Key takeaways
- Most rework traces to four site-visit inputs: obstruction heights, rafter size and spacing, the printed busbar rating, and the adopted code cycle.
- Structural capacity resolves against ASCE 7-16 or ASCE 7-22 – different editions, different wind maps.
- On a 200 A busbar behind a 200 A main, NEC 2023 705.12(B)(3)(2) caps you near 7.6 kW of AC.
- Roof access pathways and ridge setbacks come from IFC 2021 Section 1205 — Section 1204 in the 2018 edition — and IRC R324, not the NEC.
- Jurisdictions are spread across several NEC editions, adopted state by state and sometimes county by county. Every code note names its cycle.
- Standard PV plan sets return in 2-3 business days, Fast Roof in 1-2.
What determines whether a solar design succeeds?
A solar design succeeds when the site data behind it is complete and the electrical and structural math holds under the code cycle the AHJ actually adopted. Failures rarely start in the drafting. They start with a missing rafter dimension, an unverified busbar rating, or a setback pulled from the wrong code year. Capture the right twelve inputs and the drawings follow.
These are the twelve solar project design considerations we run against every intake. Each one lands on a sheet in the solar plan sets your crew builds from.
1. What does a real shade analysis have to capture?
A shade analysis is not one percentage you paste into a proposal. It is a per-plane record of what blocks the sun and when. Capture the height and offset of every obstruction that can shadow an array plane: chimneys, plumbing vents, satellite mounts, parapets, HVAC curbs, the neighbor’s firs. Photograph each against a known reference so the drafter can scale it, and work the visit from a solar site survey checklist rather than from memory.
Aurora Solar’s documentation defines solar access as the incident solar energy given shading divided by the incident solar energy if there were no shading – an hourly ratio computed against local weather data, not an annual average. That matters when one vent pipe clips a source circuit for two hours in December and drags the string down.
Report solar access per roof plane, not per system, and note which module rows an obstruction touches. Send measured azimuths and pitches, not estimates off a satellite image. When production has to be modeled rather than eyeballed, shade and production reports are a separate deliverable and belong in the same order as the design.
2. Will the roof carry the array?
The roof carries the array when the framing, the attachment pattern and the governing load case check out against the ASCE 7 edition your code cycle references. Capture rafter or truss size, spacing on center, clear span, species and grade where you can get it, and the existing dead load – including any second layer of composition shingle already up there.
IronRidge’s XR10 flush mount certification shows how the numbers resolve. It certifies allowable rail spans against ASCE/SEI 7-16 and the 2018 IBC, running roughly 29 to 89 inches depending on design wind speed (90 to 180 mph), exposure category B, C or D, roof zone, ground snow load (0 to 120 psf) and roof slope. Change the exposure category and the span table changes with it.
Name the edition on the sheet. ASCE 7-16 and ASCE 7-22 use different wind maps and snow provisions; 2021 IBC jurisdictions reference 7-16, 2024 IBC jurisdictions reference 7-22. Where the load case is marginal, structural PE stamps close the question – not a screenshot from a racking configurator.
3. How much system does this customer actually need?
Size from measured consumption, then adjust for what is coming. Pull twelve months of billed usage and, where the utility offers it, interval data. NEC 2023 220.87 lets you determine an existing dwelling’s load from the highest recorded 15-minute demand over the previous twelve months – the same data that tells you whether the service has any headroom left.
Then ask what changes in three years. A heat pump, a second EV, a shop subpanel or a hot tub each move the load calculation, and any can move the interconnection method. Write the answers on the intake form at the site visit, because the drafter cannot infer them and a reviewer will not accept a load calculation that ignores a circuit visible on the plan.
Undersizing costs a change order. Oversizing past what the busbar or the utility tariff allows costs a redesign. Both are decided here, before layout. Standardizing what sales collects at signing is the cheapest fix available, and our notes on streamlining residential design intake cover which fields matter most.
4. What does this AHJ and utility actually require?
Two reviewers, two rulebooks, and either one can stop the job. The AHJ reviews the design against the building, fire and electrical codes it has adopted. The utility reviews it against its interconnection tariff, which governs disconnect access, metering, export limits and labeling. A set that satisfies one and not the other is not finished.
Capture six things before design starts: the adopted NEC cycle, the adopted building and fire code editions, whether a separate structural submittal or PE stamp is required, whether the utility wants a lockable AC disconnect within sight of the meter, the service voltage and configuration, and the placard standard the inspector expects. What clears review in Beaverton is not what clears it two counties over, and the solar permitting nuances that separate them are set locally rather than nationally.
One scope note: Avila Solar Drafting does not take projects in APS and SRP jurisdiction in Arizona, City of Peoria, AZ, City of Phoenix, AZ, or Los Angeles County (LABD), CA. Everywhere else, name the jurisdiction at intake and we build to it. For a second set of eyes before a package goes over the counter, our pre-submittal review checklist is the one we use internally.
5. Do the components work together on paper?
Compatibility is a calculation, not a chart. NEC 2023 690.7(A) sets maximum PV system voltage from the module’s rated open circuit voltage corrected to the lowest expected ambient temperature at the site. Get it wrong and an array that ran fine in September faults the inverter on the coldest morning of the year.
SolarEdge’s system design guidance for NEC installations walks the same correction with a 1.25 factor at ambient temperatures of -36 to -40 F, and notes that in an optimized string the binding constraint is the power optimizer’s 60 Vdc maximum input, not the series module count. Different topology, different limiting number – which is why the inverter gets chosen before the layout is locked.
Check four pairings: module Voc against inverter maximum input voltage at record low temperature, module Isc against maximum input current, DC-to-AC ratio against clipping behavior, and rapid shutdown under NEC 2023 690.12, which requires controlled conductors inside the array boundary to drop to 80 V or less within 30 seconds. The string sizing math surfaces most of these first.
6. Where does the array tie into the service?
The interconnection is settled when the busbar math passes on paper. Photograph the panel directory and the busbar rating label – the printed rating, not the main breaker size. Then run NEC 2023 705.12(B)(3)(2): 125 percent of the inverter output circuit current plus the rating of the overcurrent device protecting the busbar cannot exceed 120 percent of the busbar ampacity. The 125 percent factor applies to the inverter current; the 120 percent applies to the busbar.
Worked example. A 200 A service, 200 A main breaker, 200 A rated busbar. The customer wants 7.6 kW of AC.
- Inverter continuous output: 7,600 W divided by 240 V = 31.7 A
- Backfeed breaker sized at 125 percent of continuous output per NEC 2023 690.8(B): 31.7 A x 1.25 = 39.6 A, so a 40 A breaker
- Busbar check per NEC 2023 705.12(B)(3)(2): 120 percent of the 200 A busbar = 240 A. The 200 A main plus the 40 A backfeed breaker is 240 A – exactly at the limit. It fits, with zero headroom.
Zero headroom has a cost. Any battery, EV charger or heat pump added to that panel later will not fit without a different interconnection method or a service upgrade. Take the same panel to 11.4 kW and it fails on the spot: 11,400 W divided by 240 V = 47.5 A continuous, 59.4 A at 125 percent, so a 60 A backfeed breaker. The 200 A main plus 60 A is 260 A against the same 240 A limit.
Three options remain: derate the main to 175 A (175 A + 60 A = 235 A, passes), go supply-side under NEC 2023 705.11, or upgrade the service. Two change your scope and your price. Catching that at design costs an email; catching it on install day costs a crew day, and it sits near the top of the reasons permits get rejected.
7. Does the layout meet fire access and pathway rules?
Fire access requirements come from the fire and residential codes, and they take area from the array before any production optimization happens. Draw the pathways first, then fill what is left.
Leon County, Florida’s building department publishes a summary of IRC 2020 Section R324.6 roof access requirements: not fewer than two pathways on separate roof planes, each at least 36 inches wide, running from the lowest roof edge to the ridge, plus a 36-inch pathway serving each roof plane with an array. Ridge setbacks are 18 inches where the array covers 33 percent or less of the roof and 36 inches above that; with sprinklers those thresholds move to 66 percent. Roofs sloped 2:12 or less are exempt.
That is model language. Your jurisdiction may still be on the 2018 IFC, where the same rules sit at Section 1204, or may amend either edition by state amendment, so confirm the adopted edition. When pathways take enough roof that the array no longer covers the load, the answer is often to move it off the roof – ground mount plan sets carry their own foundation, trenching and array boundary details.
8. Is storage or EV charging in scope?
Storage and EV charging are separate code articles, separate submittal content and often separate permits. Decide at design whether they are in scope, because retrofitting them into an approved set means resubmitting.
For batteries, capture which loads move to the backup panel and what they draw, then confirm the mounting location works. NEC 2023 Article 706 governs the energy storage system and its disconnecting means, while IRC R328 and NFPA 855 govern where the unit can sit relative to habitable space and how much aggregate energy a dwelling is allowed. Garage wall versus bedroom wall is a code question, not a customer preference.
For EV charging, the branch circuit is sized as a continuous load under NEC 2023 625.41, and NEC 2023 625.42 permits an energy management system to cap the charger’s demand where the service cannot absorb a full 48 A circuit. That provision is often the difference between a charger and a service upgrade. We draw these standalone too, so EV charger permit designs can be ordered with the PV set or on their own.
9. Will the design still work in five years?
Future capacity is a decision made once, at almost no cost during design, and an expensive one to add later. Ask the customer what phase two looks like and leave room for it on the drawings.
Three cheap moves. Leave a spare two-pole space at the correct end of the busbar so a future backfeed does not force a rework of the interconnection. Size raceways with fill headroom rather than to the minimum – NEC 2023 Chapter 9, Table 1 caps fill at 40 percent for three or more conductors, and running near that limit turns a future conductor pull into a conduit replacement. Lay out the first array so a second string lands on a plane with comparable azimuth instead of orphaned on a north face.
The same discipline lets a residential crew take on its first 100 kW rooftop without rebuilding its process. If that is where your book is heading, commercial plan sets add structural framing plans, equipment pads and often a switchgear sheet on top of everything above.
10. Which code cycle governs, and does it need a stamp?
Name the cycle or the citation is worthless. Jurisdictions across the United States are spread across several NEC editions, adopted state by state and sometimes county by county. A rapid shutdown note citing the wrong cycle reads to a reviewer as a set that was copied rather than drawn.
| What you are drawing | Section that governs it |
|---|---|
| Rapid shutdown and array boundary | NEC 2023 690.12 |
| Maximum PV system voltage | NEC 2023 690.7 |
| Busbar and backfeed limits | NEC 2023 705.12(B)(3) |
| Supply-side connection | NEC 2023 705.11 |
| Roof access and ridge setbacks | IFC 2021 1205 (1204 in the 2018 edition) / IRC R324 |
| Wind, snow and seismic loads | ASCE 7-16 or ASCE 7-22 |
Stamps follow a different trigger. Some jurisdictions require a structural PE stamp on every rooftop array, some only above a load threshold or on ballasted roofs, some require an electrical stamp on commercial work. Confirm at intake, not at submittal. Our breakdown of NEC solar and storage requirements tracks which articles moved between cycles, which is usually where the surprise lives.
11. Can your crew build it from the drawings?
A set a reviewer approves but a crew cannot follow has only moved the problem downstream. These are construction documents, not exhibits, and the test is simple: can a foreman who has never seen the site stage the day from them without calling the designer?
- A dimensioned site plan with array, setbacks, pathways and equipment locations tied to a real datum.
- Attachment layout with spacing, rail spans, and the specific flashing and fastener called out by part number.
- A three-line diagram showing conductor sizes, insulation type, conduit sizes, OCPD ratings, grounding and bonding.
- A placard schedule with exact label text and the mounting location for each one.
- Structural details for the roof assembly actually on site, not a generic detail block.
Ambiguity on a sheet becomes a phone call from the roof, and that call becomes a field change that no longer matches the set the AHJ approved. That is how an as-built diverges from a permit. Complete solar engineering plans carry every one of those items as a matter of course.
12. Is the package actually ready to submit?
A package is ready when every claim on the sheets is supported by something else in it: the load calculation matches the equipment schedule, the schedule matches the three-line, the three-line matches the placards, and the site plan matches the photographs. Reviewers check consistency before they check code.
Automated review is spreading and it does not remove that requirement. The U.S. Department of Energy describes SolarAPP+ as a web-based platform operated by NREL that runs automated code compliance checks on eligible residential solar and solar-plus-storage permits, while more technically complex systems are re-routed for manual review. In either lane the underlying design still has to be correct and internally consistent. The automation checks the design; it does not fix it.
Build the package once, completely, and the resubmittal cycle stops eating your calendar. Avila Solar Drafting produces standard PV plan sets in 2-3 business days and Fast Roof sets in 1-2 business days from a complete intake, designed to pass first-time review, with six months of free revisions and our guarantee of accurate solar plan sets.
FAQ
What should I check before designing a solar system?
Six site-visit items: obstruction heights and azimuths per roof plane, rafter size and spacing, the busbar rating off the panel label, twelve months of usage data, the adopted code cycles, and the utility’s labeling rules.
What are the most common solar design mistakes?
Busbar math run against the main breaker rating instead of the printed busbar rating, string voltage checked at average low temperature instead of record low, fire pathways drawn after the array, and code notes citing an unadopted cycle.
How do I know which NEC code cycle applies to my project?
Adoption is set by the state or local jurisdiction, not by the publication date. Jurisdictions are spread across several NEC editions, and a county can trail its state. Ask the building department.
How much solar can a 200 A panel take without a service upgrade?
On a 200 A busbar behind a 200 A main breaker, NEC 2023 705.12(B)(3)(2) caps the main breaker plus the backfeed breaker at 120 percent of the busbar, or 240 A. The 200 A main leaves 40 A, and a 40 A backfeed breaker carries 40 / 1.25 = 32 A continuous – about 7.6 kW at 240 V.
When does a solar project need a structural PE stamp?
It depends on the jurisdiction and the load case. Common triggers are ballasted flat roofs, ground mounts, undersized framing, high wind zones and commercial buildings.
How long does an outsourced solar plan set take?
Avila Solar Drafting delivers standard PV plan sets in 2-3 business days and Fast Roof sets in 1-2, from a complete intake. Incomplete site data is the main cause of delay.
Hand the drafting to a team that works from the code
If design is the bottleneck between a signed contract and a scheduled install, the fix is capacity you do not have to hire. Send the site data above and we return a permit package built to your AHJ’s adopted code cycle.
Standard PV plan sets in 2-3 business days, Fast Roof in 1-2, six months of free revisions, and our guarantee of accurate solar plan sets.
Or call 971-410-0655
