How to Calculate Solar String Size: 2 Worked Examples

Solar string sizing sets how many modules go in series on one string. Two limits bracket it: the maximum, fixed by the string’s open-circuit voltage (Voc) at the coldest expected cell temperature, which must stay under the inverter’s maximum input voltage and the NEC 2023 690.7 voltage ceiling for the occupancy; and the minimum, fixed by the string’s maximum power voltage (Vmp) at the hottest expected cell temperature, which must stay above the inverter’s MPPT window.

Key takeaways

• Cold sets the maximum. Voc rises as cell temperature falls, because the open-circuit voltage temperature coefficient is negative. The limiting case is a cold, clear morning with the array at open circuit.
• Heat sets the minimum. Vmp falls as cell temperature rises. If a hot string drops below the inverter’s MPPT window, the inverter cannot hold the array at maximum power.
• One- and two-family dwellings are capped at 600 volts by NEC 2020 690.7 and NEC 2023 690.7. Other occupancies commonly run to 1000 volts, and NEC 2023 690.31(G) adds requirements above that.
• Design temperatures come from ASHRAE – the extreme annual mean minimum design dry-bulb temperature for the cold case, and the 2 percent cooling design dry-bulb temperature for the hot case.
• Cell temperature is not ambient temperature in the hot case. Add a mounting-dependent rise to the ambient figure and state the assumption on the drawing.
• Round the maximum down and the minimum up. Both worked examples below show every step, with real module and inverter data.

What does string sizing actually decide?

String sizing decides how many modules are wired in series into one input on the inverter. Modules in series add voltage while current stays the same, so the string count is a voltage decision. Get it wrong high and you exceed a listing or a code limit; get it wrong low and the inverter cannot track the array at its maximum power point on the hottest, most productive afternoons.

Every permit-ready set we draw carries the string calculation somewhere the reviewer can find it, because it is the number that ties the module datasheet, the inverter datasheet and the site’s climate data together. It belongs on the electrical sheet alongside the conductor and overcurrent schedule – see what belongs in a permit-ready plan set for where it sits in the package.

Three constraints bound the answer, and all three have to be satisfied at once:

1. The inverter’s maximum input voltage. A hard equipment limit from the datasheet. Exceeding it can damage the inverter and voids the listing.
2. The NEC 2023 690.7 maximum voltage for the occupancy. Set by code, not by the equipment, and lower than most inverter ratings on a house.
3. The inverter’s MPPT voltage window. The range over which the inverter can find and hold the array’s maximum power point. This is the lower bound.

The module’s own maximum system voltage rating is a fourth limit, usually 1000 or 1500 volts, and it rarely governs on a rooftop job. Whichever of the four is lowest is the one you design to. On the solar plan sets we produce for installers, the string range is stated as a range, not a single number, so the field crew has room to work around a shading obstruction without calling for a redesign.

Why does string voltage rise when it gets cold?

A silicon PV cell’s open-circuit voltage has a negative temperature coefficient: voltage goes up as cell temperature goes down. So the highest voltage a string will ever produce is not on a hot summer afternoon – it is on the coldest, brightest morning of the year, at open circuit, before the inverter has started and drawn the array down to its operating point.

This is the single most common misconception in string sizing, and it is worth being precise about. Power output falls in the cold because irradiance is low. Voltage does the opposite. The two move independently, and the code cares about voltage.

Two conditions have to line up for the worst case, and on a clear winter morning they routinely do:

• Cold cells. With no load and no accumulated heat, cell temperature sits at or near ambient. There is no irradiance-driven temperature rise to subtract.
• Open circuit. Before the inverter wakes up, or any time the DC disconnect is open, the array sits at Voc rather than Vmp. Voc is roughly 20 percent higher than Vmp on a modern module even before the temperature correction.

Put those together and a string that measures 500 volts operating on a mild day can present well over 600 volts to the inverter terminals at sunrise in January. That is a conductor insulation question, a disconnect rating question and a listing question all at once, which is why the NEC articles that govern a plan set put maximum voltage in NEC 2023 Article 690 Part II rather than leaving it to the equipment.

The mirror image applies at the bottom. Vmp also carries a negative coefficient, so a string in full sun on a 100-degree day operates meaningfully below its nameplate voltage. That is the condition that sets the minimum. You size for both because they are different days, and both belong in the residential design workflow before anything gets drawn.

What voltage ceiling applies: 600 volts or 1000 volts?

On a one- or two-family dwelling, the PV system DC circuits are limited to 600 volts. That limit is in the parent text of NEC 2020 690.7 and carried forward in NEC 2023 690.7. It is an occupancy limit, not an equipment limit – the same module rated for 1000 volts is capped at 600 on a house and can run to 1000 on a commercial building.

NEC 2020 690.7 states that PV system DC circuits on or in one- and two-family dwellings are permitted a maximum voltage no greater than 600 volts. Multifamily, commercial and industrial occupancies are conventionally designed to 1000 volts, and NEC 2023 690.31(G) adds requirements for circuits operating above 1000 volts. Utility-scale plant is where 1500-volt architecture lives; see utility-scale PV system design for how that changes the rest of the package.

NEC 2020 690.7(A) and NEC 2023 690.7(A) give three permitted ways to calculate the maximum voltage:

1. Sum the series-connected modules’ rated Voc, corrected for the lowest expected ambient temperature using the temperature coefficients in the module’s listing or labeling instructions. This is the method used in both examples below.
2. For crystalline and multicrystalline silicon modules, sum the rated Voc and apply the correction factor from Table 690.7(A). Coarser, and it only covers the ambient ranges in the table.
3. For PV systems of 100 kW or larger, a documented and stamped system design produced by a licensed professional electrical engineer using an industry standard method. That route needs engineering stamps, not a spreadsheet.

Which cycle your authority having jurisdiction enforces matters here, because jurisdictions are spread across several NEC editions and the section numbering has moved. NFPA makes its codes and standards available online to the public for free through NFPA’s free access service, so there is no excuse for citing an article without naming the edition. Write “NEC 2023 690.7(A)” on the drawing, not “690.7”.

Commercial rooftops behave differently for a second reason: the higher ceiling makes strings long, which makes the MPPT window the binding constraint rather than the code limit. That trade-off runs through every set of commercial solar PV designs we draw, and it sits alongside the other commercial plan set fundamentals that separate a C&I set from a scaled-up house.

Where do the design temperatures come from?

From ASHRAE climatic design data, looked up by weather station for the project site. Use the extreme annual mean minimum design dry-bulb temperature for the cold case and the 2 percent cooling design dry-bulb temperature for the hot case. Do not use record lows, and do not use a number someone remembered from another job.

ASHRAE publishes climatic design conditions in Chapter 14 of the Handbook – Fundamentals and through the Weather Data Viewer, covering thousands of stations worldwide. The ASHRAE Weather Data Center is where the tables and the viewer live. Two entries matter for string sizing.

• Extreme annual mean minimum dry-bulb temperature (Tmin). ASHRAE tabulates the mean and standard deviation of the annual extreme minimum and maximum dry-bulb temperatures, plus 5-, 10-, 20- and 50-year return period values. The mean annual extreme minimum is the conventional cold-case input. A conservative designer in a severe climate uses a return-period value instead.
• 2 percent cooling design dry-bulb temperature (Tmax). ASHRAE tabulates cooling dry-bulb at 0.4, 1.0 and 2.0 percent annual cumulative frequency of occurrence. The 2 percent value is the temperature exceeded roughly 2 percent of the 8760 hours in a year – hot, but not freakish, which is what you want for a minimum-string calculation.

The cold case uses ambient directly. At open circuit with no accumulated heat, cell temperature is effectively ambient, which is exactly why NEC 2023 690.7(A) says “lowest expected ambient temperature” rather than lowest expected cell temperature.

The hot case does not. A module in full sun runs well above the air around it, so the hot-case cell temperature is the 2 percent dry bulb plus a mounting-dependent rise (Tadd). Two anchors for that rise: the module datasheet’s NMOT rating, and the Sandia module temperature model, which fits module temperature as an exponential function of plane-of-array irradiance and wind speed with separate coefficients for open-rack, close-roof-mount and insulated-back configurations. A tight flush mount with little standoff runs hotter than an open rack, and an open rack runs hotter than a ground mount in wind. State the rise you used on the drawing. It is an assumption, and assumptions that are not written down get argued about later – one of the recurring themes in the design decisions to settle before you draw.

How do you calculate maximum string size?

Correct the module’s rated Voc up to the lowest expected ambient temperature, then divide the governing voltage ceiling by that corrected figure and round down to a whole module. The governing ceiling is whichever is lowest of the inverter’s maximum input voltage, the NEC 2023 690.7 limit for the occupancy, and the module’s maximum system voltage rating.

Two steps.

Step 1 – corrected module open-circuit voltage:

Voc_max = Voc x [1 + (Tmin – Tstc) x (Tk_voc / 100)]

Step 2 – maximum modules in series:

Maximum string size = floor(V_ceiling / Voc_max)

Variable	What it is	Where it comes from
Voc	Module rated open-circuit voltage at STC, in volts	Module datasheet, STC electrical data
Voc_max	Module open-circuit voltage corrected to the cold design temperature, in volts	Calculated, Step 1
Tmin	Lowest expected ambient temperature at the site, in degrees C	ASHRAE extreme annual mean minimum design dry bulb
Tstc	Cell temperature at standard test conditions: 25 degrees C	Fixed by the STC definition
Tk_voc	Temperature coefficient of Voc, in %/K. Always negative for silicon	Module datasheet, temperature coefficients
V_ceiling	Governing maximum voltage, in volts	Lowest of: inverter max input voltage, NEC 2023 690.7 occupancy limit, module max system voltage

Round down, always. A string that computes to 13.5 modules is a 13-module string. The half module you round away is your margin against a colder-than-design morning.

How do you calculate minimum string size?

Correct the module’s rated Vmp down to the hottest expected cell temperature, then divide the bottom of the inverter’s MPPT window by that figure and round up to a whole module. The MPPT window – not the inverter’s absolute minimum operating voltage – is the number that matters, because below the window the inverter cannot deliver its rated output.

Step 1 – corrected module maximum power voltage:

Vmp_min = Vmp x [1 + ((Tmax + Tadd – Tstc) x (Tk_vmp / 100))]

Step 2 – minimum modules in series:

Minimum string size = ceiling(V_mppt_low / Vmp_min)

Variable	What it is	Where it comes from
Vmp	Module rated maximum power voltage at STC, in volts	Module datasheet, STC electrical data
Vmp_min	Module maximum power voltage corrected to the hot design cell temperature, in volts	Calculated, Step 1
Tmax	Highest expected ambient temperature at the site, in degrees C	ASHRAE 2 percent cooling design dry bulb
Tadd	Cell temperature rise above ambient at full sun, in degrees C. Mounting-dependent	Design assumption, anchored to NMOT and mounting type. State it on the drawing
Tstc	Cell temperature at standard test conditions: 25 degrees C	Fixed by the STC definition
Tk_vmp	Temperature coefficient of Vmp, in %/K. Negative	Module datasheet where published; otherwise the Pmax coefficient as a stand-in
V_mppt_low	Bottom of the inverter’s rated MPPT voltage window, in volts	Inverter datasheet

One caution on Tk_vmp. Most datasheets publish coefficients for Voc, Isc and Pmax but not for Vmp, and the usual stand-in is the Pmax coefficient. That runs slightly optimistic, because Pmax is the product of Vmp and Imp and Imp climbs a little with temperature while Vmp falls. If you want a conservative check, subtract the Isc coefficient from the Pmax coefficient and re-run the minimum. Both examples below are checked that way.

Round up, always. A string that computes to 6.01 modules is a 7-module string.

Worked example 1: a residential string on a cold-climate site

Result: 7 to 13 modules per string is code and equipment compliant, and 12 is the number to draw. At 12 modules the string peaks at 531.4 volts cold – 68.6 volts under the 600-volt dwelling ceiling – and stays inside the inverter’s rated MPPT window across the full temperature range.

Inputs. Module: Qcells Q.TRON BLK M-G2+ datasheet, 440 W model – Voc 39.88 V, Vmp 33.33 V, Isc 13.9 A, Imp 13.2 A, Tk_voc -0.24 %/K, Tk_pmax -0.29 %/K, NMOT 43 degrees C, module maximum system voltage 1000 V. Inverter: SMA Sunny Boy Smart Energy 7.7-US – maximum input voltage 600 V, rated MPP window 180-480 V, minimum/start voltage 60/66 V, 15 A maximum operating input current per MPPT, 30 A maximum short-circuit current per MPPT, one string per MPPT.

Site. A one-family dwelling, flush roof mount. ASHRAE extreme annual mean minimum design dry bulb Tmin = -21 degrees C. ASHRAE 2 percent cooling design dry bulb Tmax = 30 degrees C. Tadd = 30 degrees C for the flush mount, giving a hot-case cell temperature of 60 degrees C. That rise is anchored to the module’s own NMOT rating: 43 degrees C at 800 W/m2 and 20 degrees C ambient is a 23-degree rise, which scales to roughly 29 degrees at 1000 W/m2, and a tight flush mount is at least that hot.

Governing ceiling. Inverter 600 V, NEC 2023 690.7 dwelling limit 600 V, module rating 1000 V. Lowest is 600 V. Note that the module is rated to 1000 V and still cannot be used above 600 V here – the occupancy governs.

Maximum, step 1. Voc_max = 39.88 x [1 + (-21 – 25) x (-0.24 / 100)] = 39.88 x [1 + (-46 x -0.0024)] = 39.88 x 1.1104 = 44.28 V per module.

Maximum, step 2. 600 / 44.28 = 13.55, rounded down = 13 modules. Check: 13 x 44.28 = 575.7 V, under 600. Fourteen would give 620.0 V, over the limit and over the inverter rating.

Minimum, step 1. Vmp_min = 33.33 x [1 + ((30 + 30 – 25) x (-0.29 / 100))] = 33.33 x [1 + (35 x -0.0029)] = 33.33 x 0.8985 = 29.95 V per module.

Minimum, step 2. 180 / 29.95 = 6.01, rounded up = 7 modules. Six modules gives 179.7 V, which lands just under the bottom of the rated window. Re-running with the conservative -0.33 %/K Vmp coefficient gives 29.48 V per module and the same answer of 7.

The check most designers skip. Vmp also rises in the cold. At -21 degrees C, Vmp = 33.33 x 1.1334 = 37.78 V per module. A 13-module string therefore sits at 491.1 V on a cold bright morning – inside the 600 V ceiling, but above the 480 V top of the rated MPP window. A 12-module string sits at 453.3 V, inside the window at both extremes, with a cold Voc of 531.4 V. That is why we would draw 12 and give the crew a 7-to-13 range.

Current check. Imp 13.2 A against a 15 A per-MPPT operating limit, and Isc 13.9 A against a 30 A per-MPPT short-circuit limit. One string per MPPT, so both pass. Size the source-circuit conductors and overcurrent protection to NEC 2023 690.8 and 690.9.

Worked example 2: a commercial string on a 1000-volt inverter

Result: 19 to 23 modules per string clears the hard limits, but only 19 to 21 keeps the string inside the inverter’s rated MPP window at both temperature extremes. Draw 21. The same module that was capped at 13 modules on a house runs 21 on a commercial roof.

Inputs. Same Qcells Q.TRON BLK M-G2+ 440 W module, deliberately – it isolates the effect of the ceiling and the MPPT window. Inverter: SMA Sunny Tripower CORE1 62-US – maximum input voltage 1000 V, rated MPP window 550-800 V, minimum/start voltage 150/188 V, six MPP trackers, 20 A maximum input current per MPPT.

Site. A commercial flat roof, ballasted rack with airflow under the modules. ASHRAE extreme annual mean minimum design dry bulb Tmin = -12 degrees C. ASHRAE 2 percent cooling design dry bulb Tmax = 36 degrees C. Tadd = 25 degrees C for the ballasted rack, giving a hot-case cell temperature of 61 degrees C.

Governing ceiling. Inverter 1000 V, module rating 1000 V, and the occupancy is not a one- or two-family dwelling so the 600 V limit in NEC 2023 690.7 does not apply. Ceiling is 1000 V.

Maximum. Voc_max = 39.88 x [1 + (-12 – 25) x (-0.0024)] = 39.88 x 1.0888 = 43.42 V per module. 1000 / 43.42 = 23.03, rounded down = 23 modules. But look at the margin: 23 x 43.42 = 998.7 V. That clears 1000 V by 1.3 volts, which is not margin – it is a rounding artifact. Twenty-two gives 955.3 V, which is a real design.

Minimum. Vmp_min = 33.33 x [1 + ((36 + 25 – 25) x (-0.0029))] = 33.33 x 0.8956 = 29.85 V per module. 550 / 29.85 = 18.43, rounded up = 19 modules. Eighteen gives 537.3 V, below the window. The conservative -0.33 %/K check gives 29.37 V and the same answer of 19.

The cold-Vmp check narrows it further. At -12 degrees C, Vmp = 33.33 x 1.1073 = 36.91 V per module. A 22-module string reaches 811.9 V on a cold morning, above the 800 V top of the rated MPP window; 21 modules reaches 775.0 V and stays inside it. So the honest answer is 19 to 23 on the hard limits, 19 to 21 if you want the array inside the rated window year-round, and 21 as the design number because longer strings mean fewer homeruns and less combiner work.

Current check. Imp is 13.2 A and the CORE1 allows 20 A per MPPT, so this module supports one string per tracker, not two. Pairing a high-current module with an inverter designed around two lower-current strings per tracker is a common oversight, and it does not show up in a voltage calculation. The same discipline applies on ground-mount plan sets, where longer rows tempt designers into strings the tracker cannot carry.

How many solar panels can go in one string?

There is no single number. Divide the governing voltage ceiling by the module’s cold-corrected Voc and round down – that is the answer, and it moves with the module, the site and the occupancy. The same 440 W module used in both worked examples above tops out at 13 modules on a house under the 600-volt NEC 2023 690.7 ceiling and 23 on a commercial roof under a 1000-volt ceiling.

The design temperature moves it too, and by less than most people expect. Correct that module to a mild coastal Tmin of -5 degrees C and Voc_max is 42.75 V, which allows 14 modules under a 600 V ceiling. Correct it to -21 degrees C and Voc_max is 44.28 V, which allows 13. A 16-degree swing in design temperature costs one module of string length. What it does not do is move the answer by five, so when a rule of thumb and the calculation disagree by that much, it is the rule of thumb that is wrong.

In the residential sets we draw, strings usually land between 8 and 14 modules on a 600 V inverter, and between 16 and 24 on a 1000 V commercial inverter. Treat those as a sanity check, not as a substitute for running the numbers – the calculator above does it in one pass. And remember the maximum is only half the answer. A string also has to be long enough to hold the array inside the MPPT window on the hottest afternoon of the year, which is the constraint that decides whether the design produces what the model promised.

What happens when a string is too short?

A short string does not fail loudly. It underperforms on exactly the days that matter. When hot-case Vmp drops below the bottom of the MPPT window, the inverter can no longer hold the array at its maximum power point, so it operates off-peak and clips output on the hottest, sunniest, highest-production afternoons of the year.

Drop far enough – below the inverter’s minimum operating voltage rather than just the bottom of the rated window – and the inverter drops offline entirely until the array cools or the sun climbs. In the residential example above, the rated window bottoms out at 180 V but the inverter keeps operating down to 60 V, with a 66 V start threshold. The gap between those two numbers is the difference between “producing less than it should” and “not producing at all,” and only the first one is subtle enough to go unnoticed for a season.

The failure is hard to catch after the fact because monthly production looks broadly plausible. It shows up as a shortfall against the modeled yield in July, not as a fault code. That is one reason we cross-check string design against modeled output when a job comes through with production reports attached – a string that is legal but short shows up in the model before it shows up in a customer complaint.

Too long fails the other way, and faster: the plan checker catches it, or the inverter does. An overvoltage string is a correction notice at best, and one of the more avoidable entries in why solar permits get rejected. Run the numbers before submittal rather than after – the same principle behind a proper pre-submittal check, and one of the permitting requirements that catch installers out when a set is copied from one jurisdiction to another.

Does string sizing change with DC optimizers or microinverters?

Yes, and the change is structural rather than arithmetic. On a straight string inverter, cold Voc sets the maximum module count and everything above is the calculation. Add DC optimizers and the optimizers regulate the string, so the count is bounded by the optimizer’s published string limits instead of by a cold-Voc correction. Go to microinverters and there is no DC string at all – the sizing question moves to how many units share one AC branch circuit.

Question	String inverter	DC optimizers	Microinverters
What the count applies to	Modules in series per MPPT input	Power optimizers per string	Microinverters per AC branch circuit
Does cold Voc set the maximum?	Yes. This is the governing calculation	No. The optimizers regulate string voltage; published string length and power limits govern	No. Each module has its own inverter
Does the MPPT window set the minimum?	Yes	Yes, as a published minimum optimizer count per string	No
Does the NEC 2023 690.7 600 V dwelling cap bind?	Usually. It is normally the governing ceiling on a house	Rarely. Regulated string voltage sits well below it	No PV system DC circuit runs beyond the module
Where the limit is published	Inverter datasheet: maximum input voltage and MPPT window	Optimizer datasheet: minimum and maximum string length, maximum power per string	Microinverter datasheet and installation manual: maximum units per branch
What is still sized by hand	Conductors and overcurrent protection to NEC 2023 690.8 and 690.9	Conductors and overcurrent protection to NEC 2023 690.8 and 690.9	The same, on the AC side

The architecture also decides what the reviewer expects to see on the sheet. A string inverter set carries the Voc correction and the design temperatures. An optimizer set carries the string length checked against the optimizer’s published limits. A microinverter set carries a branch-circuit schedule. Putting a cold-Voc table on a microinverter drawing tells the plan checker that the calculation was copied from another job rather than run for this one.

How does string sizing work on a SolarEdge system?

The power optimizers regulate the string, so the cold-Voc correction that governs a straight string inverter does not govern the module count. The string is bounded instead by the optimizer’s published minimum and maximum string length and its maximum nominal power per string. On a single-phase SolarEdge Home Wave inverter, SolarEdge’s own P-series add-on optimizer datasheet puts that at a maximum of 25 power optimizers and 5,700 W nominal per string.

The mechanism is worth stating precisely, because it is what removes the temperature term. Each optimizer takes the DC output of one module and presents a regulated output to the string, so the inverter sees a fixed nominal DC input voltage rather than a voltage that tracks module Voc and ambient temperature. SolarEdge’s North American single-phase Home Wave inverter datasheet gives that nominal DC input voltage as 380 Vdc against a 480 Vdc maximum input. A colder site does not lengthen the cold Voc and therefore does not shorten the string.

The numbers, scoped to the equipment they actually apply to. SolarEdge’s P-series add-on power optimizer datasheet – covering the P370, P401, P404, P485, P500, P505 and P601, document DS-000047-ENG dated July 2023 – gives, for a single-phase SolarEdge Home Wave inverter, a maximum string length of 25 power optimizers and a maximum nominal power per string of 5,700 W, with a published minimum string length that varies by optimizer model. Three phase is a different table on the same sheet: a SolarEdge Home short-string inverter is 20 optimizers and 5,625 W per string. Read the figures off the datasheet for the optimizer and inverter you are actually installing, because they differ by optimizer family, by inverter and by region.

One more figure from the same datasheet changes what goes on the drawing. The safety output voltage is 1 V plus or minus 0.1 V per power optimizer when the string is not connected to an operating inverter, so a 20-optimizer string measures roughly 20 V at the inverter terminals before startup rather than several hundred. That is the number the maximum-voltage note has to reflect, and it changes how the shutdown and disconnect story reads – see PV disconnect placement under NEC 2017 and NEC 2023 for what the boundary and marking requirements ask for in each cycle.

What does not change: the module’s own maximum system voltage rating still applies, the source-circuit conductors and overcurrent protection still have to be sized to NEC 2023 690.8 and 690.9, and the plan checker still expects the string configuration stated on the electrical sheet with the limits it was checked against. A screenshot from a manufacturer’s design tool is not a calculation a reviewer can follow.

How does sizing work with Enphase microinverters?

It does not, because there is no DC string. Each module has its own microinverter, so the only DC circuit is the short run between the module and the unit under it, and no series count has to survive a cold-Voc correction. The sizing question moves to the AC branch circuit. Enphase’s IQ8 installation manual sets the limit at 16 IQ8, 13 IQ8+, 11 IQ8M, 11 IQ8A or 10 IQ8H units on a 20 A branch at 240 VAC, and 9 IQ8H units at 208 VAC.

The published limits, with the document they come from. Enphase’s IQ8 series microinverter installation and operation manual (IOM-00068-3.0-EN) instructs installers to “plan your AC branch circuits to meet the following limits for a maximum number of microinverters per branch when protected with a 20 A (maximum) overcurrent protection device (OCPD).” The table that follows gives 16 for the IQ8, 13 for the IQ8+, 11 for the IQ8M, 11 for the IQ8A and 10 for the IQ8H at 240 VAC, and 9 for the IQ8H at 208 VAC. Check the manual for the family you are installing – the counts differ across the IQ7, IQ8 and IQ8 Commercial lines.

The counts fall as the unit gets bigger because the binding constraint is continuous current, not voltage. NEC 2023 210.20(A) requires the branch-circuit overcurrent device to be rated at not less than 125 percent of the continuous load, which leaves 16 A of continuous output available on a 20 A branch. Divide that by the model’s maximum continuous output current and the unit count falls out. It is the same shape of calculation as a string, with the variables swapped: current instead of voltage, and the branch OCPD instead of the MPPT window.

What replaces the cold-Voc calculation is a compatibility check. The module’s Voc and Isc have to fall inside the microinverter’s DC input window on the datasheet. That is a per-module comparison rather than a series calculation, and it is the step most often skipped when a designer swaps modules late in a job without reopening the microinverter datasheet.

What still has to be drawn: the branch-circuit schedule, the AC conductor and overcurrent sizing to NEC 2023 690.8 and 690.9, and the interconnection calculation at the point of connection. Rapid shutdown reads differently as well, because a microinverter array has no PV system DC circuit running outside the array boundary – but NEC 2023 690.12 still has to be addressed on the drawing rather than assumed satisfied by the architecture.

What manufacturer string sizing tools do not check

Vendor string tools answer one question, and they answer it well: does this string work with this manufacturer’s inverter. Three things they do not do. They do not apply the NEC 2023 690.7 600-volt limit on a one- or two-family dwelling, they do not choose your ASHRAE design temperature for you, and they do not size conductors or overcurrent protection under NEC 2023 690.8 and 690.9. Those three gaps are where plan sets pick up corrections.

Every major inverter manufacturer publishes one. Fronius, SMA, SolarEdge and Enphase all offer a string sizing or system design tool, and they are genuinely useful for what they are scoped to do, which is confirm that a string is compatible with that manufacturer’s hardware. The failure mode is reading a green tick in a vendor tool as a code check. It is an equipment check. Five things it leaves to you:

1. The occupancy ceiling. A vendor tool sizes against its own inverter’s maximum input voltage. It has no way to know the building is a one- or two-family dwelling, and NEC 2023 690.7 caps PV system DC circuits there at 600 volts regardless of what the inverter is rated for. The gap only appears when the inverter is rated above 600 V – which is precisely when it matters.
2. The design temperature. Tools ask for a low temperature or offer a map lookup. They do not decide whether you meant the ASHRAE extreme annual mean minimum design dry bulb, a 50-year return-period value, or the record low somebody remembered. The extreme annual mean minimum is the conventional basis and the one used throughout this page; a record low is not, and substituting it produces shorter strings than the design calls for.
3. Conductors and overcurrent protection. NEC 2023 690.8 sets the circuit current the conductors are sized from, and NEC 2023 690.9 sets the overcurrent protection. A tool that returns “12 modules, within limits” says nothing about PV wire ampacity, the temperature correction for conduit on a hot roof, or the fuse rating in the combiner.
4. The adopted code cycle. Jurisdictions run different NEC editions, and the tool does not know which one your plan checker enforces. Article numbering has moved between cycles, so a calculation that is arithmetically correct is still incomplete if the drawing does not name the edition it was run against.
5. Everything else on the sheet. Rapid shutdown, disconnect placement, labeling, structural attachment and the interconnection calculation are all outside a string tool’s scope – and all of them are inside the plan checker’s.

That is the difference between a string that computes and a set that submits. The same conductor-and-overcurrent discipline runs through the EV charger permit designs we draw under NEC 2023 Article 625, where the load calculation decides the circuit before anything gets drawn, and skipping it sits high on the list of mistakes that get plan sets corrected.

This article is a design reference, not a substitute for the code your jurisdiction has adopted. Confirm the enforced NEC cycle and the equipment listing before you build a string.

FAQ

Get the string calculation checked before it ships

String sizing is a five-minute calculation that costs a review cycle when the design temperature is wrong or the MPPT window was read off the wrong column of the datasheet.

Avila Solar Drafting produces outsourced solar plan sets for installers from Beaverton, Oregon – residential, commercial and utility-scale – with the string calculation, the design temperatures and the NEC cycle stated on the drawing so the reviewer can follow the reasoning instead of guessing at it. Standard turnaround is 2-3 business days, Fast Roof is 1-2 business days, revisions are free for 6 months, and every set is complete, code-compliant and designed to pass first-time review.

Working through an unusual module and inverter pairing? Call 971-410-0655.