Electricity Safety (Bushfire Mitigation Duties) Regulations 2017

The regulations introduce and fix several key concepts that are central to the bushfire mitigation framework. Zone substation is a substation prescribed in Schedule 1; the list includes 45 named substations with their codes, latitudes, longitudes, and an allocated number of points (Column 6). The point allocation is critical because it determines how many fault-diagnosis or isolation devices must be installed or maintained at each substation, linking directly to the required capacity performance. Allocated substation points are the numbers set out in Column 6 for each zone substation; these vary from 1 (e.g., Merbein, Stawell, Bendigo) up to 5 (e.g., Winchelsea, Colac, Eaglehawk). The concept appears to calibrate the intensity of bushfire mitigation obligations to the risk profile of each substation, though the regulations do not explain the formula behind the point allocation.

Electric line construction area means a geographic area identified by a plan listed in Schedule 2 and lodged in the Central Plan Office. There are 33 such plans (LEGL./16-199 through LEGL./16-231). These plans likely delineate high bushfire risk zones in rural or peri-urban areas where stricter line design and maintenance standards apply.

Required capacity is the most technically detailed concept. It prescribes the ability of the protection system at each zone substation to reduce voltage on a faulted conductor relative to station earth within strict time thresholds. For high impedance faults, the voltage must be reduced to 250 volts within 2 seconds. For low impedance faults, the voltage must reach 1900 volts within 85 milliseconds, then 750 volts within 500 milliseconds, then 250 volts within 2 seconds. Additionally, during diagnostic tests for high impedance faults, fault current must be limited to 0.5 amps or less and thermal energy (I2t) to a maximum of 0.10. This is a demanding performance standard that dictates the speed and sensitivity of protection relays and fault-clearing equipment at the listed substations.

High impedance faults and low impedance faults are defined by mathematical formulas based on nominal phase-to-ground voltage. A high impedance fault has a resistance equal to twice that voltage in ohms (e.g., for a 22 kV network, that is double the phase-to-ground value). A low impedance fault has a resistance equal to the voltage divided by 31.75. These definitions translate electrical network parameters into clear binary categories that trigger different performance thresholds.

I2t is defined as a measure of thermal energy from current flow. The prescribed maximum of 0.10 during high impedance fault diagnostics ensures that even if a fault is not cleared instantly, the energy released stays below a threshold that might ignite vegetation.

Prescribed specification for covering or placing underground electric lines is that the line has a nominal voltage between 1 kV and 22 kV inclusive. This confines the duty to medium-voltage distribution lines, excluding both low-voltage service lines (under 1 kV) and high-voltage transmission lines (above 22 kV). The choice focuses mitigation effort on the network segment most commonly involved in bushfire ignition in Victoria.

The regulations directly affect major electricity companies as defined in the Electricity Safety Act 1998. These are the entities that own and operate the zone substations listed in Schedule 1 and the electric lines within the construction areas specified in Schedule 2. In practice, this means the five major Victorian electricity distribution businesses (AusNet Services, Powercor, CitiPower, Jemena, and United Energy) plus the state’s transmission company (AusNet transmission) where its assets fall within the scope. The regulations impose on these companies the technical standards they must meet to discharge their bushfire mitigation duties under Part 10A. The listed substations are geographically spread across the state, from coastal towns like Wonthaggi to inland centres like Bendigo and Mildura (Merbein). Companies must ensure that each prescribed substation’s protection system has the required capacity to clear faults within the voltage and time limits. This will require engineering assessments, possible replacement or upgrade of relays, circuit breakers, and fault-current limiting devices, and ongoing testing and maintenance. The electric line construction area plans (Schedule 2) define where additional duties regarding line design, inspection, and possibly undergrounding apply. This will affect not only the distribution businesses but also their contractors, consultants, and equipment suppliers who design and install protection systems. Landowners and occupiers in those construction areas may be indirectly affected if easements are needed for undergrounding or access for vegetation management. The Central Plan Office within the Department of Environment, Land, Water and Planning is the custodian of the plans that define the construction areas; it does not bear duties but is the repository for the spatial data used to trigger those duties. Energy Safe Victoria, the regulator, uses the regulations as the benchmark for assessing compliance; its inspectors will test whether protection performance meets the required capacity. Ultimately, consumers in bushfire-prone areas bear the costs of compliance through distribution network charges, though the link is indirect and aggregated. The regulations are silent on any cost-benefit analysis or transitional arrangements for existing substations, meaning companies must retrofit existing equipment if it cannot meet the prescribed performance.

The regulations themselves do not create duties or rights; they prescribe matters that define the scope of duties already imposed on major electricity companies by Part 10A of the Electricity Safety Act 1998. However, reading the regulations with that Act clarifies what companies must do. Under sections 120N and 120P of the Act, companies must ensure that electric lines are covered or placed underground in certain circumstances. Regulation 8 supplies the missing element: the duty applies only to lines with nominal voltage between 1 kV and 22 kV inclusive. Thus, for a line in an electric line construction area (Schedule 2) that falls within that voltage band, a company must either install covering (e.g., insulated conductors) or put it underground. There is no right to choose an alternative mitigation method; the Act mandates covering or undergrounding for those specified lines.

The required capacity duty (regulation 7) is the more onerous obligation. A zone substation listed in Schedule 1 must be able to reduce fault voltage within the strict time limits set out. This imposes a performance obligation: the protection system must be designed, set, and maintained to achieve those clearances for both high and low impedance faults. During diagnostic testing for high impedance faults, the system must also limit fault current to 0.5 amps or less and I2t to 0.10. The duty is absolute in the sense that the company must have the “ability” to achieve these outcomes; the regulations do not provide a defence of impracticability or economic hardship.

Companies have the right to request amendments to the schedules if substations or construction areas change, but the regulations do not confer any express right to apply for exemptions or variations. The only right implied is the right to rely on the regulations as stating the applicable standard: if a company meets the required capacity at its substations and covers/undergrounds lines in accordance with regulation 8, it is complying with those aspects of the bushfire mitigation duties. The regulations also give the Governor in Council the power to make future amendments under section 157 of the Act, and the Central Plan Office has the administrative role of maintaining the plan registers. No rights of appeal, review, or compensation are mentioned; any such rights would reside in the Act or general administrative law.

The regulations do not themselves prescribe penalties; enforcement is through the parent Act. Part 10A of the Electricity Safety Act 1998 creates offences and penalty provisions for breach of bushfire mitigation duties. Contravention of a duty under that Part can attract substantial financial penalties for corporations (potentially in the hundreds of thousands of dollars depending on the section, and with daily penalties for continuing breaches). In addition, the Act empowers Energy Safe Victoria to issue improvement notices, prohibition notices, and directions to comply. If a major electricity company fails to achieve the required capacity at a zone substation, or fails to cover or underground a line within the prescribed voltage range in a construction area, the regulator can take enforcement action. The regulations provide the objective standard against which compliance is measured: if a fault occurs and the protection system does not reduce voltage within the time limits, that is prima facie evidence that the company lacked the required ability, and a prosecution may follow.

The regulations also bear on liability in tort. If a bushfire is ignited by a fault on an electric line, a plaintiff (or the state seeking cost recovery) could argue that the company’s failure to meet the prescribed specification for covering or the required capacity amounts to negligence per se or breach of statutory duty. The regulations thus function as an industry-specific benchmark that courts may use to determine the standard of care.

There is no mechanism for private enforcement; only the regulator can bring criminal proceedings. However, third-party civil claims are not excluded. The sunset clause (22 August 2027) means that after that date the regulations lapse and the specifications revert to whatever the Act provides in the absence of subordinate legislation (which may be nothing, creating a gap in the enforcement framework). The endnotes note no amendments have been made and none are in operation, so the standards have remained static since 2017. This is notable because technology and network configurations evolve, and a static regulation may become either outdated or more onerous over time if companies have upgraded systems beyond the prescribed minimum.

The regulations are made solely under section 157 of the Electricity Safety Act 1998 and operate exclusively within the framework of that Act, particularly Part 10A. They are the subordinate instrument that completes the legislative scheme: the Act sets out the duties in general terms, and the regulations supply the technical and geographic specifics. Any subsequent amendment to Part 10A of the Act (or to definitions in section 120K) could render parts of the regulations redundant or inconsistent. Conversely, if the regulations are amended, the Act remains unchanged.

The regulatory reference to the Central Plan Office brings in the administrative machinery of the Department of Environment, Land, Water and Planning. The plans listed in Schedule 2 are lodged under whatever procedures that office maintains; the regulations do not specify how those plans are created, reviewed, or updated. This creates a delegation of geographic boundary-setting to an executive agency, which may shift over time without a formal amendment to the regulations.

The Subordinate Legislation Act 1994 governs the regulations themselves: they must be tabled in Parliament, are subject to disallowance, and will automatically sunset ten years after making (22 August 2027). This sunset preserves parliamentary oversight and forces periodic review. The Interpretation of Legislation Act 1984 applies to the reading of all provisions, including the schedules and endnotes; notably, the endnotes confirm that headings, examples, diagrams, notes, punctuation, and provision numbers form part of the statutory rule.

The regulations do not interact with the Victorian Building Regulations, Planning and Environment Act, or Local Government Act, but in practice the electric line construction areas may overlap with planning overlay zones such as Bushfire Management Overlay, creating a web of overlapping compliance requirements for landowners and utilities. The regulations are silent on this intersection, meaning companies must navigate co-regulatory obligations independently.

There is no reference to Commonwealth laws (e.g., National Electricity Rules, Environment Protection and Biodiversity Conservation Act). While the National Electricity Rules govern technical standards for connection and reliability, bushfire mitigation duties under state law operate as an overlay. To the extent that the required capacity prescribes protection settings that differ from those under the National Electricity Rules, companies must meet the higher standard or seek a derogation.

The regulations as at the version date (1 September 2017) have no amendments. The Table of Amendments (endnote 2) states: “There are no amendments made to the Electricity Safety (Bushfire Mitigation Duties) Regulations 2017 by statutory rules, subordinate instruments and Acts.” The table for Amendments Not in Operation is also empty. This means the regulations have remained in their original form since commencement. Given the sunset date of 22 August 2027, the regulations have a fixed ten-year life without any interim updating. This is significant because the technical definitions (e.g., voltage thresholds, time limits) and geographic schedules have not been adjusted to reflect network changes (new substations, decommissioned substations, changed bushfire risk classifications). Companies must still comply with a 2017 baseline, even if risk profiles or technology have moved on. The absence of amendment may indicate either that the regulations have operated without perceived flaw, or that the regulatory burden of amending a subordinate instrument has not been prioritised. The static nature also creates a potential trap: if a company adds a new substation that is not in Schedule 1, it is not a prescribed “zone substation” for the purposes of the required capacity duty, even if it is functionally similar. That gap may be unintended. Conversely, if a substation is decommissioned, it remains in Schedule 1 until formally removed, theoretically still subject to the duty unless the Act or administrative practice provides otherwise. The regulations do not provide any mechanism for listing updates between sunset reviews.

The source text (the regulations as published) does not record any litigation history. The endnotes contain no references to court decisions or tribunal rulings involving these regulations. This is unsurprising for a technical subordinate instrument that has been in force for under a decade without amendment. However, the absence of reported litigation does not mean no disputes have arisen; they may have been settled, resolved by regulatory action without court involvement, or litigated under the parent Act without the regulations being directly challenged. The regulations themselves are unlikely to be the central subject of litigation; instead, they are the evidentiary backdrop in prosecutions for breaches of bushfire mitigation duties. A defendant might argue that the regulations are ultra vires the Act if they go beyond what section 157 authorises, or that the required capacity is impossible to achieve (though the regulations state the “ability” must exist, leaving room for technical impossibility arguments). There may be merits review under the Victorian Civil and Administrative Tribunal regarding enforcement notices that rely on these regulations, but no such cases are recorded in the source. The lack of amendment and litigation could also indicate that the regulated entities accept the standards as achievable or that the regulator has not strictly enforced the letter of the regulation. For a well-informed analyst, the litigation silence is notable but not conclusive.

Several traps await the unwary. First, the definition of “high impedance faults” uses a formula: twice the nominal phase-to-ground voltage in volts. For a 22 kV line, phase-to-ground is about 12.7 kV, so a high impedance fault is around 25.4 kΩ. This is a very high resistance, making it difficult for conventional protection relays to detect. The required capacity demands that the substation reduce voltage to 250 volts within 2 seconds for such faults, during diagnostic tests with fault current limited to 0.5 amps and I2t to 0.10. This pushes detection technology to its limits; companies may need specialist high-impedance fault detection relays that are expensive and have a record of nuisance tripping. The threshold may be technically challenging for aging networks.

Second, the allocated substation points (Column 6 of Schedule 1) are not explained. They range from 1 to 5. The regulations do not define what a “point” represents, how many points are required for compliance, or what happens if the number of protection devices or fault-clearing capacity is reduced. This ambiguity could lead to disputes about whether a substation with 5 points requires five separate detection circuits or five times the capacity of a 1-point substation.

Third, the “required capacity” is a performance standard, not a prescriptive equipment list. A company might believe it is compliant based on relay settings, but if a real-world fault does not clear within the prescribed times due to network configuration (e.g., long lines, high resistance ground paths), the company is in breach. The regulations do not allow for exemption if the fault clearing time is technically impossible given the line length; the standard is absolute.

Fourth, the specification for covering or undergrounding applies only to lines between 1 kV and 22 kV inclusive. Lines below 1 kV (e.g., 240/415 V service lines) are excluded even if they are in high-risk areas. While these low-voltage lines carry less energy, they can still ignite fires if they contact vegetation. This gap may be exploited by plantiff lawyers in civil claims if a fire starts from a low-voltage line.

Fifth, the electric line construction areas are defined by plans lodged at the Central Plan Office. Those plan numbers (LEGL./16-199 to LEGL./16-231) are not publicly described in the regulations. A company must physically access those plans to know the precise boundaries. If the plans have been updated or are ambiguous (e.g., missing metadata), compliance becomes uncertain.

Sixth, the regulations are static. As of the version date, no amendments exist and none are proposed. A new substation built after 2017 falls outside Schedule 1, so it is not a “zone substation” for the required capacity duty, even if it serves the same function. This may be an oversight or may reflect a deliberate policy to only regulate legacy substations.

Seventh, the sunset date is 22 August 2027. If the regulations are not remade, the prescribed specifications and definitions vanish, leaving the Act’s duties without operational standards. Companies and the regulator need to plan for this transition.

Finally, the definition of “low impedance faults” uses the formula nominal phase-to-ground voltage divided by 31.75. For a 22 kV system, that is about 400 Ω. This is relatively low resistance, but the required capacity demands voltage reduction to 1900 volts in 85 milliseconds, then 750 volts in 500 ms, then 250 volts in 2 seconds. These are fast clearance times, comparable to transmission protection standards, which may require investment in high-speed protection schemes that are not currently installed in some rural zone substations.

Compliance requires a systematic engineering and administrative approach. Major electricity companies should start by identifying all zone substations they operate that appear in Schedule 1. For each such substation, they must confirm the allocated substation points (Column 6) and ensure that the protection system can achieve the required capacity as defined in regulation 7. This means conducting fault studies, relay coordination studies, and dynamic simulations to verify that for both high and low impedance faults the voltage on the faulted conductor relative to station earth will reduce to the prescribed levels within the time limits. Particular attention must be paid to the high impedance fault diagnostics: the system must be able to limit fault current to 0.5 A and I2t to 0.10 during tests. Companies may need to install sensitive earth fault protection, adaptive protection algorithms, or communication-based protection schemes (e.g., transferring trip signals) to meet the 85 ms and 500 ms time targets for low impedance faults. Existing electro-mechanical relays are unlikely to be fast enough; digital relay upgrades are almost certainly required.

For electric line construction areas, companies must obtain the plans referenced in Schedule 2 from the Central Plan Office and map them against their network. Any line with nominal voltage 1 kV to 22 kV that lies within such an area must be covered (e.g., with insulated conductors) or placed underground. This is a physical asset modification that may require capital expenditure planning, community consultation, and easement acquisition. Companies should prioritise areas with highest fire risk or where lines are most exposed to vegetation.

Documentation is critical. Companies should maintain a register for each zone substation showing the as-built protection settings and test results demonstrating compliance with the voltage and time parameters. Diagnostic tests for high impedance faults should be scheduled and logged. For lines in construction areas, a list of covered/underground assets should be kept, with dates of installation and maintenance records.

Regular audits by internal compliance teams and external consultants can help identify non-compliant substations or lines. The regulator (Energy Safe Victoria) expects proactive compliance; waiting for a fault or an inspection to find deficiencies risks enforcement action. Companies should also monitor any amendments to the schedules or the regulations (though none have occurred so far) and participate in consultation if the regulations are due for review before the sunset date.

Finally, given the sunset on 22 August 2027, companies should engage with DELWP and Energy Safe Victoria early in the process to ensure the regulations are remade with appropriate updates, especially to include any new substations and to adjust points allocations if warranted. Failing that, companies must prepare contingency plans for the regulatory gap that would result. Compliance is not just about meeting today’s standard but about anticipating the future.