed in complex mountainous terrain and a plant neatly arranged on flat land. Therefore, it is important to read array losses by breaking down where and why the losses occur, rather than focusing only on the numerical value.

The flow of energy production you should know before reading array losses

To understand array losses, you need to grasp the sequence in which energy production is calculated. In PV simulation, you start with horizontal-plane irradiance and meteorological data, then convert that to the module plane based on the module tilt and azimuth. Next, considering reflection, shading, soiling, etc., you determine the effective irradiance available for power generation on the module plane. Then, taking into account module rated characteristics, temperature characteristics, low-irradiance behavior, and quality variation, DC power is calculated. After subtracting inter-string variations and DC wiring losses, the power is input to the power conversion equipment.

If you do not understand this flow, the position of array losses will be ambiguous. For example, low irradiance incident on the module plane and reduced module efficiency at the power conversion stage are different phenomena. The former is related to azimuth, tilt, terrain, shading, and meteorological conditions; the latter is related to temperature, module performance, and electrical variability. Both reduce final production, but improvement measures differ.

When reading array losses, it is also important to be aware of “what the reference baseline is.” The meaning changes depending on whether a loss rate is relative to horizontal-plane irradiance, module-plane irradiance, or ideal DC output. In loss charts, it is easier to understand by sequentially checking what is being subtracted as you move from one stage’s value to the next.

A common source of confusion in practice is that irradiance losses and electrical losses are displayed together under the single term “losses.” For example, shading and soiling reduce the effective irradiance reaching modules. In contrast, temperature loss and wiring loss occur during the process of extracting electricity after irradiance is received. If you look only at the combined loss rate, you may not know which area to improve.

Also, array losses are easier to understand when viewed monthly. Losses that look small annually may be concentrated in particular seasons. For example, temperature losses tend to be larger in summer, and shading losses tend to be larger in winter or during morning/evening when solar elevation is low. In snowy or soiling-prone areas, production can drop sharply in specific months. Looking only at the annual total loss rate may overlook such seasonality.

Therefore, before reading array losses, organize the flow of production into these stages: “irradiance arrives,” “effective irradiance,” “becomes DC power,” “passes through DC wiring,” and “enters the power conversion equipment.” Simply understanding this order greatly changes how you interpret the loss chart.

Reading 1: Check losses that occur when converting irradiance to module-plane irradiance

The first thing to confirm is the stage where horizontal-plane irradiance is converted to module-plane irradiance. In PV, meteorological data are often given as horizontal-plane irradiance, while modules are actually installed with a tilt. Therefore, a conversion is performed from horizontal-plane to module-plane irradiance. Azimuth, tilt angle, direct irradiance, diffuse irradiance, and reflected components are involved at this stage.

Strictly speaking, this stage is not an electrical loss inside the module. However, it is very important for reading overall array production because if irradiance on the module plane is low, no matter how good the electrical design, generation will not increase. Especially if azimuth or tilt settings are misaligned with site conditions, annual production estimates can differ significantly.

For example, a near-south orientation tends to provide stable annual irradiance, while east-west orientations increase morning and evening generation and tend to suppress midday peaks. Shallow tilt angles often favor summer performance, while steep tilt angles favor winter. Which is better depends on regional irradiance characteristics, snow, land shape, racking structure, and considerations such as feed-in sales or self-consumption.

At this stage, be careful not to simply judge that any tilt deviation from south is bad. Plant design must account for many constraints—land shape, earthworks, accessways, drainage, racking arrangement, adjacent objects, and grid connection conditions. Even if azimuth or tilt deviates slightly from the theoretical optimum, it may be reasonable when considering overall capacity and constructability. Therefore, irradiance conversion loss should be evaluated not only against theoretical optimum layout but also with site constraints in mind.

Also, in regions where diffuse irradiance is a large fraction, the effects of azimuth and tilt differ from regions dominated by direct irradiance. In cloudy regions, differences due to azimuth may be relatively small. Conversely, in sunny regions with strong direct irradiance, the relationship between the sun position and module orientation has a larger impact. Looking only at losses without understanding the nature of the meteorological data can lead to over- or under-estimation.

In practice, first confirm that module-plane irradiance is reasonable. If values are extremely high or low compared to nearby projects or nearby meteorological stations, check meteorological data, coordinates, elevation, azimuth, tilt, and albedo settings. Errors in these inputs can make all subsequent array loss analysis unreliable because the base irradiance is incorrect.

Reading 2: Confirm output reduction due to temperature

Among array losses, temperature loss is one that often becomes particularly large in practice. PV modules heat up as they generate power when exposed to irradiance. Generally, as module temperature rises, output decreases. This is because rated output is measured at a fixed standard condition, while modules in the field often experience higher temperatures than that standard.

When reading temperature losses, simply looking at the annual loss rate is insufficient. Ambient temperature, wind speed, racking ventilation, mounting method, and heat dissipation conditions on the module rear surface all have an impact. For ground-mounted arrays with airflow behind the modules, module temperature tends to be lower than for rooftop installations close to the roof. The poorer the ventilation, the more module temperature tends to rise and the larger the temperature loss.

Temperature loss is not only a problem in hot regions. Even in cold regions, module temperature can become high during strong irradiance and weak wind periods in summer. Conversely, regions with low annual mean temperature tend to show relatively smaller temperature loss and therefore higher-looking PR. When comparing PR across regions, it is necessary to consider differences in temperature conditions. A high PR in a cold region does not necessarily mean design or construction is superior.

When checking temperature loss, also verify whether the module temperature calculation conditions are appropriate. Simulations simplify thermal behavior, so the thermal loss coefficient and mounting inputs affect the results. If the racking type, height above ground, rear ventilation condition, or distance from the roof surface do not match reality, temperature loss assessment may be off.

Temperature loss is also related to curtailment and inverter capacity design. At high temperatures, module output drops, which can suppress DC-side peaks. Conversely, on cold, sunny days, module output can increase and may reach inverter input limits. It is important in practice to check temperature loss together with overloading ratio, curtailment settings, and the input range of the power conversion equipment, rather than viewing temperature loss in isolation.

Improvement measures for large temperature losses include racking design that ensures ventilation, avoiding excessively enclosed installations, and inputting thermal conditions that match local ambient temperature and wind conditions. However, since temperature loss is heavily influenced by natural conditions, it cannot be completely eliminated. The key is to judge whether the loss is within a reasonable range for the region and mounting method.

Reading 3: Confirm low-irradiance characteristics and module quality losses

Next, check module low-irradiance characteristics and quality losses. Module rated output is measured under standard test conditions, but in reality irradiance at a plant is not always the same as those conditions. Low-irradiance periods occur frequently at dawn/dusk, during cloudy weather, and due to seasonal differences in solar elevation. How efficiently a module can generate power under these conditions is reflected in its low-irradiance characteristics.

Low-irradiance losses vary depending on module type and characteristics. Modules that look the same at STC can behave differently at low irradiance, resulting in differences in annual production. In regions with frequent cloud cover or a high share of diffuse irradiance, low-irradiance characteristics are not negligible.

However, low-irradiance loss tends to be overlooked in practice compared to temperature or shading losses. This is because it is hard to verify directly from design drawings and depends on module specifications and simulation model inputs. You need to confirm whether module data are correctly selected and whether rated power, temperature coefficients, and efficiency curves are appropriate. Selecting a similar model by mistake or failing to reflect a specification change can cause differences in estimated production.

Quality loss reflects nominal output variation, manufacturing tolerances, and initial differences before aging. Modules have rated tolerances; not every module will produce exactly the rated value. In a plant, many modules are connected in series and parallel, so individual variations affect the overall output.

When checking quality loss in practice, make sure the assumed values are not overly optimistic. Even for modules with good quality control, not every unit installed in the field will operate ideally. Transport, storage, installation, connections, soiling, and minor damage can all have effects. Conversely, being too conservative with quality loss assumptions can unnecessarily lower production estimates.

Low-irradiance characteristics and quality loss may not individually appear as large differences, but they affect annual production and PR comparisons. Especially when comparing multiple analyses, differences in module data or quality loss assumptions can change output even with the same layout. Therefore, when creating comparison tables, check module input conditions as well as final production figures.

Reading 4: Look at mismatch losses and the impact of string configuration

Mismatch loss is a very practical item when reading array losses. In PV systems, multiple modules are connected in series to form strings, and multiple strings are connected in parallel. Due to per-module output differences, differences in azimuth and tilt, shading patterns, temperature differences, and wiring conditions, operating points of individual modules and strings do not perfectly match. The loss due to this mismatch is the mismatch loss.

In series connections, current must basically be equal. Therefore, if some modules in a series string have lower output, the entire string’s output is affected. For example, partial shading, heavy soiling, differing azimuths, or differing tilts can pull down the whole string. This is the basic idea of mismatch loss.

If string configuration is inappropriate, mismatch loss can become large. Designs that mix modules of different azimuths into the same input circuit, combine racks with different tilts in the same circuit, or place shaded and unshaded areas in the same string should be treated carefully. In some site conditions such mixing may be unavoidable, but in that case you should quantify how much loss will result.

When reading mismatch loss, it is important to consider not only the annual value but also what causes it. Whether it arises from manufacturing variation, shading, or mixed azimuths/tilts will dictate different countermeasures. Small mismatch from manufacturing variation is somewhat unavoidable, but mismatch from string design can often be improved at the design stage.

Also, in plants on complex terrain, azimuths and tilts may slightly differ by rack within the same plant. In developed ground, slopes, valleys, or terraced sites, rack orientation and height may be non-uniform. In such cases, summarizing the whole array with a single condition may not adequately represent actual mismatch or shading effects.

In practice, check string diagrams, layout drawings, topography, and shading analysis together. Seeing which modules are in the same string, which input circuits they connect to, and where shading affects which circuits makes it easier to judge the validity of mismatch loss. If mismatch loss is large, do not just adjust a number — consider revising the circuit configuration itself.

Reading 5: Confirm DC wiring losses and voltage drop

DC wiring loss is the loss due to cable resistance dissipating heat as DC power generated at modules travels to the power conversion equipment. It is one of the array losses that is easiest to manage in design and is frequently checked in practical reviews. Wiring loss depends on cable length, conductor cross-section, current, voltage, circuit configuration, location of combiner boxes, and placement of power conversion equipment.

When reading DC wiring loss, first confirm whether the set values are based on the actual wiring plan. Sometimes a uniform loss rate is used as an estimate, but for large plants or long wiring distances it is more appropriate to calculate from actual wiring lengths and cable sizes. Distances from racking to combiner boxes, from combiner boxes to converters, and the cross-section of the main conductors significantly influence results.

Wiring loss increases proportionally with the square of the current, so for the same cable resistance the loss increases with higher current. Conversely, in higher-voltage systems the current required to transmit the same power is smaller, which helps reduce wiring loss. Therefore, DC voltage, number of strings, parallel count, and number of input circuits are related to wiring loss.

One thing to watch in wiring loss is averaging distance. Within a plant, some strings are close to converters while others are far. Calculating with a simple average distance can underestimate or overestimate reality. For wide sites or biased combiner-box placement, it is important to check actual routing. Consider actual cable routing rather than straight-line distance.

Also, thinking about DC wiring loss depends on equipment layout approach. Distributed placement of converters near each array can shorten DC wiring, though it may increase AC-side wiring and equipment count. Centralized placement tends to lengthen DC mains and may increase DC wiring loss. Which is appropriate depends on plant size, maintainability, constructability, transformer placement, and land conditions.

Improvement measures for large DC wiring loss include increasing cable cross-section, reviewing combiner-box and converter placement, shortening wiring routes, reducing current per circuit, and optimizing string configuration. However, increasing cable size affects material costs and constructability, so balance loss reduction with cost and constructability. It is important not only to reduce simulated losses but also to ensure the design is practically buildable.

Reading 6: See the reduction of effective irradiance due to shading, soiling, and reflection

When reading array losses, shading, soiling, and reflection impacts must always be checked. These reduce the effective irradiance a module receives. Even if overall irradiance is sufficient, shading, surface soiling, or increased reflection due to large incidence angles reduce the light available for generation.

Shading loss occurs from surrounding topography, trees, buildings, utility poles, spacing between racks, and shading between module rows. Especially in winter or during morning/evening when solar elevation is low, shadows extend and inter-row shading or shadows from surrounding obstacles tend to increase. Even if annual shading loss appears small, it may have a large impact on production during specific times or months.

When looking at shading loss, check not just whether shading exists but when, where, and which circuits it affects. The electrical impact differs between shading that affects part of a string and shading that uniformly affects multiple strings, even if the shaded area is the same. Shading not only reduces irradiance but can increase mismatch loss, so shading and mismatch should be considered together.

Soiling loss occurs when sand, dust, pollen, bird droppings, fallen leaves, volcanic ash, salt, or snow residue adheres to module surfaces. The degree of soiling varies greatly with region, surroundings, rainfall frequency, tilt angle, and cleaning schedule. Modules with shallow tilt do not shed soiling easily and may experience larger soiling loss. Types of soiling to consider differ for farmland, factories, highways, coastal areas, and mountainous regions.

Soiling loss is sometimes entered as a constant annual value, but in reality it varies seasonally. Rainy seasons may provide natural cleaning, whereas dry periods lead to accumulation. In snowy regions, handling periods when snow covers modules and the generation reduction during those times, as well as post-snowfall effects like increased reflection or residual snow shading, is important. When reading soiling loss, confirm that assumptions match local conditions.

Reflection loss occurs when part of incident sunlight is reflected at the module surface and not used for generation. Reflection increases with large incidence angles, so it tends to affect morning/evening and winter. Results also vary with module glass properties and incident-angle modifiers. Reflection loss is often overlooked, but depending on tilt, azimuth, and regional irradiance conditions it can be significant.

Shading, soiling, and reflection all reduce effective irradiance. If these losses are large, review layout, row spacing, racking height, surrounding obstacles, cleaning plan, and module tilt for potential improvement. However, because these must be balanced with land area and construction conditions, do not minimize losses blindly — consider the balance with installed capacity and overall revenue.

Items easily confused when reading array losses

A confusing point when reading array losses is distinguishing DC-side losses from AC-side losses. Array losses mainly cover losses from modules to DC input, but final production is also affected by inverter efficiency, AC wiring, transformers, curtailment, and internal consumption. If you draw conclusions from array loss alone when investigating low PR, you may overlook AC-side problems.

For example, even if DC generation is sufficient, output may be clipped by inverter capacity limits. This loss is not because the array underperforms but due to the design balance between DC and AC capacities. In overloading designs, some output clipping is an accepted design choice. Therefore, do not simply treat clipping as a bad loss — evaluate it from the perspective of annual production, equipment utilization, and profitability.

Also, internal consumption and auxiliary losses are separate from array losses. Power consumed by monitoring equipment, communications devices, cooling units, transformer equipment, and control devices affects final exported power, but these differ in nature from losses occurring when modules generate power. Confusing array losses with auxiliary losses can misdirect improvement efforts.

Further, distinguish degradation loss over time from first-year array losses. Modules experience output decline with time, which is handled in long-term production forecasts. This is different from quality or mismatch losses included in first-year simulations. For long-term financial evaluation, separate first-year array losses from aging degradation.

When comparing reports, similar-named loss items may not cover the same ranges. An item categorized as an irradiance-side loss in one report may be treated as an array-side loss in another. When comparing analyses, do not judge solely by item names — confirm from which stage of energy to which stage the loss refers.

Procedure for checking array losses in practice

When checking array losses in practice, start by verifying assumptions rather than immediately looking at final production or PR. Confirm that site location, meteorological data, elevation, azimuth, tilt angle, module model, DC capacity, AC capacity, wiring conditions, shading inputs, and soiling assumptions are correct. If assumptions differ, loss-rate comparisons become meaningless.

Next, check module-plane irradiance. Verify that the conversion from horizontal-plane to tilted-plane irradiance is reasonable and not extreme compared to nearby sites. If anything looks odd, review meteorological data and azimuth/tilt inputs. Since irradiance is the starting point for all calculations, this step is critical.

Then check items that reduce effective irradiance such as shading, soiling, and reflection. If shading loss is large, determine whether the cause is inter-row shading, surrounding obstacles, or terrain. If soiling loss is large, confirm consistency with regional environment and cleaning plans. For reflection loss, check whether the effect of tilt and incidence angle is reasonable.

Next, confirm temperature loss. Assess whether temperature loss is within a reasonable range for local ambient temperature, wind speed, and mounting type. Rooftop or poorly ventilated installations tend to have larger temperature losses, while well-ventilated ground-mounted systems have smaller losses. Confirm that thermal inputs match reality.

Then check module quality, low-irradiance characteristics, and mismatch loss. Verify module data, whether string configuration is appropriate, and whether shading or azimuth differences are mixed within circuits. Comparing layout drawings, single-line diagrams, and string diagrams is effective here. Even if the loss chart alone does not reveal the cause, combining it with drawings helps judgment.

Finally, check DC wiring losses. Confirm whether the values are approximate or based on actual wiring; ensure cable lengths, cross-sections, combiner-box locations, and converter locations are consistent. DC wiring loss is often improvable by design changes, so inspect large values carefully.

Thus, checking array losses is not just scanning the loss chart top-down; it is a cross-checking task that spans meteorology, layout, electrical design, and construction conditions. Track not only the magnitude of numbers but also the assumptions that produced them.

Design and construction focal points to improve array losses

To improve array losses, first separate losses that can be improved from those that are difficult to improve. Losses heavily influenced by natural conditions, such as temperature and reflection, cannot be completely eliminated. On the other hand, some DC wiring loss, mismatch loss, shading loss, and portions of soiling loss may be improved through design and operation.

On layout: check consistency of azimuth and tilt, row spacing, rack height, and clearance from surrounding obstacles. Overpacking racks to maximize land use can increase inter-row shading and worsen maintenance access. While denser packing may look to increase short-term installed capacity, shading and poorer maintainability can reduce long-term performance.

In electrical design: string configuration and how input circuits are divided are important. Combining modules with different shading conditions or different azimuths/tilts into the same circuit can increase mismatch. The basic rule is to group modules with similar conditions in the same string or input circuit. For complex terrain, design by area is effective.

In wiring: optimize combiner-box and converter placement to avoid unnecessarily long DC runs. Increasing cable cross-section reduces loss but affects material cost and constructability. Instead of simply choosing thicker cables, optimize equipment placement, routing, circuit count, and installation procedures.

In construction: ensure azimuth, tilt, wiring, and connections are implemented as designed. Even if losses are small on paper, field deviations such as incorrect rack angles, longer routing, different connection points, or newly added shading sources can change actual generation. As-built verification of positions, heights, and angles at completion directly relates to understanding actual array losses.

In operation: soiling and vegetation control and periodic inspections are important. Issues such as weeds causing shading under modules, locally heavy soiling from birds or dust, and mud splashing from poor drainage occur during operation. These are hard to foresee in simulation but can be addressed by combining measured data and field checks.

Improving array losses requires not only simulated figures but also accurate knowledge of the site condition. Connecting design drawings, as-built drawings, site surveys, photos, point clouds, and production records helps identify loss causes concretely.

Summary

PVSyst array losses are an important item for understanding where generation in a PV plant is being reduced. Rather than only judging by loss-rate magnitude, read them by stages: conversion from irradiance to module plane, changes to effective irradiance, module generation of DC power, passage through strings and DC wiring, and input to the power conversion equipment.

Key points to check are conversion from irradiance to module plane, temperature loss, low-irradiance characteristics and quality loss, mismatch loss, DC wiring loss, and losses due to shading, soiling, and reflection. Each has different causes and different remedies. Some, like temperature, are largely governed by natural conditions, while others, such as wiring length and string configuration, are more amenable to design improvements.

Practitioners should not judge array losses solely from loss charts; confirm them alongside layout drawings, string diagrams, single-line diagrams, meteorological and site conditions. Viewing monthly and seasonal values as well as annual totals helps identify impacts from shading, temperature, soiling, and snow. When comparing multiple analyses, confirm not only item names but whether the calculation ranges and assumptions are the same.

Mastering how to read array losses lets you explain low production with evidence rather than intuition. In the design phase, it becomes easier to find layout and wiring improvements. After construction, comparing with measured production helps identify shading, soiling, wiring, angle deviations, and operational issues. In short, array losses are not just a line item in analysis but a verification point connecting design, construction, and operation.

To accurately understand a PV plant’s performance, it is essential to link simulation figures with site conditions. If module layout, rack angles, site elevation differences, surrounding obstacles, and as-built status can be accurately confirmed, array loss causes can be explained more concretely. LRTK is a GNSS high-precision positioning device that can be attached to an iPhone and used for on-site position verification, as-built confirmation, and point-cloud/drawing comparison. If you want to validate production analysis results against field conditions rather than leaving them as desk figures, high-precision on-site verification using LRTK can make PV plant design, construction, and maintenance more reliable.