Residential Solar Design Workflow: Site to Permit

A residential solar project is won or lost in the design phase. Most change orders, permit rejections and underperforming systems trace back to a decision made before a single panel was ordered. The residential solar design workflow is where accuracy gets built in, or where errors get locked in.

Speed matters as much as accuracy. Cloud PV design software can remove much of the manual layout and modeling work, which decides whether design is a bottleneck or a same-day service when you run many projects a month.

This guide walks through the full solar design process, step by step: site assessment, roof layout, shading analysis, system sizing, string design, electrical design, structural checks, and permit documentation. It also covers the NEC Article 690 and IEC 62446-1 topics that shape each step, plus the mistakes that cause expensive change orders.

Last updated: November 2026. SurgePV publishes this post and sells solar design software. Code and standard requirements change by edition and jurisdiction, so check the standard your authority having jurisdiction (AHJ) has adopted.

In this guide:

• The 7-step residential solar design workflow, with inputs and outputs for each step
• What to collect during the site assessment, and what installers most often forget
• How to run shading analysis and production modeling that survives utility scrutiny
• A worked string-sizing example with cold-weather voltage correction
• NEC Article 690 requirements for rapid shutdown, grounding, and labeling
• Structural and racking checks that keep the AHJ from asking for a PE stamp
• The 8 design mistakes behind most change orders, and how to prevent each one

The Residential Solar Design Workflow at a Glance

Residential solar design is a chain of dependencies. The site assessment defines what the layout can be. The layout defines what shading and production modeling can promise. Production numbers define system sizing, and sizing drives the electrical and structural design.

Break the sequence, and you pay for it later. A roof measured 2 feet short means modules do not fit on install day. A shading model built on satellite guesses means the production estimate in the proposal was fiction. A string sized without temperature correction means a failed inspection in January.

In our experience, rework tends to start in two of these steps: bad site data in step 1 and shallow shading analysis in step 3. The fix is not more engineering hours. It is a tighter process at the front of the chain.

This is also where tooling helps. A single cloud solar software workspace can carry the same project data from the 3D roof model through production simulation to the proposal, so less is re-keyed between steps. Re-keying is where transcription errors, a transposed digit in a module count, a stale derate factor, sneak into plan sets.

Treat the table above as a checklist, not a suggestion. Skip a step, and the AHJ, the utility, or the install crew will find the gap for you.

Step 1: Site Assessment and Data Collection

Design output is only as good as site input. An error in measured roof pitch or azimuth shifts the production estimate, and a missed obstruction can make the shading model wrong. The site assessment is the cheapest place to get things right and the most expensive place to get them wrong.

What to Collect

The Assessment Sequence

1. Pull 12 months of utility bills before the visit. Annual kWh usage is the sizing baseline, and rate structure hints at export compensation.
2. Capture roof geometry. Measure each roof plane’s width, height, and pitch, and record the azimuth, the compass direction the plane faces.
3. Document every obstruction with photos and rough heights. Include off-roof objects like trees and neighboring buildings, not just roof furniture.
4. Inspect the service panel. Record the brand, model, main breaker rating, busbar rating, and count of open breaker slots. Photograph the panel label.
5. Check the attic where accessible. Note rafter size, spacing, span, and condition, this feeds step 6.
6. Record roof age and material. Flag an old roof for a replacement conversation before design proceeds.

Remote assessment works for a growing share of projects. Satellite imagery, LIDAR data, and drone capture can replace the tape measure for geometry, and many utilities release interval usage data with customer consent. The tradeoff: remote data cannot see inside the panel or the attic, so budget a verification visit before the install is scheduled.

Step 2: Roof Layout and Module Placement

Roof layout is a constraint-satisfaction problem. Fire-code setbacks, obstructions, and structural zones carve the roof down to its usable area, and only then does module count become a real number. Start from constraints, not from the roof edge.

Layout Parameters That Govern Placement

The Layout Sequence

1. Draw the roof planes to scale with every obstruction placed. Accurate obstruction positions matter more than pretty graphics.
2. Apply fire-code setbacks and pathways. Verify the local amendment, some AHJs relax ridge setbacks when array coverage stays under a stated threshold.
3. Place modules within the remaining usable zones. Keep rows off hips, valleys, and overhangs.
4. Standardize row lengths where the roof allows. Uniform strings of modules simplify both the electrical design and the install.
5. Choose portrait or horizontal orientation per plane. Portrait fits narrow planes better; horizontal orientation threads between vents on cluttered roofs.
6. Check the module count against the consumption target from step 1. Adjust before moving on, changing the count after string design wastes work.

A practical habit: do not fill every plane to its theoretical maximum. Maxing out the roof leaves no room when the AHJ asks for an extra pathway, the homeowner adds a vent, or a module is discontinued before install. Call the last possible row the change-order row, and leave it out unless the production target needs it.

Cloud design tools shorten this step. SurgePV’s solar design workspace supports 3D roof modeling, solar array layout and bill-of-materials output, so iteration is quicker than a CAD redraw. The designer’s job shifts from drawing to reviewing, and catching the cases where the roof’s reality beats the tool’s assumptions.

Step 3: Shading Analysis and Production Modeling

Shading analysis is where production estimates go to die. A single unmodeled tree can cut a string’s annual yield noticeably, and the homeowner finds out only after the first utility bill arrives. This step separates designs that perform from designs that generate complaints.

What Shading Analysis Must Capture

Shade comes in 2 categories. Near obstructions (chimneys, vents, dormers) cast hard shadows that move across specific modules by hour and season. Far obstructions (trees, adjacent buildings, terrain) reduce solar access, the share of the sky dome visible from the array.

Both reduce the plane-of-array (POA) irradiance that actually reaches the modules. Production modeling converts that irradiance, hour by hour, into kWh. The solar irradiance glossary entry covers the irradiance components (direct, diffuse and reflected) that drive the math.

Three Ways to Measure Shade

1. On-site shade measurement with a dedicated instrument (Solmetric SunEye class). Accurate and fast, but requires a site visit and roof access.
2. Drone capture with photogrammetry. Builds a 3D obstruction model without anyone climbing a ladder.
3. Run a cloud 3D simulation. Tools like solar shadow analysis software render the roof and its surroundings, then compute irradiance losses per module per hour, no site visit required for the first pass.

From Irradiance to kWh

For a first-pass estimate, the PVWatts calculator from the National Laboratory of the Rockies (formerly NREL) estimates the energy output of a grid-connected system for a location. For permit-grade and proposal-grade numbers, run a full 8,760-hour simulation that applies loss factors hour by hour.

PVWatts publishes default values for each loss category on its system losses input page. They are a useful starting point, not a substitute for a site-specific shade model:

When Full 3D Shade Modeling Is Overkill

Here is a tradeoff most guides skip: not every roof justifies a full 3D shade study. A new subdivision with no mature trees, no chimneys, and 8-foot separation to the neighbors has a horizon profile, not a shading problem. A long obstruction model there adds little.

A practical rule: spend modeling time in proportion to obstruction density. If the site photos show nothing above the eave line nearby, a horizon check and a standard loss assumption can suffice. If anything taller than the ridge is visible, model it properly. Off-roof objects such as trees and neighboring structures are easy to miss and can cause the largest production misses.

Step 4: System Sizing and String Design

Sizing answers 2 questions: how many kW of modules the home needs, and how those modules wire into the inverter. Get the first wrong and the system misses its offset target. Get the second wrong and the system fails inspection, or fails on the coldest morning of the year.

Sizing the Array

Start from consumption, not roof area. The core formula:

System size (kW DC) = annual usage (kWh) ÷ specific yield (kWh per kWp)

Specific yield is the annual energy a 1 kW array produces at that site, tilt, and azimuth, your step 3 production model outputs it directly. It varies with region, tilt, azimuth and shading, so take it from your own model.

Worked example, with assumed inputs: a home using 10,500 kWh per year with a modeled specific yield of 1,450 kWh per kWp needs 10,500 ÷ 1,450 = 7.24 kW DC. With 400 W modules, that is 18 modules, 7.2 kW DC.

Inverter Loading and the DC-to-AC Ratio

Designers often pair the array with an inverter somewhat smaller than the DC capacity. The DC-to-AC ratio is array DC capacity divided by inverter AC rating. The array rarely hits its nameplate output, so a smaller inverter can run closer to its peak efficiency for more hours. Check the inverter manufacturer’s allowed maximum DC input.

The tradeoff is clipping: energy lost when DC output exceeds the inverter’s AC ceiling. Model a few ratios and keep the one with better lifetime economics. The generation and financial modeling tool can compare production and payback for each option, so the tradeoff is a number instead of a guess.

String Sizing: The Worked Example

String sizing groups modules into series circuits whose voltage and current stay inside the inverter’s operating window at every temperature the site will ever see. The solar string-sizing calculator guide covers the definitions; here is the process:

1. Find the coldest design temperature for the site and the correction factor for it. Take the factor from the NEC 690.7 temperature table for your code edition, or use the module’s Voc temperature coefficient. This example assumes a factor of 1.14 for illustration only.
2. Compute maximum string voltage: modules per string × module Voc × correction factor. With an assumed 41.5 V module and 12 modules: 12 × 41.5 × 1.14 = 567.7 V.
3. Compare against the inverter’s absolute maximum input voltage and the maximum system voltage your code edition allows for dwellings (check the standard). Assuming a 600 V limit here: at 567.7 V, 12 modules pass, and 13 modules would reach 615 V and fail.
4. Check the hot side: at high cell temperatures, string operating voltage sags. Confirm it stays above the inverter’s minimum MPPT voltage, or the inverter drops out on hot afternoons.
5. Confirm string current against the inverter’s input limit per maximum power point tracker (MPPT), and distribute strings across MPPTs so shaded and unshaded faces do not share a tracker.

Temperature is the silent killer in this calculation. A string that passes at standard test conditions (STC) can fail at the site’s coldest expected temperature, and inspectors in cold climates know where to look.

A Contrarian Take: Stop Designing for Maximum Offset

Conventional wisdom says to size to the whole annual load or above. That advice is aging in markets where exports earn less than retail. Under California’s net billing tariff, the CPUC states that exports are credited at avoided cost values, which are usually lower than import rates, whereas net metering credited exports at the retail rate. In such markets, surplus kWh are worth less than the kWh the home uses itself.

The federal residential clean energy credit is also gone for new systems: the IRS states that it is not available for property placed in service after December 31, 2025. Without that subsidy, every extra kW of capacity must pay for itself through production value alone, and oversized systems push their marginal kWh into low-value export hours. Check your own tariff before you decide.

A reasonable default in low-export-value markets is to size close to the home’s actual load, and reserve roof space for a future battery or a second array when an EV arrives. Design for the load the home has, not the load the sales deck imagines.

Step 5: Electrical Design and Single-Line Diagram

The electrical design converts the physical layout into a code-compliant circuit plan. Its core deliverable is the single-line diagram, a simplified schematic showing every conductor, overcurrent device, disconnect, and connection point from the array to the utility service. Most AHJs and utilities will not review a permit package without one.

What the Single-Line Diagram Must Show

1. Array: module count, string configuration, and per-string wire size.
2. Inverter: manufacturer, model, and maximum continuous AC output current.
3. Rapid shutdown: the initiation method and device location.
4. Disconnects: AC disconnect rating and location.
5. Interconnection: breaker size, location in the panel, or supply-side tap detail.
6. Grounding: equipment grounding conductor sizes and bonding method.

NEC Article 690 Requirements

US residential design lives inside NFPA 70, the National Electrical Code, primarily Article 690 with Article 705 for interconnection. Section numbers below can shift between code editions, so check the edition your AHJ enforces. Three areas generate most permit corrections.

Rapid shutdown under NEC 690.12 requires PV conductors to reduce to a safe voltage within a set time after initiation, with different limits inside and outside the array boundary. The limits depend on the code edition, so read the one your AHJ has adopted. The plan set must show the initiation device location and the rapid shutdown placard required by the code.

Grounding under NEC 690.41–690.47 requires an equipment grounding conductor sized per NEC 250.122 and bonding of all metallic racking. Much modern racking carries a UL 2703 listing that integrates bonding through the rail and clamp hardware. If yours does, show the listing on the plan set to preempt the question.

Labeling closes out the package: the rapid shutdown placard at the service equipment, a power source directory per NEC 705.10 at the interconnection point, and PV source circuit labels along raceways per NEC 690.31(G).

The 120% Interconnection Rule

Many residential systems interconnect with a load-side breaker under NEC 705.12. The commonly applied busbar check, often called the 120% rule, is: panel busbar rating × 1.2 − main breaker rating = maximum solar breaker. Check the standard for the edition in force. As an example of the arithmetic, a 200 A busbar with a 200 A main gives 200 × 1.2 − 200 = 40 A of solar.

That 40 A ceiling is why step 1’s panel inspection matters. A 125 A panel or a full breaker slot count can force a panel upgrade, a supply-side tap, or a smaller system, all cheaper to surface in design than on install day.

Step 6: Structural and Racking Design

The roof is a structure first and a mounting surface second. Racking design proves the array stays attached through wind, snow, and time, and gives the AHJ the calculations to believe it.

Loads and Attachments

A flush-mounted residential array adds dead load that many code-built roofs can absorb, but the roof’s reserve capacity still needs checking. The critical checks are uplift from wind and racking point loads, both calculated per ASCE 7 for the site’s wind speed and exposure category.

Field Rules That Prevent Callbacks

1. Attach to rafters, never to decking alone. Fasteners that miss the rafter are a common cause of pullout failure.
2. Flash every penetration. A missed flashing is a leak claim waiting to happen.
3. Respect the rail manufacturer’s cantilever limits at row ends. Overhanging rails beyond the rated cantilever voids the engineering letter.
4. Keep attachments inside the setback zones from step 2. Fire pathways and attachment rows conflict more often than designers expect.

When You Need a PE Stamp

Some AHJs accept the racking manufacturer’s pre-engineered span tables. Others require a site-specific structural letter when spans exceed table values, the roof uses tile or slate, or the building predates modern code.

Know your AHJ’s threshold before you finish the plan set. Commissioning the PE letter after a rejection adds weeks to the permit timeline, and it is one of the most avoidable delays in residential solar.

Step 7: Permit Documentation and Plan Set

The plan set is the workflow’s final product: the package the AHJ reviews, the utility approves for interconnection, and the install crew builds from. A clean plan set sails through review; a sloppy one enters a correction loop that can double the project timeline.

The Standard Plan Set

The Submittal Sequence

1. Pull the AHJ’s current checklist. Requirements vary by jurisdiction and change without notice, last year’s template fails this year’s review.
2. Assemble the plan set against that checklist, in the AHJ’s preferred order.
3. File the utility interconnection application in parallel. Utility approval and the building permit run on separate clocks.
4. Submit through the fastest channel available. SolarAPP+, managed by the SolarAPP Foundation, automates residential solar permitting and lists 350+ participating jurisdictions on its site. It states that code-compliant applications receive a permit instantly.
5. Respond to corrections within 24 hours. Every idle day in the correction queue is a day added to the install date.

Design data should not die at the permit stage. The same model feeds the customer-facing deliverable, solar proposal tools turns the layout, production numbers, and financials into a branded proposal without re-entering a single value. Once the permit issues, the workflow hands off to operations. Our guide on how to organize a solar panel installation covers the install-day side of the handoff.

One last documentation layer closes the loop after installation. IEC 62446-1 covers documentation, commissioning tests and inspection for grid-connected PV systems, including the information handed over to the customer (see the BSI catalogue entry for BS EN 62446-1). Building that dossier from the design file, rather than reconstructing it in the field, is what separates a professional handover from a folder of loose photos.

Common Design Mistakes That Cause Change Orders

Change orders are design failures that survive to install day. Three mistakes commonly cause resubmits and field changes: incorrect string sizing, missing rapid shutdown labels, and shading analysis that never left the satellite image. All 3 are process failures, not knowledge failures.

Mistake 1: Incorrect String Sizing

This one tops our list because it passes every warm-weather check and fails exactly once, on the coldest morning. The fix costs nothing at design time: apply the NEC 690.7(A) correction factor before the string count is locked.

Design software with a current module and inverter database reduces the arithmetic risk. Check that your tool applies the Voc correction and the MPPT window check against the selected hardware, so an over-voltage string never reaches the plan set.

Mistake 2: Missing Rapid Shutdown Labels

Placards are cheap, and their absence can fail a final inspection and cost a truck roll. The mistake happens because labeling sits at the end of the workflow, where attention is lowest.

Move the label schedule into the plan set template itself. When the labels print with the drawings, the install crew applies them with the drawings.

Mistake 3: Shading Analysis on Autopilot

A satellite image shows where the roof is. It does not show how tall the neighbor’s oak grew since the imagery was captured, and it shows nothing about winter sun angles.

Treat every production estimate as a claim the homeowner will test against their utility bill. If the shade model would not survive that test, redo the model, not after the complaint, but before the proposal.

Residential installers can see how SurgePV supports the design-to-proposal workflow on the page for solar installers. All 8 mistakes share one cure: a standardized workflow with checks at the same points, every project. Speed comes from repetition, and accuracy comes from not trusting memory.

How to Buy Rooftop Solar Design Services

Define whether the assignment stops at a sales layout, produces a permit package, or continues through construction-ready engineering. Give every bidder the same roof survey, obstruction and shading data, electrical-service information, equipment schedule, authority requirements, file-format list, and acceptance checklist.

Request project-matched samples and identify who prepares, checks, and professionally approves structural or electrical work. The written scope should address roof layout, attachment assumptions, stringing, energy-model inputs, electrical diagram, structural information, labels, calculations, native files, revisions, and handover. A remote designer cannot verify concealed roof conditions or replace field measurement; the installer retains site verification and final acceptance unless the contract expressly assigns those duties.

Use the solar permit design services guide for plan-set procurement and the solar CAD design services guide for native-file controls.

Disclosure: SurgePV is promoting Heaven Designs through a commercial relationship. Apply the same sample review, professional verification, paid-pilot, and qualified QA process to every provider.

Review the Heaven Designs rooftop detailed engineering service, visit the Heaven Designs website, and request a project-matched sample before seeking a quote.

Conclusion

The residential solar design workflow is 7 linked steps: site assessment, roof layout, shading analysis, system sizing and string design, electrical design, structural design, and permit documentation. Each step’s output is the next step’s input, which is why errors made early cost the most.

Two disciplines separate fast, accurate installers from the rest. They standardize the workflow so the same checks fire on every project, and they automate the repetitive math (layout, shading, and string voltage) so engineering attention goes to the exceptions.

The business case compounds in both directions. Faster design means same-day proposals, and same-day proposals reach homeowners while they are still comparing quotes, speed wins the deal. Accurate design means the finished system performs as promised, and that performance drives referrals, reviews, and the next 3 installs on the street.

Three actions to take from this guide:

1. Standardize the site assessment. Use the step 1 checklist on every project, and photograph the panel label every time.
2. Automate the middle steps. Move layout, shading, and string sizing into a cloud design tool, and reserve manual review for obstructions, odd panels, and old roofs.
3. Build a pre-submittal checklist. The 8 mistakes in the table above are your first draft, check every plan set against it before the AHJ does.

None of this requires more engineering hours. It requires the same hours applied in the same order, with software carrying the arithmetic and checklists carrying the memory work.

Teams that treat design as a repeatable process, not a per-project craft, find it easier to grow without adding design headcount.

Book a SurgePV demo and bring a real address to design live. Bring a second address if you want to see shading handled on a tree-heavy lot.

Frequently Asked Questions

What is the first step in residential solar design?

The first step is a site assessment covering roof measurements, orientation, tilt, obstructions and the electrical panel. This sets the usable roof area and production potential before any equipment is chosen.

How do you size a residential solar system?

Divide annual electricity use by the modeled specific yield for the site, then adjust for roof space, shading and inverter limits. For example, 10,500 kWh at 1,450 kWh per kWp is about 7.2 kW DC. Use PVWatts or design software to model production.

What is string sizing in solar design?

String sizing groups panels into series circuits so voltage and current stay inside the inverter’s operating window at every site temperature. It uses module Voc, the cold-temperature correction your code edition requires, and the inverter’s MPPT range.

What documents are needed for a solar permit?

Typical permit documents include a site plan, roof plan, single-line diagram, electrical calculations, structural documentation, equipment specifications and a label schedule. Some jurisdictions also require stamped engineering. Pull your AHJ’s current checklist before you assemble the set.

How long does residential solar design take?

It depends on the roof, the tools and how standard your process is, so measure your own baseline per step. Cloud design software can reduce manual layout and modeling work. Track design time per project before and after any tool change.

What is a single-line diagram in solar?

A single-line diagram is a simplified electrical schematic of how panels, inverters, disconnects and the utility connection are wired. Most AHJs and utilities ask for one with a permit or interconnection application.