AS/NZS 5139 Amendment 1: What Changed for Battery System Safety (2025–2026)
AS/NZS 5139 Amendment 1 changed how batteries get installed across Australia and New Zealand. It arrived on 19 December 2025. So if you designed a BESS install before that date, several of your default assumptions just moved. This guide walks through every real change. New definitions. New clearance figures. A genuinely useful garage exception. A new appendix for fault current calculations. It’s one of three standards in Australia’s new battery rules.
| Quick Answer AS/NZS 5139 Amendment 1 updates 18 clauses. It also adds five new figures, plus Appendix I for calculating cell short-circuit current. It’s mandatory now in NSW. Western Australia set a specific deadline of 19 June 2026, after a six-month transition. The headline practical change is a new exception. Batteries can now sit within 600mm of a garage opening wider than 900mm, provided safe egress is preserved. |
What Is AS/NZS 5139 Amendment 1?
AS/NZS 5139:2019 is the standard that governs safety for battery energy storage systems. It covers systems connected to power conversion equipment. It replaced the older AS 4086.2 standard back in 2019. AS/NZS 5139 Amendment 1 doesn’t replace this base standard. Instead, it updates specific clauses. It adds new figures. It also adds one new appendix. The rest of the 2019 standard stays in force. The full amended text is available through the Standards Australia Store.
The full clause list is in the table below. It also touches Figures 2.11 and 2.12, and adds five entirely new figures: 4.1A, 4.1B, 4.1C, 4.1D, and 4.2A. Appendix I is new. So is a set of new Bibliography references.
Everything AS/NZS 5139 Amendment 1 Changed, at a Glance
| Type | Reference |
| Clauses updated | 1.3, 3.2.3.3, 4.2.2.1, 4.2.2.2, 4.2.4.2, 4.2.5, 5.2.2.1, 5.2.2.2, 5.2.4.2, 5.3.1.2.1, 5.3.1.3.8, 6.3.6.4, 7.2, 7.7, 7.8, 7.9, 7.10, 7.11 |
| Figures updated | 2.11, 2.12 |
| Figures added (new) | 4.1A, 4.1B, 4.1C, 4.1D, 4.2A |
| Appendix added (new) | Appendix I — calculating cell short-circuit current |
| Bibliography | New references added |
When AS/NZS 5139 Amendment 1 Takes Effect
Timing isn’t the same in every state. NSW treats the amendment as mandatory right away. Any install that misses the updated requirements no longer complies with the Standard there. WA took a different path. It set a full-compliance date of 19 June 2026, six months after publication. Until then, either the old or the new version is fine. Other states are still working out their own position. So check with your state regulator before you quote a date to a client.
| Jurisdiction | Position | Source |
| NSW | Mandatory immediately on publication (19 Dec 2025) | NSW Building Commission advisory |
| Western Australia | Full compliance required from 19 Jun 2026, after a 6-month transition where either edition is acceptable | WA Building and Energy notice |
| Queensland | Amendment issued and communicated to electricians; specific compliance date not published in the source reviewed | WorkSafe QLD eSafe newsletter |
| Other states/NZ | Not confirmed in this research pass — verify with the relevant state or NZ regulator before quoting a date | — |
New Definitions Under AS/NZS 5139 Amendment 1
Clause 1.3 covers terms and definitions, and it picked up real changes. The main addition is a new definition: a battery energy storage system room. That’s a dedicated room. It holds the battery, the power conversion equipment, and other BESS accessories. A note attached to this definition matters just as much as the definition. It says a multi-purpose room doesn’t count as “dedicated,” just because a battery sits in it. A garage or a general storage room are both good examples.
Three other definitions picked up clarifying notes too, with practical examples. So electricians should still read Clause 1.3 in full. Drawings and compliance paperwork need to use the amended wording exactly.
New Clearance Figures: 4.1A Through 4.2A
The amendment replaces the old typical BESS installation diagrams with five new figures. First, Figure 4.1A covers egress clearance in a corridor, hallway, or lobby. Then Figure 4.1B covers clearance to doors and openings. Also, Figure 4.1C adds further detail to the clearance picture. Figure 4.1D shows a side-view diagram of clearance from restricted locations, with the familiar 600mm front clearance and 900mm above-battery clearance both drawn out. Finally, Figure 4.2A covers clearances for battery connection access, split by whether the connection is DC or AC.
One structural cleanup came along with the new figures. Also, the standard used to repeat similar diagrams in Section 5. So the amendment removes that duplication. Section 5 now just refers back to the Section 4 figures instead of reprinting them.
The Garage Door Exception — Clause 4.2.2.2
The most talked-about change is a new exception for garage installations. Under the amended Clause 4.2.2.2, a battery can now sit within 600mm of an opening wider than 900mm — a typical garage door, in other words — as long as the opening still allows sufficient clearance for safe egress, and the clearance is no less than 1m from any front or side a person might need to pass through during an exit.
This matters because garages are the preferred spot for a lot of installers. They’re usually not living spaces, they’re weather-protected, often shaded, and close to the switchboard. But the old blanket 600mm rule ruled out a lot of good garage walls, just because of a wide roller door. The amendment keeps the safety goal in place. People still need a safe way out. It just stops punishing a battery for sitting near a large opening when someone could still walk past it safely.
In practice, this means a designer needs two numbers, not one. The first is the 600mm distance to the opening itself. The second is the 1m clearance from whichever front or side edge a person would need to pass. So both conditions have to hold at the same time. A wide garage door with a wall corner narrowing the walk-through space to less than a metre still fails, even if the 600mm figure looks fine on a drawing.
Worked Example
A garage has a 2.4m-wide roller door. The nearest wall section suitable for a battery sits 500mm from the door opening. Under the amended clause, 500mm is within the 600mm allowance, and the door is well over the 900mm width threshold. So far, this passes. But the same wall has a support post 800mm from the door edge, narrowing the usable walk-through space to 800mm at that point. Since 800mm is under the 1m minimum clearance the amendment also requires, this specific layout still fails — even though the headline 600mm number looks fine. Moving the battery, or resolving the post clearance, is the fix.
Inverters as Associated Appliances
The amendment also reclassifies inverters. Power conversion equipment now counts as an associated appliance. So it can go inside a restricted location, where it couldn’t before. That’s a useful change for compact installs, where wall space near the battery is already tight.
Fire Barrier and Overcurrent Protection Changes
Fire barrier requirements moved the other way. Stricter, not looser. So exempt materials used as a barrier to a habitable room now need a minimum thickness of 6mm. Also, building materials within 1 metre of a battery system classed as a chemical hazard pick up new requirements.
Paralleled pre-assembled battery systems get a new rule for overcurrent protection. The protective device’s kA rating now has to cover the combined fault current of every paralleled unit, not just the biggest one. That’s a real change for multi-unit homes and light commercial jobs. Two or three battery modules often get paralleled to hit a target capacity.
To make that calculation possible, the amendment adds Appendix I. It sets out the method for calculating cell short-circuit current within a battery system. So that’s the number a designer needs before sizing the paralleled OCPD correctly. This connects directly to broader short-circuit protection design work on the DC side of a BESS installation. This connects directly to broader short-circuit protection design work on the DC side of a BESS installation.
Safety Data Sheet Requirements
Safety Data Sheet handling picked up a clarification too. A physical copy of the SDS must be provided on site. It also has to stay protected from damage or degradation. The standard specifically mentions storing it in a sealed, durable, clear pouch as an acceptable method. So treat SDS storage as part of the handover package, not an afterthought bolted on at final inspection.
Background: Restricted Locations Under AS/NZS 5139
It helps to know what this amendment did NOT change. The base restricted-location rules still apply. Batteries still can’t sit within 600mm of an exit, a window edge, a vent into a living room, or an appliance. They still can’t sit within 900mm below any of those. Ceiling spaces, wall cavities, roofs, stairways, walkways, escape routes, and living rooms themselves are still off-limits. The ERAC Battery Energy Storage System Guideline backs up these same rules. None of this changed. The amendment only added the wide-opening exception above, plus the inverter reclassification.
Restricted Locations — Unchanged by Amendment 1
- Within 600mm of any exit or entry
- Within 600mm of any window’s vertical side, or a ventilation opening into a habitable room
- In an evacuation or designated escape route
- Within 600mm of any appliance
- Within 900mm below any of the items above
- In ceiling spaces or wall cavities
- On roofs
- Under stairways or access walkways
- Within a habitable room itself
AS/NZS 5139 Amendment 1 Compliance Checklist
- Confirm the installation drawings use Clause 1.3’s updated terminology, including the new battery energy storage system room definition.
- Check clearance layouts against the new Figures 4.1A–4.2A, not the pre-amendment diagrams.
- If relying on the garage-door exception, verify both the 600mm opening distance AND the 1m walk-through clearance — not just one of them.
- Confirm inverter placement against the updated associated-appliance classification if it sits in a restricted location.
- Check fire-barrier materials meet the 6mm minimum thickness where used as exempt materials.
- For paralleled pre-assembled battery systems, recalculate the OCPD kA rating against the combined fault current using Appendix I.
- Confirm a physical SDS copy is on site and stored in a protective pouch before handover.
- Verify your state’s specific compliance timeline before telling a client the installation is (or isn’t) required to meet Amendment 1 yet.
Frequently Asked Questions
When did AS/NZS 5139 Amendment 1 take effect?
It was published on 19 December 2025. NSW treats it as mandatory immediately. Western Australia requires full compliance from 19 June 2026, after a six-month transition period. Confirm the position in your own state before quoting a date.
What is the garage door exception under this amendment?
Under the amended Clause 4.2.2.2, a battery can be installed within 600mm of an opening wider than 900mm — such as a garage door — provided safe egress is maintained and clearance is no less than 1m from any front or side a person might need to pass through.
Does this amendment change where inverters can be installed?
Yes. Power conversion equipment is now classified as an associated appliance, which means it can be installed inside a restricted location where it previously couldn’t.
What is Appendix I, and what does it calculate?
Appendix I is a new addition that sets out how to calculate cell short-circuit current within a battery system. It’s needed to correctly size overcurrent protection for paralleled pre-assembled battery systems under the amendment’s new kA rating requirement.
Do the pre-existing restricted-location rules still apply under Amendment 1?
Yes, unchanged. Batteries still can’t be installed within 600mm of exits, windows, ventilation openings, or appliances, within 900mm below those items, or in ceiling spaces, wall cavities, roofs, under stairways, escape routes, or habitable rooms. Amendment 1 only added the specific wide-opening exception and the inverter reclassification — it didn’t touch the base restricted-location list.
Further Reading
Australia’s New Battery Rules: The 2026 Compliance Stack
Australia has new battery rules for 2026, and they arrived from three different directions at once. Between August 2025 and December 2025, regulators updated the inverter standard, the battery safety standard, and the cable selection standard. Two of them landed on the very same day. So anyone installing, supplying, or specifying a BESS in Australia now answers to all three of these new battery rules. Miss one, and the other two won’t save the project.
| Quick Answer Australia’s new battery rules for 2026 span three standards. AS/NZS 5139:2019 Amendment 1 (published 19 Dec 2025) covers battery system safety. AS/NZS 4777.2:2020 Amendment 2 (mandatory from 23 Aug 2025) governs inverter performance and grid behaviour. AS/NZS 3008.1.1:2025 (also published 19 Dec 2025) sets cable selection and DC ratings. In Western Australia, full compliance with both the 5139 and 3008.1.1 updates is required from 19 June 2026, following a six-month transition period — other states administer their own timelines. A compliant BESS install needs all three standards, and a battery’s international product certifications (IEC 62619, UL 1973, UN38.3) do not substitute for any of them. |
What Are Australia’s New Battery Rules?
Together, Australia’s new battery rules form what’s best understood as a compliance stack, not three unrelated updates. A battery energy storage system never sits under a single rulebook. Instead, it sits at the intersection of three. AS/NZS 5139 governs how the battery gets installed, ventilated, and protected. AS/NZS 4777.2 governs how the inverter behaves once it talks to the grid. AS/NZS 3008.1.1 governs every cable that connects the two. So a design can pass one standard and still fail the job. Also, it only takes one missed layer to cause it.
It’s also worth separating two things international suppliers often conflate. So battery product certification and Australian installation compliance are not the same thing. A cell or module can carry IEC 62619, UL 1973, and UN38.3 certification and still fail an Australian project if the installation, inverter, or cable design doesn’t separately satisfy the three standards below.
This page works as a living hub, not a one-time post, since Australia’s new battery rules will keep changing. Also, each standard below links out to its own detailed guide as those go live. As amendments publish, this hub updates first, then the change log at the bottom records exactly what moved and when. Bookmark this page, not a single standard’s guide — the compliance stack shifts as a set, not one piece at a time.
Australia’s New Battery Rules: Compliance Stack Overview
The table below summarises where each standard sits today. Full detail on each one follows in its own section, and a dedicated guide for each standard is in progress.
| Standard | Governs | Published | Mandatory From | Administered By |
| AS/NZS 5139:2019 | Battery system and BESS installation safety | Amendment 1: 19 Dec 2025 | Immediate in NSW; full compliance from 19 Jun 2026 in WA (6-month transition) — confirm with your state regulator | Standards Australia / Standards NZ; state electrical safety regulators |
| AS/NZS 4777.2:2020 | Grid-connect inverter performance | Amendment 2: Aug 2024 | 23 Aug 2025 | Standards Australia / Standards NZ; Clean Energy Council; DNSPs |
| AS/NZS 3008.1.1 | Cable selection, current-carrying capacity, DC ratings to 1500V | 2025 edition: 19 Dec 2025 | Full compliance from 19 Jun 2026 in WA (6-month transition); NZ 2017 edition withdrawal ~Nov 2026 | Standards Australia / Standards NZ |
Note on dates: AS/NZS 5139 Amendment 1 and AS/NZS 3008.1.1:2025 were both published on 19 December 2025, not on separate dates. Mandatory compliance timing varies by state; Western Australia’s Building and Energy division has published the clearest specific deadline (19 June 2026, after a six-month dual-acceptance period), while NSW guidance describes the 5139 update as mandatory immediately on publication. Confirm the position in your specific state before quoting a date to a client.
Australia’s New Battery Rules, Part 1: AS/NZS 5139:2019 Amendment 1 — Battery System Safety
Amendment 1 to AS/NZS 5139:2019 was published on 19 December 2025. The NSW Building Commission confirms that a battery installation failing to meet the updated requirements no longer complies with the Standard in NSW.
Western Australia’s Building and Energy division has set a specific full-compliance date: 19 June 2026. That follows a six-month transition period, during which both the 2019 base standard and the amended version are acceptable.
So the amendment touches definitions, installation diagrams, clearances, overcurrent protection, and safety documentation.
What Changed in Amendment 1
Several changes matter for day-to-day design work. First, Clause 1.3 introduces new and updated definitions. So terminology used on drawings needs a fresh check. Also, the typical BESS installation diagrams were revised — new figures 4.1A through 4.2A cover egress clearance, door and opening clearance, and unimpeded access to a pre-assembled integrated BESS.
Location, Fire Barriers, and Overcurrent Protection
Still, location rules loosened in one specific way. A battery system may now sit within 600mm of an opening, provided that opening is wider than 900mm, such as a garage door. Inverters are also now treated as an associated appliance, and are permitted inside a restricted location, which they previously were not.
Fire-barrier requirements got stricter instead. So exempt materials used as a barrier to a habitable room must now be at least 6mm thick. Building materials within 1 metre of a battery system classed as a chemical hazard also face new requirements.
Also, overcurrent protection for paralleled pre-assembled battery systems changed. The protection device’s kA rating must now match or exceed the combined fault current of every paralleled battery system, not just one. So a new Appendix I sets out how to calculate that cell short-circuit current. This pairs directly with existing short-circuit protection design work on the DC side of the system.
Safety Data Sheets
Safety Data Sheet handling was clarified too. A physical copy must stay on site, protected from damage — for example inside a sealed, durable, clear pouch. Installers should treat SDS storage as part of the handover package, not an afterthought.
AS/NZS 5139 Compliance Checklist for BESS Suppliers and Installers
- Battery enclosure design meets updated location and clearance rules
- Installation clearances reflect revised figures 4.1A–4.2A
- Fire protection strategy accounts for the 6mm minimum barrier thickness
- Overcurrent protection kA rating is calculated against combined paralleled fault current (Appendix I)
- Safety Data Sheets are on-site in a protective pouch
- Installation manuals and terminology match Clause 1.3 definitions
- Maintenance and emergency access procedures documented
Full guide: AS/NZS 5139 Battery Safety Standard — Amendment 1 Explained
Australia’s New Battery Rules, Part 2: AS/NZS 4777.2:2020 Amendment 2 — Inverter Requirements
AS/NZS 4777.2:2020 Amendment 2 governs how grid-connect inverters behave once installed. It is the second of the three new rules. Standards Australia released it in August 2024, then set a 12-month transition period. Full compliance became mandatory from 23 August 2025. So it now applies to every new low-voltage grid-connect inverter installation. That makes it the second pillar of the battery compliance stack.
CSIP-AUS and Smart Communication
First, the headline addition is CSIP-AUS, the Common Smart Inverter Profile for Australia. This communication protocol lets network operators manage dynamic export limits. In some cases, it also allows remote curtailment. A modern compliant inverter is built to be talked to by the grid, not just to push power onto it. The Clean Energy Council’s approved inverter list now reflects Amendment 2 as the current benchmark. Clean Energy Council’s approved inverter list now reflects Amendment 2 as the current benchmark.
What Installers Must Check
Older CEC listings did not carry over automatically. So manufacturers had to submit a declaration plus supporting evidence that their products met Amendment 2 before their listings kept standing. Installers should verify the exact model against the current CEC list — never trust a listing checked before August 2025.
Power quality settings still follow a region-based profile — Australia A, B, or C — set by the local distribution network service provider. This includes the ride-through behaviour covered in our LVRT and HVRT guide. This includes the ride-through behaviour covered in our LVRT and HVRT guide.
EV and V2G Provisions
Next, the amendment adds requirements supporting vehicle-to-grid and vehicle-to-building inverters. So bidirectional EV charging now shares the same grid-connect framework as solar and battery inverters. See our PCS overvoltage protection guide for how these settings interact with anti-islanding and ride-through coordination.
AS/NZS 4777.2 Compliance Checklist
- CEC approval status confirmed against the current list, not a pre-Aug-2025 listing
- Correct firmware version installed
- Grid protection settings match the DNSP’s region profile (A, B, or C)
- Anti-islanding function verified
- Export control compatibility confirmed
- CSIP-AUS capability documented
- LVRT/HVRT settings verified against ride-through requirements
Full guide: AS/NZS 4777.2 Amendment 2: What Changed for Inverter Requirements
Australia’s New Battery Rules, Part 3: AS/NZS 3008.1.1:2025 — Cable Selection
AS/NZS 3008.1.1:2025 is the third of Australia’s new battery rules. It replaces the 2017 edition that governed cable selection for eight years. Standards Australia published the new edition on 19 December 2025. That’s the same day as AS/NZS 5139 Amendment 1, not late 2024 as some secondary sources report. Both editions currently remain valid during the transition. In Western Australia, full compliance with the 2025 edition is required from 19 June 2026. This is the third and final pillar of the battery compliance stack.
New 1500V DC Cable Ratings
So the most significant scope change is new DC cable rating provisions up to 1500 volts. The 2017 edition barely covered DC circuits above 1000 volts. That left utility-scale solar strings and BESS rack-to-inverter cabling without a proper rating table. So the 2025 edition adds explicit current-rating tables for single-core DC cables, plus new provisions for DC fast-charger cabling. These new tables are already referenced alongside the DC specifications in our Understanding BESS Specifications guide.
Revised Grouping and Soil Derating Factors
Also, grouping and soil derating factors tightened. Cables on unperforated trays now carry lower derating factors than before. A six-circuit run on a solid tray, for instance, drops from a factor of 0.73 to 0.68. So that can push a cable size up a full commercial step. A new “very dry soil” row now covers desert and remote mining conditions the 2017 tables never addressed.
Transition Timeline
New Zealand runs its own transition clock. Still, the 2025 edition became available there at the same time as in Australia. But the 2017 edition is expected to be formally withdrawn around November 2026, once the standard 24-month transition period closes. Western Australia’s Building and Energy division confirms that both AS/NZS 5139 Amd 1:2025 and AS/NZS 3008.1.1:2025 were published 19 December 2025, with full compliance required from 19 June 2026 following a six-month period in which either edition is acceptable.
AS/NZS 3008.1.1 Compliance Checklist
- Cable voltage rating confirmed for the full DC operating window (up to 1500V where applicable)
- Maximum operating current calculated against the 2025 tables
- Short-circuit withstand capability checked against combined fault current
- Grouping and derating factors recalculated for unperforated trays with six or more circuits
- Soil thermal resistivity checked for underground runs, including the new “very dry soil” category
- Voltage drop calculation completed for the full cable run
Full guide: AS/NZS 3008.1.1:2025: What Changed for Cable Selection
Battery Product Certification vs. Australian Installation Compliance
One misunderstanding shows up often among international BESS suppliers. Often, they assume battery product certification alone satisfies Australia’s new battery rules and allows market entry. It doesn’t. A battery module can pass every relevant international safety test and still fail an Australian project. That happens whenever the installation, inverter, or cable design doesn’t separately satisfy AS/NZS 5139, AS/NZS 4777.2, and AS/NZS 3008.1.1. So product certification and installation compliance are different regulatory layers, and both are required.
Common Battery Product Certifications Referenced in Australian BESS Projects
| Certification | What It Covers | Typical Use |
| IEC 62619 | Industrial lithium-ion battery safety: electrical abuse protection, thermal safety, operational reliability | Commercial and industrial BESS, telecom energy storage |
| UL 1973 | Stationary battery safety at module, rack, and system level | Utility-scale and North American-influenced BESS specifications |
| UN38.3 | Transport safety: altitude, temperature, vibration, shock, short-circuit, and overcharge testing | Required before any international lithium battery shipment |
| IEC 63056 | Secondary lithium battery safety for stationary energy storage applications | Residential and commercial ESS, increasingly requested alongside IEC 62619 |
For a full breakdown of these certifications — what each one tests, who issues it, and typical cost and timeline — see our complete BESS Certifications Guide.
So none of these substitute for AS/NZS 5139 installation compliance, AS/NZS 4777.2 inverter or CEC approval, or AS/NZS 3008.1.1 cable design. For suppliers planning an Australian entry, compliance needs to be considered during BESS design. Enclosure layout, protection settings, and documentation format all belong at the design stage. None of it works well retrofitted after manufacturing is locked in.
How Australia’s New Battery Rules Work Together on One Job
These three standards do not operate in isolation on a real job. Take a paralleled battery system as an example, since it shows how Australia’s new battery rules stack on top of one another. First, AS/NZS 5139 Amendment 1 sets the required kA rating for its overcurrent protection device, based on the combined fault current. Then that same fault current drives the short-circuit withstand check on the DC cable under AS/NZS 3008.1.1. Meanwhile, the inverter tying it all to the grid still needs a valid CEC listing under AS/NZS 4777.2 Amendment 2. Miss any one layer, and the other two will not save the design.
So treat the battery compliance stack as one system, not three separate checklists. A designer who only checks the inverter datasheet will eventually hit a cable run that neither standard alone was built to catch. The same goes for a designer who only checks enclosure clearances. Check all three, every time — and check that the underlying battery product certification is in place before any of it matters.
Change Log — Australia’s New Battery Rules Hub
| Date | Version | Update |
|---|---|---|
| 26 Jul 2026 | v1.0 | Initial publication covering AS/NZS 5139 Amendment 1, AS/NZS 4777.2 Amendment 2, and AS/NZS 3008.1.1:2025. |
| 26 Jul 2026 | v2.0 | Corrected the AS/NZS 3008.1.1:2025 publication date to 19 December 2025. Added Western Australia’s specific 19 June 2026 compliance date. Added a new section comparing battery product certification (IEC 62619, UL 1973, UN38.3) with Australian installation compliance. |
| 26 Jul 2026 | v3.0 | Updated the page framing to lead with “Australia’s new battery rules” for clarity. |
| 26 Jul 2026 | v3.1 | Finalised page details ahead of publishing. |
| 28 Jul 2026 | v3.2 | Published all three detailed guides — AS/NZS 5139 Amendment 1, AS/NZS 4777.2 Amendment 2, and AS/NZS 3008.1.1:2025 — and linked them from their respective sections above. |
Australia’s New Battery Rules Checklist for 2026
- Confirm every new BESS design references AS/NZS 5139:2019 including Amendment 1, and check your state’s specific enforcement timeline.
- Check the inverter model against the current CEC approved list for AS/NZS 4777.2:2020 Amendment 2 compliance — a pre-amendment listing did not carry over automatically.
- Specify cable sizing to AS/NZS 3008.1.1:2025 for new designs, even during the transition period.
- Recalculate DC cable sizes on unperforated trays with six or more circuits — the 2025 grouping factors are more conservative.
- Confirm battery product certifications (IEC 62619, UL 1973, UN38.3, IEC 63056 as applicable) are current, and don’t treat them as a substitute for the three installation standards above.
- Revisit this hub whenever an amendment publishes — the battery compliance stack changes faster than most single-standard guides track.
Frequently Asked Questions
What are Australia’s new battery rules?
It’s the combination of standards required for a compliant BESS installation in Australia: AS/NZS 5139 for battery system safety, AS/NZS 4777.2 for inverter/grid-connect performance, and AS/NZS 3008.1.1 for cable selection. A project needs all three — passing one doesn’t clear the others.
When did AS/NZS 5139 Amendment 1 and AS/NZS 3008.1.1:2025 take effect?
Both were published on 19 December 2025. NSW guidance treats the 5139 update as mandatory immediately on publication. Western Australia’s Building and Energy division has set 19 June 2026 as the date full compliance is required for both standards, following a six-month transition period. Confirm the position with your specific state regulator, since implementation timing is not uniform nationally.
Does every battery inverter need CEC approval in Australia?
Grid-connected inverters used in eligible Australian installations generally require approval through the Clean Energy Council’s approved inverter list, and that listing must reflect AS/NZS 4777.2 Amendment 2 compliance specifically — pre-August-2025 listings did not carry over automatically.
Are IEC 62619 or UL 1973-certified batteries automatically approved for use in Australia?
No. These certifications demonstrate battery product safety, but the complete BESS system still needs to separately satisfy AS/NZS 5139 installation compliance, AS/NZS 4777.2 inverter compliance, and AS/NZS 3008.1.1 cable design compliance.
What standard covers BESS cable sizing in Australia?
AS/NZS 3008.1.1:2025 provides current-carrying capacity, voltage drop, and derating guidance for AC and DC cables, including the new tables for DC systems up to 1500V introduced in the 2025 edition.
Further Reading
- Changes to the Battery Standard — NSW Government
- Updated Electrical Installation Standards for Battery Systems and Cable Selection — WA Government (Building and Energy)
- AS/NZS 4777.2 Inverter Standards Change — Clean Energy Council
- AS/NZS 3008.1.1:2025 Updates for Solar Cable Design — GSES
- AS/NZS 5139:2019 (incorporating Amendment 1) — Standards Australia Store
- BESS Short Circuit Protection
- PCS Overvoltage Protection
- LVRT and HVRT Ride-Through
- Understanding BESS Specifications
- VEU Rebate for Victoria: What the Program Actually Covers in 2026
Earthing (Grounding) for a Battery Energy Storage System (BESS): A Complete Design Guide
A BESS grounding system ties every battery rack, enclosure, and steel structure back to a common earth point. So, when a fault happens, current gets a fast path home. But get the BESS grounding system wrong, and one insulation fault can turn a cabinet into a shock hazard. It can also start a slow fire risk. So this guide covers the earthing methods, code rules, and design steps that keep a battery storage site safe. First, it covers soil testing. Then it covers ground grid sizing.
| Quick Answer A BESS grounding system bonds every metal part of a battery storage site to a common earth reference. Earthing is the term IEC-based countries use. Grounding is the U.S. term. But both mean the same thing. In the U.S., NEC Article 706 sets the rules for systems above 50V AC or 60V DC. Meanwhile, most other countries follow IEC 60364 instead. That standard defines TN, TT, and IT earthing systems. Also, a strong BESS grounding system needs a buried grounding electrode system. Many modern DC buses add high-resistance grounding too. So an insulation monitoring device watches for faults, instead of a solid ground wire alone. |
Why a BESS Grounding System Matters
Grounding is not paperwork. Instead, it decides whether a fault trips a breaker in milliseconds. Or, it decides whether a fault energizes a cabinet a technician is standing next to. A BESS site packs high fault current into a small footprint. Also, workers open enclosures often for maintenance. So the margin for error stays thin.
Personnel Safety
A bonded enclosure stays close to earth potential during a fault. But without that bond, a failure inside a battery cabinet can raise the metal casing to a dangerous voltage. Then anyone touching it completes the circuit. So this is the core safety case behind every BESS grounding system, at any project size.
Equipment and Fire Protection
A fast, low-impedance fault path lets breakers clear a ground fault quickly. Otherwise, the fault can grow into an arcing fault. And arcing near lithium-ion cells is a real ignition risk.
Our BESS short-circuit protection guide covers that risk in detail. So a sound BESS grounding system and short-circuit protection work as one safety strategy, not two separate items.
Protective-Device Coordination
Relays and fuses only work as fast as the fault path allows. But a weak ground path slows fault detection down. As a result, a fault can stay energized far longer than planned. So grounding design and protection coordination need to be solved together.
Earthing vs. Grounding: Same Idea, Different Vocabulary
Earthing and grounding name the same practice. First, IEC-based markets say earthing. That includes the UK, the EU, Australia, and most of Asia. Then, NEC-based markets say grounding. The United States is the main example. Still, both terms mean bonding conductive parts to earth for safety. So this guide uses both terms, matching whichever code applies to a given project.
Codes and Standards Behind a BESS Grounding System
No single global code covers earthing for battery storage. Instead, a BESS grounding system usually has to satisfy several overlapping standards. So the table below summarizes the main ones.
| Standard | Region | What It Covers |
|---|---|---|
| NEC (NFPA 70) Article 706 | United States | Covers permanently installed ESS above 50V AC or 60V DC. Sets bonding, disconnect, and circuit-protection rules |
| IEC 60364 | International | Defines TN, TT, and IT earthing system classes for low-voltage installations |
| IEEE Std 80 | International reference | Guide for AC substation grounding. Sets step- and touch-voltage limits for larger ground grids |
| IEEE Std 142 (Green Book) | International reference | General power-system grounding practice, covering equipment and system grounding |
| NFPA 855 | United States | ESS siting and spacing, which pairs with grounding design |
For example, NEC Article 706 sets the U.S. baseline for a BESS grounding system. Also, our NFPA 855 guide covers the fire-code side of siting and spacing. Meanwhile, lightning protection sits alongside a BESS grounding system, not inside it. We cover that later in this guide.
NEC Article 706’s scope line matters most for design choices. So it applies to any permanently installed ESS above 50V AC or 60V DC. That covers nearly every commercial and utility-scale BESS grounding system built today.
Types of Earthing Systems in a BESS Grounding System
TN, TT, and IT Systems (IEC 60364)
IEC 60364 uses a two-letter code for each earthing system. First, the first letter shows how the source relates to earth. Then, the second shows how equipment is earthed. TN systems bond equipment to the source’s earthed neutral. So that gives fast fault clearance through ordinary breakers. TT systems instead use a separate, independent earth electrode at the site. They rely on residual-current devices to catch smaller faults. IT systems isolate the source from earth, or use high impedance instead. So this favors continuity of supply over instant clearance. It is a common choice for critical DC sections.
See this IEC 60364 earthing system overview for the full classification breakdown.
Solidly Grounded, Ungrounded, and High-Resistance Grounded DC Buses
The battery-side DC bus needs its own decision, separate from the AC earthing system. First, older, PV-derived designs often grounded the DC bus solidly. Then a ground-fault detector-interrupter opened the bond on a fault. Today, many modern, transformerless power conversion systems instead run the DC bus ungrounded or high-resistance grounded. So an insulation monitoring device watches it continuously, instead of a fuse-based interrupter. The table below compares all three approaches.
| Approach | Fault Detection | Typical BESS Use |
|---|---|---|
| Solidly grounded | Fast — an overcurrent device clears the fault path directly | Legacy PV-battery hybrids, some low-voltage residential or C&I designs |
| Ungrounded (floating) | Continuous insulation-resistance monitoring, no automatic first-fault trip | Modern transformerless PCS topologies where uptime matters most |
| High-resistance grounded | Limits fault current while a monitoring device flags the fault | Utility-scale strings and central PCS designs balancing safety and uptime |
This choice depends heavily on PCS topology. So it belongs in the same conversation as PCS overvoltage protection and grid-forming versus grid-following control. It should never be bolted on after the fact.
Core Components of a BESS Grounding System
Equipment Grounding and Bonding in a BESS Grounding System
Every metal enclosure, rack, and structural part needs a bonding jumper. That jumper must reach back to the grounding system. Also, it needs to be sized for the worst-case fault current. First, painted surfaces need a bare-metal bonding point, since paint is an insulator. Also, fence gates and conduit expansion joints need flexible jumpers, so thermal movement never breaks continuity.
Conductor size follows the code, not a guess. So the table below gives quick reference points for both major code families.
| Reference | Basis | Quick Rule |
|---|---|---|
| NEC Table 250.66 (GEC sizing) | Size of the largest ungrounded service conductor | A GEC run solely to a rod, pipe, or plate electrode never needs to exceed 6 AWG copper |
| NEC Table 250.122 (EGC sizing) | Rating of the upstream overcurrent device | Equipment grounding conductors scale with breaker or fuse size, not with the circuit conductor size |
| IEC 60364-5-54 (PE sizing) | Cross-sectional area of the phase conductor | PE equals the phase size up to 16 mm², stays at 16 mm² up to 35 mm², then drops to half the phase size above that |
The Grounding Electrode System
This is the buried hardware that gives fault current a path into the earth. It can be ground rods, a ground ring, or a full mesh grid. So, site size drives the choice. First, a small C&I rooftop or pad-mounted BESS can use a simple rod-based electrode system. Then, a utility-scale site instead needs a buried copper mesh grid. That grid must meet IEEE 80 step- and touch-voltage limits.
Grounding a Containerized or Mobile BESS
Containerized and trailer-mounted BESS units add a wrinkle. Often, they sit on gravel, asphalt, or a temporary pad, not poured concrete. So a concrete-encased electrode is rarely an option there. Instead, crews drive temporary ground rods, or lay a portable ground mat, at each deployment site. Also, every container or trailer section needs a bonding strap back to that temporary electrode, plus jumpers between linked sections. Since soil conditions change from site to site, resistance needs a fresh test at every new location, not just once back at the factory.
DC Ground-Fault Detection and Insulation Monitoring
On the DC side, ground-fault detector-interrupters and insulation monitoring devices solve the same problem in different ways. Both catch a fault between a live conductor and ground before it becomes an arc. Also, an insulation monitoring device measures leakage resistance continuously. So it raises an alarm well before resistance drops to a dangerous level. That is why it has become the default choice on ungrounded and high-resistance grounded DC buses.
Avoiding Ground Loops in a BESS Grounding System
Power grounding is not the only ground reference on a BESS site. Comms wiring also needs care. That includes CAN bus, RS-485, or IEC 61850 links between racks, the BMS, and the PCS. So a shielded comms cable should bond to ground at one end only. Otherwise, bonding both ends creates a ground loop. Then, even a small voltage difference between the two ground points drives current through the shield. That current, in turn, induces noise onto the signal pair. Common symptoms include noisy cell-voltage readings, checksum errors, and comms dropouts, especially during heavy charge or discharge events. So plan single-point grounding for comms at design time, not after commissioning turns up faults.
Designing a BESS Grounding System’s Electrode Network
Soil Resistivity Testing
Soil resistivity, not conductor size, drives ground rod performance the most. It shifts with moisture, temperature, and soil type. So a resistivity survey should happen early in site design, not after the rods are already buried. The four-pin Wenner method is the standard test. Also, sandy or rocky soil can carry resistivity several times higher than loam. That directly raises the rod count, the grid area, or the need for ground-enhancement material.
The Concrete-Encased Electrode (Ufer Ground)
Most C&I and utility-scale BESS pads already sit on poured concrete. So that concrete can double as a grounding electrode. NEC 250.52(A)(3) allows this. A concrete-encased electrode, often called a Ufer ground, uses at least 20 feet of rebar or bare copper conductor, encased in at least 2 inches of concrete that touches the earth. Since a Ufer ground typically beats a driven rod on resistance, especially in dry or rocky soil, it is worth planning before the pour, not after. Once the concrete cures, adding one later means breaking into a finished pad.
Worked Example: Sizing Ground Rods for a C&I BESS Pad
Take a standard 8-foot, 5/8-inch copper-clad ground rod. Place it in average loam soil, with a resistivity of 100 Ω·m. Using the standard single-rod resistance formula, that rod works out to roughly 40 Ω. So that is above the 25 Ω threshold NEC 250.53(A)(2) sets for a single rod, pipe, or plate electrode. Then, a second rod, spaced at least 6 feet away, usually brings the combined resistance under that 25 Ω limit. But mutual interference between rods means the drop is never a clean 50%. In high-resistivity ground — sandy or rocky soil at 300 Ω·m or more — a single rod can exceed 100 Ω. There, the fix shifts from adding rods to a driven ground ring, chemical rods, or ground-enhancement backfill.
Step and Touch Voltage for Utility-Scale Sites
Larger sites need more than a resistance number. So IEEE Std 80 sets tolerable step- and touch-voltage limits. These depend on soil resistivity, fault-current size, and clearing time. Then, the standard works backward to the mesh spacing a ground grid needs. Still, a grid can show low overall resistance and still fail an IEEE 80 check. That happens when the voltage gradient across the grid surface runs too steep. So resistance alone is never the full design target for a utility-scale BESS grounding system.
See this IEEE Std 80 grounding interpretation for the underlying safety criteria.
Lightning Protection Sits Alongside Earthing
Lightning protection systems use their own down-conductor and electrode network. NFPA 780 covers this in the U.S. IEC 62305 covers it internationally. So this network is engineered for high-frequency surge current. It stays distinct from the power-system grounding electrode system. Still, the two networks are typically bonded together at grade. That prevents a dangerous potential difference between them during a strike.
Surge protective devices on the AC and DC sides, covered in our PCS overvoltage protection guide, round out the site’s full surge coordination plan.
Common BESS Grounding System Mistakes
- Treating a painted enclosure surface as a bonding point, instead of scraping to bare metal first.
- Installing a single ground rod without testing resistance, then assuming it clears the NEC 25 Ω threshold.
- Skipping flexible bonding jumpers across fence gates and conduit joints, which breaks continuity as materials move.
- Solidly grounding a DC bus on a transformerless PCS without checking manufacturer guidance, which can cause nuisance trips.
- Sizing a ground grid to a resistance target alone, with no IEEE 80 step- and touch-voltage check on a utility-scale site.
- Bonding bare copper directly to galvanized steel rebar or racking in humid or coastal soil, which speeds up galvanic corrosion at the connection point.
- Never re-testing soil resistivity or ground resistance after commissioning, even though seasonal moisture changes both.
Key Takeaways
- A BESS grounding system bonds every conductive part to a common earth reference. That gives fault current a defined, low-impedance path home.
- NEC Article 706 governs U.S. installations above 50V AC or 60V DC. IEC 60364’s TN, TT, and IT classes govern most other markets.
- Many modern, transformerless PCS designs run the DC bus ungrounded or high-resistance grounded. An insulation monitoring device watches it instead of a solidly grounded fuse-based interrupter.
- A single ground rod in average soil rarely meets NEC’s 25 Ω threshold alone. Test soil resistivity before the rods go in the ground, not after.
- A poured concrete BESS pad can double as a Ufer ground under NEC 250.52(A)(3), often beating a driven rod on resistance in dry or rocky soil.
- Keep comms shields single-point grounded. Bonding both ends of a CAN bus, RS-485, or IEC 61850 shield creates a ground loop that shows up as noisy readings and comms dropouts.
- Utility-scale sites need an IEEE 80 step- and touch-voltage check. A low resistance reading alone does not guarantee a safe voltage gradient.
- Lightning protection and power-system grounding are separate networks. Bond them together at grade; do not treat them as one system.
- Grounding design, short-circuit protection, and overvoltage protection form one coordinated safety strategy, not three separate checklists.
Frequently Asked Questions
Does the NEC Require a BESS Grounding System?
Yes. For any permanently installed ESS above 50V AC or 60V DC, NEC Article 706 sets bonding, disconnect, and circuit-protection rules. These form the core of a compliant BESS grounding system.
What Ground Resistance Does a BESS Grounding System Need?
The NEC benchmark for a single rod, pipe, or plate electrode is 25 Ω or less. If one rod misses that mark, add a supplemental rod at least 6 feet away. Utility-scale sites also need an IEEE 80 step- and touch-voltage check, on top of a lower target resistance.
Should a BESS DC bus be grounded or ungrounded?
It depends on the PCS topology. Many modern, transformerless designs use an ungrounded or high-resistance grounded DC bus with continuous insulation monitoring. Some legacy or transformer-based designs still solidly ground the bus with a ground-fault detector-interrupter. Follow the PCS manufacturer’s guidance rather than a default assumption.
Does a Containerized or Mobile BESS Need Different Grounding?
Yes, somewhat. A fixed pad lets a BESS grounding system use a concrete-encased electrode. A mobile or trailer-mounted unit usually cannot rely on that. So it needs temporary ground rods or a portable ground mat at each site, plus fresh resistance testing every time it moves.
How often should a BESS grounding system be tested?
Test ground resistance and bonding continuity at commissioning first, using a fall-of-potential test or a clamp-on ground resistance tester. Then, re-test on a regular maintenance schedule. Soil resistivity shifts with seasonal moisture and temperature, so a compliant reading at commissioning can drift over time.
Further Reading
- BESS Short Circuit Protection
- PCS Overvoltage Protection
- Understanding BESS Specifications
- NFPA 855 Guide
- LVRT and HVRT Ride-Through
- Grid-Forming vs. Grid-Following BESS
- BESS PCS Functions and Features
- NEC Article 706 overview (up.codes)
- IEEE Std 80 substation grounding interpretation (standards.ieee.org)
- IEC 60364 earthing system classification overview (ecalpro.com)
BESS Augmentation: AC Block Addition vs. DC Shuffling — How Mid-Life Capacity Upgrades Actually Work
AC block addition is one of two ways to carry out BESS augmentation. BESS augmentation, in short, restores capacity a battery loses over time. Every charge and discharge cycle wears the cells down. So, after a few years, the system can no longer deliver its full contracted energy or power. AC block addition fixes this by adding new inverters and battery racks on the AC side. DC shuffling, the other path, instead reallocates existing modules behind the inverters already on site. Each approach, however, solves the same problem differently.
| Quick Answer AC block addition installs a new, independent power block behind its own connection point. It costs more and needs more space. However, it works with any battery chemistry, and it skips synchronization headaches with old cells. DC shuffling, by contrast, reorganizes and adds battery modules behind the existing inverters. It costs less, and it often avoids new interconnection permits. But busbar ratings, breaker capacity, and voltage matching all limit how much capacity it can add. |
Why BESS Augmentation Needs a Capacity-Adding Strategy
This guide focuses on the technical mechanics of the two paths. For the full picture on BESS augmentation as a strategy, including how it compares to oversizing capacity upfront, see our BESS Augmentation: The Complete Guide.
Lithium-ion cells degrade with use. So does calendar time alone. Each cycle stresses the electrode material. Specifically, the protective SEI layer on the anode cracks and reforms. This, in turn, consumes active lithium every time. High charge rates and cold temperatures make it worse.
Fade rates vary by chemistry and duty cycle. Many grid-scale LFP systems, for instance, lose roughly 2 to 3 percent of usable capacity per year. As a result, after five to seven years, a project can fall short of its contracted energy or power. That, in turn, threatens revenue under tolling agreements and capacity contracts.
BESS augmentation exists to close that gap. It adds capacity back, either instead of, or alongside, overbuilding extra capacity at day one. Modo Energy’s research on the topic frames it simply: augmentation restores or increases capacity, and both outcomes improve a project’s revenue potential.
Cycle Aging and the Restore Buffer
BESS augmentation is not a one-time fix. Instead, most projects restore capacity to a buffer above nameplate, not just back to nameplate. That buffer, in turn, gives headroom before the next augmentation cycle is needed.
Here is the catch. That buffer is defined in AC terms, at the point of interconnection. See our guide to understanding BESS specifications for how nameplate, usable, and contracted energy differ. But the actual work is a DC decision, since operators install battery cells, not AC megawatts. So, converting between the two requires accounting for round-trip losses across the inverter and transformer.
AC Block Addition Explained
How the AC Path Works
AC block addition adds a self-contained power block next to the existing system. New battery racks, a new PCS, and often a new transformer, arrive as one unit. The block then synchronizes independently at the AC bus, or at a new point of interconnection. Because the new block does not share a DC bus with old batteries, voltage and state-of-charge mismatches between aged and fresh cells never become a problem.
Pros and Cons of the AC Path
Advantages:
- Works with any battery chemistry — operators can add a sodium-ion or next-generation LFP block next to an aging system.
- Needs no voltage or state-of-charge synchronization with degraded cells.
Offers a chance to upgrade PCS technology, such as adding grid-forming capability, alongside the capacity add.
- Creates a clean equipment and warranty boundary between old and new hardware.
Drawbacks:
- Costs more, since a new PCS, transformer, and switchgear all add expense.
- Needs more physical footprint.
- Often triggers a new interconnection study or re-permitting, since new grid-connected hardware is involved.
Adds a new fault-current source, so protection settings must be re-coordinated.
DC Shuffling Explained
DC shuffling reorganizes existing battery modules behind the inverters already in service. Modules with similar degradation profiles get grouped together. This, in turn, spreads energy more evenly across the stack. On its own, however, shuffling does not add any capacity. It just rebalances what is already there.
Real capacity gets added only when new racks are added behind the same PCS, after the existing fleet has been shuffled and rebalanced. Because the new capacity shares the existing inverter and bus, the project may be able to avoid a new grid interconnection point. However, permitting and approval requirements still depend on the scope of the modification and the applicable jurisdiction. A DC-to-DC converter can help reconcile the voltage gap between old and new modules. The converter itself, though, adds no capacity on its own.
Technical Limits of DC Shuffling
DC shuffling looks cheap on paper. However, it runs into hard technical ceilings. As Energy-Storage.News has reported, auxiliary load breakers and busbars were sized for the original system. So, adding capacity behind them can exceed that rating.
Adding capacity also raises the available fault current the busbar must survive, measured against its short-time withstand rating. As a result, retrofitting an undersized bus is expensive and disruptive.
Old and new modules, moreover, rarely match perfectly in voltage, capacity, resistance, SOC, or SOH. Without careful matching and appropriate BMS coordination, the newer modules may be limited or taken offline to protect the string. That, in turn, can reduce the usable capacity gain.
For a detailed look at the electrical, thermal, BMS, and string-level challenges of combining different-age modules, see our guide to Mixed-Age String Design After BESS Augmentation.
Sizing the Restore Buffer: AC Target to DC Install
Sizing starts at the point of interconnection, not at the battery rack. Consider a 100 MW, 400 MWh project. After five years, it has faded to 340 MWh of usable energy at the AC side. The operator, in this case, wants to restore headroom to 110 percent of nameplate, or 440 MWh.
That means the project needs 100 MWh of additional AC-side energy. Because DC-to-AC conversion is not lossless, the DC installation must be larger than the AC target. At a typical round-trip factor near 96.5 percent, for example, the operator installs about 104 MWh of new DC capacity to deliver 100 MWh at the AC side.
This buffer-based approach, in short, avoids a common trap. Sizing an augmentation exactly to today’s shortfall just guarantees another shortfall, and another expensive site visit, a year or two later.
AC Block Addition vs. DC Shuffling: At a Glance
| Dimension | AC Block Addition | DC Shuffling |
| New grid connection required | Usually, yes | Usually, no |
| Typical capital cost | Higher | Lower |
| Footprint | Larger — new PCS, transformer, switchgear | Smaller — reuses existing enclosures |
| Chemistry flexibility | Any chemistry | Must match voltage/SOC with existing cells |
| PCS / protection impact | New PCS; new fault-current source to coordinate | Existing PCS; busbar and breaker ratings cap headroom |
| Typical permitting timeline | Months — new interconnection study | Weeks to months — often no new grid approval |
| Best fit | Later-life projects, chemistry upgrades, PCS refresh | Earlier-life projects with headroom in the existing bus |
Choosing Between AC Block Addition and DC Shuffling
When AC Block Addition Makes Sense
AC block addition tends to make sense later in a project’s life, once the original PCS is also due for a technology refresh. It is also the better fit when an operator wants to introduce a different battery chemistry, such as pairing a sodium-ion block with an existing LFP fleet.
When DC Shuffling Makes Sense
DC shuffling, on the other hand, fits best earlier in a project’s life, while the existing busbar and breakers still have headroom. It also suits sites where a new interconnection study would be slow or costly. As cell sizes grow past 500 Ah and system voltages rise, some integrators expect DC block designs, and DC shuffling along with them, to look different in the next generation of projects.
Key Takeaways: AC Block Addition vs. DC Shuffling
1. Degradation is inevitable — plan for it before contracted capacity is at risk.
2. Restore buffers are set in AC terms at the point of interconnection, but installed as DC energy.
3. AC block addition costs more but sidesteps chemistry-matching and synchronization limits.
4. DC shuffling costs less but is capped by busbar, breaker, and voltage-matching limits.
5. The right path depends on project age, available headroom, and permitting timeline.
FAQ About AC Block Addition and DC Shuffling
What Is AC Block Addition?
AC block addition is one way to carry out BESS augmentation. It installs a new, independent power block, complete with its own inverters, next to an existing system, to restore or increase capacity lost to degradation.
Does DC Shuffling Alone Add Capacity?
No. Shuffling alone just reorganizes existing modules for better balance. Capacity, however, is only added when new racks get installed behind the shuffled system.
How Much Does This Augmentation Path Cost?
Cost varies by project size, chemistry, and the path chosen. DC shuffling generally costs less per MWh added, since it reuses the existing PCS and transformer. AC block addition, by contrast, costs more, but it includes new power conversion equipment.
Does DC Shuffling Require New Interconnection Permits?
Usually not. Since no new physical connection is made to the grid, DC shuffling can often bypass a fresh interconnection study. AC block addition, on the other hand, usually cannot.
Can AC Block Addition Mix Battery Chemistries?
Yes. Because the new block has its own PCS and DC bus, it does not need to match the voltage or chemistry of the existing system.
Further Reading
- BESS Augmentation: The Complete Guide
- Mixed-Age String Design After BESS Augmentation
- BESS PCS Functions and Features
- Grid-Forming vs. Grid-Following BESS
- BESS Short Circuit Protection
- PCS Overvoltage Protection
- Understanding BESS Specifications
- AC and DC Augmentation in BESS — Energy-Storage.News
- Augmentation: What Is It and Why Is It Important to BESS? — Modo Energy
BESS Augmentation: The Complete Guide to Restoring Capacity Lost to Degradation
BESS augmentation is the process of adding new battery capacity to an existing energy storage system. It restores or increases capacity lost to degradation. Every BESS loses usable capacity over time. Cycling wears down the cells. Calendar aging adds to it too, even when the system sits idle. So, eventually, the project can no longer deliver the energy or power it promised. BESS augmentation exists to close that gap. It does this by restoring nameplate capacity, or by pushing past it.
| Quick Answer BESS augmentation adds new battery capacity to an existing system, later in its life, to restore or increase capacity lost to degradation. It differs from oversizing, which installs extra capacity upfront. Owners execute augmentation one of two ways: AC block addition, which adds a new self-contained power block, or DC shuffling, which reallocates and adds capacity behind the existing inverters. |
What Is BESS Augmentation?
BESS augmentation and BESS oversizing solve the same problem. However, they act at different points in a project’s life. Oversizing installs extra capacity on day one. This happens before any degradation occurs. BESS augmentation, on the other hand, adds capacity later. It happens once real-world fade has been measured. Our BESS oversizing guide covers that upfront strategy in full. It also covers the trade-off between the two paths. This guide, instead, focuses on the mid-life path. It covers what triggers augmentation, how it works, and how to plan for it.
BESS Augmentation vs. Oversizing: The Short Version
Neither strategy is strictly better. Oversizing locks in capital and tax credits early. But it carries idle capacity for years. BESS augmentation, in contrast, defers that capital. It depends on good execution years later. By then, battery prices, chemistry options, and site conditions may all have changed.
| Factor | BESS Augmentation (Mid-Life) | BESS Oversizing (Upfront) |
| Capex timing | Deferred to year 5-10 | Higher Day-1 cost |
| Section 48E ITC eligibility | Can face reduced eligibility on added capacity | Full credit on entire capacity at commissioning |
| Execution risk | Depends on future prices, chemistry, site conditions | Locked in at commissioning |
| Physical planning | Needs reserved space and headroom | Full footprint installed upfront |
| Best fit | Falling-price markets, budget-constrained projects | ITC-sensitive, stable-forecast projects |
Why Projects Need BESS Augmentation
Lithium-ion cells fade with every charge and discharge cycle. Specifically, the protective layer on the anode cracks and reforms with each cycle. This consumes active lithium. High charge rates and cold temperatures also speed up the damage. Meanwhile, calendar time adds a slower fade on top of cycling.
For some grid-scale LFP projects, usable-capacity fade may average around 2–3% per year, but actual degradation varies substantially with operating conditions, climate, duty cycle, and cell design. As a result, after five to seven years, many projects fall short of their contracted energy or power. That, in turn, threatens revenue directly.
Capacity Guarantees and Tolling Agreements
Most utility-scale BESS projects operate under a tolling agreement or a capacity sale agreement. These contracts are priced against a guaranteed deliverable capacity. This is not simply nameplate capacity at commissioning. So, if degradation erodes that capacity below the contracted floor, trouble follows. The owner then faces liquidated damages or lost revenue. BESS augmentation, therefore, is how owners keep that promise as the asset ages.
These agreements often run 10 to 20 years. So, the augmentation plan is not an afterthought. Instead, it gets built into the financial model at financial close. It sits alongside the degradation curve and the warranty terms.
The Two Paths to BESS Augmentation: AC and DC
There are two ways to physically carry out BESS augmentation. One works on the AC side. The other works on the DC side.
AC Block Addition
First, AC block addition installs a new, self-contained power block next to the existing system. It comes with its own inverters, and often its own transformer too. Because it does not share a DC bus with the old batteries, it avoids voltage and state-of-charge mismatches. It also works with any battery chemistry. As a result, it opens the door to pairing a newer chemistry with an aging LFP fleet.
DC Shuffling
Second, DC shuffling reorganizes existing battery modules behind the inverters already on site. It does not add capacity by itself; additional capacity requires installing new battery modules or racks. It reuses the existing power conversion equipment. This, in turn, keeps costs down. However, busbar ratings, breaker capacity, and voltage matching all place a ceiling on how much it can add.
When new and aged modules share the same DC string, however, the design becomes more complex. For the BMS and string-level considerations, see our guide to Mixed-Age String Design After BESS Augmentation.
For a detailed technical comparison of these two approaches, see our guide to AC block addition vs. DC shuffling guide walks through the full technical comparison. It includes a worked example for sizing the restore buffer. It also covers the busbar and short-circuit limits that cap DC shuffling.
What Triggers a BESS Augmentation Decision?
BESS augmentation planning typically starts at a trigger point. That point is when a site’s measured state of health nears the level needed for its contracted output. Operators track this through periodic capacity tests. In addition, battery management system state-of-health estimates support the tracking. So, neither relies on guesswork.
Typical Timing: Year Five to Year Ten
For most grid-scale LFP projects, that point arrives between year five and year ten. Cycling intensity and climate both affect the timing. For instance, hot climates and aggressive cycling schedules push the timeline sooner. On the other hand, shallow cycling, or oversizing at commissioning, pushes it further out.
Planning early matters a great deal. A reactive BESS augmentation project, ordered only after a shortfall occurs, has far less room to negotiate. Because of that, procurement timelines, chemistry options, and price all suffer.
Battery Chemistry and BESS Augmentation Planning
Battery chemistry affects how easily new capacity can be added. LFP has a relatively flat voltage curve, which can make voltage matching less restrictive than with chemistries such as NMC. However, old and new LFP modules still require careful matching of SOC, SOH, resistance, voltage limits, and BMS behavior before they are combined. This is one reason DC shuffling is more common on LFP systems.
AC block addition, however, removes chemistry matching from the equation entirely. The new block runs its own inverters. So, an operator can add a different chemistry, such as sodium-ion, next to an existing LFP fleet. No voltage curves need to line up.
Tax Credits, Costs, and Procurement for BESS Augmentation
The tax picture for BESS augmentation is less favorable than for oversizing. Under Section 48E, the tax credit applies most cleanly to capacity installed at commissioning. The tax treatment of capacity added through mid-life augmentation can differ from capacity installed at initial commissioning. Project owners should confirm current Section 48E eligibility and applicable requirements with qualified tax advisors before making the augmentation decision. It can also add compliance work. This is a core trade-off against upfront oversizing. So, model it carefully before committing to a mid-life augmentation strategy.
Procurement timelines also differ sharply between the two paths. DC shuffling makes no new grid connection. So, it can often skip a fresh interconnection study. AC block addition, in contrast, usually cannot skip that step, since it adds new grid-connected hardware. That difference alone can add months to the schedule.
Cost varies too. DC shuffling generally costs less per megawatt-hour added. This is because it reuses the existing PCS, transformer, and switchgear. AC block addition costs more. However, it buys a clean equipment boundary. It also adds the option to upgrade power conversion technology at the same time.
A Practical BESS Augmentation Planning Checklist
1. Confirm the site’s actual state-of-health trend against the contracted capacity floor.
2. Model the restore buffer in AC terms, then convert it to a DC installation size, accounting for round-trip losses.
3. Choose between AC block addition and DC shuffling based on busbar/breaker headroom, chemistry needs, and permitting timeline.
4. Reserve physical space for future modules if a DC shuffling path is likely.
5. Model the Section 48E tax credit and financing impact of adding capacity mid-life.
6. Build procurement and, if needed, interconnection lead time into the schedule early.
Key Takeaways on BESS Augmentation
1. BESS augmentation restores or increases capacity lost to degradation, later in a project’s life.
2. Most grid-scale LFP projects need to plan for it between year five and year ten.
3. Tolling agreements and capacity sale agreements make augmentation a contractual necessity, not an option.
4. AC block addition and DC shuffling are the two execution paths, with different cost, timeline, and chemistry trade-offs.
5. Augmented capacity can face reduced Section 48E tax credit eligibility compared to capacity installed at commissioning.
Frequently Asked Questions About BESS Augmentation
When Should a Project Plan for BESS Augmentation?
In short, BESS augmentation planning should begin early. It should start as soon as a site’s degradation curve first threatens a future contract obligation. It should not wait until after a shortfall occurs.
What’s the Difference Between BESS Augmentation and BESS Oversizing?
Oversizing installs extra capacity upfront, before degradation happens. BESS augmentation, by contrast, adds capacity later, once real-world fade has been measured. Oversizing generally captures a fuller tax credit. It also carries lower operational complexity. Augmentation, however, defers capital and can benefit from falling battery prices.
Does Augmented Capacity Qualify for the Section 48E Tax Credit?
Capacity installed at commissioning generally qualifies most cleanly for the Section 48E credit. Capacity added later through augmentation, however, can face reduced eligibility or added compliance work. So, this should be modeled carefully before choosing a mid-life strategy.
How Long Does a BESS Augmentation Project Take?
Timelines vary by path. DC shuffling projects typically avoid a new interconnection study. So, they can often move in weeks to a few months. AC block addition projects, on the other hand, usually require new grid-connected hardware. As a result, they more commonly take several months, due to interconnection and permitting steps.
What’s the Difference Between AC Block Addition and DC Shuffling?
AC block addition installs a new, independent power block with its own inverters. It works with any battery chemistry. DC shuffling, in contrast, reallocates and adds capacity behind the existing inverters. It costs less, but it is limited by busbar, breaker, and voltage-matching constraints.
Further Reading
- BESS Oversizing: Pros, Cons & the Right-Sizing Strategy
- AC Block Addition vs. DC Shuffling
- Mixed-Age String Design: Managing a BESS String After Augmentation Adds New Cells
- Understanding BESS Specifications
- Battery State of Health (SoH) Estimation Guide
- What Is a Tolling Agreement in BESS? — BESS.courses
- Augmentation: What Is It and Why Is It Important to BESS? — Modo Energy
PCS Overvoltage Protection: Coordinating Transformer and Inverter Defense Against High-Voltage Grid Faults
Key Takeaway
PCS overvoltage protection is the layered set of defenses that keeps power conversion systems and transformers online, and undamaged, when grid voltage swells past normal limits. It combines fast surge arresters, DC-bus crowbar circuits, software ride-through control, and coordinated relay settings into one system. So it does not treat the transformer and the inverter as separate problems.
In short, it lines up transformer insulation limits with inverter chip limits. When a high-voltage grid fault hits, ride-through control briefly adjusts reactive current. At the same time, surge arresters and firmware limits shield the delicate IGBT or SiC switches from damaging voltage spikes.
Modern grid codes such as IEEE 1547-2018 require both to stay connected through many of these events. As a result, protection has to work in layers. It also has to be planned jointly. Get the coordination wrong, and the surge arrester clamps too late. Or, just as often, the PCS rides through longer than the transformer’s insulation can bear.
| Quick Answer PCS overvoltage protection combines transformer-side relays (ANSI 59, ANSI 24), surge arresters, and differential protection (ANSI 87T) with PCS-side defenses (DC-bus crowbar circuits, ride-through control, gate-driver clamps). The two systems must be coordinated. Specifically, the arrester should clamp below the PCS trip threshold. Also, the ride-through duration should stay inside the transformer’s short-time withstand rating, per IEEE C57.12. |
Why PCS Overvoltage Protection Differs From Overcurrent Protection
Most protection engineers think in terms of overcurrent first. So fuses, breakers, and relays are usually sized to clear a fault before wires or windings overheat. Voltage swells flip that logic around. Here, the equipment is not drawing too much current. Instead, it is facing too much voltage. So the failure paths are different:
- Load rejection — a large downstream load trips offline, and voltage spikes upstream before regulation catches up
- Single-line-to-ground faults on ungrounded or high-impedance grounded systems, which can push healthy phases toward line-to-line voltage
- Switching transients from capacitor bank energization, transformer tap changes, or line reclosing
- Ferroresonance, more common on lightly loaded systems with long cable runs
Overall, the transformer and the PCS each feel this stress in their own way. That is why PCS overvoltage protection needs two coordinated strategies, not one shared setting. For reference, full ride-through requirements sit inside IEEE 1547-2018, the standard most U.S. interconnection agreements now reference.
Transformer-Side Defenses That Support PCS Overvoltage Protection
Insulation and Core Stress From Sustained Overvoltage
Sustained overvoltage raises the transformer’s flux density. This pushes the core toward saturation. As a result, a saturating core draws jagged, inrush-like current. It also creates hot spots in the windings. Over time, the added vibration and noise speed up insulation aging.
In short, the standard protection layers are:
- ANSI 59 (overvoltage relay) — inverse-time or definite-time curves set to match the interconnection standard’s HVRT voltage-duration envelope
- ANSI 24 (volts/hertz protection) — catches overexcitation specifically. A plain overvoltage relay does not track the frequency side of core saturation. So this is a separate layer, not a substitute
- Surge arresters (gapped silicon-carbide or MOV-based) on both HV and LV terminals, sized to the transformer’s Basic Insulation Level (BIL)
Dielectric Stress From Fast Transients
Switching surges hit inter-turn winding insulation on a fast timescale. Relays cannot catch it. Specifically, that timescale runs sub-millisecond. Protective relaying, by contrast, works over cycles to seconds. So surge arresters and terminal snubber circuits carry the real burden here. By the time an ANSI 59 or 24 element reacts, the fast transient is already gone.
Differential and Overcurrent Protection (ANSI 87T, 50/51)
Alongside overvoltage-specific relaying, transformer protection schemes standardly add two more layers.
Differential protection (ANSI 87T) compares current entering the HV side against current leaving the LV side. It uses Kirchhoff’s Current Law to do this. A mismatch past a set threshold signals an internal winding fault. It trips the breaker within roughly 30 ms. However, inrush and magnetizing current during energization or overvoltage can also create a differential current. So modern relays use harmonic restraint. This tells real faults apart from these normal transients.
Overcurrent and earth fault protection (ANSI 50/51) clears sustained high fault current from grid-side short circuits. It uses instantaneous (50) and inverse-time (51) elements. These typically sit behind the differential scheme. Instead, they act as backup protection, not the first line of defense. Engineers also selectively coordinate the trip settings, so the device closest to a fault clears it first and leaves the rest of the system energized.
Voltage Regulation via On-Load Tap Changers (OLTC)
A BESS often connects to a weak or highly variable grid. There, an on-load tap changer adjusts the transformer’s turns ratio while it stays in service. This holds secondary-side voltage within range without shutting the unit down. So OLTCs offer a slower, mechanical form of voltage regulation. They help absorb sustained voltage drift from renewable generation. But they cannot replace surge arresters or relay protection against fault-driven transients.
Grounding and Shielding
- Low-impedance grounding grid — the transformer enclosure, surge arresters, and PCS frame should bond to the same grounding network. This limits ground potential rise during a fault. It also keeps protective devices on a common reference.
- Electrostatic shielding — an interwinding shield between primary and secondary cuts high-frequency noise and voltage-spike coupling from the grid side into the PCS side. It works alongside surge arrester protection, not in place of it.
PCS Overvoltage Protection: Inverter-Side Defenses
The inverter’s semiconductor switches, whether IGBT or SiC, face DC-bus overvoltage that flows back from an AC-side voltage swell. That exposure gets worse during unbalanced faults. There, the control loop’s own feedback signal becomes thrown off.
DC-Bus Overvoltage Protection
Braking choppers or crowbar circuits dump excess energy into resistors once bus voltage crosses a threshold. This protects the DC-link capacitors and the switches from overvoltage. Usually, it is the first active layer of PCS overvoltage protection to engage during a swell. DC contactors, meanwhile, serve as a hardware failsafe. They isolate the battery racks if the chopper alone cannot keep bus voltage inside a safe window.
AC Overvoltage Ride-Through Control
Older firmware tripped the PCS offline at the first sign of a swell. Modern firmware, built to current interconnection standards, keeps the PCS connected instead. Under IEEE 1547-2018’s default Category III envelope, for example, the PCS must ride through up to 1.10 per-unit for 2 seconds. Between 1.10 and 1.20 per-unit, it can briefly cease energizing instead of disconnecting outright. Above 1.20 per-unit, a full trip is required.
Also, the PCS actively absorbs reactive power, or VARs, to help pull grid voltage back down. As a result, the PCS becomes part of the fix, not just a bystander that disconnects. The LVRT and HVRT ride-through curves that govern this behavior work the same way in both directions. They are just mirrored for sags versus swells.
Volt-VAR and Volt-Watt Curve Control
Ride-through handles transient swells. But IEEE 1547-2018 also standardizes a separate, ongoing grid-support function for milder, sustained overvoltage. When a utility activates it, the PCS runs a volt-VAR curve. Below 1.02 per-unit voltage, the curve sits in a dead zone, and the PCS adds no reactive power. Above that, it starts absorbing reactive power, reaching its full absorption limit at 1.08 per-unit. These are the default curve settings described in a recent IEEE-affiliated study.
Some interconnection agreements also activate volt-watt control. This trims active power output if voltage stays high despite the reactive response alone. It works alongside volt-VAR, not in place of it.
Negative-Sequence Current Limiting
Unbalanced high-voltage faults produce negative-sequence currents. These heat phase legs unevenly. So control loops need an explicit limit here, separate from the general overcurrent limit. Otherwise, a single-phase-biased fault could overheat one leg while the others stay fine.
Fast Semiconductor-Level PCS Overvoltage Protection
Gate-driver desaturation detection and hardware-level overvoltage clamps work in microseconds. They act independently of the software control loop, and faster than it. As a result, they serve as the last line of defense when everything upstream fails to act in time.
Anti-Islanding and Ride-Through Coordination
A high-voltage fault can sometimes cascade into a full outage. When that happens, the PCS must detect that it is energizing a dead section of grid, then disconnect. IEEE 1547-2018 requires this within 2 seconds of island formation. Detection methods split into two types. Passive methods watch for abnormal voltage, frequency, or phase jumps. Active methods, instead, inject a small perturbation, such as a frequency drift, to force a detectable response if the grid is truly gone.
There is a real design tension here. Specifically, a 2019 NREL laboratory study found that ride-through behavior can noticeably slow islanding detection. Even so, run-on times stayed inside the 2-second IEEE 1547-2018 window in every case tested. That happens because a PCS holding voltage and frequency steady during a disturbance can look like a healthy grid connection. For this reason, ride-through and anti-islanding logic need coordinated tuning. They should not run as independent settings. For the full technical report behind this finding, see the Sandia National Laboratories study on OSTI.
Active Voltage Conditioning
Some sites see voltage that never settles, beyond what ride-through settings alone can absorb. For these sites, dedicated power-electronic conditioners sit in-line ahead of the main PCS. One example is ABB’s PCS100 AVC-40, rated from 225 kVA to 3,600 kVA with efficiency above 98 percent.
These units fix sags and swells within milliseconds. Even so, this is an extra device for grids that are weak or noisy all the time. It cannot replace the PCS’s own ride-through and protection functions.
Comparison: Transformer vs. PCS Overvoltage Protection
Overall, the table below lines up each side’s defenses by timescale. This makes the gaps between them easy to spot at a glance.
| Protection layer | Transformer | PCS |
|---|---|---|
| Primary threat | Core saturation, insulation aging | DC-bus overvoltage, switch stress |
| Slow protection (cycles–seconds) | ANSI 59 / ANSI 24 relays, ANSI 50/51 overcurrent | Software-based AC overvoltage ride-through control |
| Internal fault detection | ANSI 87T differential protection | Negative-sequence current limiting |
| Fast protection (µs–ms) | Surge arresters, terminal snubbers | Gate-driver desaturation, hardware clamps |
| Energy dissipation | Arrester let-through to ground | Braking chopper / crowbar resistors |
| Sustained voltage drift | On-load tap changer (OLTC) | Active voltage conditioning (external, supplementary) |
| Outage/dead-grid response | Coordinated with PCS anti-islanding | Anti-islanding, disconnect within 2s (IEEE 1547-2018) |
| Fault type most sensitive to | Single-line-to-ground on ungrounded systems | Unbalanced faults (negative-sequence) |
| Governing standard | IEEE C57.12 series | IEEE 1547-2018, UL 1741 SB |
Coordinating Transformer and PCS Overvoltage Protection
Treating these as two independent systems is a common design gap. So three coordination checks matter most for site-wide PCS overvoltage protection.
- Let-through voltage vs. PCS trip threshold. The transformer’s surge arrester should clamp transients below the PCS’s hardware overvoltage trip point. This way, the arrester absorbs the transient, not the PCS’s own protection.
- HVRT duration vs. transformer withstand. The voltage-time ride-through curve set in the PCS needs to sit inside the transformer’s short-time overvoltage withstand rating, per IEEE C57.12. Otherwise, the PCS could ride through an event longer than the transformer can structurally take.
- Grounding configuration vs. overvoltage settings. How the system is grounded — solidly grounded, resistance-grounded, or ungrounded — directly sets how much overvoltage a single-line-to-ground fault produces on the healthy phases. This needs joint modeling with the PCS overvoltage settings during system design. It should not be a decision each discipline makes on its own.
- Selective tripping. Transformer relay settings and the PCS’s own protection should be time-graded, so a fault on the PCS side clears at the device closest to it first. Otherwise, a local fault trips more of the system than it needs to.
- Fault current contribution vs. inverter control mode. The differential (87T) and overcurrent (50/51) settings assume a certain fault current magnitude to detect against. A grid-following PCS contributes only limited fault current during a fault, while a grid-forming PCS contributes significantly more. So these relay settings should be checked against which control mode the PCS actually runs — see our grid-forming vs. grid-following BESS guide for the underlying comparison.
Governing Standards for PCS Overvoltage Protection
- IEEE 1547-2018 — interconnection requirements for distributed energy resources, including HVRT voltage-duration curves
- UL 1741 SB — certification testing that verifies HVRT compliance for grid-support equipment
- IEC 61000-4-11 / IEC 61000-4-34 — voltage dip and swell immunity testing for equipment rated below and above 16 A per phase
- IEEE C57.12 series — transformer design and short-time overvoltage withstand standards
For system designers weighing broader grid-support tradeoffs, this same coordination logic also shows up in Fast Frequency Response design. There, too, BESS control settings must stay inside both a grid-code window and the hardware’s own physical limits.
Key Takeaways for PCS Overvoltage Protection Design
| Point | Why It Matters |
|---|---|
| Voltage swells stress equipment differently than overcurrent faults | Insulation and semiconductor limits, not wire heating, drive the failure modes |
| Transformer and PCS need separate, coordinated protection layers | A single shared setting misses the different timescales each device needs |
| Surge arresters and relays cover different timescales | Arresters catch microsecond transients; relays catch cycles-to-seconds events |
| Ride-through duration must stay inside transformer withstand ratings | Otherwise the PCS can hold an overvoltage longer than the transformer can survive |
| Anti-islanding and ride-through logic must be tuned together | Ride-through behavior can otherwise slow dead-grid detection |
FAQ
What’s the Difference Between LVRT and HVRT?
LVRT, or Low Voltage Ride-Through, keeps equipment connected during voltage sags. These are typically caused by faults or heavy load switching. HVRT, or High Voltage Ride-Through, does the same for voltage swells instead. So the control challenges largely mirror each other. But the hardware failure modes differ. Sags stress current limits. Swells stress insulation and semiconductor overvoltage limits instead. For the underlying voltage-duration curves, see our full LVRT and HVRT guide.
Why Does the PCS Absorb Reactive Power During a High-Voltage Fault Instead of Just Disconnecting?
Modern grid codes require ride-through for a clear reason. Mass disconnection of distributed generation during a voltage event can worsen grid instability. So absorbing VARs actively helps pull the voltage back toward normal. As a result, the PCS becomes part of the grid’s self-correction, not a source of added disturbance. For more on how this reactive-power capability is sized and rated, see our BESS power factor guide.
Can a Surge Arrester Alone Provide PCS Overvoltage Protection?
No. Arresters handle fast transients, such as switching surges and lightning-induced events. They work on a timescale of microseconds to milliseconds. Sustained overvoltage from load rejection or a ground fault lasts cycles to seconds instead. That needs the PCS’s own ride-through control. Where ride-through limits run out, it also needs overvoltage relay protection. In short, the two protection types are not interchangeable.
Does Ride-Through Conflict With Anti-Islanding Requirements?
They can pull against each other. Anti-islanding must detect a dead grid and disconnect within 2 seconds under IEEE 1547-2018. Ride-through, meanwhile, is built to keep the PCS connected through a disturbance rather than tripping. A 2019 NREL study found ride-through can slow islanding detection. That happens because a PCS holding voltage and frequency steady during the event looks like a stable grid connection. For this reason, both functions need tuning together at commissioning. Neither should be set on its own.
Why Must PCS Overvoltage Protection Settings Match the Transformer’s Withstand Rating?
Say the PCS’s HVRT setting runs longer than the transformer can withstand. The PCS still stays connected and rides through the event as designed. But the transformer can suffer accelerated insulation aging. In a severe enough event, it can suffer immediate insulation failure instead. That happens because it sits at an overvoltage level longer than its short-time withstand rating allows. This is the core reason the two systems’ settings need coordination at the design stage. They should not be configured apart from each other.
Further Reading
LVRT and HVRT: Voltage Ride-Through for BESS and Solar
Fast Frequency Response (FFR): How BESS Stabilizes Grid Frequency in Milliseconds