ELECTRICITY REFORM (SYSTEM CONTROL AND MARKET OPERATOR FUNCTIONS CODE) REGULATIONS 2015

The Code focuses on the narrow operational concept of out-of-balance energy in relation to NAC electricity networks and sets a framework for how system controllers and market participants should treat such energy. The main concepts, as defined in Schedule clause 2 and applied in clause 4, are the following.

• NAC electricity network. The Code applies to all NAC electricity networks, the term being defined by cross-reference to section 2A of the Electricity Networks (Third Party Access) Act 2000 (Schedule cl 2, definition of NAC electricity network; Schedule cl 3). The Regulations therefore operate only in the jurisdiction and classes of network covered by that Act.

• Connection infrastructure and points. The Schedule defines connection assets as all electrical equipment used solely to transfer electricity to or from an NAC electricity network at the connection point, including transformers and switchgear that support or provide backup for such equipment (Schedule cl 2). A connection point is where electricity is transferred to or from an NAC network. The Code also distinguishes entry points (where electricity is more likely transferred to the NAC network) and exit points (where electricity is more likely transferred from the NAC network) (Schedule cl 2, definitions of connection point, entry point, exit point).

• Generator user and load user. A generator user is a person granted access to an NAC network who supplies electricity into the NAC network at an entry point (Schedule cl 2). A load user is a person granted access who takes electricity from the NAC network at an exit point. These definitions allocate operational roles and therefore financial exposures in relation to out-of-balance energy.

• Out-of-balance energy. Out-of-balance energy is defined as the supply of electrical energy to a load user by a generator user other than the generator user who is party to the access agreement when there is a mismatch between transfers into and out of the NAC network by the parties to the access agreement (Schedule cl 2). Clause 4(2) elaborates that out-of-balance energy services involve (a) energy dispatched by a generator user at the system controller’s request to meet mismatches between transfers into and out of the network under an access agreement, and (b) provision of generation capacity by a generator user when requested by the system controller to meet a shortfall between a network user’s own effective generation capacity and its customers’ load (Schedule cl 4(2)(a)-(b)).

• Network energy loss. Network energy loss is defined as the energy loss incurred in transporting electricity from an entry or transfer point to an exit or another transfer point on an NAC network (Schedule cl 2). Clause 4(3) requires the system controller’s assessment of out-of-balance energy to take full account of network energy losses as determined from time to time by the Utilities Commission.

• System controller and Utilities Commission roles. The system controller is the operative decision maker for dispatch requests under the Code, because out-of-balance energy services are supplied at the system controller’s request (Schedule cl 4(2)). The Utilities Commission has the role of determining network energy losses from time to time; those determinations must be fully taken into account by the system controller when assessing out-of-balance energy (Schedule cl 4(3)).

• Commercial negotiation of price. The Schedule specifies that prices of electrical energy supplied under access agreements or standby generation agreements are subject to commercial negotiation between the parties and are not subject to regulation under the Code (Schedule cl 4(4)). The Code therefore licenses private contract pricing for out-of-balance energy and related capacity services instead of setting regulated tariffs.

These concepts establish a limited institutional architecture: system controllers instruct dispatch and must account for loss factors set by the Utilities Commission; generator users and load users are defined as parties to access agreements and as the subjects of dispatch instructions; pricing is left to private negotiation; and the Code binds electricity entities that use NAC networks by virtue of regulation 3.

The instrument explicitly targets entities and persons that interact with NAC electricity networks. The primary categories identified in the Schedule are:

• Electricity entities that use NAC electricity networks. Regulation 3 makes clear that the Code applies to electricity entities to the extent the Code is applicable to them, for the purposes of section 24(1)(b) of the Electricity Reform Act 2000. The Schedule defines several participant roles that fall within the class of entities affected (Schedule cl 2 definitions).

• Generator users. Defined as persons granted access by a network provider who supply electricity into an NAC electricity network at an entry point (Schedule cl 2). The Code applies to services provided by a generator user that relate to out-of-balance energy (Schedule cl 4(1)). Generator users therefore face the operational exposure of being the suppliers of out-of-balance energy when requested by the system controller and the commercial negotiation of prices for those supplies (Schedule cl 4(2) and cl 4(4)).

• Load users. Defined as persons granted access by a network provider who take electricity from an NAC network at an exit point (Schedule cl 2). Load users are the recipients of out-of-balance energy and are implicated where a generator other than the contracted generator supplies energy to meet mismatches (Schedule cl 2 definition of out-of-balance energy; cl 4(2)(a)).

• Network providers and network users. The Code’s definitions include network provider and network user (Schedule cl 2). Network providers are those who provide network access, and the network user labels those who use the NAC network. The interaction between access agreements and out-of-balance services impacts these parties because out-of-balance events occur where transfers under access agreements do not match.

• System controller. The system controller for an NAC network is defined as a participant with operational control functions (Schedule cl 2). The Code empowers the system controller to request dispatch of out-of-balance energy and to request provision of generation capacity to meet shortfalls (Schedule cl 4(2)). The system controller is obliged to take into account network energy losses as determined by the Utilities Commission when assessing out-of-balance energy (cl 4(3)).

• Utilities Commission. The Utilities Commission is explicitly given the role of determining network energy losses from time to time (Schedule cl 4(3)). While the Commission is not a market participant, its determinations affect assessments and therefore the volumes that are dispatched and potentially the commercial arrangements between parties.

• Parties to access agreements and standby generation agreements. The Code expressly contemplates that prices under access agreements or standby generation agreements are subject to commercial negotiation and not regulated (Schedule cl 4(4)). Parties who enter such agreements therefore have freedom to contract.

Who pays and who decides, in practical terms, flow from these definitions and rules. Generator users supply out-of-balance energy on the system controller’s request; pricing is determined by commercial negotiation among the contracting parties, not by the Code (Schedule cl 4(2)-(4)). The Utilities Commission determines network energy loss factors that the system controller must incorporate (Schedule cl 4(3)). The Regulations therefore affect both operational behaviour (dispatch decisions and accounting for losses) and contractual relations (negotiated prices).

Notably, the instrument applies to all NAC electricity networks (Schedule cl 3). That breadth means that any generator user, load user, network user or provider operating on a NAC network is within scope. The instrument does not identify distinct obligations or exemptions for classes of participants within NAC networks; rather, it sets a small number of rules that apply across all NAC networks and delegates certain technical determinations to the Utilities Commission (Schedule cl 4(3)).

The Code prescribes a small set of duties, allocates decision roles, and recognises marketplace rights within its limited subject matter. The principal duties and rights that can be read directly from the instrument are:

Duties and procedural obligations

• Obligation to comply with the Code. Regulation 3 requires an electricity entity to comply with the System Control and Market Operator Functions Code, as set out in the Schedule, to the extent that it is applicable to the entity, for the purposes of section 24(1)(b) of the Electricity Reform Act 2000. The duty is made statutory by regulation 3; the instrument does not specify sanctions (regulation 3).

• System controller’s assessment obligation. Clause 4(3) places a specific duty on the system controller in its assessment of out-of-balance energy supplied or demanded by a generator user: the system controller must take full account of such network energy losses as are determined from time to time by the Utilities Commission. This is an operational duty tied to the Commission’s determinations and affects how the system controller calculates the necessary dispatch volumes.

Delegated decision-making rights

• System controller’s dispatch authority. Clause 4(2) recognises that out-of-balance energy services involve energy dispatched by a generator user into the power system at the request of the system controller to meet mismatches, and the provision of generation capacity at the request of the system controller to meet shortfalls. The Code therefore affirms the system controller’s right to direct dispatch and capacity calls within NAC networks in relation to out-of-balance events.

• Utilities Commission’s determination right. Clause 4(3) gives the Utilities Commission the right to determine network energy losses from time to time. Those determinations are binding on the system controller for assessment purposes.

Contractual rights and commercial freedom

• Parties’ commercial negotiation rights. Clause 4(4) explicitly states that prices for electrical energy supplied under access agreements or standby generation agreements are subject to commercial negotiation between the parties and are not subject to regulation under the Code. The Code preserves contracting freedom for price formation in these agreements.

Defined statuses and entitlements

• Generator user and load user statuses. The Schedule defines who is a generator user and who is a load user (Schedule cl 2). Those entitlements are operationally significant: generator users can be called upon to supply out-of-balance energy, and load users are the recipients of supply and therefore the subjects of potential imbalance adjustments.

What the Code does not do, by specific omission in the Schedule, is set regulated prices, prescribe settlement or metering procedures, set service levels, provide enforcement sanctions in the text, or specify point-in-time processes for dispute resolution. Clause 4(4) is explicit that the Code does not regulate prices; it leaves price terms to private negotiation. The duty to take “full account” of network energy losses (clause 4(3)) is operational but does not specify the method for implementing that requirement, beyond deferring to the Utilities Commission’s determinations.

In short, duties in the instrument are a statutory compliance requirement for electricity entities (regulation 3) and an operational duty on system controllers to incorporate Utilities Commission loss determinations (Schedule cl 4(3)). Rights include the system controller’s operational dispatch authority (Schedule cl 4(2)), the Utilities Commission’s role in determining loss factors (Schedule cl 4(3)), and the parties’ commercial freedom to negotiate prices (Schedule cl 4(4)).

The text of the Regulations and the Schedule does not specify penalties, infringement notices, pecuniary fines or enforcement machinery. Regulation 3 is framed as a compliance obligation,"an electricity entity must comply with the System Control and Market Operator Functions Code, as set out in the Schedule, to the extent that it is applicable to the entity",but the instrument does not itself articulate the legal consequences of non-compliance, nor does the Schedule include enforcement powers, sanctions or remedial procedures.

The instrument’s heading describes it as being made under the Electricity Reform Act 2000. Regulation 3 expressly references "section 24(1)(b) of the Act" as the statutory basis for requiring compliance. The Regulations therefore situate the Code within the statutory architecture of the parent Act. The instrument does not reproduce or summarise section 24(1)(b) of the Electricity Reform Act 2000, and the text does not state whether enforcement, sanctioning or dispute resolution mechanisms are provided by that Act or elsewhere. Because the source text supplied here is limited to these Regulations and the Schedule, no internal sanctioning provisions can be quoted for this instrument.

Operational obligations that are amenable to administrative oversight are present: for example, the system controller must take full account of network energy losses as determined by the Utilities Commission when assessing out-of-balance energy (Schedule cl 4(3)). That obligation is capable of review or challenge under other statutory mechanisms that might exist in the parent Act or administrative law generally, but the Regulations themselves do not establish an enforcement route or penalty. Similarly, the commercial negotiation rule for pricing (Schedule cl 4(4)) is a non-regulatory posture; failure to agree commercially would be a contractual/commercial issue rather than a contravention of a price-setting rule.

In sum, the Regulations create binding compliance duties on electricity entities to follow the Code, and an operational duty on system controllers to account for Utilities Commission loss determinations, but they do not set out penalties or specific enforcement processes within the text of the instrument as provided. Any enforcement mechanisms, remedies or sanctions therefore must be located in the parent Act or other laws, which are not reproduced here.

The Regulations are expressly subordinate to and made under the Electricity Reform Act 2000, as stated at the head of the document (Regulations under the Electricity Reform Act 2000). Regulation 3 establishes the Code’s legal force by reference to section 24(1)(b) of the Act,that is the statutory hook for making compliance mandatory for electricity entities. The text of these Regulations does not reproduce section 24(1)(b), so the detailed interplay with the Act’s enforcement or administrative provisions must be read from that Act itself. The instrument, however, makes clear that the Code operates within the Act’s statutory framework.

The Schedule cross-references the Electricity Networks (Third Party Access) Act 2000 by defining NAC electricity network with reference to section 2A of that Act (Schedule cl 2). This cross-reference means that the class of networks to which this Code applies is determined by that other Act’s definition. The scope and technical characteristics of NAC electricity networks are therefore derived from the Third Party Access Act’s text, not from the Code itself.

The Code vests a determinate role in the Utilities Commission by requiring that the system controller take full account of network energy losses "as are determined from time to time by the Utilities Commission" (Schedule cl 4(3)). That provision imports the Utilities Commission’s determinations into the operational assessment process under the Code. The Commission’s determinations therefore become a controlling technical input for dispatch and assessment decisions. How the Commission makes those determinations, the review mechanisms for them, or whether they are subject to consultation is not detailed in the Code and will depend on the Utilities Commission’s statutory regime and processes under its enabling legislation.

Pricing under access agreements and standby generation agreements is expressly left to commercial negotiation and excluded from regulation under the Code (Schedule cl 4(4)). That means the Code deliberately avoids overlapping with any price-regulation provisions that might exist elsewhere; where other laws do regulate prices for particular services, the Code makes clear it does not impose regulated price terms for out-of-balance energy under the Code itself. How regulated price regimes in other instruments, if any, interact with commercial negotiation under private agreements is a question dependent on those other instruments.

The Endnotes document consequential amendments and related subordinate instruments: the National Electricity (Northern Territory) (National Uniform Legislation) Consequential Amendment Regulations 2019 (SL No. 16, 2019) and the Electricity Reform Legislation Amendment Act 2021 (Act No. 23, 2021). Those instruments and Acts may alter definitions, application, or the parent Act’s provisions and thus affect how the Code operates in context. The reprint endnotes show the Regulations were notified 30 June 2015, commenced 1 July 2015 (r 2), and that subsequent instruments and an Act have amended the Schedule (see endnotes listing).

Finally, because the instrument is confined in scope and largely delegates technical determinations to other bodies, its practical interaction with other laws will be heavily shaped by: the definition of NAC electricity networks in the Third Party Access Act (Schedule cl 2; Schedule cl 3); the powers, procedures and determinations of the Utilities Commission; and the framing of compliance and enforcement under the Electricity Reform Act 2000. None of those external sources are included in the text supplied here beyond the cross-references, so the Code should be read as a focused instrument that allocates operational roles and preserves commercial negotiation within a broader regulatory architecture.

The instrument and its Schedule have a concise recorded amendment history in the Endnotes. Material dates and instruments recorded are:

• Original instrument: Electricity Reform (System Control and Market Operator Functions Code) Regulations (SL No. 15, 2015). The instrument was notified on 30 June 2015 and commenced on 1 July 2015 (see Endnotes item 2, and Regulation 2 which fixes the commencement date). The Schedule containing the Code commenced with the Regulations.

• National Electricity consequential amendment regulations: National Electricity (Northern Territory) (National Uniform Legislation) Consequential Amendment Regulations 2019 (SL No. 16, 2019). These regulations were notified on 1 July 2019 and commenced on 1 July 2019 (Endnotes item 2). The Endnotes also record a specific amendment entry: "sch amd No. 16, 2019, r 27", indicating the Schedule was amended by SL No. 16 of 2019 by regulation 27 of that instrument. The reprint notes show that the Schedule was amended in 2019.

• Electricity Reform Legislation Amendment Act 2021: Act No. 23, 2021. The Act received assent on 18 November 2021 and commenced on 19 November 2021 (Endnotes item 2). The Endnotes record "Act No. 23, 2021, s 14" in the list of amendments, indicating that section 14 of that amending Act amended the Schedule. The reprint states it is "As in force at 19 November 2021", so the 2021 Act’s commencement is reflected in the reprint.

• General formal amendments: The Endnotes note that general amendments of a formal nature were made by the Interpretation Legislation Amendment Act 2018 (Act No. 22, 2018) to regulation 1 and the Schedule (Endnotes item 3). Those amendments are described as being of a formal nature and are not detailed in the table of amendments to the reprint.

• Citation of amendments: The Endnotes include a "List of amendments" entry noting "sch amd No. 16, 2019, r 27; Act No. 23, 2021, s 14" (Endnotes item 4). This confirms that the Schedule was amended by the 2019 consequential regulations and by the 2021 amending Act.

The reprint includes these endnotes so that a reader can trace which later instruments and Acts have modified the Schedule since original notification. The Regulations themselves do not contain an internal amendment log, but the Endnotes give the key amending instruments and commencement dates. Any detailed textual changes introduced by the 2019 or 2021 instruments would need to be read in those instruments or in a consolidated legislation database; the reprint here annotates that those amendments were made.

The instrument and its Schedule do not include citations to judicial or administrative decisions, and the document provided contains no references to cases. The Endnotes do not list any litigation connected to the Regulations or the Schedule. Consequently, within the supplied source text there is no recorded litigation history to summarise, no named authorities to apply, and no cases cited. The Schedule is an operational code inserted as subordinate legislation; any litigation that might arise would need to be located in external records or case law databases. The text before you does not provide any judicial interpretations, appeals, or case law that apply or construe the Code, nor does it record disputes or determinations under the Code.

Practically, this absence in the instrument means that anyone attempting to interpret ambiguous terms, exercise or challenge the system controller’s assessment duties, or contest Utilities Commission determinations would need to look outside these Regulations to case law, administrative decisions, or other statutory review mechanisms. But the Regulations themselves do not supply a litigation record or decisions that clarify the meaning of key terms such as "more likely to be transferred", "full account", or the mechanics of network energy loss determinations. Any precedent-based guidance must therefore be sought in external sources, which are not included in this document.

The Code is concise and leaves significant operational and legal gaps to be filled by other instruments, agreements, or administrative determinations. The following are practical pitfalls and implementation risks that flow directly from the instrument’s text.

• Broad but sparse coverage. The Schedule applies to all NAC electricity networks (Schedule cl 3) but contains only a few operative rules. It sets definitions and two operational constraints,system controller must account for Utilities Commission-determined losses (cl 4(3)), and prices are commercially negotiated and not regulated (cl 4(4)). The Code does not prescribe measurement protocols, timing and settlement procedures, dispute resolution mechanisms, or enforcement processes. That scarcity creates implementation ambiguity for participants seeking rule clarity.

• “More likely to be transferred” test for entry and exit points. Entry points and exit points are defined by what is "more likely" to be transferred, into or from the NAC network (Schedule cl 2 definitions). That probabilistic formulation can create classification disputes where a connection is bidirectional or frequently switches flow direction, leading to uncertainty about whether a participant is a generator user or load user for particular purposes. This classification affects the obligations and commercial arrangements that apply.

• System controller’s obligation tied to Utilities Commission determinations. Clause 4(3) requires the system controller's assessment of out-of-balance energy to take "full account" of network energy losses "as are determined from time to time by the Utilities Commission". The Commission’s determinations therefore materially affect dispatch volumes and calculations of imbalance. If the Commission’s methodology, timing, reviewability or publication practices are unclear, the system controller and participants may face uncertainty about the loss factors to be applied at any given time. The term "from time to time" also suggests changes over time that may affect commercial exposures after agreements are concluded.

• Commercial pricing left to the parties. Clause 4(4) makes clear that prices for energy supplied under access agreements or standby generation agreements are not regulated under the Code and are subject to commercial negotiation. This preserves contracting freedom but also places the financial risk on participants negotiating bilateral terms. In circumstances of imbalance, generator users may need to provide energy at commercially negotiated prices that could be disputed if the code provides no price floor, default rate or dispute mechanism.

• No internal enforcement or penalty regime in the instrument. Regulation 3 creates the duty to comply but does not specify sanctions or enforcement mechanisms. That omission forces parties to look to the Electricity Reform Act 2000 or other laws to determine remedies for non-compliance, which may produce timing and legal uncertainty in enforcement and dispute resolution.

• Definition of out-of-balance energy hinges on "generator user other than the generator user who is party to the access agreement". The definition in Schedule cl 2 means that where another generator supplies the load user, that supply is considered out-of-balance. In practice, this can create cross-party exposures where a network user’s contracted generator did not supply and another party did, possibly leading to complex billing and reconciliation. The Code does not prescribe the settlement mechanics for resolving those differences.

• Transfer points and different ownership. Transfer points are defined as points at which electricity is transferred between differently owned and operated NAC networks (Schedule cl 2). The Code does not elaborate coordination mechanisms for inter-network transfers, leaving potential for mismatched commercial and operational procedures at ownership boundaries.

• Potential for shifting costs through private agreements. Because pricing is left to private negotiation, there is scope for concentrated negotiating power to shape terms for out-of-balance services in ways that redistribute costs between generator users, load users and network providers. The instrument contains no safeguards addressing market power or inequitable contract terms.

• Reliance on external determinations and cross-referenced definitions. The effective operation of the Code depends on two external inputs: the definition of NAC electricity network in the Electricity Networks (Third Party Access) Act 2000 (Schedule cl 2) and the Utilities Commission’s determinations of network energy loss (Schedule cl 4(3)). Any ambiguity, delay, or procedural issues in those external regimes will directly affect the Code’s operation.

These "gotchas" are not normative criticisms but practical flags for participants and regulators. They describe areas where the Code intentionally defers to commercial contracting or to other statutory or administrative bodies, and where that deferral creates uncertainty, negotiation exposure, or operational complexity. Parties structuring access agreements, standby arrangements or operating procedures should take these gaps into account.

Compliance with the instrument involves a combination of legal adherence, contractual drafting, operational implementation, and administrative coordination with the Utilities Commission and the system controller. The Regulations require that an electricity entity must comply with the Code to the extent that it is applicable to the entity (regulation 3). Beyond that statutory duty, the practical steps to achieve compliance, grounded in the instrument’s text, are:

1. Determine whether you are within scope. Confirm whether the network or networks you use are NAC electricity networks as defined by section 2A of the Electricity Networks (Third Party Access) Act 2000 (Schedule cl 2 and Schedule cl 3). If you use an NAC electricity network, the Code applies to you to the extent relevant.

2. Classify roles and connection points. For each connection point, determine whether it is an entry point, an exit point or a transfer point under the Schedule definitions (Schedule cl 2). Where a connection is bidirectional, document the technical and historical flow patterns to support the "more likely to be transferred" test for entry/exit classification. Establish whether your entity qualifies as a generator user, load user, network provider or network user.

3. Reflect the Code in access agreements and standby generation agreements. Clause 4(4) makes clear that prices are subject to commercial negotiation and not regulated under the Code. Access agreements and standby generation agreements should therefore explicitly record pricing arrangements for out-of-balance energy and capacity calls, allocation of costs and liabilities for imbalance events, measurement and metering standards, invoicing and settlement timelines, and dispute resolution mechanisms. Because the Code does not set default prices or settlement rules, contract terms should be comprehensive.

4. Prepare operational procedures for out-of-balance events. The system controller may request generator users to dispatch energy or provide generation capacity to meet mismatches or shortfalls (Schedule cl 4(2)). Generator users and load users should have operational plans, dispatch acceptance protocols, notice and response times, capacity availability schedules, and communications procedures aligned with the system controller’s operational regime.

5. Incorporate Utilities Commission loss factors. Clause 4(3) obliges the system controller to take full account of network energy losses as determined from time to time by the Utilities Commission. Entities should monitor the Utilities Commission’s determinations and incorporate the applicable loss factors into their energy accounting, dispatch calculations and settlement models. If a party is a system controller, implement processes that ensure the Commission’s determinations are applied in real time and that changes are communicated to relevant market participants.

6. Ensure metering and measurement capability. Although the Code does not specify metering standards, out-of-balance accounting presupposes accurate measurement of flows at entry, exit and transfer points. Participants should ensure meters and data collection systems can support the necessary measurement granularity, time-stamping and reporting to reconcile transfers and support invoicing.

7. Manage commercial negotiation risks. Parties that are generator users or load users should model exposure to commercial negotiations for prices under clause 4(4). Where market power or concentration may affect price negotiations, consider contractual protections such as pre-agreed pricing formulas, default rates, price review clauses, or escalation/dispute mechanisms to reduce negotiation risk.

8. Recordkeeping and audit trails. Because the Code delegates key determinations and leaves settlement to agreement, maintain robust records of dispatch instructions, system controller requests, acceptance of dispatch, measurement readings, applied loss factors, and communications. These records will be important for reconciliation, audits, and any referral to the Utilities Commission or other review bodies.

9. Monitor amendments and external instruments. The Endnotes record that the Schedule has been amended by SL No. 16, 2019 and Act No. 23, 2021. Entities should monitor legislative updates and consequential amendments that may change definitions, duties or technical parameters. Also watch for Utilities Commission publications setting network energy losses.

10. Legal review and alignment with other regulatory regimes. Because the Code interfaces with the Electricity Reform Act 2000 and the Electricity Networks (Third Party Access) Act 2000, obtain legal advice on how those Acts interact with contractual terms and operational obligations. The Code is short and deliberately leaves many matters to agreement or other bodies; legal review is necessary to ensure that contracts and operational processes do not conflict with statutory duties implied by regulation 3.

These steps derive from the instrument’s operative provisions: the compliance requirement (regulation 3), the definitions and roles (Schedule cl 2), the Code’s scope (Schedule cl 3), and the substantive obligations on system controllers and parties with respect to out-of-balance energy and pricing (Schedule cl 4(1)-(4)). Implementation requires coordination across legal, commercial and engineering teams to align contracts, dispatch processes and accounting systems with the Code and with Utilities Commission determinations.