Overcurrent Protection Coordination in Solar PV 2026: Fuse-Breaker Selective

A single mis-sized fuse can take a 5 MW solar plant offline for a day. That is the lesson every electrical engineer learns the first time they sit through a forensic review after a combiner box clears upstream instead of at the string. Overcurrent protection coordination is the discipline of making sure that never happens. It is the engineered selection of fuses and breakers so that the device closest to a fault clears it first, leaving every other circuit producing.

This guide covers selective coordination for solar PV systems in 2026. It starts at the module, walks through the combiner, the inverter, and the AC tie, and explains how to read time-current curves, apply the 2:1 ratio, and avoid the common mistakes that fail at plan review. Every example uses current NEC 240 and 690 references, and the data tables come from published manufacturer curves and IEEE 242 Buff Book guidance.

In this guide:

• The four-level OCPD hierarchy in solar PV
• NEC 240 coordination rules with article-by-article references
• Reading time-current curves for fuse and breaker selectivity
• The 2:1 ratio for fuse-to-fuse coordination
• Current-limiting fuses ahead of molded-case breakers
• Series-rated breaker combinations and when they fail
• Inverter internal protection vs external OCPD
• When coordination studies are required and who pays for them
• The seven most common coordination mistakes
• Software tools for time-current curve plotting

What Selective Coordination Means in Solar PV 2026

Selective coordination is the property of a protective device arrangement where the protective device closest to the fault opens first, and no upstream device opens. NEC 100 defines coordination as “the proper localization of a fault condition to restrict outages to the equipment affected, accomplished by the selection and installation of overcurrent protective devices and their ratings or settings.”

In solar terms, this means a fault on string 12 of combiner 4 should clear the string fuse on string 12, not the combiner main fuse, not the inverter input breaker, and certainly not the AC tie. The other 23 strings on that combiner keep producing, the inverter keeps converting, and the plant keeps exporting. Without coordination, that same string fault can take an entire 250 kW inverter offline.

The economics matter. A typical utility-scale plant earns roughly 5 to 12 cents per kWh, and a 250 kW inverter generates about 1,200 kWh on a sunny day. Every uncoordinated trip that drops the inverter for four hours costs 30 to 70 dollars in lost revenue plus a service call. On a 5 MW site with 20 inverters, two uncoordinated events per month equals 5,000 to 15,000 dollars in annual lost generation. Coordination pays for the engineering study in the first year.

Why PV is Harder than Conventional Power Systems

Conventional power systems flow current in one direction, from utility to load. Solar systems are bidirectional and have current limited by irradiance on the DC side. Three properties make PV coordination harder than the typical solar wire sizing task:

• DC fault current is irradiance-limited. A string can deliver no more than 1.25 to 1.56 times its Isc even into a bolted fault. There is no infinite bus on the DC side.
• Inverter AC fault contribution is small and brief. Most string inverters contribute 1 to 2 per-unit of rated current for 2 to 5 cycles, then drop to zero when the anti-islanding protection trips.
• Multiple sources feed the same bus. A combiner box can have 24 string sources, all of which contribute to a fault on the output bus.

These properties mean DC overcurrent devices live in a narrow window. The fuse must clear in time, but the available fault current may be less than twice the fuse rating. That is why coordination math on the DC side looks different from utility transformer math, and why standard fuse classes from the 1960s do not work for PV strings.

The OCPD Hierarchy: String → Combiner → Inverter → AC Tie

Every grid-tied solar plant has four levels of overcurrent protection between the module and the utility meter. Each level has its own device, its own sizing rule, and its own role in the coordination plan.

Level 1 — String Fuse

Located in the combiner box, the string fuse protects each module string from reverse current that can flow when the rest of the array faults to ground or shorts. NEC 690.9 sets the size at 1.56 × Isc. Class gPV fuses to IEC 60269-6 or UL 2579 are required. Typical ratings are 15A, 20A, 25A, and 30A for residential and commercial modules with Isc between 10A and 20A.

The string fuse is the first device to clear in a coordinated plan. It also protects the string conductor from reverse fault current sourced by the other strings on the combiner bus.

Level 2 — Combiner Output Fuse or Breaker

The combiner main protects the conductor from the combiner box to the inverter input. NEC 690.8(B)(1) sizes it at 1.25 × Isc(combined) × 1.25, often abbreviated as 1.56 × the sum of string Isc values. A 24-string combiner with 13.5A Isc per string sees 24 × 13.5 = 324A continuous source current. The main fuse is sized at 1.56 × 324 = 506A, rounded up to 600A.

The combiner main is typically a Class J or RK1 current-limiting fuse on the positive output, with a matched DC disconnect switch. Some designs use a molded-case DC breaker rated 1000V or 1500V instead.

Level 3 — Inverter DC Input and AC Output

The inverter has two protection points. On the DC side, NEC 690.9(A) Exception 1 allows the inverter input to omit a separate OCPD if the inverter is listed for use without one, which most modern string inverters are. On the AC side, NEC 705.30 requires an OCPD sized at 125 percent of the continuous AC output current.

For a 100 kW inverter at 480 V three-phase, output current is 100,000 / (480 × 1.732) = 120A. The AC OCPD is 120 × 1.25 = 150A, rounded to the next standard size.

Level 4 — AC Tie Breaker and Main Switchboard

The AC tie is the final overcurrent device between the inverter and the point of common coupling with the utility. It serves as the disconnect required by NEC 690.15 and the OCPD required by NEC 705.30. It must be lockable in the open position and accessible to first responders.

On large plants, the AC tie feeds into a medium-voltage transformer and then a utility switchgear breaker. The utility breaker is set by the interconnection agreement, not by the PV designer, but coordination with the utility relay is still the PV engineer’s job.

OCPD Hierarchy Summary Table

This four-level structure is the foundation. Every coordination study walks through these levels in order and verifies selectivity at each transition. The solar PV grounding system design interacts with this hierarchy at every level because ground-fault current paths run through the same OCPD network.

NEC 240 Coordination Requirements Articles 240.10 to 240.93

NEC Article 240 is the master article on overcurrent protection. It applies to every circuit in a PV system that operates at 1000 V or less, with extensions in Article 690 for PV-specific cases and Article 705 for interconnection. Coordination-relevant sections are 240.10 through 240.93.

240.10 — Supplementary Overcurrent Protection

NEC 240.10 permits supplementary overcurrent protection in addition to branch-circuit OCPD. PV string fuses are supplementary protection per this article. They are sized below the main combiner OCPD and protect the string conductor from reverse currents. The string fuse rating must be at least 1.56 × Isc per 690.9.

240.12 — Electrical System Coordination

NEC 240.12 says that an orderly shutdown is permitted to minimize hazards. It allows coordinated short-circuit protection and overload indication to substitute for an instantaneous opening device “where required for orderly shutdown.” This is the closest the NEC comes to requiring selective coordination outside of emergency systems. In practice, plan reviewers cite 240.12 to ask for a coordination study on plants over 1 MW.

240.21 — Location of Overcurrent Devices

NEC 240.21 says OCPD must be located at the point where the conductor receives its supply. There are exceptions for tap conductors that allow OCPD to be located up to 100 feet downstream, which matters for combiner-to-inverter runs. For PV, 240.21(C) is the relevant subsection because the combiner output is technically a transformer secondary tap.

240.60 — General Fuse Rules

NEC 240.60 covers cartridge fuses. It allows non-time-delay fuses for short-circuit only protection and dual-element fuses for both overload and short-circuit. Most PV combiner main fuses are dual-element Class J or RK1 to provide both functions.

240.83 — Marking of Circuit Breakers

NEC 240.83 requires the interrupting rating to be marked on every breaker rated above 5,000A. For PV systems, both AC and DC breakers must carry the correct AIC rating, and DC breakers must be marked for the maximum system voltage at which they retain their interrupting rating. A breaker rated 22 kAIC at 480 V may only be 10 kAIC at 1000 VDC.

240.86 — Series Ratings

NEC 240.86 is the section that allows series-rated breaker combinations. The combination must be tested as a unit by the manufacturer and listed on the equipment label. Section 240.86(B) prohibits the use of series ratings where motor loads connected between the upstream and downstream breakers contribute more than 1 percent of the downstream breaker’s interrupting rating. For PV, inverter contribution is usually well under this threshold, so series ratings are commonly used.

240.87 — Arc Energy Reduction

NEC 240.87 requires arc energy reduction on circuit breakers rated 1200A or more. Methods include zone-selective interlocking, differential relaying, or energy-reducing maintenance switching. On utility-scale PV inverter pad transformers and switchgear, this article forces the engineer to evaluate arc flash and either use a lower-rated breaker or install a maintenance switch.

240.92 — Location in Circuit

NEC 240.92 limits the locations where OCPD can be installed. For PV, the practical impact is that combiner output OCPD must be inside the combiner box or in a separate enclosure within the same conduit run, and AC OCPD must be at the inverter pad or in the AC combiner enclosure.

240.93 — Selective Coordination

NEC 240.93 explicitly addresses selective coordination. It applies where required by other NEC articles, such as 700.32 for emergency systems and 708.54 for critical operations. The coordination must be done by a licensed professional engineer based on time-current curves and short-circuit calculations.

For PV, 240.93 is rarely directly applicable, but plan reviewers often invoke 240.93 by analogy when asking for a study on a large plant or a microgrid project.

Time-Current Curves Reading Them for Selectivity

A time-current curve, or TCC, is a log-log plot of trip time on the y-axis versus current on the x-axis. Every fuse and breaker has a published TCC from the manufacturer. Selective coordination is the graphical verification that the downstream device’s clearing curve fits entirely below and to the left of the upstream device’s minimum melting curve, with at least a 0.1 second margin at all currents up to the maximum available fault current.

Anatomy of a Fuse TCC

A fuse has two curves on its TCC plot:

• Minimum melt curve. The time required for the fuse element to start melting at a given current. The fuse is still intact below this curve.
• Maximum total clear curve. The time required for the fuse to interrupt the circuit completely, including arc extinction. The fault is cleared by the time this curve is reached.

Between minimum melt and maximum clear is the band where the fuse is partially melted. Coordination requires that the upstream fuse’s minimum melt curve sits above the downstream fuse’s maximum clear curve at every current value.

Anatomy of a Breaker TCC

A breaker has three regions on its TCC:

• Overload region (long time). Inverse-time characteristic, typically 1.5 to 10 seconds at 200 percent of rating, set by a thermal-magnetic element or an electronic trip.
• Short-time region. A flat or slightly sloped band between roughly 5x and 10x the rating, configurable on electronic trip units.
• Instantaneous region. A vertical line at the instantaneous pickup current, typically 8x to 12x the rating for thermal-magnetic breakers, adjustable for electronic units.

For coordination, the breaker’s instantaneous region is the hardest part. Once two devices both enter their instantaneous region, both can trip in less than one cycle, and selectivity is lost regardless of the curve shape.

TCC Selectivity Check — Step by Step

1. Plot the upstream device’s minimum melt or instantaneous trip curve.
2. Plot the downstream device’s maximum total clear or instantaneous trip curve.
3. Identify the maximum available fault current at the downstream device location from a short-circuit study.
4. At that current, measure the vertical distance between the two curves.
5. If the upstream curve is above the downstream curve with at least a 0.1 second gap up to the maximum fault current, the devices are selectively coordinated.
6. If the curves cross or come within 0.1 seconds, change one device’s rating, type, or trip setting and re-plot.

Real-World TCC Example for a 250 kW PV System

For a 250 kW PV system with 30A string fuses, 600A combiner mains, and a 400A AC inverter breaker, here is a typical coordination check:

The numbers show the four-level hierarchy in action. Each device clears its zone without involving the next level upstream. This is the essence of single-line diagram solar PV permit drawings — the TCC plot is the math that backs up the single-line.

Fuse-to-Fuse Coordination Ratios typically 2:1

The 2:1 ratio is the most quoted rule in fuse coordination, and the most often misunderstood. It says that for two fuses of the same class in series, the upstream fuse must have an ampere rating at least twice that of the downstream fuse for the two to selectively coordinate.

Where the 2:1 Ratio Comes From

The ratio comes from the slope of the standard fuse TCC. For Class RK5 dual-element fuses, the minimum melt curve at the upstream fuse meets the maximum total clear curve of the downstream fuse at roughly a 2:1 current ratio. For Class J and RK1 fuses, the ratio is slightly tighter, often 1.5:1 or 1.6:1 because these are faster-acting current-limiting fuses with a steeper slope.

IEEE 242 Buff Book table 15-4 publishes the verified ratios for every common fuse class. Manufacturers also publish their own tables, and the ratios may differ slightly between Bussmann, Mersen, and Littelfuse.

Published Fuse-to-Fuse Ratios by Class

The cross-class ratios are larger because mixing fuse classes is mixing TCC shapes. A fast-acting Class J upstream paired with a slow Class CC downstream needs more current separation to avoid simultaneous opening.

Applying the 2:1 Ratio to PV Strings

For a PV combiner with 30A string fuses, the smallest combiner main fuse that coordinates selectively is 60A. In practice, the combiner main is much larger than 60A because it sees the sum of all string Isc values. A 24-string combiner main is typically 400A to 600A. The 2:1 ratio is easily satisfied, often with a 13:1 to 20:1 margin.

The 2:1 ratio becomes binding when the combiner has only 2 or 3 strings, as in residential and small commercial systems. With three 30A string fuses on a 75A combiner output fuse, the ratio is 2.5:1, which is selective. With three 30A string fuses on a 60A output, the ratio is exactly 2:1, which is the minimum.

Cross-Class Coordination — When to Use Different Fuse Types

Most PV designers use gPV string fuses paired with Class J or RK1 combiner mains. The reason is that gPV string fuses are the only class listed for PV string protection under UL 2579, and Class J is the most common AC industrial fuse. The two classes coordinate well at 2:1 to 2.5:1 ratios.

For inverter AC output protection downstream of an AC combiner, Class L fuses paired with Class J or RK1 work well at 2:1. Class CC fuses are common for small inverters under 30A AC output, and they coordinate with Class J at 4:1.

Fuse-to-Breaker Coordination Current-Limiting Fuses Critical

Mixing fuses and breakers is the most common coordination problem in solar PV. The fuse and the breaker have fundamentally different TCC shapes. The fuse is fast and current-limiting. The breaker is slower and has an instantaneous trip that triggers a near-vertical line at a fixed current.

Why Standard Breakers Cannot Sit Upstream of Fuses Easily

A breaker upstream of a fuse needs its long-time and short-time delays set higher than the fuse’s maximum total clear time. This is possible with electronic trip units. With thermal-magnetic breakers, the instantaneous trip pickup may be lower than the fuse’s clearing current, which forces both devices to open together.

For example, a 100A thermal-magnetic breaker has an instantaneous pickup of roughly 1000A. A 30A Class CC fuse downstream clears a 1000A fault in about 0.005 seconds. The breaker’s instantaneous trip releases the latch in about 0.020 seconds. Both devices open within the same cycle. The system is not selective.

Why Current-Limiting Fuses Upstream of Breakers Work Well

Current-limiting fuses interrupt the fault before it reaches the first peak. They cut off the let-through current at a value far below the prospective fault current. The peak let-through is typically 10 to 30 percent of the prospective peak, and the I²t let-through is typically 1 to 5 percent of the prospective I²t.

This means a current-limiting fuse upstream of a circuit breaker actually protects the breaker. The fuse limits the energy that reaches the breaker so much that the breaker may never trip on a downstream fault, leaving the fuse to clear it. Series-rated combinations exploit this property.

Series-Rated Combinations Using Current-Limiting Fuses

NEC 240.86 allows a low-AIC breaker to be used downstream of a current-limiting fuse if the combination is tested and listed by the manufacturer. The combination must be marked on the equipment, and the installation must include the specific fuse class and rating.

For PV, this is common practice on the AC side. A 65 kAIC Class J fuse upstream of a 14 kAIC molded-case breaker can be marked as a 65 kAIC series-rated combination. The PV designer saves several thousand dollars on the breaker by using the lower AIC rating, but loses selectivity between the two devices.

Coordination Ratio Tables — Current-Limiting Fuse to Breaker

The published ratios assume that the breaker’s instantaneous trip is either disabled or set above the fuse’s clearing current. Without that setting, the ratio does not hold and the devices open together.

Breaker-to-Breaker Coordination and Series-Rated Combinations

Two molded-case breakers in series rarely coordinate selectively above the instantaneous region. Both breakers have instantaneous trips, and both pickups are typically set at 10x rating. Once the fault current exceeds 10x the downstream breaker’s rating, both devices enter the instantaneous region and open in less than one cycle.

Zone-Selective Interlocking

The standard solution for breaker-to-breaker coordination above the instantaneous region is zone-selective interlocking, or ZSI. ZSI is a hardwired or fiber-optic communication scheme between breakers. When the downstream breaker detects a fault, it signals the upstream breaker to use its full short-time delay. When the downstream breaker does not detect the fault, the upstream breaker uses its zero-delay instantaneous trip.

ZSI requires electronic trip units with ZSI capability. The leading vendors are Eaton (Magnum DS), Schneider (Masterpact NW), Siemens (3WL), and ABB (Emax 2). ZSI is used on large PV plants at the AC collection switchgear, particularly where multiple inverters feed a common bus.

Series-Rated Combinations as a Cost Saver

Series-rated combinations are listed pairs of breakers where the upstream breaker limits fault current enough to protect the downstream breaker. The downstream breaker has a lower AIC rating than the available fault current, but the combination as a whole has the AIC rating of the upstream breaker.

The cost savings can be substantial. A 22 kAIC 200A molded-case breaker costs roughly 350 dollars. A 65 kAIC version costs roughly 800 dollars. On a 24-breaker AC combiner, the savings are 24 × 450 = 10,800 dollars.

The cost is loss of selectivity. Both breakers in the series pair will open together on most downstream faults. For PV, this is usually acceptable on the AC side because the inverter AC output is a single circuit, and tripping both the inverter breaker and the AC combiner main only takes one inverter offline.

When Not to Use Series Ratings

NEC 240.86(B) prohibits series ratings where motor loads connected between the upstream and downstream breakers contribute more than 1 percent of the downstream breaker’s interrupting rating. For PV, this rarely applies, but for hybrid microgrid plants with rotating generators or large motor loads, series ratings can be blocked.

NEC 240.86 also requires the field-installed combination to match the tested combination exactly. Substituting a different breaker brand or model breaks the listing. Many PV plan reviews fail because a different breaker was installed than what was listed in the manufacturer’s series-rated table.

Inverter Internal Protection vs External OCPD

Every grid-tied solar inverter contains internal overcurrent protection on both the DC and AC sides. These internal devices are listed with the inverter under UL 1741. They are not a substitute for the external OCPD required by NEC 690 and 705, but they interact with the external devices in the coordination plan.

Inverter Internal DC Protection

Modern string inverters include DC fuses or solid-state DC protection on each MPPT input. The fuses are rated to interrupt the maximum DC fault current the inverter can sink, typically 25 to 50A per input. Some inverters also include a DC arc fault detector required by NEC 690.11, which the solar arc fault detection guide covers in depth.

The inverter’s DC fuse is not a coordinated device. It is a backup that catches catastrophic failure of the inverter’s input stage. The combiner output fuse is the coordinated device for the DC bus.

Inverter Internal AC Protection

The inverter’s AC output is protected by the inverter’s firmware. Anti-islanding protection trips the AC contactor in 2 to 5 cycles when grid voltage or frequency leaves the IEEE 1547 limits. Overcurrent protection trips when the output exceeds the inverter’s continuous rating for more than a few seconds.

The internal AC protection is for the inverter’s protection, not the system’s protection. A fault on the conductor between the inverter and the AC tie can still flow through the inverter’s contactor until the external breaker trips. NEC 705.30 requires the external breaker to provide overcurrent protection for the AC conductor.

Coordinating External OCPD with Inverter Limits

The external AC OCPD must be sized between 1.25 × inverter continuous output (per NEC 705.30) and the conductor ampacity. The OCPD’s instantaneous trip must be above the inverter’s transient overcurrent capability, which is typically 2 to 4 per-unit for 5 to 10 cycles. If the breaker’s instantaneous pickup is set at 8 per-unit, the inverter starts and operates normally without nuisance tripping.

For a 100 kW 480 V inverter, continuous output is 120A. The minimum breaker is 150A. The instantaneous trip should be set at 1200A minimum to ride through inverter inrush. A 150A breaker with adjustable instantaneous typically tops out at 1500A.

Coordination Studies When They Are Required

A coordination study is a written engineering analysis that demonstrates selective coordination across every OCPD in a system. It includes a short-circuit calculation, a TCC plot for each fault location, and a narrative explaining the coordination logic. The study is signed and sealed by a licensed professional engineer in the state of the project.

When the NEC Requires a Coordination Study

NEC explicitly requires selective coordination in only a few cases:

• 700.32 — Emergency systems (life-safety branches)
• 701.18 — Legally required standby systems
• 708.54 — Critical operations power systems (COPS)

For most PV systems, the NEC does not require a coordination study. The exceptions are PV systems serving emergency loads, hospital essential loads, or COPS facilities, which are rare in commercial PV.

When the AHJ or Utility Requires a Coordination Study

Authority having jurisdiction reviewers often require a coordination study on plants above a certain size. Thresholds vary:

Utilities also require coordination studies for interconnection. The utility relay at the point of common coupling must coordinate with the PV plant’s protective devices, and the utility engineer needs the plant’s TCC plots to verify this.

When Insurance and Lenders Require a Coordination Study

Lenders financing utility-scale PV typically require a coordination study as part of the technical due diligence. The study confirms that the plant will not suffer extended outages due to OCPD mis-coordination, which protects the lender’s revenue forecast. Insurance carriers require coordination studies for similar reasons, often as a condition of property coverage.

Cost and Timeline of a Coordination Study

A coordination study for a 5 MW commercial PV plant costs 8,000 to 25,000 dollars and takes two to four weeks. The cost scales with the number of OCPD devices, the number of inverter pads, and the complexity of the AC collection system. Utility-scale plants over 50 MW can cost 50,000 to 150,000 dollars for the full study, including arc flash analysis.

The study should start during detailed design, not after construction. Late changes to OCPD ratings or types force a re-run of the TCC plots, which is expensive and can delay commissioning. The solar permit package checklist lists the coordination study as a required deliverable for commercial projects.

Common Coordination Mistakes Matched Fuse Sizes Wrong Curve Types

The same coordination mistakes appear in plan reviews year after year. Here are the seven most common, with the fix for each.

Mistake 1 — Matched String and Combiner Fuses

The most common mistake is putting a 30A fuse on the combiner output when each string has a 30A fuse. Both fuses see the same fault current if a single string shorts to ground. Both open. The whole combiner drops out.

Fix. Size the combiner main at 1.56 × Isc × N strings, never at the same rating as the string fuse. For a 24-string combiner with 30A string fuses, the main should be 400 to 600A.

Mistake 2 — Wrong Fuse Class for PV Strings

Class RK5 or Class H fuses are not listed for PV string protection. They are slower to clear and do not have the DC interrupting rating required by UL 2579. Using them violates NEC 690.9 and creates fire risk.

Fix. Use only gPV-class fuses listed to UL 2579 or IEC 60269-6 for PV string protection. Bussmann PV-15A10F, Mersen HelioProtection, and Littelfuse SPF series are common choices.

Mistake 3 — Thermal-Magnetic Breaker Upstream of Fast Fuse

A thermal-magnetic breaker has a fixed instantaneous trip at roughly 8 to 12x rating. A fast fuse downstream clears in under 0.01 seconds at 10x rating. The breaker’s instantaneous trip releases in 0.02 to 0.05 seconds. The breaker still opens because the unlatching is mechanical and not interruptible.

Fix. Use a current-limiting fuse upstream of the breaker, not the other way around. If a breaker upstream is unavoidable, use an electronic trip unit with adjustable instantaneous and set the pickup above the fuse’s clearing current.

Mistake 4 — Series-Rated Combination Not Listed

Field-substituting a breaker for one of equal AIC but different model breaks the manufacturer’s listed series rating. The combination is no longer NEC-compliant under 240.86. Plan reviewers catch this on the breaker model number printed in the submittal.

Fix. Always specify the exact breaker model from the manufacturer’s series rating table. If a substitute is needed, request a new series rating from the manufacturer or re-rate the downstream breaker to a higher AIC.

Mistake 5 — Forgetting DC Voltage Rating on AC Breakers

Molded-case breakers carry both an AC and a DC interrupting rating. The DC rating is much lower than the AC rating, often 65 kAIC at 480 VAC versus 10 kAIC at 250 VDC. Using a 480V AC breaker on a 1000V DC combiner output is non-compliant and dangerous.

Fix. Use breakers listed for the DC system voltage. Schneider Compact NSX-DC, ABB Tmax PV, and Eaton PVS series are listed for 1000V or 1500V DC.

Mistake 6 — Ignoring Inverter Contribution to AC Faults

PV inverters contribute fault current to AC faults. The contribution is typically 1 to 2 per-unit of inverter rating for 2 to 5 cycles. For a 100 kW inverter with 120A rated output, the contribution is 120 to 240A for the first few cycles. Ignoring this contribution in the short-circuit study underestimates the fault current at the AC tie.

Fix. Use a short-circuit calculation tool that models inverter contribution explicitly. Most utility-scale tools (ETAP, SKM, PSS/E) have inverter source models. Hand calculations should add the inverter contribution as a current source for the first 5 cycles.

Mistake 7 — No Coordination Across Inverter Pads

On large plants with multiple inverter pads, the AC collection breakers at the MV switchgear must coordinate with the inverter AC breakers below them. Plan reviews often catch a missing coordination between pad-level and switchgear-level OCPD because each pad was designed in isolation.

Fix. Run the coordination study across the whole AC collection system, not just one pad. The switchgear breaker must have a long enough short-time delay to allow the pad breaker to clear first.

Software Tools for Coordination Analysis SKM PowerTools ETAP

Coordination analysis on a plant with more than a few dozen OCPD devices requires software. Manual TCC plotting on log-log paper still works for small systems and is excellent for learning, but no professional study above 1 MW is done by hand.

SKM PowerTools CAPTOR

SKM PowerTools is the most widely used coordination tool in North American engineering firms. The CAPTOR module plots TCC for fuses, breakers, relays, and transformer damage curves. The library includes over 50,000 protective devices from every major manufacturer. The PowerTools DAPPER module performs the short-circuit calculation that feeds CAPTOR.

PowerTools is a desktop application with a Windows-only client. Licenses start around 8,000 dollars per seat per year. SKM is the standard tool for utility coordination studies in the United States.

ETAP Star

ETAP is the other major North American coordination tool. The Star module is similar to CAPTOR in scope, with a slightly more modern UI and tighter integration with ETAP’s other modules (load flow, transient stability, arc flash). ETAP is widely used in industrial, oil and gas, and utility-scale renewable projects.

ETAP licenses start around 10,000 dollars per seat per year. The arc flash module integrates the coordination study with the IEEE 1584 arc energy calculation automatically.

Open-Source and Lower-Cost Tools

For smaller projects, open-source and lower-cost tools work well:

• EasyPower. Affordable Windows tool with a strong coordination module and a user-friendly UI. Licenses around 3,000 dollars per year.
• EDSA Paladin. Similar feature set to SKM at a slightly lower price.
• Schneider Ecodial. Free tool from Schneider for sizing OCPD and verifying coordination using Schneider products only. Useful for project bids and feasibility studies.

Tool Comparison Table

Workflow for a Coordination Study

A typical study runs in this order:

1. Build the one-line diagram in the software.
2. Enter source impedances (utility, transformer, conductor, inverter).
3. Run the short-circuit calculation at every bus.
4. Place every OCPD on the TCC plot.
5. Visually inspect the curves for selectivity, looking for crossings and minimum gaps.
6. Adjust trip settings or replace devices where coordination fails.
7. Document the final settings and curves in the study report.
8. Issue the report to the client, the AHJ, and the utility.

This workflow ties directly into the broader solar safety compliance checklist for commercial projects. Coordination is one element of the full electrical safety package, alongside arc flash, grounding, and rapid shutdown.

Worked Coordination Examples

A short worked example for each project size makes the math concrete.

Example 1 — Residential 10 kW Rooftop

A 10 kW residential rooftop with 24 modules in two strings of 12. Module Isc is 13.5A. Inverter is a 10 kW single-phase 240V string inverter with two MPPT inputs and integrated DC disconnect. AC output current is 41.7A.

• String fuse. 13.5 × 1.56 = 21.06A. Next standard size 25A gPV fuse. The 10 kW inverter typically includes 25A or 30A string fuses internally.
• Combiner main. Not used. The two strings feed directly into the inverter MPPT inputs.
• Inverter AC OCPD. 41.7 × 1.25 = 52A. A 60A 2-pole breaker is standard. The inverter manual usually specifies 60A or 70A maximum.
• Coordination check. String 25A fuse versus 60A inverter breaker. Ratio 60 / 25 = 2.4. Selective.

Example 2 — Commercial 250 kW Rooftop

A 250 kW commercial flat roof with 600 modules in 24 strings of 25. Module Isc is 14A. Inverter is a 250 kW 480V three-phase string inverter with one DC input from a single combiner. AC output current is 301A.

• String fuse. 14 × 1.56 = 21.8A. Next standard size 25A gPV fuse.
• Combiner main. 24 strings × 14A × 1.56 = 524A. Next standard 600A Class J fuse.
• Inverter AC OCPD. 301 × 1.25 = 376A. Next standard 400A 3-pole breaker.
• Coordination check. String 25A versus combiner main 600A. Ratio 600 / 25 = 24. Selective. Combiner main 600A versus inverter AC 400A. Direction reverses on the AC side, so this check does not apply directly. The AC tie 600A versus inverter 400A. Ratio 600 / 400 = 1.5. Need short-time delay on AC tie to coordinate above instantaneous.

Example 3 — Utility-Scale 5 MW Plant

A 5 MW utility-scale plant with 20 inverters of 250 kW each, three combiners per inverter, 24 strings per combiner. AC collection at 480V then a 5 MVA pad transformer to 13.8 kV.

• String fuse. 14 × 1.56 = 21.8A. 25A gPV fuses, 1440 total across the plant.
• Combiner main. 24 × 14 × 1.56 = 524A. 600A Class J. 60 combiners total.
• Inverter AC OCPD. 301 × 1.25 = 376A. 400A 3-pole breaker per inverter.
• AC collection breaker. 4 inverters per collection circuit × 301A = 1204A continuous, × 1.25 = 1505A. Next standard 1600A insulated-case breaker with electronic trip and short-time delay.
• Main switchgear breaker. 20 × 301A = 6020A continuous, × 1.25 = 7525A. Next standard 8000A insulated-case with ZSI.
• Pad transformer 480V primary OCPD. 8000A.
• MV breaker. 5 MVA / 13.8 kV / 1.732 = 209A continuous. Next standard 600A vacuum breaker with utility-coordinated overcurrent relay.

The coordination check across all five levels uses ZSI between the AC collection and main switchgear breakers, and time-current curves to verify selectivity at every transition. The full study runs to roughly 40 to 60 pages including TCC plots.

Verification at Commissioning

Coordination is not finished when the study is signed. It is finished when every breaker setting in the field matches the study. Commissioning is the verification step that catches the gap between paper and reality.

Settings Verification

Every electronic trip breaker has adjustable settings: long-time pickup, long-time delay, short-time pickup, short-time delay, instantaneous pickup, and ground-fault pickup if equipped. The settings in the field must match the values in the coordination study report.

A commissioning checklist for each breaker includes:

1. Verify breaker model and AIC rating against the study.
2. Verify trip unit model and firmware version.
3. Read and record every dial or DIP switch setting.
4. Test the breaker with a primary injection tester at the pickup and delay points.
5. Sign and date the commissioning report.
6. File the report with the project closeout documents.

Secondary Injection vs Primary Injection Testing

Secondary injection injects a current signal into the trip unit’s electronics. It verifies the trip unit’s response curve but does not verify the current transformers, the mechanical trip mechanism, or the contact integrity. Primary injection injects a real high current through the breaker’s main contacts. It verifies the entire chain end-to-end.

For PV plants over 1 MW, primary injection testing of every AC OCPD is standard practice at commissioning. Test currents range from 200A for a 100A breaker to 8000A for a 1600A breaker, using portable test sets from Megger, Doble, or Omicron.

As-Built TCC Plots

The final coordination study should include as-built TCC plots that reflect the actual breaker settings, not the design intent. If a breaker was set differently than the study specified, the as-built plot should show the actual setting and either update the study or document the deviation.

How Solar Design Software Reduces Coordination Errors

Coordination errors are most often the result of manual data entry mistakes. The string fuse rating is keyed in wrong, the inverter AC output is mis-calculated, the breaker is specified at the wrong AIC. Software that automates the sizing reduces these errors by design.

SurgePV is solar design software that sizes every OCPD per NEC 690 and 705 automatically as the design is built. The string fuse comes from the module Isc and the 1.56 multiplier. The combiner main comes from the string count. The inverter AC OCPD comes from the inverter database with the 1.25 multiplier already applied.

When a designer changes the module or the inverter, every downstream OCPD recalculates instantly. The single-line diagram updates. The bill of materials updates. The plan reviewer’s check is straightforward because the numbers are internally consistent.

For commercial designers running solar proposal software with multiple system variants in parallel, this automatic coordination is the difference between a one-day proposal and a one-week proposal. The same logic applies to the generation and financial tool when comparing OCPD costs across design alternatives.

External coordination study software such as SKM PowerTools or ETAP Star still has a role for plants above 1 MW. SurgePV exports the OCPD schedule and short-circuit data in formats that import directly into those tools, saving the engineer the data-entry step.

ROI of Doing Coordination Right

The financial case for coordination is straightforward. A coordinated system loses one string per fault. An uncoordinated system can lose a whole inverter, a whole AC combiner, or a whole MV feeder per fault.

Lost Revenue Per Uncoordinated Trip

The numbers scale fast. A 50 MW plant that suffers two uncoordinated MV trips per year loses 48,000 dollars in revenue. The coordination study and the better breakers cost less than that in year one.

Equipment Damage from Uncoordinated Faults

Beyond lost revenue, uncoordinated systems can suffer equipment damage. A breaker that fails to clear a fault within its interrupting rating can rupture, damage adjacent equipment, and cause a fire. Insurance claims from breaker failures average 50,000 to 250,000 dollars per event. A properly coordinated system with current-limiting fuses upstream avoids this entirely.

Total Cost of Coordination Done Right

A complete coordination program for a 5 MW plant costs:

• Coordination study: $15,000
• Premium current-limiting fuses vs standard: $4,000 extra
• Premium electronic trip breakers vs thermal-magnetic: $10,000 extra
• Primary injection commissioning testing: $8,000
• Total: $37,000

Against $48,000 in avoided lost revenue per year on a moderately faulty site, the payback is under one year. On a clean site with no major faults, the program still pays for itself in 3 to 5 years via avoided equipment damage and lower insurance premiums.

Conclusion

Three action items to take from this guide:

• Build the four-level OCPD hierarchy into every design from day one. String fuse, combiner main, inverter AC, AC tie. Size each per NEC 690.9 and 705.30, and verify the 2:1 fuse ratio at every transition.
• Use current-limiting Class J or RK1 fuses upstream of any molded-case breaker. The fuse protects the breaker and clears the fault. Series-rated combinations only save money on the AC side and only when listed by the manufacturer.
• Run a coordination study with TCC plots for any plant above 1 MW. The study costs less than the lost revenue from a single uncoordinated trip on a 5 MW plant. Verify the settings at commissioning with primary injection testing.

Coordination is not glamorous engineering. It is the difference between a plant that runs at 99.5 percent uptime and one that runs at 95 percent because of nuisance trips. The math has been published since the 1960s, the software has existed since the 1990s, and the NEC has been clear since 2008. The plants that get it right are the plants that take the article-by-article walk through NEC 240 seriously.

For more on the broader electrical design context, see the solar wire sizing per NEC 690.8 guide, the solar PV grounding system design reference, and the arc fault detection AFCI guide for the related fault protection layer. The single-line diagram for PV permits shows how the coordination study integrates with the permit submittal package.

External References

• NFPA 70 National Electrical Code — Articles 240, 690, 700, 705, 708.
• IEEE 242 Buff Book — Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems.
• IEEE 1584 — Guide for Performing Arc Flash Hazard Calculations.
• Eaton Bussmann Solar Application Guide — PV fuse selection and coordination tables.
• Mersen Solar Protection Application Guide — gPV fuse data sheets and coordination examples.
• NEMA AB-1 — Standard for Molded-Case Circuit Breakers.
• ETAP Star Coordination Module — Product documentation.

Frequently Asked Questions

What is overcurrent protection coordination in solar PV?

Overcurrent protection coordination in solar PV is the engineered selection of fuses and circuit breakers so that the device closest to a fault clears it first. The upstream devices stay closed. The goal is to isolate only the faulted string, combiner, or AC branch without tripping the whole array. Coordination uses time-current curves, fault current studies, and NEC 240 rules to verify selectivity at every step from the module to the utility tie.

What is the 2:1 ratio rule for solar fuses?

The 2:1 ratio is a rule of thumb for fuse-to-fuse selective coordination. The upstream fuse must carry at least twice the ampere rating of the downstream fuse so their time-current curves do not overlap. For example, a 30A string fuse downstream needs at least a 60A combiner output fuse upstream of the same class. The ratio comes from IEEE 242 Buff Book guidance for low-voltage fuse coordination.

Does NEC require a coordination study for solar?

NEC 240.10 and 240.12 do not mandate a written coordination study for most PV systems. Selective coordination is only required by NEC 700, 701, and 708 for emergency, legally required standby, and critical operations power systems. Most commercial and utility solar projects perform coordination studies because plan reviewers, insurance carriers, and equipment manufacturers expect them. IEEE 242 and IEEE 1584 outline the methods.

What is the difference between current-limiting fuses and standard fuses?

Current-limiting fuses interrupt fault current before it reaches the first peak, typically within a quarter cycle. Standard fuses can let the full prospective fault current pass through. Class RK1, J, and CC fuses are current limiting. Class K5, H, and RK5 are not. In PV combiner boxes, gPV fuses to IEC 60269-6 are current limiting and are the only type listed for PV string protection.

How do you size a string fuse for a PV combiner?

NEC 690.9 sizes the string fuse at 1.56 times the module short-circuit current Isc. The factor accounts for irradiance enhancement of 125 percent and a 125 percent continuous load multiplier. For a module with Isc of 13.5A, the minimum fuse is 21.06A. The next standard size is 25A. The fuse must also be rated for the maximum system voltage, typically 1000 or 1500 VDC, and be listed as gPV per UL 2579 or IEC 60269-6.

What is a series-rated combination and why does it matter?

A series-rated combination is a tested pairing of an upstream and downstream circuit breaker where the upstream device limits fault current enough to protect the lower-rated downstream breaker. The combination is listed by the manufacturer and printed on the panelboard label. NEC 240.86 allows series ratings but prohibits motor contributions above 1 percent of the interrupting rating. Series ratings save money on lugged AC equipment but sacrifice selectivity, since both breakers can trip together.

Which software tools handle solar coordination studies?

SKM PowerTools CAPTOR module and ETAP Star are the two dominant commercial coordination tools. EasyPower, EDSA Paladin, and Schneider Ecodial also handle PV systems. For utility-scale projects, PSS/E and DigSilent PowerFactory model the inverter response. Most studies combine a short-circuit calculation, a protective device evaluation, and a time-current curve plot to demonstrate selectivity at every fault location.

Do solar inverters need external overcurrent protection on the AC side?

Yes. NEC 705.30 requires an overcurrent device for the inverter output circuit sized at 125 percent of the inverter continuous output current. The OCPD also serves as the disconnect required by NEC 690.15 if it is lockable. The inverter does have internal AC protection, but the internal device is for the inverter’s own faults, not the conductor or the load center. A separate listed breaker or fuse is required upstream of every grid-tied inverter.

What happens if PV OCPD is not coordinated?

If OCPD is not coordinated, a single string fault can trip the combiner main fuse or the inverter AC breaker. The entire inverter stops producing energy until the breaker is reset, which can take hours on a remote site. On large plants this can cost thousands of dollars in lost generation per event. Uncoordinated systems also create arc flash risk because workers may need to reset devices closer to the fault than necessary.

Where can I find a sample PV coordination study?

Sample PV coordination studies are published by Cooper Bussmann, Mersen, and Eaton in their solar fusing application guides. IEEE 242 chapter 15 walks through a low-voltage example that translates directly to PV combiner design. Most engineering firms also include a TCC plot in the solar PV permit single-line diagram package for commercial submissions over 100 kW.