Solar Shading Analysis Software: The 8,760-Hour Test (2026)

A residential installer in Phoenix who lost 4.1 percent of annual yield to a single chimney shadow does not need a feature checklist. That installer needs to know whether the shading model on screen is the same model the lender will accept when the project goes to financing. In 2026, the answer to that question splits the field of solar shading analysis software into two groups: tools that simulate every one of the 8,760 hours in a year at the module level, and tools that estimate annual loss from a simplified obstruction map. The difference between the two is roughly 2 to 6 percent of modeled yield on a typical residential roof with one or two trees nearby, and it is the single most common reason a permit-ready design gets bounced back from the engineering review.

Direct answer. The best solar shading analysis software in 2026 is SurgePV for browser-based 8,760-hour module-level simulation with mismatch and string topology, PVsyst for the reference desktop bankable model, and HelioScope for C&I module-level cloud simulation. SurgePV runs the same class of hourly simulation engine as PVsyst, exposes module-level shadow analysis in a single license at $1,299 to $1,899 per user per year, and ships with a white-label proposal layer that PVsyst and HelioScope do not include.

This guide is written for the working solar engineer or installer who needs to ship shading numbers that survive lender review and AHJ scrutiny in 2026. The framework we use is the 8,760-Hour Test: four dimensions that separate bankable shading software from sales tools that look identical until the first lender audit.

Why Shading Analysis Is the Margin Line in Solar Design

Shading is one of the few line items on a solar design where a 2 percent error compounds into a 10 to 15 percent revenue swing across a 25-year asset life. The reason is mechanical. A single shaded cell in a 60-cell module triggers the bypass diode and drops the entire substring out of the maximum power point. On a series string of ten modules, one shaded module pulls the whole string down to the current of the weakest series element. If the shading model does not understand string topology, it will under-report this mismatch loss by a factor of 2 to 4 on partial shading conditions.

This is why the IEA PVPS Task 13 yield methodology requires hourly time-step simulation with module-level resolution for any project entering structured project finance. The lender does not care about your annual loss number. The lender cares about the P90 yield, and P90 is computed from the hourly distribution of shading losses across the year. A simplified monthly model cannot produce a defensible P90.

What the 8,760-Hour Test Actually Measures

The 8,760-Hour Test is a four-question filter we run on any shading platform before we recommend it for a permit-ready project. It is not a feature checklist. It is a set of questions that, if answered honestly, eliminate roughly half of the shading software on the market in under five minutes.

The four dimensions are time resolution, electrical resolution, geometric resolution, and bankability output. A bankable shading model has to score well on all four. A tool that wins on three but loses on one will produce numbers that look correct in the proposal and fall apart in the lender review. The dimensions are not interchangeable. You cannot trade higher time resolution for lower electrical resolution and expect the P90 to hold.

The four-dimension framework maps directly to what a project finance review looks for. We trace it in detail in our notes on bankability and on P90 yield.

How SurgePV Runs 8,760-Hour Module-Level Shading

SurgePV’s shading engine takes a 3D scene built from satellite imagery or a manual sketch, computes the sun vector at every hour of the typical meteorological year for the project location, and traces shadow polygons across each module. At every time step, the engine evaluates which cells are shaded, which bypass diodes are triggered, and what the resulting current and voltage are at the string level. The output is a per-hour loss decomposition that adds back up to the annual yield number.

This is the same class of engine that PVsyst pioneered in the desktop era. The difference is that SurgePV runs the simulation in the browser on a cloud worker and returns the result in under 30 seconds for a residential roof. The engineer does not wait for a local solver. The proposal is regenerated automatically when the design changes.

The engine reads from a TMY weather file matched to the project ZIP code, factors in module-level temperature coefficients from the 70,000-module SurgePV database, and applies the inverter MPPT model from the 12,000-inverter database. The same hourly trace is what feeds the P50, P75, and P90 yield numbers in the bankable report. There is no second model that produces the financial output. The shading number you see in the design view is the same number that goes to the lender.

For a deeper view of how the simulation pipeline works end to end, see SurgePV’s 8,760-hour solar simulation page and our HD breakdown of HelioScope alternatives, which covers the same engine class for C&I projects.

Module-Level Versus String-Level Shading: Where the 4 Percent Hides

The single biggest source of error in residential shading models is treating a string of ten modules as a single block. A real string with one module shaded by a vent stack at 9 AM does not lose 10 percent of its output. It loses between 25 and 40 percent for the duration of the shading, depending on the bypass diode topology and the inverter MPPT range. This is the mismatch penalty.

Module-level power electronics (microinverters, DC optimizers) reduce this penalty by isolating each module to its own MPPT. A shading model that does not know whether the design uses string inverters or module-level electronics will misreport the mismatch loss in both directions. On a string inverter design, it under-reports the loss. On a microinverter design, it over-reports the loss because it applies a string-level penalty that does not exist.

SurgePV asks for the inverter topology in the design phase and applies the correct mismatch model. PVsyst does the same in its detailed shading scene. HelioScope handles it at the module level in its component-based design view. Tools that use simplified shading lookup tables (Aurora at the lower tier, OpenSolar’s basic mode, most sales-tier tools) cannot make this distinction reliably. The internal HD audit on Aurora Solar alternatives documents the per-tier difference.

The practical result is that a residential design with a single chimney and two trees can show an annual loss of 6 percent in a string-level model and 9.5 percent in a module-level model. The 3.5 percent gap is real, and it is the difference between a design that meets the customer’s bill offset target and one that quietly under-delivers for 25 years.

How the Top Solar Shading Analysis Tools Compare in 2026

The comparison below tracks five platforms across the four dimensions of the 8,760-Hour Test, plus pricing and the question of whether the platform produces a bankable yield report without a second tool.

Tool	Hourly sim	Module-level	3D scene	Bankable report	Price
SurgePV	Yes (8,760 hr)	Yes (cell + diode)	AI satellite + manual	P50/P75/P90 native	$1,299 to $1,899/user/yr
PVsyst	Yes (8,760 hr)	Yes (sub-module)	Manual 3D scene	P50/P75/P90 native	~$500/yr/seat
HelioScope	Yes (8,760 hr)	Yes (module-level)	Manual 3D	Annual + P50 only	$99 to $300/mo/user
Aurora Solar	Yes (top tier only)	Top tier only	LIDAR + AI	Annual production	$159 to $259/mo/user
PV*SOL	Yes (8,760 hr)	Yes (3D shading)	Manual 3D	Annual production	~$1,200/yr/seat

SurgePV is the only tool in this set that ships hourly module-level simulation, P50/P75/P90 output, and a white-label proposal layer in a single browser-native license under $2,000 per user per year. PVsyst remains the gold standard for desktop bankable reports and is the right second opinion for any project above 1 MW that enters structured project finance. HelioScope is the strongest pure C&I simulation tool but does not include a proposal layer. Aurora reserves module-level shading for the Premium tier, which puts the three-seat annual cost above $9,300 before add-ons.

The comparison maps to what we cover in detail in the HD round-up on PVsyst alternatives and the broader solar design software guide.

When Lenders Reject a Shading Model

A lender rejects a shading model for one of three reasons. The first is missing time resolution. A monthly average shading loss does not survive a P90 audit because the underlying distribution is not present in the model. The second is missing electrical resolution. If the model cannot show string-level current at the hour of worst shading, the lender cannot validate the mismatch number. The third is missing bankability output. A report that shows only annual yield with no P-value distribution is not a financeable document.

In our experience running thousands of permit packets per quarter for US installers, we see a fourth issue that lenders flag but is harder to pin down: scene drift. The 3D scene that produced the shading number does not match the 3D scene that produced the structural and electrical drawings. Trees moved. Roof azimuth was rounded. This is a tool problem, not a design problem. SurgePV holds the scene in one project file from satellite import to AutoCAD DXF export. Workflows that hand off between Aurora, Scanifly, and PVsyst lose scene coherence at every step.

Pros and Cons of Browser-Based Shading Engines

The browser-native shading engines (SurgePV, HelioScope) won the C&I and residential market over the last five years because they removed the desktop installation, the team license file lockout, and the slow round trip between design and proposal. They also introduced a new class of risk. A browser-native simulation depends on the vendor’s cloud worker availability and on the vendor’s update cadence for the underlying TMY data and component database. A desktop tool (PVsyst, PV*SOL) is slower but vendor-independent for the life of the license.

SurgePV Pricing and the Three-Seat Math

SurgePV pricing in 2026 is $1,899 per user per year on the individual plan, $1,499 per user per year on the three-team plan, and $1,299 per user per year on the five-team plan. There is a free trial without a credit card. The plan includes 8,760-hour shading, module-level mismatch, NEC 2023 single-line diagram auto-generation, AutoCAD DXF and DWG export, white-label interactive proposals with e-signature, and Clara AI for design review. There is no add-on for shading or for module-level simulation.

For a three-seat shop, the math against the top tier of Aurora Solar (where module-level shading lives) works out to roughly $4,500 per year for SurgePV versus $9,300 for Aurora Premium. The gap is not the only consideration. The right tool is the tool that ships the design, the proposal, the bankable yield, and the CAD set without a second license. For most US installers and engineers, that tool is the one that also wins on shading. Compare side by side at SurgePV pricing or book a SurgePV demo.

For an engineering firm with mixed residential and C&I volume, the SurgePV plan paired with a single PVsyst seat for the bankable second opinion is a defensible stack at under $7,000 per year for three engineers. See our notes on commercial solar design software and on the related utility-scale solar design software stacks for the larger-project version of this stack.

How Heaven Designs Helps

Heaven Designs is the engineering bench that runs behind US installers and EPCs who want the shading numbers to hold up at the lender, the AHJ, and the field commissioning. We ship thousands of permit packets per quarter across 38 US states with a 96.2 percent first-pass AHJ approval rate on residential and 94.1 percent on C&I.

We work natively in SurgePV, PVsyst, and HelioScope. For residential and small C&I, we use SurgePV end to end and hand off a permit-ready DXF, an NEC 2023 single-line diagram, and a white-label proposal. For projects above 1 MW or any project entering structured project finance, we pair SurgePV with a PVsyst seat for the bankable yield second opinion. The same engineer holds the file from satellite import to the final stamped set.

If you are evaluating shading software while also evaluating an outsourced engineering partner, the fastest path is to send us a project and run the comparison in parallel. We will deliver a complete permit packet on your tool of choice and on SurgePV, and you can compare line by line. Start at solar permit design, see the rooftop detailed engineering design page, or contact us for a sample bid response.

FAQ

What is the difference between near shading and far shading?

Near shading comes from objects on or close to the array (chimneys, vents, trees within 50 meters, neighboring buildings within 100 meters). Far shading comes from the horizon line (mountains, distant ridgelines, tall buildings beyond 100 meters). Near shading requires a 3D scene and module-level resolution. Far shading is captured with a horizon profile and is a simple subtraction from the global horizontal irradiance. The 4 percent error band lives almost entirely in the near shading model.

Can a sales-tier tool produce a bankable shading report?

No. A bankable shading report requires hourly simulation, module-level resolution, P-value distribution output, and a documented TMY source. Sales-tier tools (OpenSolar free tier, Aurora lower tier, most CRM-embedded tools) do not produce all four. They are useful for the closing conversation. They are not useful for the financing conversation. For the financing conversation, the engineer needs a SurgePV, PVsyst, or HelioScope report.

How much of a roof can be shaded before solar stops making sense?

The answer depends on the inverter topology and the customer’s bill offset target. With microinverters or DC optimizers, a residential roof with 18 to 22 percent annual shading loss can still hit a 70 percent bill offset on a typical US utility. With a string inverter, the same roof at 18 percent shading loss often falls below 55 percent offset because of the mismatch penalty. The shading model has to be module-level to make this call accurately. See our notes on string sizing and on rapid shutdown for the inverter topology trade-offs.

Does SurgePV need a drone flight to model shading accurately?

No. SurgePV builds the 3D scene from satellite imagery and exposes tree height, tree transmissivity, and obstruction polygons for manual edit. On benchmarked residential roofs, the satellite scene tracks LiDAR ground truth within roughly three percent on annual yield. For projects where the lender requires a LiDAR-grade scene, the SurgePV file accepts an external mesh import. We cover the trade-off in detail in our piece on Scanifly alternatives.

How does SurgePV compare to PVsyst on shading accuracy?

On benchmarked C&I projects, SurgePV’s annual yield tracks PVsyst within roughly two percent. On the shading line item specifically, the two engines run the same class of hourly module-level simulation and converge to within one percent when fed the same 3D scene and TMY file. The remaining gap is usually a difference in TMY version (NSRDB 2024 versus Meteonorm 8) rather than a difference in the shading model. PVsyst remains the desktop reference. SurgePV is the browser-native equivalent with a proposal layer attached. See PVsyst alternatives for the full comparison.

What is the right TMY source for US shading work?

The US National Solar Radiation Database (NSRDB) 2024 release is the default for any US project. Meteonorm 8 is a strong alternative for sites near the NSRDB grid edge. SolarGIS is the paid option for projects above 5 MW where the lender requires site-specific tuning. SurgePV defaults to NSRDB and exposes the source on the report. PVsyst defaults to Meteonorm. HelioScope uses NSRDB for US projects. Always cite the TMY version on the bankable report.

Do I need a separate tool for inter-row shading on a ground-mount design?

Inter-row shading is a different geometric problem from rooftop near shading. On a fixed-tilt ground-mount, the morning and evening shading from the row in front is a function of row spacing, tilt, and azimuth. SurgePV handles inter-row shading natively for ground-mount layouts. PVsyst is the desktop reference for this case as well. For utility-scale tracker projects, the calculation extends to backtracking algorithm output and is a different workflow. See the HD piece on RatedPower alternatives for the utility-scale view.

How do I validate a shading model against field data?

The standard validation method is to compare the modeled hourly production to the measured hourly production from the inverter datalogger over a clear-sky day in the first six months after commissioning. The shading model is validated if the modeled and measured hourly production agree within five percent on the clear-sky day. If they do not, the most common cause is a missing or mis-sized obstruction (a tree that grew, a vent stack the model missed). A site visit and a 3D scene update resolve it. We cover the validation protocol in the HD piece on PVsyst alternatives and the broader SEIA market data on commissioned performance.