Sizing AC Cables in a Utility-Scale Solar PV Plant

The US / NEC Method

Power Systems Design  |  Technical Guide, FAQ and Case Studies  |  August 2026

There is a well-circulated infographic on AC cable sizing for PV plants. It lays out four checks — ampacity, voltage drop, derating, short-circuit withstand — and works an example from a 350 kW inverter to a 300 mm² copper cable. The framework is right. The sequencing is right. It is a better starting point than most.



It is also written to IEC practice, and if you carry it onto a US project it will produce conductors that are the wrong material, the wrong size, and non-compliant for reasons the graphic never mentions.

This article rebuilds the whole method on NEC 2023 (with 2026 changes flagged), in AWG and kcmil, with aluminum conductors, at real US inverter voltages — and works two complete examples: a 240 A string-inverter AC output circuit and a 2,500 kVA central inverter block. Along the way we will be specific about what the popular version gets wrong, because two of its errors are the kind that survive design review and show up as a re-pull.

1.  The four checks — and the one that is missing

Any AC conductor in a PV plant has to pass four independent tests. Fail any one and the conductor is wrong, no matter how comfortably it passes the other three.

The popular graphic covers the first three. It omits the fourth almost entirely, and inside the first it omits the single most important number in US PV conductor sizing: 125%.

NEC 690.8(B)(1) requires that PV circuit conductors have an ampacity, before the application of adjustment and correction factors, of not less than 125% of the maximum current determined in 690.8(A). This is the continuous-duty multiplier, and it exists because a PV plant runs at full output for hours at a time — unlike almost any other load on a distribution system.

Skip it and every conductor in your plant is undersized by 25%. There is no derating stack, no cable-tray factor, and no clever conductor material that recovers from that.

Edition note. 690.8(A)(3) is the inverter-output-circuit current rule in the 2017, 2020 and 2023 NEC. The 2026 NEC restructured 690.8(A), and the same rule now sits at 690.8(A)(1)(c). Cite the subsection with its edition, or cite the rule by name.

2.  Step 1 — Design current: use the nameplate, not the power formula

The graphic starts with I = P / (√3 × V × PF). For a motor or a general load, fine. For a PV inverter, the NEC tells you not to.



NEC 690.8(A)(3) (2023): for the inverter output circuit, the maximum current shall be the inverter continuous output current rating. That is a value on the nameplate. You look it up; you do not derive it.

This is not pedantry. Three things go wrong when you compute it instead.

The power factor assumption is usually wrong

The graphic assumes PF = 1.0. Most US interconnection agreements require the plant to operate across a 0.95 leading to 0.95 lagging power factor range for voltage support. An inverter is a kVA-limited device: at 0.95 PF it still pushes its full rated current, it just delivers less real power. If you size the conductor from kW at unity power factor and the plant is later required to run at 0.95, your design current was 5.3% low before you started. See Case Study 3.

The AC voltage is not a single number

A 4,200 kVA SMA Sunny Central UP-US is nominally 630 V but operates across 504–756 V. Current at the low end of that window is materially higher than current at nominal. The nameplate continuous output current rating already accounts for this. Your formula does not.

Inverters derate on temperature

Continuous output at 50 °C ambient is not continuous output at 25 °C. The nameplate rating is defined; a back-calculation from DC nameplate is not.

Get the rating from the datasheet. If the datasheet is not final, do not finalize the cable schedule.

3.  Step 2 — Ampacity: two tests, then a ceiling

US ampacity is a three-part exercise, and the popular guide does only the middle part.

The two-part 690.8(B) test

• 690.8(B)(1) — ampacity, before adjustment and correction factors, ≥ 125% × maximum current
• 690.8(B)(2) — ampacity, after adjustment and correction factors, ≥ maximum current

You compute both and take the larger conductor. On a hot site with heavy derating, (B)(2) can govern. On a cool site in a single conduit, (B)(1) governs. Neither one alone is the answer.

Which table

Table 310.16 — "Ampacities of Insulated Conductors with Not More Than Three Current-Carrying Conductors in Raceway, Cable, or Earth (Directly Buried)," based on 30 °C (86 °F) ambient.

Note the renumbering: Article 310 was reorganized in the 2020 NEC. What older references call Table 310.15(B)(16) is now Table 310.16; 310.15(B)(17) is now 310.17 (free air). Medium-voltage conductors moved out of Article 310 entirely — to Article 311 in 2020, and then to Article 315, "Medium Voltage Conductors and Cable," in the 2023 NEC. Your collector system lives there, not in 310.



Working values for utility-scale PV, Table 310.16, three current-carrying conductors, 30 °C:

The ceiling almost everyone forgets: NEC 110.14(C)

This is the most consequential difference between the graphic and US practice.

The graphic reads ampacity straight off a 90 °C XLPE table and derates from there. In the US you cannot do that, because NEC 110.14(C) requires conductor ampacity to be selected so as not to exceed the lowest temperature rating of any connected termination, conductor, or device.

• Circuits rated 100 A or less, or marked for 14 AWG–1 AWG → 60 °C column, unless the equipment is listed and identified for higher
• Circuits rated over 100 A, or marked for conductors larger than 1 AWG → 75 °C column

Virtually all utility-scale PV AC equipment — breakers, AC combiners, inverter terminals, switchgear lugs — is listed for 75 °C terminations. So:

You may use the 90 °C column as the basis for applying correction and adjustment factors. You may not end up above the 75 °C ampacity.

XHHW-2 aluminum is a 90 °C wet-and-dry conductor. You buy it for the derating headroom, not for the ampacity. A 750 kcmil aluminum conductor is a 435 A conductor for derating math and a 385 A conductor at the lug.

This single rule is why US conductor schedules run larger than an IEC-trained engineer expects, and why "but the cable is rated 90 °C" is the most common losing argument in a US design review.

4.  Step 3 — Correction and adjustment: what counts, and what does no

The graphic multiplies five factors together:

Three separate problems, in increasing order of seriousness.

The arithmetic is wrong. 0.91 × 0.91 × 0.80 × 0.90 × 0.95 = 0.566, not 0.60. A 6% error in the conservative direction, presented as an equality.



Installation method is not a multiplier. In-tray versus in-conduit versus direct-buried determines which table and which column you read. It is not a coefficient you apply on top of a value you already read from the correct table. Applying 0.91 for "in cable tray" to a tray ampacity is double-counting the same physics.

Soil thermal resistivity does not apply to cable in a tray. The example route is explicitly "In Cable Tray." Soil rho is a buried-cable parameter. This factor is simply from a different problem.

And the same double-count logic applies to spacing versus grouping: IEC 60364-5-52 grouping factors are already tabulated by arrangement, including touching. Multiplying a grouping factor by a separate "touching" factor applies the same derate twice.

What the NEC actually gives you

Two factors, and they are cleanly separated. Ambient correction — Table 310.15(B)(1) (for the 30 °C-based tables):

Two traps here. The NEC works in bands, not point values — 44 °C and 41 °C get the same factor. And there are two correction tables: 310.15(B)(1) for the 30 °C-based tables (310.16) and 310.15(B)(2) for the 40 °C-based free-air and medium-voltage tables. They are routinely confused online. Using the wrong one on a desert site is a real error with a real magnitude.

Adjustment for conductor count — 310.15(C)(1), applies to more than three current-carrying conductors:

For a three-phase, three-wire inverter output circuit in its own conduit, there are exactly three current-carrying conductors and no adjustment applies. The EGC is not a current-carrying conductor.

Cable tray is its own rule set

If you are in tray — and in utility-scale PV you often are — the governing section is NEC 392.80, not 310.15(C)(1).

• 392.80(A)(1), multiconductor cables: base ampacity from Table 310.16. 310.15(C)(1) adjustment applies only to cables containing more than three current-carrying conductors, counted per cable — not per tray population. A solid unventilated cover longer than 6 ft imposes 95%.
• 392.80(A)(2), single-conductor cables: base ampacity from Table 310.17 (free air), then in uncovered tray, 75% for 600 kcmil and larger, 65% for 1/0 AWG through 500 kcmil. Single layer, uncovered, with one conductor diameter of maintained spacing, 1/0 and larger: full free-air ampacity.

The tray factors replace the conduit-fill adjustment. Do not stack both. This is the tray version of the same double-counting error the graphic makes.

5.  Step 4 — Voltage drop: not a code check in the United States

The graphic frames voltage drop as a compliance test with a "Typical Limit: 1% to 1.5%" and a green checkmark. In the US that framing is wrong, and the correction is worth understanding because it changes what you optimize.

The NEC does not mandate a voltage drop limit for feeders or branch circuits. The familiar 3% and 5% figures appear in 210.19(A) Informational Note and 215.2(A) Informational Note. Per NEC 90.5(C), informational notes are explanatory and are not enforceable as requirements. No inspector can red-tag a feeder for 4% drop.

Voltage drop becomes enforceable only in specific places — through 110.3(B) where a listing or manufacturer's instructions specify a minimum operating voltage, and through 695.7 for fire pumps.

So why do we still care? Two real reasons, neither of which is compliance.

Inverter operating window. The inverter must stay inside its AC voltage range at full output, and the plant must meet its reactive-power obligation at the point of interconnection. Excessive drop between the inverter and the LV winding of the pad-mount eats into that headroom.

Energy yield. Voltage drop is I²R loss, and in a PV plant that loss runs for 25 years. Design practice targets around 1% total AC cabling loss, with most designs aiming to stay under 1.5%.

In a US PV plant, the code sets the minimum conductor; the loss economics usually set the actual conductor, and it is frequently one or two sizes larger. That is an engineering-economics decision, not a code compliance box.

And do not drop the reactance term

The graphic's formula is correct and better than most:

ΔV  =  √3 × I × L × ( R cos φ  +  X sin φ )

But its worked example sets PF = 1.0, which makes sin φ = 0 and quietly deletes the reactance term. At 0.95 PF — the condition your interconnection agreement is likely to require — the reactance term is real. In Example A below, including it takes voltage drop from 1.18% to 1.47%, a 25% increase, on the same conductor at the same current.

Use NEC Chapter 9, Table 9 for AC resistance and reactance at 75 °C in your actual raceway type. Values differ between PVC, aluminum and steel conduit, and steel is materially worse.

6.  Step 5 — Short-circuit withstand: the US method

The graphic uses the IEC adiabatic criterion, I²t ≤ k²S², and then makes the most quantifiable error on the sheet.

The graphic states: "k = Constant (115 for Cu, 143 for Al)." Both numbers are copper. Per IEC 60364-4-43, Table 43A: copper PVC = 115, copper XLPE/EPR = 143, aluminium PVC = 76, aluminium XLPE/EPR = 94. The aluminium value is not 143 and does not appear on the sheet at all.

The example compounds it. The cable is specified as XLPE, 90 °C — but the calculation uses 115, the PVC value. Correcting to k = 143 changes the answer from S ≥ 217 mm² to S ≥ 175 mm², a 24% overstatement of the required area. Conservative, so nobody gets hurt; wrong, so nobody should copy it.

The North American formula

US practice uses the ICEA P-32-382 form of the Onderdonk equation:

( I / A )²  ×  t   =   K  ×  log₁₀ [ ( T₂ + C ) / ( T₁ + C ) ]



with A in circular mils, I in amperes, t in seconds, and:

Typical temperatures: T₁ = 90 °C (XLPE/EPR continuous rating), T₂ = 250 °C (XLPE/EPR short-circuit limit).

Both forms are adiabatic — they assume no heat escapes into the insulation. That is conservative below roughly 5–10 seconds and increasingly inaccurate above it. Neither should be used for long-duration backup clearing times without a thermal model.

Where the fault current actually comes from

The graphic gives a 25 kA prospective fault current with no source identified, and this matters more in a PV plant than almost anywhere else.

A grid-following PV inverter is a current-limited source. IEEE PES-TR67.r1 models inverter fault contribution at approximately 1.2 per unit; Sandia puts grid-following inverters at 1.2–1.5 p.u. and grid-forming inverters at 2–3 p.u. A 2,400 A inverter contributes on the order of 2,900 A into a bolted fault — not 25 kA.

The 25 kA comes from the grid, backfeeding through the medium-voltage step-up transformer. So the fault current on your inverter output circuit is set by the utility source impedance and the GSU impedance, not by the inverter. Two consequences:

1. Get the number from the system short-circuit study, not from the inverter datasheet.
2. Use the actual protective device clearing time for that fault path, including relay time plus breaker interrupting time. The graphic's t = 1 s is a placeholder; real clearing on a modern AC combiner breaker is closer to 0.1–0.3 s, and the required area scales with √t.
   

7.  Worked Example A — 240 A string-inverter AC output circuit

System. Three-phase, 600 V AC, string inverter with a nameplate continuous output current rating of 240 A. XHHW-2 aluminum in PVC conduit, one circuit per conduit, 400 ft one-way, desert site with 45 °C design ambient, 75 °C-rated terminations at both ends.

Step 1 — Design current

240 A, read from the nameplate per NEC 690.8(A)(3). Not calculated.

Step 2 — Ampacity, test one: 690.8(B)(1)

Required ampacity before correction and adjustment = 1.25 × 240 = 300 A. Because terminations are 75 °C and the circuit is over 100 A, this test is read against the 75 °C column:

500 kcmil Al, Table 310.16, 75 °C = 310 A ≥ 300 A — passes.

Step 3 — Ampacity, test two: 690.8(B)(2)

Required ampacity after correction and adjustment ≥ 240 A. Here we may use the 90 °C column as the derating basis, because the conductor is XHHW-2.

• 500 kcmil Al, 90 °C = 350 A
• Ambient 45 °C, Table 310.15(B)(1), 41–45 °C band, 90 °C conductor: × 0.87
• Conduit fill: three current-carrying conductors → no adjustment

350 × 0.87 = 304.5 A ≥ 240 A — passes.

Now apply the 110.14(C) ceiling. The corrected value, 304.5 A, is compared against the 75 °C termination limit of 310 A. It is lower, so the effective ampacity is 304.5 A. Had the ambient been milder, the answer would have been capped at 310 A regardless of what the 90 °C column said.

Step 4 — Overcurrent protection

The OCPD must be at least 125% of continuous current (300 A) and must not exceed conductor ampacity (304.5 A). A 300 A device satisfies both. Per 240.4(B), the next standard size up would be permitted where the ampacity does not land on a standard rating, up to 800 A — not needed here.

Step 5 — Voltage drop

500 kcmil aluminum in PVC conduit, NEC Chapter 9 Table 9: R ≈ 0.0424 Ω/1000 ft, X ≈ 0.041 Ω/1000 ft at 75 °C. (Sanity check from first principles: ρ_Al ≈ 17.0 Ω·cmil/ft at 20 °C gives 0.0340 Ω/kft, corrected to 75 °C gives 0.0415, plus stranding and skin effect ≈ 0.042. The table value is sound.)

At unity power factor:  ΔV = √3 × 240 × 0.400 × 0.0424 = 7.05 V = 1.18%

At 0.95 power factor, with the reactance term included:  ΔV = √3 × 240 × 0.400 × (0.0424 × 0.95 + 0.041 × 0.312) = 8.83 V = 1.47%

Both acceptable. Note that ignoring reactance would have understated the answer by 25%.

Step 6 — Short-circuit withstand

Available fault current at the AC combiner from the system study: 25 kA, clearing in 0.2 s. Aluminum, T₁ = 90 °C, T₂ = 250 °C:

(I/A)² × 0.2 = 0.0125 × log₁₀(478/318) = 0.0022125    →    A ≥ 25,000 / √(0.0022125 / 0.2) = 237,700 cmil ≈ 238 kcmil

500 kcmil provides 500,000 cmil — better than 2× margin.

Cross-check. 237,700 cmil is 120.4 mm². The IEC method on the same problem gives S ≥ 25,000 × √0.2 / 94 = 118.9 mm². The two methods agree within 1.3% — which is what you would expect, since they are the same adiabatic physics expressed in different units. If your ICEA and IEC answers disagree by more than a few percent, you have used the wrong k or the wrong constants.

Step 7 — Equipment grounding conductor

Per Table 250.122, a 300 A OCPD requires 4 AWG copper or 2 AWG aluminum.

If the ungrounded conductors are later upsized for voltage drop, 250.122(B) requires the EGC to be increased proportionally to the increase in circular mil area — not by AWG steps, and not proportionally to ampacity. Note the nuance: upsizing to compensate for ambient or fill derating under 310.15(B)/(C) does not trigger 250.122(B). Upsizing for voltage drop does.

Result

8.  Worked Example B — 2,500 kVA central inverter block

System. 2,500 kVA central inverter, 600 V AC, feeding the LV winding of a pad-mounted step-up transformer. XHHW-2 aluminum, parallel sets in individual PVC conduits, 40 °C design ambient, 75 °C terminations.

• Nameplate continuous output current: 2,500,000 / (√3 × 600) = 2,406 A
• 690.8(B)(1): 1.25 × 2,406 = 3,007 A required before derating
• Conductor: 750 kcmil Al — Table 310.16: 75 °C = 385 A, 90 °C = 435 A
• Derating: 40 °C ambient, 36–40 band, 90 °C conductor → 435 × 0.91 = 395.9 A. Three current-carrying conductors per conduit → no fill adjustment.
• 110.14(C) ceiling: 395.9 A exceeds the 75 °C limit of 385 A, so the effective ampacity is 385 A per conductor.
• Sets required: 3,007 / 385 = 7.81 → 8 parallel sets
• Verify: 8 × 385 = 3,080 A ≥ 3,007 A and ≥ 2,406 A
• Overcurrent protection: a 3,000 A device. Per 240.4(C), for OCPDs rated over 800 A the conductor ampacity must be equal to or greater than the device rating — there is no next-size-up allowance. 3,080 A ≥ 3,000 A.

Parallel conductor rules — NEC 310.10(G). Conductors 1/0 AWG and larger may be paralleled, but every set must be the same length, material, size, insulation type, and terminated in the same manner. On a 2,500 kVA block that is eight sets of three conductors plus EGCs — 24 phase conductors that must all match. Length mismatch between sets causes current sharing imbalance, which is a thermal problem long before it is an electrical one.

Reality check. A published US design for a 2,500 kVA inverter block landed on nine sets of 750 kcmil aluminum at 75 °C. Our eight-set answer differs because of ambient and voltage assumptions — which is exactly the point. The method is deterministic; the inputs are where projects diverge. Document your ambient, your terminations, and your inverter nameplate, and the review is short.

Figure 1, on the following page, summarizes the whole method: the circuit and which rule governs each segment, the three ampacity rules, the eight-step sequence, both worked examples, the NEC tables, and the errors to avoid.

FIGURE 1  —  AC cable sizing for utility-scale solar PV, US / NEC method: circuit segments, the three ampacity rules, sizing sequence, worked examples and tables

9.  Nine things worth correcting in the popular guides

1. IS 10262 is a concrete standard. The reference list cites "IS 10262" among the derating factor standards. *IS 10262 is the Bureau of Indian Standards guideline for Concrete Mix Proportioning. It has nothing to do with cables. The Indian cable standards are IS 1554 (PVC), IS 7098 (XLPE), and IS 3961* (current ratings). On a US project none of them apply anyway.

2. The k values are both copper. "115 for Cu, 143 for Al" — 115 is copper PVC, 143 is copper XLPE, aluminium XLPE is 94. Correcting the worked example from k = 115 to the appropriate XLPE value moves the answer from 217 mm² to 175 mm².

3. The derating product is 0.566, not 0.60.

4. Installation method is not a derating factor. It selects the table.

5. Soil thermal resistivity does not apply to a cable in a tray.

6. The 125% continuous-duty multiplier is missing. NEC 690.8(B)(1). This is the largest single omission for a US reader.

7. Terminal temperature limitation is missing. NEC 110.14(C). Reading 90 °C ampacity straight to a 75 °C lug is the most common ampacity error in US practice, and it is invisible until the thermal scan.

8. Design current should come off the nameplate. NEC 690.8(A)(3). And the PF = 1.0 assumption hides the reactive-power obligation most US plants carry.

9. Voltage drop is not a US code check. It is an informational note. Which means the real target is not 1.5% — it is whatever the 25-year loss economics and the inverter operating window justify.

What the graphic gets right, and should get credit for: the four-check framework in the correct order, the full voltage drop formula including reactance, the reminder that ampacity tables are reference-only and manufacturer data governs, and the closing line — good cable sizing is about safety, efficiency, reliability and economy, not just current rating. That is exactly right, and it is the part most engineers skip.

10.  Design checks that catch real problems

Conductor material. US utility-scale PV AC collection is overwhelmingly aluminum, not copper. Aluminum is roughly twice as conductive per pound, and at commodity ratios near 4:1 the cost case is not close. AA-8000 series compact-stranded aluminum has been the code-recognized standard since 1972. A copper-only worked example is not representative of how these plants are actually built.

Conductor listing voltage

Most building wire is listed to 600 V. At 630, 660 or 690 V inverter output — all common on 1500 Vdc central inverters — you are above that and need conductors and terminations listed for 1000 V. Note that the NEC's low-voltage boundary moved from 600 V to 1000 V ac / 1500 V dc across the 2014–2017 cycles, and in the 2023 NEC the over-1000 V equipment rules live in the new Article 495. So 690 V does not put you into the medium-voltage chapters — but it does put you outside standard 600 V-listed wire. These are two different constraints and they are frequently conflated.

Article 691 applicability. NEC Article 691, "Large-Scale Photovoltaic (PV) Electric Supply Stations," applies to facilities with a generating capacity of not less than 5,000 kW and not under exclusive utility control. Generating capacity here is read as the sum of inverter continuous AC output at 40 °C, not DC nameplate. Above that threshold, engineered designs stamped by a licensed PE can substitute for certain prescriptive requirements — which changes what you have to prove and to whom.

Medium-voltage collector is a different article. The 34.5 kV collector system is governed by Article 315 in the 2023 NEC (Article 311 in 2020), with its own ampacity tables and its own 40 °C-based correction table. Do not carry Table 310.16 or Table 310.15(B)(1) into the collector design.

Conductor type on the AC side. XHHW-2 aluminum is the workhorse — 90 °C wet and dry, UL 44, tray-rated at 1/0 AWG and larger. PV Wire and USE-2 are DC-side conductors under NEC 690.31(C); they do not belong on an AC circuit.

Terminations and torque



Aluminum terminations require listed connectors, an oxide-inhibiting compound where specified by the listing, and calibrated torque per 110.14(D). More aluminum conductor failures trace to the termination than to the conductor.

11.  Anonymized case studies

The following are anonymized and composited from typical engagements. Figures are representative of the scenarios described and have been rounded and adjusted; they do not identify any specific client or facility.

Case Study 1 — Desert Southwest, 200 MWac: the 30 °C assumption

Situation. An EPC submitted the AC cable schedule for a 200 MWac single-axis-tracker project in southern Arizona. Conductor sizes had been carried over from a prior project of similar block size in the upper Midwest.

What the analysis found

Every inverter output circuit had been sized against Table 310.16 with no ambient correction applied. The 30 °C table basis had been treated as the site condition. Recorded design ambient at the site was 45 °C in the conduit environment, and above-grade conduit in direct sun runs hotter still.

Applying Table 310.15(B)(1) at the 41–45 °C band — a 0.87 factor on the 90 °C column — moved a substantial fraction of the blocks below their required post-derating ampacity. Roughly a third of the AC circuits needed one size up. The conductors would not have failed immediately; they would have run continuously above their rated insulation temperature every summer afternoon, aging the insulation on a curve nobody was tracking.

What was done

The schedule was rebuilt with the correct ambient band, and the design ambient was pinned in the basis of design so it could not be silently inherited again. Circuits were reviewed for the 110.14(C) ceiling at the same time, which caught a separate set of blocks where the 90 °C column had been used at 75 °C lugs. Conductor cost rose about 4% on the AC scope. The change was made in design, before procurement.

Engineering takeaway

An ampacity table is a statement about a thermal environment, not about a conductor. A conductor schedule that travels between climates without its ambient assumption travelling with it is a latent defect.

Case Study 2 — Northeast, 20 MWac: the 90 °C conductor at the 75 °C lug

Situation. A 20 MWac project reached AHJ review with a complete, internally consistent AC design. The inspector flagged the inverter output conductors.

What the analysis found

The designer had specified XHHW-2 aluminum and sized every circuit from the 90 °C column of Table 310.16 — correctly noting that XHHW-2 is a 90 °C wet-and-dry conductor. But all the AC combiner breakers, inverter terminals and switchgear lugs were listed for 75 °C terminations. Under NEC 110.14(C)(1)(b), circuits over 100 A must be sized from the 75 °C column.

The gap between the two columns is roughly 13% at these sizes — a 750 kcmil aluminum conductor is 435 A at 90 °C and 385 A at 75 °C. Across the plant, that put a meaningful number of circuits one size undersized against the termination limit.

What was done

The circuits were resized against the 75 °C column, with the 90 °C column retained only as the derating basis. Because conductors were upsized for a code requirement under 110.14(C) rather than for voltage drop, 250.122(B) did not require the EGCs to be increased proportionally — a distinction worth several thousand dollars of copper on a plant this size, and one that is frequently applied incorrectly in the conservative direction.

Outcome

The design cleared review on resubmittal. Because the issue was caught before the conductors were pulled, the cost was engineering hours rather than a re-pull.

Engineering takeaway

The conductor's temperature rating and the circuit's usable ampacity are two different things, and the equipment decides which one you get. If you cannot name the termination temperature rating of every device on a circuit, you cannot yet state its ampacity.

Case Study 3 — ERCOT, 150 MWac: sized in kilowatts, operated in kilovolt-amperes

Situation. A 150 MWac project completed detailed design with the AC collection sized from block real power at unity power factor. Late in the process the interconnection agreement was finalized, requiring the plant to maintain 0.95 leading to 0.95 lagging power factor at the point of interconnection across its operating range.

What the analysis found

The design current for every inverter output circuit had been computed as P / (√3 × V × 1.0). Meeting a 0.95 power factor obligation at full real power output requires the inverters to be sized and operated on kVA, not kW — which raised continuous output current by a factor of 1/0.95, or 5.3%, above the value the cable schedule had been built on.

On its own, 5.3% is inside most conductors' margin. Stacked on top of the 125% continuous multiplier and a summer ambient correction, it pushed a set of circuits past their limit — and it also degraded voltage drop, because the reactance term that vanishes at unity power factor becomes significant at 0.95. On the longest runs, calculated drop went from about 1.2% to about 1.5%, tightening the inverter's AC operating window exactly when it was being asked to produce reactive power.

What was done

Design current was re-established from inverter nameplate continuous output current, per NEC 690.8(A)(3), rather than from a power calculation. Voltage drop was recomputed with the full R cos φ + X sin φ expression at 0.95 PF. Circuits on the longest runs were upsized one size — and because that upsize was for voltage drop rather than for derating, 250.122(B) did require the EGCs to be increased proportionally to circular mil area.

Outcome

The revision touched approximately 15% of the AC circuits and was absorbed in design. The reactive-power obligation was verified against the corrected operating window before the interconnection studies were finalized.

Engineering takeaway



An inverter is a kVA machine, and the interconnection agreement decides how much of that kVA is real power. Sizing conductors from kW at unity power factor builds a plant that is correct only on the days it is not asked to support voltage.

12.  Frequently asked questions

13.  Standards reference

Closing



The four-check framework in that infographic is sound, and anyone using it is ahead of an engineer who sizes conductors by ampacity alone. The problem is not the method. The problem is that the method was assembled from one code family and is being applied in another, and the two do not disagree politely — they disagree by 25% on the continuous-duty multiplier and by 13% at the lug.

On a US utility-scale PV project the conductor schedule is one of the largest single material line items on the AC scope, and it is also one of the least forgiving. Undersize it and you get insulation aging you cannot see and losses you pay for every day for 25 years. Oversize it uniformly and you have spent money that had better returns elsewhere in the plant.

At Keentel Engineering, AC and DC collection design, cable schedules, short-circuit and arc-flash studies, and POI interconnection engineering are delivered together, because they are the same problem viewed from different angles. If you have a cable schedule to review, an ambient assumption you inherited, or an interconnection requirement that just changed your design current, we would be glad to look at it.

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Engineering note: NEC section numbers are given for the 2023 edition unless otherwise stated, with 2020 and 2026 differences flagged where they exist. Confirm against the edition adopted in your jurisdiction. Ampacity values are from NEC Table 310.16 and are reproduced for illustration; design from the code book. Nothing here substitutes for a project-specific engineering design.