Electricity Industry (Network Quality and Reliability of Supply) Code 2005

The Code organises around a small set of core regulatory concepts which determine who acts, what counts as compliance, and what operational and financial consequences follow.

• “So far as is reasonably practicable”. This repeated standard qualifies most performance obligations (ss 5, 9, 10, 13, 13B-13C). It is a fault‑tolerance test, not an absolute promise of zero non‑compliance. The statutory language requires network operators to take steps that are reasonably practicable in the circumstances; the Code does not itself define the factors that make an action reasonably practicable, but it does create monitoring, audit and reporting mechanisms to assess compliance (ss 23, 26, 27). Where the Minister grants exemptions under s 14, the exemption is expressly conditioned and may be limited geographically or by condition (s 14(3)-(6)).

• Compatibility levels for power quality. The Code references established technical measures: Pst and Plt for voltage fluctuation (s 6) and a harmonic voltage table with specified percentage limits and a Total Harmonic Distortion (THD) note (s 7). Compliance is measured at the customer’s point of connection unless the cause of non‑compliance is in the customer’s installations or an act/omission of the customer (s 5(2)). These provisions identify the technical thresholds the network must meet at the point of connection.

• Interruption standards: three complementary constructs:

  • Individual reliability duties: general duty to minimise interruptions (s 9) and to reduce effects on customers, including consideration of alternative supply for significant impacts or health needs (s 10).
  • Planned interruption rules: permitted maximum duration tied to geographic location (latitude), and specified notice mechanisms and minimum notice of 72 hours unless not reasonably practicable (s 11). Notice methods are closed‑list (s 11(3)-(4)).
  • Area average standards: numeric targets for average total interruption minutes for Perth CBD (30 minutes), other urban areas (160) and other areas (290), calculated as the average of four consecutive annual totals (s 13).

• Small use customers and eligible persons: the Code distinguishes “small use customers” (≤160 MWh/year, s 3) from “eligible persons” for payment rules (≤50 MWh/year, s 16). The “small use customer” category triggers complaint handling and reporting obligations (ss 25, 27, Sch 1), and the “eligible person” category triggers the fixed payment entitlements under Part 3 (ss 16-22). The distributor’s duties under s 12 concerning significant interruptions are framed specifically around small use customers.

• Temporal and area‑specific deviations: the Code carries temporary, location‑specific obligations in Div 3A. Between 1 October 2018 and 30 September 2028, Electricity Networks Corporation must have arrangements to restore and maintain specified MW levels to essential services and the majority of small use customers in Eastern Goldfields (45MW) and North Country (50MW) for unplanned and planned outages (ss 13A-13C). These are explicit performance tiers for a fixed period.

• Administrative checks and transparency: continuous monitoring (s 23), customer‑triggered quality investigations (s 24) with 20 working day timeframes, complaints handling information for small use customers (s 25), independent audit of monitoring systems (s 26), Authority powers to vary reporting cadence (s 26A), and prescribed public reporting content (s 27 and Sch 1). Records must be retained for at least five years after publication (s 23(2)).

• Ministerial/Authority roles and private arrangement flexibility: the Minister can grant exemptions/alternate provisions on application, subject to Authority advice, and can revoke/modify instruments with notice (s 14). Customers can agree in writing to exclude or modify Part 2 provisions provided the agreement identifies advantages and disadvantages to the customer (s 15). Those mechanisms create regulatory flexibility and permit bespoke arrangements within a statutory framework.

These concepts together create a regulatory architecture that blends prescriptive technical minima, quantitative area performance metrics, limited financial penalties for particular failures by corporations, and administrative oversight intended to produce public disclosure and independent auditing of monitoring practices.

The Code explicitly names multiple affected groups and allocates responsibilities and rights across them:

• Transmitters and distributors. The main operative duties fall on holders of transmission and distribution licences (s 3(1) definitions for “transmitter”, “distributor”) and on the Electricity Networks Corporation when it operates distribution systems (ss 16; Div 3A). Transmitters and distributors are subject to the technical quality standards (ss 5-8), reliability duties (ss 9-13), monitoring and record‑keeping requirements (s 23), complaint handling duties for small use customers (s 25), and reporting/audit duties (ss 26-27). They must also undertake quality investigations when requested (s 24).

• Electricity Networks Corporation and other “corporations”. Part 3’s payment obligations specifically apply to “corporation”, defined as Electricity Networks Corporation, the Regional Power Corporation, or a subsidiary of either, but only when the corporation is operating a distribution system (s 16). Parts of Div 3A place express duties on Electricity Networks Corporation to have arrangements that restore certain MW thresholds to essential services and most small use customers in specified regions (ss 13B-13C).

• Small use customers. Defined as customers consuming not more than 160 MWh per year (s 3(1)), small use customers trigger several obligations: access to complaints handling information at no cost (s 25), protections under s 12 (if interruptions exceed certain thresholds or permitted frequency), and inclusion in published performance metrics (Sch 1, items 5-11).

• Eligible persons. For Part 3 payments an “eligible person” is defined with a lower consumption threshold (≤50 MWh/year) and covers customers supplied from distribution systems operated by a corporation and persons supplied at premises where they principally reside or carry on business at separately metered premises (s 16). Eligible persons can apply for statutory payments under ss 18 and 19 subject to time limits and exceptions in s 17.

• Customers generally. All customers have treaty rights to protection from harmful voltage/harmonic levels measured at point of connection (s 5), and the ability to request a quality investigation where they reasonably consider non‑compliance with s 6(2) or s 7 (s 24). They are also entitled to be given, on request, a copy of any Ministerial instrument exempting a network operator that might affect them (s 14(8)).

• Minister and Economic Regulation Authority. The Minister receives applications for exemptions/alternative provisions and may grant, revoke or vary instruments subject to Authority advice (s 14). The Authority advises the Minister on s 14 applications (s 14(2)), can direct shorter reporting periods for audits (s 26A), and is a recipient of reports (ss 26(5), 27(3)). The Authority is also a defined term and central to the administrative control architecture.

• Retail licensees. Although retail licensees are not primarily regulated by this Code, s 22 allows corporations to make payments under ss 18 and 19 to retail licensees if an arrangement exists to ensure the amount is passed through or credited to the eligible person. This permits operational coordination between distribution corporations and retailers.

• Ombudsman. While the Code does not create its own dispute resolution body, the note to s 19 states that a person dissatisfied with a corporation’s failure to pay may seek to enforce payment by application to the electricity ombudsman under the Act Part 7. Thus the ombudsman and its jurisdiction under the Act interact with the Code’s enforcement pathways.

Who pays and who receives: the primary payers for the fixed compensation entitlements are corporations operating distribution systems (s 16). Eligible persons are the recipients of the $20/$120 statutory payments (ss 18-19) when qualifying conditions are met. Network operators, broadly, bear compliance costs for monitoring, audits and reporting (ss 23, 26, 27), and distributors may face operational costs to meet area average standards and temporary MW obligations in Div 3A (ss 13, 13B-13C).

Who decides: day‑to‑day operational decisions remain with network operators subject to the “reasonably practicable” standard. Regulatory discretion is exercised by the Minister (s 14) after receiving advice from the Authority (s 14(2)), while the Authority has a separate power to adjust reporting periods (s 26A).

This section summarises the principal operative requirements and statutory entitlements in the Code, with section references.

Duties on transmitters and distributors

• Quality and emission limits: ensure supply to customer installations measured at point of connection complies with voltage fluctuation and harmonic distortion compatibility levels (s 5 read with ss 6-7). Exceptions where the root cause is within customer installations or an act/omission of the customer (s 5(2)).

• Disconnect to prevent damage: where non‑compliance with voltage fluctuation or harmonics will or may result in damage, the operator must, so far as is reasonably practicable, disconnect supply unless maintaining supply is in the customer’s interests (s 8).

• Reliability and interruption minimisation: a general duty to maintain supply and keep occurrence/duration of interruptions to a minimum (s 9) and a duty to reduce the effect of interruptions (s 10). Substantive direction in s 10 requires consideration of alternative supplies where the interruption is expected to exceed the planned durations (s 11(2)), where business effect is likely to be substantial, or where a person at the premises has health needs requiring electricity.

• Planned interruption constraints and notice: planned interruptions for maintenance/alteration are permitted provided they do not exceed location‑specific durations (s 11(1)-(2)) and the operator gives at least 72 hours’ notice unless impracticable (s 11(1)(b)(i)-(ii); s 11(3)). Notice methods are explicit; telephone and posting solely on the operator’s website do not satisfy the notice requirement (s 11(4)).

• Area average performance: ensure, so far as is reasonably practicable, that the average total length of interruptions in respective areas does not exceed statutory minutes, calculated by averaging four years of data in a specified way (s 13(2)-(3)).

• Temporary performance obligations: Electricity Networks Corporation must have arrangements to restore and maintain minimum MW levels for essential services and most small use customers in Eastern Goldfields and North Country during planned/unplanned outages for the 2018-2028 decade (ss 13A-13C).

Administrative and transparency duties

• Monitoring and record keeping: operators must take reasonably necessary steps to monitor network operation for compliance and reporting, keep records required for this purpose and retain information for at least five years after publication (s 23).

• Quality investigations: on a customer’s written request, the operator must investigate alleged non‑compliance with s 6(2) or s 7, complete the investigation within 20 working days, take necessary field measurements and report results to the customer (s 24). Requests can be refused if frivolous, vexatious or not in good faith (s 24(5)).

• Complaints handling: small use customers must be provided, at no cost, a document explaining complaints handling processes, including the right to refer unresolved complaints to the electricity ombudsman under the Act Part 7 (s 25).

• Independent audit and publication: independent expert audits of monitoring systems are required for each reporting period (normally three years unless Authority varies to 1-2 years, s 26A) and reports must be published by 1 October following the reporting period (s 26). Annual reports with the detailed Schedule 1 metrics for each year ending 30 June must be published by 1 October (s 27; Sch 1). Copies of reports must be provided to the Minister and the Authority at least seven days before publication (ss 26(5), 27(3)).

Customer rights and remedies

• Right to request investigation and receive results (s 24(2)-(4)).

• Right to complaint handling information and knowledge of referral rights to the ombudsman (s 25).

• Eligible persons’ right to statutory payments for late notice ($20) or interruptions exceeding 12 hours ($120), subject to application within 60 days and specific exclusions (ss 18-19, 17). Corporations must pay within 30 days of a valid application (ss 18-19).

• Right to obtain, free of charge on request, a copy of a Ministerial instrument exempting a supplier if the customer is or may be affected (s 14(8)).

Variation and agreement mechanisms

• Ministerial exemption and substitution: licensees can apply for exemption or replacement provisions; instruments can be area‑specific, conditional, revoked or varied by the Minister after Authority advice (s 14).

• Bilateral customer agreements: customers may enter written agreements to exclude or modify Part 2 provisions if the agreement records advantages and disadvantages to the customer (s 15); the Code continues to have effect subject to such agreements (s 15(3)).

Limits and exclusions

• Part 3 payments are limited to “corporations” operating distribution systems as defined (s 16) and to “eligible persons” (s 16); other network failures may be excluded from payments if they occur during an emergency operating state, are caused by the eligible person or equipment under their control, or the Minister determines the interruption occurred in exceptional circumstances (s 17).

• Only one application may be made in respect of any particular premises for each qualifying interruption (s 20).

These duties and rights create both operational and disclosure burdens for network operators and a limited direct monetary remedy for a defined class of customers, with administrative pathways for bespoke variations and Ministerial discretion.

The Code does not prescribe criminal penalties or graduated monetary fines for failures to meet the substantive technical or reliability standards. Enforcement and consequences under the Code are a combination of statutory entitlements, administrative oversight and external dispute resolution:

Direct monetary entitlements (statutory payments)

• Fixed payments against corporations: the Code imposes strict, time‑limited payment obligations on corporations (Electricity Networks Corporation, Regional Power Corporation or their subsidiaries when operating distribution systems) in two narrow instances. If a corporation fails to give an eligible person at least 72 hours’ notice of a planned interruption as required by s 11(1)(b)(i) and the person applies within 60 days, the corporation must pay $20 within 30 days (s 18). If an eligible person's supply is interrupted for more than 12 continuous hours and the person applies within 60 days, the corporation must pay $120 within 30 days (s 19). These are direct statutory liabilities, not discretionary penalties.

Administrative enforcement and oversight

• Independent audits and publication: ss 26-27 require independent expert audits of monitoring systems at specified reporting periods and annual publication of performance reports containing prescribed metrics (Sch 1). Failure to conduct audits or publish required information could expose a transmitter/distributor to regulatory scrutiny from the Authority, and provide evidence in administrative or ombudsman processes, though the Code does not itself state sanctions for failure to publish.

• Ministerial powers: the Minister may grant, revoke or vary exemptions and substitute alternative provisions after receiving Authority advice (s 14(2)-(7)). The ability to revoke an exemption provides an administrative lever; the Code does not specify a penalty regime but the Minister’s revocation/variation power can adjust obligations where compliance is inadequate or circumstances change.

Dispute resolution and private enforcement

• Ombudsman enforcement: the Code notes that a person dissatisfied with a failure or refusal of a corporation to pay under s 18 or 19 may seek to enforce payment by application to the electricity ombudsman under the Act Part 7 (note to s 19). That provides a specific external dispute mechanism for the payment entitlements. The Code also requires complaints handling information to advise small use customers of their right to refer unresolved complaints to the electricity ombudsman (s 25(3)).

Regulatory information asymmetry and evidentiary controls

• Monitoring and records obligations are central to enforcement: ss 23 and 26 require monitoring, record keeping for at least five years after publication, and independent audit. These provisions create an evidentiary trail that can be used by the Authority, Minister, ombudsman or other parties when assessing compliance. The Code’s dependence on “so far as is reasonably practicable” means enforcement will be fact‑sensitive and hinge on factual records, audit findings and operational justifications.

Limitations and exclusions that limit enforcement exposure

• Exceptions for emergency operating state and ministerial determinations: s 17 excludes interruptions during declared emergency operating states and those caused by exercise of written law powers to disconnect for fire or other hazard or to facilitate rescue. The Minister can also declare interruptions as occurring in exceptional circumstances so they do not attract payment under Part 3. These exclusions reduce corporations’ exposure to monetary payments in specified high‑risk scenarios.

No express criminal sanctions or civil penalty regime within the Code

• The Code does not set out civil penalty provisions or criminal offences for non‑compliance with the technical or reliability standards. Instead it embeds administrative remedies (audits, publication, Ministerial instruments) and bespoke statutory payments limited to corporations and eligible persons. Enforcement therefore depends on administrative and ombudsman processes, contractual arrangements between distributors and retailers, and the Authority’s oversight.

Operational enforcement practicalities

• The audit and publication timetables (audits per reporting period and annual reports due by 1 October after 30 June year end; copies to Minister and Authority 7 days prior, ss 26(3)-(5), 27(1)-(3)) create checkpoints for regulatory oversight. The Code’s schedule of metrics (Sch 1) focuses transparency on breaches, remedial actions, complaints, payments, and discreet area statistics, which are the practical levers for reputational and regulatory pressure.

In summary, the Code builds enforcement around: (a) narrow statutory payment obligations for corporations; (b) transparency and audit obligations that enable administrative oversight; (c) Ministerial discretion to vary or revoke obligations; and (d) access to the electricity ombudsman for dispute resolution. The statutory architecture privileges fact‑based administrative remedies and transparent reporting over an internal civil penalty or criminal penalty regime within the Code itself.

The Code exists within the statutory electricity regulatory framework of Western Australia and explicitly cross‑references other laws and instruments. The Code relies on, complements and in some cases defers to other statutory regimes.

Interaction with the Electricity Industry Act 2004 and the Act’s definitions

• Many defined terms and the scope of regulated infrastructure trace back to the Act. The Code uses definitions such as “covered network”, “distribution system”, and “network infrastructure facilities” as given in the Act, but modifies or clarifies them via s 3 of the Code (see s 3(1) notes and s 3(3) excluding equipment on customer premises beyond the point of connection). The legal boundary of operator responsibility is therefore determined by the Code’s point‑of‑connection measurement rule (s 5) and the Act’s definitions.

Interaction with the Economic Regulation Authority Act 2003

• The “Authority” is defined in the Code as the Economic Regulation Authority established under the Economic Regulation Authority Act 2003 (s 3(1)). The Authority has a procedural role: it must be provided advice on Ministerial exemption applications (s 14(2)), receives copies of audit and performance reports (ss 26(5), 27(3)), and may give notice shortening the audit reporting period (s 26A). The Code therefore builds on and utilises the Authority’s institutional competence in regulatory oversight.

Interaction with the Wholesale Electricity Market Rules

• The definition of “emergency operating state” is imported from section 3.5.1 of the Wholesale Electricity Market Rules (s 16). This cross‑reference deems certain interruptions occurring during an emergency operating state to be excluded from Part 3 payments (s 17(1)(a)(i)), aligning the Code with the operational realities governed by the Wholesale Market Rules.

Interaction with the Energy Operators (Powers) Act 1979

• Metering and the identification of separate premises for the purposes of averages and payment eligibility are tied to metering under the Energy Operators (Powers) Act 1979 s 62(5) (see s 13(4) and definition of “separately metered premises” in s 16). This pinpoints how interruptions and payments are allocated to physical premises in accordance with metering rules.

Interaction with the Electricity Act 1945 (historical note)

• The Code’s note after s 8 states that voltage level and frequency standards are provided for by the Electricity Act 1945 s 25(1)(d) and are not covered by this Code. The note records historical declared nominal voltages and frequency tolerances while clarifying that the Code’s remit is compatibility levels and harmonics rather than primary voltage and frequency control, which remain covered under other statutory provisions (the Electricity Act 1945 note).

Interaction with the electricity ombudsman and Act Part 7

• The Code explicitly points users to the electricity ombudsman under the Act Part 7 for enforcement of payment obligations and unresolved complaints (note to s 19 and s 25(3)). This integrates the Code’s remedies with the Act’s dispute resolution framework.

Interaction with other statutory instruments and the Minister’s instruments

• The Minister may issue instruments granting exemptions or attaching conditions under s 14(3). Those Ministerial instruments interact with and can temporarily or permanently change the Code’s application to particular licensees or areas. The Code requires distributors to provide customers copies of such instruments on request (s 14(8)), creating a direct operational link between statutory instruments and customer rights.

Reporting and standards interoperation

• The Code’s technical references (Standard 61000:2001 for Pst and Plt at the commencement of the Code, s 6(1)) and the harmonic tables (s 7) connect statutory obligations to established technical standards. While the Code gives the numerical thresholds, the implementation and measurement are based on technical standards that are external to the Code.

Uncommenced provisions and future interaction

• The compilation table records an uncommenced provision from the Electricity Industry Amendment (Distributed Energy Resources) Act 2024 s 83(b) (uncommenced). When proclaimed, future amendments from that Act may change the Code’s relationship with distributed energy resources, but the Code as published includes the uncommenced note without operative change.

In effect, the Code is designed to operate as a middle tier: it prescribes specific quality and reliability minimums and process requirements, while drawing on the Act, Authority, Wholesale Market Rules and metering rules to define boundaries, exceptions and enforcement pathways. Practitioners must therefore read the Code alongside the Act, Authority instruments, the Wholesale Electricity Market Rules, metering legislation and Ministerial instruments to understand the full regulatory obligations and available defences.

The Code’s compilation table and in‑text amendment notes show a sequence of amendments that have altered definitions, added temporary reliability standards, expanded audit and reporting requirements and introduced procedural provisions. The compilation shows the following chronological milestones and insertions as published:

• Original Code: Electricity Industry (Network Quality and Reliability of Supply) Code 2005, published 13 December 2005 and commenced 1 January 2006 (ss 1-2).

• 2006 consequential amendments: Electricity Corporations (Consequential Amendments) Regulations 2006 r 75, published 31 March 2006 and commenced 1 April 2006 (compilation table).

• 2007 amendment: Electricity Industry (Network Quality and Reliability of Supply) Amendment Code 2007, published 19 September 2007 and mostly commenced on 20 September 2007 (compilation table).

• 2009 amendment: Electricity Industry (Network Quality and Reliability of Supply) Amendment Code 2009, published 27 November 2009 with Code provisions (other than ss 1 and 2) commencing 28 November 2009 (compilation table). The in‑text notes show s 11 and s 3 amended by Gazette 27 Nov 2009 (various changes reflected in s 3 and s 11).

• 2017 amendment: Electricity Industry (Network Quality and Reliability of Supply) Amendment Code 2017, published 2 May 2017. The amendment introduced or amended multiple provisions with staggered commencement: ss 1 and 2 commenced 2 May 2017, most of the Code other than ss 8-14 commenced 3 May 2017, and ss 8-14 commenced 1 July 2017 (compilation table). Specific insertions in 2017 include s 11A (interruption to restore supply from network) and Part 4 additions (s 25A reporting period, s 26A Authority notice) as indicated by the in‑text amendment notes (e.g., s 11A inserted: Gazette 2 May 2017 p. 2288; s 25A, 26A, 29 inserted: Gazette 2 May 2017 p. 2289‑91).

• 2018 amendment: Electricity Industry (Network Quality and Reliability of Supply) Amendment Code 2018, published 25 September 2018 and commenced 1 October 2018 (compilation table). This insertion added Division 3A, temporary reliability standards for Eastern Goldfields and North Country (ss 13A-13C), and the commencement date for those temporary standards is stated as 1 October 2018 (s 13A(1)).

• 2021 amendments: Code amendments published 5 November 2021 (Code Amendments 2021) and an Amendment Code published 12 November 2021; commencement for Code Amendments 2021 was 6 November 2021 and for the Amendment Code 13 November 2021 (compilation table). The in‑text notes record amendments to s 3 on 5 Nov 2021 and s 13A amended 12 Nov 2021.

• 2022 amendment: Electricity Industry (Network Quality and Reliability of Supply) Amendment Code 2022, published 1 April 2022 and with a commencement date of 1 July 2022 for that instrument (compilation table). The in‑text note indicates s 19 was amended with Gazette 1 Apr 2022 p. 2457.

• Uncommenced provisions listed: Electricity Industry Amendment (Distributed Energy Resources) Act 2024 s 83(b) assented 7 March 2024 but to be proclaimed; the compilation table records it as uncommenced. The Code’s compilation table invites users to the WA Legislation website for text of any uncommenced provisions.

Where the in‑text notes identify the insertion date of a particular section, those notes are reproduced in the Code. For example:

• s 11A was inserted by Gazette 2 May 2017 p. 2288.
• s 25A and s 26A were inserted and s 29 added by Gazette 2 May 2017 p. 2289-91.
• Div 3A (ss 13A-13C) was inserted by Gazette 25 Sep 2018 p. 3568-69.
• s 3 has multiple amendments recorded (Gazette dates listed in s 3 notes).

The compilation table and in‑text amendment notes are the authoritative record in the published Code and should be consulted to track precise wording changes and commencement dates. Practitioners should check the WA Legislation website for consolidated reprints and any subsequent amendments or proclamations affecting uncommenced provisions.

The Code text and compilation materials supplied here do not list or cite any judicial decisions or tribunal determinations that have interpreted, applied or invalidated the Code. The Code itself contains no annotated case law. Consequently, this section reports what the Code provides about dispute pathways and evidential bases for litigation or adjudication, rather than any historical litigation outcomes.

• Dispute pathways referenced by the Code. The Code directs dissatisfied customers in limited contexts to the electricity ombudsman under the Electricity Industry Act 2004 Part 7. The note to s 19 expressly states that a person dissatisfied with a failure or refusal of a corporation to pay a sum may enforce payment by application to the electricity ombudsman under Act Part 7. Section 25(3) requires small use customers be informed of the right to refer unresolved complaints to the ombudsman. These references indicate administrative dispute resolution via the ombudsman is the intended first port of call for enforcement of the Code’s payment and complaints provisions.

• Evidentiary framework the Code creates. The Code requires monitoring, record keeping and independent audits (ss 23, 26) and prescribes the data elements to be published annually (Sch 1). Those records, audits and publications constitute the primary evidence that would support any enforcement action, complaint to the ombudsman, or judicial review should a party seek such remedies. The Code’s retention requirement (records kept for at least five years after publication under s 23(2)) ensures an evidentiary trail.

• Nature of causes likely to give rise to disputes. The Code anticipates disputes about whether technical standards were met at the point of connection (s 5 and ss 6-7), whether a planned interruption notice complied with s 11(1)(b)(i) and the specific notice method rules (s 11(3)-(4)), whether interruptions exceeded the statutory durations (s 11(2)), and whether an eligible person’s supply was interrupted for more than 12 hours (s 19). The Code provides procedural time limits for applications (60 days for ss 18-19) and employer/utility time limits to respond (30 days to pay), creating clear procedural stages that would shape any complaint.

• Likely standard of review. Given the repeated phrasing “so far as is reasonably practicable” and the Code’s reliance on monitoring and audit, disputes about substantive compliance will turn on operational facts, records, and expert measurement of power quality and interruptions. Independent audits under s 26 and field measurements in s 24 are specifically designed to produce technical evidence relevant to any adjudication.

• No internal civil penalty or criminal sanction scheme in the Code. Litigation or administrative enforcement under the Code would therefore generally concern: (a) enforcement of payment entitlements through the ombudsman; (b) administrative or judicial review of Ministerial instruments (for example, if a grant or revocation of an exemption under s 14 were challenged on public law grounds); or (c) actions seeking remedies under other statutory regimes where overlaps arise. The Code itself does not prescribe civil penalty proceedings.

If legal practitioners require examples of how courts or the ombudsman have treated identical or similar language (for example, “so far as is reasonably practicable”), they will need to consult case law outside the Code and decisions of the electricity ombudsman. The published Code as supplied does not include such case references.

The Code contains several practical traps and non‑intuitive provisions that can lead to compliance failure, unexpected liability, or customer disputes. The following matters are drawn directly from the statutory text and should be watched closely.

“Reasonably practicable” is a high uncertainty factor

• Many core duties are qualified by “so far as is reasonably practicable” (ss 5, 9, 10, 13, 13B-13C). That phrase leaves substantial discretion to network operators and to the Authority/Minister to assess whether actions taken were adequate. Compliance therefore depends heavily on documented risk assessment, cost/benefit records, and contemporaneous decision‑making. The audit and record keeping rules (s 23; s 26 independent audits) mean the operator’s files will be the primary evidence in any complaint or review.

Notice method exclusions and electronic notice limits

• Planned interruption notice has a closed list of acceptable delivery methods (s 11(3)). Importantly, telephone notification and publication on the operator’s own website do not satisfy the notice requirement (s 11(4)). Electronic notice is allowed (including email, facsimile, text message or the internet) but only as an express option in s 11(3)(ab). Operators relying on automated outbound calls or website posts without individual notice risk failing the 72‑hour notice requirement.

Latitude and temperature affect permitted interruption duration

• The permitted duration for a planned interruption differs by latitude and, for premises on or south of the 26th parallel, may be shortened from 6 to 4 hours if the Bureau of Meteorology forecast maximum temperature is 30°C or more for any part of the interruption period (s 11(2)(a)(ii)). Operators must therefore integrate weather forecasts into planning and notice systems to determine the correct permitted duration at the time notice is given.

Different customer categories, different entitlements

• “Small use customer” (≤160 MWh/year) and “eligible person” (≤50 MWh/year) are distinct categories triggering different rights. Eligible persons are the only ones entitled to the $20/$120 payments (ss 16, 18-19). A small use customer outside the eligible person threshold cannot claim those specified statutory payments against a corporation. Mistakenly conflating these categories can produce incorrect customer communications or refused claims.

Payment scope limited and procedural

• Payments under ss 18-19 are nominal fixed sums, limited to corporations operating distribution systems and to eligible persons. They require application within 60 days and the corporation has 30 days to pay (ss 18-19). Operators should implement simple application handling and payment processes to avoid ombudsman complaints about failure to pay on time.

Only corporations (not all distributors) bear Part 3 payment obligations

• The payment obligations in Part 3 apply only to a narrow class of “corporation” as defined in s 16, which excludes many private distributors or non‑corporate licensees unless they are the Electricity Networks Corporation or Regional Power Corporation operating a distribution system. Practitioners should check the operator’s status before assuming Part 3 payments apply.

Single application per premises

• For any particular qualifying interruption only one application may be made in respect of any premises (s 20(1)). Where multiple occupants or tenants exist at metered or unmetered premises, operators must check who is entitled and whether multiple applications are precluded.

Quality investigation refusal standard is narrow

• A distributor must investigate a customer’s written request about non‑compliance with s 6(2) or s 7 within 20 working days and take field measurements (s 24). The distributor can refuse only if the request is frivolous, vexatious or not in good faith (s 24(5)). Operationally, distributors should not rely on informal deferral; they must promptly document and complete investigations to meet statutory time limits.

Ministerial exemptions and customer agreements can alter rights

• The Minister may make area‑specific exemptions or replacements subject to Authority advice (s 14). Customers affected by such an instrument can obtain a free copy on request (s 14(8)). Separately, customers and operators may enter written agreements to exclude or modify Part 2 provisions (s 15); the agreement must set out advantages and disadvantages to the customer. Parties should ensure such agreements are clear and documented because they change the baseline statutory entitlements.

Reporting and audit deadlines are rigid

• Annual reports (s 27) and audit reports (s 26) must be published by 1 October following the reporting year or reporting period. Copies must be provided to the Minister and Authority at least 7 days prior to publication (ss 26(5), 27(3)). Failure to publish or miss deadlines could prompt regulatory queries and reputational consequences. Note that these obligations only apply if the operator had one or more small use customers during the reporting period (s 28).

Geographical calculation method for area averages can obscure issues

• The average total length of interruptions for area standards is computed as a 4‑year average of annual figures (s 13(3)). A single bad year can thus be diluted over the averaging period, and conversely a string of years may raise the 4‑year average. Operators’ investment and remediation timing should account for this smoothing effect and for how corrective actions will reflect in the rolling calculation.

Temporary Div 3A obligations are time‑bounded

• The Div 3A reliability obligations for Eastern Goldfields and North Country run from 1/10/2018 to 30/9/2028 (s 13A(1)). Those are explicit time‑bounded performance obligations on Electricity Networks Corporation to maintain specified MW to essential services and most small use customers during outages (ss 13B-13C). Operations that align with the temporary nature of these obligations should be documented to demonstrate compliance during the decade and to show transition plans thereafter.

Records retention timing linked to publication dates

• Records required under s 23 must be retained for at least five years after the day on which a report containing the information is published under s 26 or s 27. Because publication dates may vary, retention expiry will be computed relative to publication, not the underlying event, which affects document management planning.

These “gotchas” point to the need for tightly configured operational procedures: notice systems with proof of delivery that meet s 11(3), weather integration for permitted durations, category checks for eligible person status, a defined process for s 24 investigations with field measurements and record retention schedules tied to publication dates, and formalised procedures for handling Ministerial instruments and customer agreements.

This section outlines practical, statute‑grounded compliance measures and operational controls linked to the Code’s specific clauses. It is a checklist of actions, documents and governance arrangements that transmitters and distributors (and corporations operating distribution systems) should implement to satisfy the Code’s provisions and to create the evidentiary basis for “reasonably practicable” decision‑making.

Governance and policy

• Document a “reasonably practicable” policy. Draft and maintain a written internal policy for how the operator interprets and applies “so far as is reasonably practicable” across quality and reliability decisions (refer to ss 5, 9, 10, 13, 13B-13C). Ensure the policy records factors considered (safety, cost, available technology, materiality, network constraints), decision processes, and escalation points. Link policy to Board minutes or executive approvals where material capital works are deferred.

• Ministerial instrument and agreement protocol. Develop a standard operating procedure for responding to s 14 exemption applications, including preparing the Authority referral materials, maintaining copies of any instrument granted and ensuring customers who may be affected can obtain a free copy on request (s 14(8)). Similarly develop standard templates for s 15 written customer agreements that record advantages and disadvantages to the customer.

Operational monitoring, measurement and record keeping

• Implement continuous monitoring systems that measure voltage fluctuation (Pst and Plt), harmonic distortion levels and interruption events at the point of customer connection per ss 5-7 and s 23. Ensure monitoring hardware/software aligns with the referenced standard (Standard 61000:2001 as cited in s 6(1) when measuring Pst and Plt) and can produce auditable output.

• Keep records required to demonstrate compliance and retain them for at least five years after publication of the relevant report (s 23(2)). Tie document retention scheduling to publication dates (s 26(3), s 27(1)).

Quality investigations and customer engagement

• Put in place a written process to handle s 24 customer requests for investigation. A formal intake form should capture dates, facts, and customer assertions. Ensure field measurement teams are available to complete investigations within 20 working days and have the technical capability to measure harmonics and voltage fluctuations at the point of connection (s 24(3)-(4)). Document any reasonable ground for refusing a request under s 24(5).

• For planned interruptions, build notice templates and delivery mechanisms that comply with the acceptable methods in s 11(3). Maintain proof of posting, electronic transmission logs and broadcast copies. Do not rely solely on website postings or telephone, as s 11(4) excludes these methods. Where a customer has nominated a postal address for notices under s 11(3)(aa), track and respect that nomination.

Planned interruption scheduling and temperature rules

• Integrate Bureau of Meteorology forecasts into planned maintenance scheduling to identify when the 6‑hour permitted duration for premises on or south of 26° must be treated as 4 hours because forecast maximum temperature is 30°C or higher for any part of the interruption period (s 11(2)(a)(ii)). Capture forecast snapshots at the time notice is given and retain them to support any later disputes.

Alternative supply and vulnerable customers

• Implement a process that identifies customers whose business impact would be substantial or where a person living at the premises has special health needs requiring electricity (s 10(2)). For such customers consider arranging alternative supplies, temporary generators or rescheduling. Document the risk assessment and communications.

Area averages and reporting

• Build an interruption‑event database that aggregates customer premises interruptions by discrete area (Perth CBD, other urban areas, other areas) and by the further discrete areas in Sch 1 (North West interconnected system, isolated system areas, stand‑alone power systems). Use the s 13(3) calculation method to produce rolling 4‑year averages and make this calculation part of annual reporting.

• Prepare annual reports containing the Schedule 1 items (Sch 1) and publish by 1 October following the year ending 30 June, with a copy to the Minister and the Authority at least 7 days earlier (s 27(1)-(3)). Ensure reports are available free at business transaction locations and on a website (s 26(4), s 27(2)). If the operator had no small use customers during the reporting period, the operator may not be required to audit or report under ss 26-27 (s 28).

Independent audits

• Procure independent expert audits of monitoring systems for each reporting period (s 26(1)-(2)). If the Authority issues a s 26A notice, adapt the reporting period to 1 or 2 years as required. Publish audit reports by 1 October following the reporting period and provide copies to the Minister and Authority not less than 7 days before publication (s 26(3)-(5)).

Complaint handling and ombudsman referrals

• Create and publish a complaints handling document for small use customers, provide it at no cost to complaining customers and ensure it explains the right to refer unresolved complaints to the electricity ombudsman under Act Part 7 (s 25(2)-(3)). Keep a log of complaints (Sch 1 items 4-9) and costs spent addressing complaints, excluding statutory payments.

Part 3 payments and applications

• For corporations operating distribution systems, establish a simple application intake and payment procedure for s 18 and s 19 claims. Track eligible person status (≤50 MWh/year) and ensure applications are processed within 30 days of receipt (ss 16, 18(1), 19(1)). Record the time of notification or when the operator should reasonably have been aware of the interruption for s 19 timing calculations (s 19(2)).

• Where appropriate, put arrangements in place under s 22 to pay retail licensees so payments are credited to customers via billing arrangements. Document these arrangements and customer communications.

Temporary Div 3A obligations (Electricity Networks Corporation)

• If operating in Eastern Goldfields or North Country, document the arrangements required by ss 13B-13C to restore and maintain the specified MW thresholds to essential services and the majority of small use customers during planned/unplanned outages. Create contingency plans, resource allocation plans and testing protocols to demonstrate that the corporation has systems in place “so far as is reasonably practicable” for the 2018-2028 period.

Records and evidence for auditability

• Maintain dated logs, decision memos, meeting minutes, forecasts, proof of notice delivery, field measurement results and measurement instrument calibration records. These documents will be central in independent audits and complaints handling where the “reasonably practicable” test is assessed.

Legal and regulatory liaison

• Liaise with the Authority when applying for Ministerial exemptions under s 14. Ensure submissions for exemptions include full technical justification and documentation of alternatives considered because the Minister must have regard to Authority advice before granting an exemption (s 14(2)-(3)).

Training and culture

• Train operations, customer service and legal/compliance teams on the Code’s distinctions (eligible person vs small use customer), notification methods allowed, investigation timelines, and the reporting/audit calendar. Ensure customer service scripts and billing systems reflect the Code’s payment entitlements and application timelines.

Putting these operational steps into practice aligns an operator’s processes with the Code’s obligations (ss 5-27), builds the record evidence required by audits (s 26), and reduces the risk of disputes under the Code’s complaint and payment pathways.