Best Solar Shading Analysis Software South Africa 2026

Choosing solar shading analysis software in South Africa starts with two corrections. The first is geometric: this is the southern hemisphere, June is winter, and a fixed array faces north, not south. Templates, spreadsheets and vendor demo files imported from Europe or North America get this backwards, and the error survives longer than it should because a mirrored azimuth still produces a plausible-looking annual number. The second correction is economic. In a market shaped by load shedding, most residential and small commercial arrays are paired with a battery, and the array’s real job is to refill that battery before the next scheduled block. A shading loss at 8 am that delays state of charge by two hours costs the client a block of backup they paid for. The same number of kilowatt-hours lost at midday, when the bank is already full and the array is curtailing anyway, may cost nothing at all. An annual shading percentage cannot distinguish those two cases. This guide ranks ten tools in rand and shows which ones can.

Direct answer. The best solar shading analysis software in South Africa for 2026 is SurgePV at roughly ZAR 24,000 (US$1,299) per user per year on the 5-User Team plan, for design-side shading: 8,760-hour module-level simulation with bypass-diode physics and a near-object scene built from satellite imagery. For the question that actually decides a hybrid design, whether the battery reaches full charge before the next outage block, HOMER Pro from US$1,575 a year on its Base tier, about ZAR 29,000, models state of charge better and we rank it second on that basis.

This page is written for South African designers, C&I integrators and consultants whose yield or backup numbers are being challenged. It gives the Johannesburg and Cape Town sun arithmetic first, then the ranking. The universal engine mechanics sit in the pillar guide to solar shading analysis software; everything here is what changes below the equator with a battery in the loop.

Southern Hemisphere Geometry: North-Facing, and a Low June Sun

State it plainly because imported templates get it wrong. In South Africa the sun tracks across the northern sky, a fixed array is oriented toward true north, and shadows at solar noon fall to the south. The winter solstice is 21 June, not 21 December, and that is when the sun is lowest and shadows longest. A design file inherited from a European reference project has its azimuth mirrored and its seasonal shading window inverted, and both errors have to be fixed before the shading result means anything.

June solar noon elevation is 90 degrees minus the absolute difference between site latitude and the plus 23.44 degree declination. That gives:

Cape Town’s 32.6 degrees is the number that surprises people. South Africa markets itself as a sunny country and the summer numbers support that: at Cape Town’s December solar noon the sun is 79.5 degrees up and a metre of height casts just 0.19 m of shadow. Six months later the same metre casts 1.56 m, and at 9 am solar time in June the sun is only 18.5 degrees up, in the north-east, and that metre throws 3.0 m. Nothing about the summer site walk prepares a client, or a junior designer, for the winter shadow map.

Location	Latitude	June noon elevation	9 am June elevation	Shadow per 1 m (June 9 am)	Minimum pitch, 2.28 m module at 30 degrees
Cape Town	33.9S	32.6°	18.5°	3.00 m	~4.47 m
Johannesburg	26.2S	40.4°	24.0°	2.25 m	~3.85 m
Durban	29.9S	36.7°	21°	2.61 m	~4.16 m
Lagos, for contrast	6.5N	60° in December	36.9° in December	1.33 m	~2.66 m

The pitch column uses a 2.28 m module in portrait at 30 degrees tilt, giving 1.14 m of rise and a 1.97 m base, with the 9 am shadow resolved into the row direction. Unlike Nigeria, inter-row spacing genuinely binds here, and a Cape Town ground-mount or flat-roof ballast layout designed at Johannesburg pitch will self-shade through winter mornings. It also means the two ends of this country need different row spacing, which a national standard drawing cannot express.

The Recharge Window Test: Why Morning Shade Costs More Than Midday Shade

This is our named framework for South African work, and it is the reason a shading percentage is the wrong deliverable here. In a load-shedding hybrid the array has two jobs: carry the daytime load, and refill the battery before the next scheduled block. Those jobs compete, and the second one is time-critical in a way annual energy accounting cannot represent.

Five steps, scored against any tool you are evaluating.

1. Map the outage schedule onto the day. At a given stage the site loses supply for defined blocks. Write down the block times. The recharge window is whatever daylight sits between the end of one block and the start of the next.
2. Establish the state of charge floor. After an evening and overnight block, most banks start the day well down. That deficit has to be recovered from morning production before anything else is achieved.
3. Locate the shading loss in the day, not the year. A tree or a neighbouring wall to the east shades from sunrise to perhaps 10 am in June. That is exactly the window doing the recovery work.
4. Ask what the loss displaced. Morning kilowatt-hours lost are recharge kilowatt-hours lost, so they translate directly into a lower state of charge at the start of the next block. Midday kilowatt-hours lost, on a system where the bank has already reached full and the inverter is curtailing, may cost the client nothing measurable.
5. Re-run and compare state of charge, not energy. The correct output is the minimum state of charge reached across the worst realistic day, with and without the shading. If a tool cannot show you that curve, it cannot price the shade in this market.

Verdict. Two arrays can post an identical 6 percent annual shading loss and behave completely differently under Stage 4. The one shaded from the east runs the bank flat by the evening block. The one shaded at noon barely notices. Ask any vendor to show you both curves before you buy.

The practical consequence for design is that east-side obstructions deserve far more attention than west-side ones on a battery-backed South African system, which inverts the usual advice on a grid-tied roof where morning and afternoon losses are commercially symmetric. Where you cannot remove the eastern obstruction, the answer is often extra array capacity facing slightly east of north to steepen the morning ramp, accepting a small annual energy penalty to buy back the recharge window. No tool will suggest that trade to you. You have to know to test it.

Cape Town Is Not the Highveld: Diffuse Fraction Changes the Answer

A single national irradiance assumption is wrong in South Africa, and shading is where the error shows up most sharply. The Western Cape has a Mediterranean climate with a wet, cloudy winter. The Highveld has a dry, bright winter and its rain in summer. That means during exactly the season when the sun is lowest and shadows longest, Cape Town also has a much higher diffuse fraction than Johannesburg.

Diffuse light matters for shading because a shaded module is not dark. It still receives light from the portion of sky it can see, and how much depends on the sky model. Under a bright clear sky most irradiance is direct beam, so an obstruction blocking the sun removes most of the resource and the geometric shadow map tells nearly the whole story. Under a Cape Town winter overcast, much of the resource is diffuse and arriving from the whole sky dome, so what matters is the fraction of sky the module can still see, not whether the solar disc is blocked.

An isotropic sky model, which assumes diffuse light arrives evenly from all directions, misprices this. Circumsolar brightening and horizon brightening are real, and an anisotropic model such as Perez or Hay-Davies handles them. On a partly shaded Cape Town roof in June the difference between the two model families is not academic, and it runs in the direction of the isotropic model being too optimistic about what a sky-restricted module recovers. Check which sky model your tool uses and whether you can change it. Our diffuse horizontal irradiance entry defines the underlying quantity.

The mirror-image error is also common: applying Cape Town’s diffuse assumptions to a Northern Cape or Free State site, where clear-sky direct beam dominates and the geometric shadow map really does carry the analysis. Two different countries, one border post apart.

Getting a shading claim challenged? Bring a real Johannesburg or Cape Town site with its critical-load list and outage schedule and we will run the state of charge comparison with and without the shading. Talk to our engineering team.

Top 10 Solar Shading Analysis Software in South Africa Compared

Pricing is each vendor’s own published 2026 list price in the currency they bill in, annualised for one seat unless stated. Rand equivalents are approximate at about ZAR 18.5 to the US dollar and move with the exchange rate.

#	Tool	Published price	Shading capability	Answers the recharge question?
1	SurgePV	US$1,299/user/yr (about ZAR 24,000)	8,760-hour module-level, AI near-object scene, per-module heatmap	Partly, through hybrid backup sizing
2	HOMER Pro	Base US$1,575/yr; Professional US$3,100/yr; Expert US$4,650/yr	Weak geometry, consumes an hourly series	✓ Best on this list
3	PVsyst	CHF 700/user/yr, Professional	Reference near-shading 3D scene and loss diagram	Partly, through its storage module
4	PV*SOL Premium	EUR 845/named user/yr + VAT	3D shading animation, battery module, runs offline	Partly
5	HelioScope	Basic US$1,620/yr; Pro US$2,640/yr	Clean module-level loss tree	✗
6	Aurora Solar	Basic US$135/user/mo billed annually (US$1,620/yr); Premium US$220 (US$2,640/yr)	Strong irradiance maps, LIDAR where available	✗
7	Scanifly	Not publicly listed, quote only	Drone photogrammetry as-built obstruction capture	✗ Capture only
8	Solmetric SunEye 210	US$2,195 base, North America, plus import duty	Measured on-roof skyline, no modelling assumption	✗ Measurement only
9	PVGIS horizon import	Free	Far-horizon profile from terrain data	✗
10	Sunsynk, Deye and Victron tooling	Free with hardware	No shading model, but measured state of charge history	✓ After the fact

Worth stating rather than sliding past: three of those competitors are cheaper per seat than we are. PVsyst Professional is CHF 700 per user per year, PV*SOL Premium EUR 845, and Aurora Basic US$1,620 a year, all against US$1,299 per seat on a five-seat SurgePV team and US$1,899 for a SurgePV Individual seat. Five PVsyst seats cost CHF 3,500 against US$6,495 for five SurgePV seats. We rank SurgePV first on scene-building speed and on the shading result feeding backup sizing, not on price.

Positions 1 and 3 to 6 are shading engines. Position 2 is a dispatch and economics engine that consumes a shading result. Positions 7 to 9 are capture and data sources. Position 10 is the monitoring layer already sitting on most South African hybrids, and it earns a place because it is the only entry that shows what the battery really did.

1. SurgePV

What it does best for South African shading. SurgePV runs a true 8,760-hour, module-level shading simulation with bypass-diode physics on every paid plan, with no add-on tier gating it. Southern hemisphere geometry is handled natively rather than by mirroring a northern template, so a north-facing default and a June winter window come out correctly without you overriding anything. You enter an address, the AI builds the 3D roof from satellite imagery in about a minute and proposes obstruction objects, then you correct heights by hand. Arbitrary objects with explicit heights let you place a boundary wall, a neighbour’s double storey, a chimney and a tree at ten-year height as separate scenarios. The annual per-module heatmap drives re-stringing and MPPT grouping. Most relevantly for this market, the shading result feeds the same project’s hybrid backup sizing, so you can watch a shading change move the autonomy figure rather than only the annual percentage.

Pricing. Roughly ZAR 24,000 (US$1,299) per user per year on the 5-User Team plan, about ZAR 120,000 for five seats. Free trial, no card.

Who it suits. South African installers and C&I integrators who want a defensible shading study attached to every hybrid quote rather than only on financed projects.

Honest limitations, and one of them is central to this page. SurgePV does not run a scheduled-outage dispatch optimiser. It will size a hybrid and show backup behaviour, but it will not search combinations of PV, battery and generator for the least-cost answer under a given shading penalty the way HOMER Pro does, so mine, estate and microgrid work belongs in HOMER. It carries no South African municipal tariff library, so City of Cape Town, City of Johannesburg and eThekwini rate structures are entered by hand. It does not filter inverters against a municipality’s accepted list and does not generate an SSEG application pack. It is cloud-only with no offline design mode. And utility-scale single-axis tracker shading is still maturing, so cross-check a large Northern Cape ground-mount in PVsyst.

See the SurgePV shadow analysis module, and the best solar design software in South Africa ranking for the wider workflow comparison.

2. HOMER Pro

What it does best, and why it is second on a shading page. HOMER Pro has no meaningful 3D shading geometry. What it has is the thing this page argues decides the design: hour-by-hour dispatch across PV, battery, generator and an intermittent or scheduled-outage grid, with battery state of charge tracked throughout. Feed it your shaded hourly production series instead of the clean one, impose the outage schedule, and compare the minimum state of charge across the worst day. The difference between those two runs is the real cost of the shade in a load-shedding market, expressed as backup hours lost rather than as a percentage.

Pricing. US$1,575 a year for Base, US$3,100 for Professional and US$4,650 for Expert on annual billing, roughly ZAR 29,000, ZAR 57,000 and ZAR 86,000. Monthly billing costs about a third more, and there is a 25 percent discount at four or more licences.

Who it suits. Consultants sizing mine, estate, farm and microgrid systems, and anyone whose contract promises a number of hours of backup rather than a number of kilowatt-hours.

Honest limitations. It draws no roof, designs no strings, produces no single-line diagram, no bill of quantities and no proposal, and it cannot compute a shading loss from geometry at all. It is always a second seat. The interface is dense, the learning curve is steep, and it is desktop-bound. A residential installer doing two systems a month does not need it.

3. PVsyst

What it does best. The near-shading 3D scene editor is still the most complete implementation of obstruction geometry available, and the loss diagram is what a South African bank or development finance institution reads fastest. Its storage module handles self-consumption and backup cases competently, its thermal model deals properly with high-irradiance summer conditions, and its sky modelling is anisotropic by default, which matters for Western Cape winters. On lender acceptance PVsyst beats SurgePV outright and we say so.

Pricing. CHF 700 per user per year for the Professional edition, an annual subscription rather than a perpetual licence, with 5 to 20 percent group discounts by quantity. That is cheaper per seat than SurgePV, and five seats come to CHF 3,500 against US$6,495 for five SurgePV seats.

Honest limitations. Building the near-shading scene by hand is slow, commonly an hour or more for a cluttered suburban roof that a satellite-driven tool proposes in a minute. Desktop-only and Windows-first. No proposal output, no client-facing heatmap, no SSEG or NRS 097-2 awareness, and its outage-schedule modelling is far weaker than HOMER’s. Our engineering group’s guide to reading a PVsyst loss diagram explains the output, and our PVsyst alternative comparison covers where teams replace it.

4. PV*SOL Premium

What it does best. The 3D shading animation is the best client-facing shading artefact on the market, rendering shadow movement across the array through the day and the year plus a per-module shade frequency visual. On a Cape Town site where the client refuses to believe the neighbour’s wall matters in June, showing the animation ends the argument in about thirty seconds. Battery and generator modules are included, and it runs offline.

Pricing. EUR 845 per named user per year plus VAT for PVSOL Premium, with standard PVSOL at EUR 585. There is no longer a perpetual licence option: Valentin Software stopped selling perpetual licences on 19 November 2024 and maintenance renewals on existing perpetual licences ended on 1 October 2024, though those licences remain usable. At EUR 845 a named user it is cheaper per seat than SurgePV.

Honest limitations. Desktop and Windows-only, effectively single-user, dated interface, manual scene building, no South African compliance content, and an annual euro subscription rather than the one-time purchase many local teams still believe they are buying. Support hours align poorly with South African working days.

5. HelioScope

What it does best. Module-level 8,760-hour simulation with the cleanest loss tree in the category, separating shading from soiling, mismatch and thermal losses. On a 500 kW Gauteng or KwaZulu-Natal warehouse roof it is fast and the report passes technical review without argument.

Pricing. Basic is US$159 a month, US$1,620 a year, for one user and 10 projects a month with a 1.25 MW DC design cap. Pro is US$259 a month, US$2,640 a year, with a 5 MW cap.

Honest limitations. Obstruction modelling is manual with no AI roof build. Storage modelling is thin and there is no outage simulation at all, so in a load-shedding market it answers the annual question well and the question that matters not at all. No South African compliance content and weak proposal tooling. Our HelioScope alternative guide covers the migration path.

6. Aurora Solar

What it does best. Irradiance mapping and the shade engine are genuinely strong, and where LIDAR coverage exists roof detection is excellent. For a South African team doing design outsourcing for US installers, Aurora fluency has commercial value on its own.

Pricing. Basic is US$135 per user per month billed annually, US$1,620 a year, and Premium US$220 annually, US$2,640 a year. Enterprise is quoted. Plan sets are a separately priced service rather than a plan inclusion, and site models start at US$9.99. Aurora Basic is cheaper than a SurgePV Individual seat.

Honest limitations. LIDAR coverage in South Africa is patchy, so the capability that makes Aurora excellent in California degrades to manual tracing in Randburg. Its roof AI is trained on North American imagery and handles South African tile roofs, boundary walls and dense suburban infill less reliably. Storage is an add-on rather than the core, and the capabilities you would buy Aurora for here, LIDAR modelling and bankable shade reports, sit on Premium at US$220 per user per month rather than on Basic. Covered in our Aurora Solar alternative writeup.

7. Scanifly

What it does best. Drone photogrammetry turns a short flight into an as-built 3D site model with every wall, chimney, flue and tree at its real height. On a multi-level building or a complex industrial site it removes the largest single source of shading error, which is a guessed obstruction height, and it captures the eastern obstructions that the recharge window depends on.

Pricing. Scanifly does not publish a price list. Pricing is quoted and scales with team size and capture volume, so budget from a quote rather than from a directory figure.

Honest limitations. It is a capture tool, not a simulation engine, so you export into something that runs the physics. South African Civil Aviation Authority rules on commercial drone operation impose licensing and operating requirements that installers routinely underestimate, and restricted airspace around airports rules out a meaningful share of urban sites.

8. Solmetric SunEye 210

What it does best. A handheld fisheye skyline instrument. Stand at a point on the roof, take one capture, and it returns measured sky obstruction and monthly solar access for that exact position with no modelling assumption. Because it reports by month, it shows the June case directly, which is the case South African clients dispute. When a commissioned system’s shading number is challenged, this is the strongest evidence available.

Pricing. US$2,195 base for North America, roughly ZAR 40,600 before import duty and shipping, as capital equipment rather than a subscription, and the price includes a lifetime PV Designer licence. The 210 is a current product rather than a discontinued one: Solmetric has been a Fluke company since the acquisition announced in September 2023. As of 2 August 2026 it is out of stock with a stated 10 to 12 week lead time, which matters more here because import and clearance sit on top of that.

Honest limitations. It measures points, not arrays, so a large roof needs many captures and interpolation between them. It cannot model a tree at ten-year height or a neighbour’s future second storey. Lead time is currently 10 to 12 weeks and servicing routes abroad. Treat it as an audit instrument, not a design tool.

9. PVGIS Horizon Import

What it does best. The European Commission Joint Research Centre’s PVGIS tool covers South African coordinates and returns a free far-horizon profile derived from terrain elevation, along with irradiance and diffuse fraction data. Export the horizon and import it into PVsyst and the model accounts for the mountain behind the site. In a country with Table Mountain, the Drakensberg, the Magaliesberg and thousands of valley sites, terrain horizon is not a rounding error: a ridge to the north-east can delay first light by an hour in June, which is precisely the recharge window.

Pricing. Free.

Honest limitations. It sees terrain, not buildings or trees. A boundary wall five metres away does not exist in a PVGIS horizon, and on a suburban roof the wall and the neighbour’s oak are the whole problem. Never submit a PVGIS horizon as a shading study; it is one input to a scene.

10. Sunsynk, Deye and Victron Inverter Tooling

What it does best. None of these vendors models shading, and that is not their purpose. What the Sunsynk and Deye portals and Victron’s VRM give you is the measured record: PV input power minute by minute, per-tracker data on Victron, and battery state of charge across every day the system has run. That is how you confirm or refute a shading hypothesis after commissioning. A morning dip on one tracker while the other holds, at the same clock time daily and drifting slowly through the year, is a shadow. A whole-array reduction flat across the day that recovers after rain is soiling.

Pricing. Free with the hardware, which is already installed on most South African hybrids.

Honest limitations. It is entirely retrospective and cannot inform the design decision, which happens months earlier. It will not attribute a loss to a specific obstruction, and the state of charge trace tells you the bank fell short without telling you why. Use it to validate a model, never to replace one. The autonomy arithmetic behind those curves is set out in QBits Energy’s hybrid battery sizing guide, and the battery energy storage system entry defines the terms.

Is a Shading Report Required in South Africa?

Plainly: no. No South African regulation mandates a shading study. SANS 10142-1 governs the wiring installation and the Certificate of Compliance, NRS 097-2 governs grid connection of small-scale embedded generation, and SSEG registration with Eskom or your municipality is required for a grid-connected inverter regardless of export intent. None of those documents asks for a shading analysis. Nothing published by NERSA requires one either. Unlike the UK’s MCS Standard Estimation Method, which defines a shading factor inside a regulated calculation, this is entirely informal practice here and we are not going to pretend otherwise.

What is real is commercial exposure, and in a backup market it bites faster than in a grid-tied one.

• Backup guarantees. If your proposal promises the client rides through a Stage 4 evening block, the shading assumption is what you are underwriting. A single winter month proves or disproves it.
• Lender and DFI review. Commercial and utility-scale finance asks for P50, P75 and P90 yield bands from a recognised engine, with shading as an explicit loss line. PVsyst’s name recognition still carries here.
• Battery warranty claims. An array that repeatedly fails to bring the bank to full charge deepens cycling and shortens life. When the battery underperforms, the shading model is the first document requested.
• Consumer disputes. The commonest complaint on a residential hybrid is that the system “does not last through load shedding”, and it usually surfaces in the first winter, when the sun is 32 degrees up and the shadows are three times longer than at handover.

Market and capacity context for these arguments sits with the IEA and IRENA.

Mistakes South African Design Teams Make on Shading

1. 1
   Inheriting a south-facing template. Arrays face north here and the winter solstice is in June. A mirrored azimuth still produces a plausible annual number, which is why the error survives review.
2. 2
   Surveying in summer and designing from what you saw. At Cape Town's December noon a metre casts 0.19 m of shadow. In June the same metre casts 1.56 m. The site walk is not the shading study.
3. 3
   Reporting an annual shading percentage on a battery system. The client bought backup hours. Report the minimum state of charge on the worst realistic day, with and without the shading.
4. 4
   Treating east and west obstructions as equivalent. On a load-shedding hybrid the morning recharge is the critical window, so an eastern tree costs far more than an identical western one.
5. 5
   Applying one national weather assumption. Cape Town's winter is wet and diffuse, the Highveld's is dry and bright. Use site-specific hourly data and an anisotropic sky model.
6. 6
   Using one row pitch nationally. A 2.28 m module at 30 degrees needs about 3.85 m of pitch in Johannesburg and about 4.47 m in Cape Town. Pitch follows latitude, not a company standard.

Should a South African Team Standardise on SurgePV for Shading?

For most South African rooftop installers the honest answer is one design platform carrying shading, layout and the proposal, plus a single HOMER Pro seat if you sell backup guarantees or size microgrids. One tool answers geometry, the other answers what the geometry does to the battery, and a single product claiming both usually does one of them badly.

How Heaven Green Energy and SurgePV Help

Heaven Green Energy delivers EPC projects in India and provides design support across African hybrid and backup work, and our engineering group builds the software we run. Every hybrid proposal we issue carries a shading heatmap and the backup consequence rather than only an annual percentage, because the backup number is what clients challenge in their first winter. Entry points:

• SurgePV shadow analysis: 8,760-hour module-level shading on pitched tile and flat commercial roofs.
• SurgePV solar simulation: P50, P75 and P90 yield with hourly thermal and diffuse handling.
• Solar EPC services: turnkey delivery and independent review of a disputed shading or backup claim.
• Commercial solar and industrial solar: warehouse and factory rooftop hybrids.
• Heaven Designs guide to reading a solar single-line diagram for the drawing standard your SSEG application depends on.

For the wider decision, read the best solar design software in South Africa ranking, the solar plus storage design software roundup for battery-specific tooling, and the solar shading analysis software pillar for engine mechanics. Choosing solar shading analysis software in South Africa comes down to one test: can it show you the battery’s state of charge on a shaded June morning?

Related Solar Software Guides

• Solar Shading Analysis Software: The Global Guide
• Best Solar Shading Analysis Software in Nigeria
• Best Solar Shading Analysis Software in Australia
• Best Solar Design Software in South Africa
• Best Solar Proposal Software in South Africa
• Best Solar Software in South Africa: The Full Stack
• Best Solar Design Software: The Global Ranking

Frequently Asked Questions

What is the best solar shading analysis software in South Africa in 2026?

SurgePV ranks first for design-side shading at roughly ZAR 24,000 per user per year on the 5-User Team plan. It runs 8,760-hour module-level simulation with bypass-diode physics, handles southern hemisphere geometry natively, builds the near-object scene from satellite imagery in about a minute, and feeds the result into hybrid backup sizing. HOMER Pro from US$1,575 a year on Base, about ZAR 29,000, is the better tool for the question that decides a load-shedding design, which is what the shading does to battery state of charge.

Which way should solar panels face in South Africa?

North. South Africa is in the southern hemisphere, so the sun tracks across the northern sky and a fixed array is oriented toward true north for maximum annual yield. This is the single most common error in design templates imported from Europe or North America, and it survives review because a mirrored azimuth still produces a plausible-looking annual figure. The winter solstice is 21 June, so the shading design case is a June morning, not a December one.

How low is the winter sun in Cape Town?

Lower than most people expect. At 33.9 degrees south, Cape Town’s June solar noon elevation is about 32.6 degrees, so one metre of obstruction height casts 1.56 m of shadow at midday. At 9 am solar time in June the sun is only 18.5 degrees up in the north-east and that same metre casts 3.0 m. The December figure is 0.19 m, roughly one eighth as long, which is why a summer site walk gives a badly misleading impression of the winter shadow map.

Why does morning shading matter more than midday shading on a battery system?

Because of what each one displaces. In a load-shedding hybrid the array has to refill the battery before the next scheduled block, and after an overnight block the bank starts the day well down. Morning kilowatt-hours are recharge kilowatt-hours, so losing them lowers the state of charge at the start of the next outage. Midday kilowatt-hours lost on a system where the bank has already reached full may cost nothing at all. Two arrays with the same annual shading percentage can behave completely differently.

Can an annual shading percentage tell me if the battery will hold through load shedding?

No. An annual figure has discarded the time dimension the answer depends on. To know whether the bank reaches the next block charged you need the shading loss located by hour, the load profile, the outage schedule and a state of charge simulation running together. The correct output is the minimum state of charge across the worst realistic day, with and without the shading, not a single percentage. HOMER Pro produces this natively; hybrid-aware design tools produce an approximation.

Is a shading study legally required in South Africa?

No. SANS 10142-1 covers the wiring installation and the Certificate of Compliance, NRS 097-2 covers grid connection of small-scale embedded generation, and SSEG registration with Eskom or your municipality is required for any grid-connected inverter regardless of export. None of them requires a shading analysis, and nothing published by NERSA does either. The pressure is commercial: backup guarantees, lender loss trees, battery warranty claims and first-winter consumer disputes all turn on the shading assumption.

Should I use the same weather assumptions for Cape Town and Johannesburg?

No. The Western Cape has a Mediterranean climate with a wet, cloudy winter and a high diffuse fraction exactly when the sun is lowest. The Highveld has a dry, bright winter with rain in summer. On a partly shaded Cape Town roof in June, how much sky a module can still see matters more than whether the solar disc is blocked, which makes an anisotropic sky model such as Perez or Hay-Davies important. A national dataset applied in Cape Town will overstate winter yield.

How much does shading analysis software cost in South Africa?

Quote the vendor’s own currency, because that is what you are billed in. PVsyst Professional is CHF 700 per user per year and PV*SOL Premium is EUR 845 per named user per year plus VAT, both cheaper per seat than SurgePV at US$1,299 on the 5-User Team plan. HelioScope is US$1,620 a year on Basic and US$2,640 on Pro. Aurora is US$1,620 a year on Basic and US$2,640 on Premium, with plan sets charged separately. HOMER Pro runs US$1,575 to US$4,650 a year by tier. A Solmetric SunEye 210 is US$2,195 base for North America plus import duty. Scanifly does not publish pricing. PVGIS and inverter vendor monitoring portals are free. At about ZAR 18.5 to the dollar, SurgePV works out near ZAR 24,000 per user per year, but every dollar and euro figure here moves with the exchange rate.