11 Glossary

12 Peak SWIS Trading Intervals: Means, for a Hot Season, the 3

Trading Intervals with the highest Total Sent Out Generation on each of the 4 Trading Days with the highest maximum demand in that Hot Season, as published by AEMO in accordance with clause 4.1.23A, where the maximum demand for a Trading Day is the highest Total Sent Out Generation for any Trading Interval in that Trading Day.

2016 Reserve Capacity Cycle: Means the Reserve Capacity Cycle:

$a$ in which Year 1 of that Reserve Capacity Cycle is 2016; and

$b$ which relates to Reserve Capacity required between 1 October 2018 and 1 October 2019.

2017 Reserve Capacity Cycle: Means the Reserve Capacity Cycle:

$a$ in which Year 1 of that Reserve Capacity Cycle is 2017; and

$b$ which relates to Reserve Capacity required between 1 October 2019 and 1 October 2020.

2018 Reserve Capacity Cycle: Means the Reserve Capacity Cycle:

$a$ in which Year 1 of that Reserve Capacity Cycle is 2018; and

$b$ which relates to Reserve Capacity required between 1 October 2020 and 1 October 2021.

2019 Reserve Capacity Cycle: Means the Reserve Capacity Cycle:

$a$ in which Year 1 of that Reserve Capacity Cycle is 2019; and

$b$ which relates to Reserve Capacity required between 1 October 2021 and 1 October 2022.

4 Peak SWIS Trading Intervals: Means, for a Trading Month, the 4

Trading Intervals in the relevant Trading Month with the highest Total Sent Out Generation, as published by AEMO in accordance with clause 4.1.23B.

Acceptable Credit Criteria: The criteria set out in clause 2.38.6.

Access Code: The code established by the Minister under section 104

of the Electricity Industry Act 2004.

Access Proposal: Has the meaning given in clause 4.2.7(b)(ii)(1).

Accumulated Time Error: Means in respect of a frequency measurement

of the SWIS, the integral over time of the difference between 20 milliseconds and the inverse of that frequency measurement, starting from a time determined by AEMO, and recorded by AEMO in its SCADA system.

Additional RoCoF Control Requirement: The smallest quantity of RoCoF

Control Service additional to the Minimum RoCoF Control Requirement that meets the requirement in clause 3.10.3 while maximizing the overall value of Real-Time Market trading under clause 7.2.4.

Adjustment Process: Has the meaning given in clause 9.3.5.

AEMO or Australian Energy Market Operator: Means the Australian

Energy Market Operator Limited (ACN 072 010 327).

This includes an information confidentiality status which was set by the IMO under clause 10.2.2(f) prior to its abolition on the day the Electricity Industry (Independent Market Operator) Repeal Regulations 2018 commenced¹.

¹Note: the Electricity Industry (Independent Market Operator) Repeal Regulations 2018 commenced on 10 April 2018.

AEMO Intervention Event: An event where AEMO intervenes in the

Real-Time Market by issuing a direction in accordance with clause 3.4.4(c), clause 3.4.4(d), clause 3.4.5, clause 7.7.4(b), or clause 7.7.5.

AEMO Deposit Rate: A rate equal to the rate received by AEMO for the

Security Deposit. (AEMO must use reasonable endeavours to obtain a rate which reflects reasonable commercial terms as regards to other deposit rates available at the time.)

AEMO-procured NCESS Contract: A contract between AEMO and a Market

Participant or Ancillary Service Provider for the provision of an NCESS.

AEMO Regulations: Means the *Australian Energy Market Operator

(Functions) Regulations 2015*.

AEMO Transition Date: Means 8:00 AM on 30 November 2015.

Affected Dispatch Interval: A Dispatch Interval for which the

Dispatch Algorithm has been used to determine Dispatch Targets, Dispatch Caps and Market Clearing Prices, but the Dispatch Inputs included manifestly incorrect data that AEMO reasonably considers have caused material differences in Market Clearing Prices.

Aggregated Facility: A group of Facilities of the type defined in

clause 2.29.1B(c), aggregated under section 2.30, and treated as a single Facility for the purpose of these WEM Rules.

Allowable Revenue: Means the allowable revenue for AEMO in

performing its functions set out in clause 2.1A.2 as determined by the Economic Regulation Authority in accordance with section 2.22A.

Alternative Network Constraint Equation: A Constraint Equation

formulation for a Network Constraint other than a Fully Co-optimised Network Constraint Equation.

Amending Rules: Has the meaning given in clause 2.4.1(c).

Application Fee: A fee determined by AEMO under clause 2.24.2.

Approval to Generate Notification: Means the notification issued by

the Network Operator to a Market Participant in accordance with clause 3A.8.12 granting final approval to a Transmission Connected Generating System to generate electricity.

Arrangement for Access: When used in the context of a “covered

network” (as that term is defined in the Access Code) means an “access contract” (as that term is defined in the Access Code). When used in the context of a network which is not a “covered network” (as that term is defined in the Access Code) means any commercial arrangement through which “access” (as that term is defined in the Access Code) to that network is obtained.

Associated Load: Has the meaning given in clause 2.29.5G.

Association Period:Has the meaning given in clause 2.29.5G.

Authorised Officer: In respect of a Rule Participant, means:

$a$ “Officer” as defined in Section 9 of the Corporations Act;

$b$ “executive officer” as defined in section 3(1) of the Electricity Corporations Act; or

$c$ for a Rule Participant that is not a body corporate, a person who is legally able to bind that Rule Participant.

Automatic Generation Control System (AGC): The system into which

Dispatch Targets or Dispatch Caps are entered and processed by AEMO for Registered Facilities operating on automatic generation control.

Availability Class: Means the annual availability of Certified

Reserve Capacity set out in clause 4.5.12, as either Availability Class 1 or Availability Class 2, as applicable.

Availability Class 1: The Availability Class assigned by AEMO to a

facility containing an Intermittent Generating System or Non-Intermittent Generating System, and any other facility that is expected to be available to be dispatched for all Trading Intervals in a Capacity Year, under clause 4.11.4(a).

Availability Class 2: The Availability Class assigned by AEMO to

Certified Reserve Capacity that is not expected to be available to be dispatched for all Trading Intervals in a Capacity Year, under clause 4.11.4(b).

Availability Curve: A curve developed by AEMO under clause

4.5.10(e).

Availability Declaration: A declaration included with a STEM

Submission or Standing STEM Submission and which includes the information described in clause 6.6.2A(b).

Availability Declaration Exemption: Means a condition specified in

clause 3.18B.4.

Explanatory Note

The definition for 'Available Capacity' is amended to clarify that the concept does not relate specifically to synchronisation, and includes intermittent capacity and other non-synchronous capacity.

Available Capacity: For a Registered Facility in a Dispatch

Interval, Injection or Withdrawal capacity that the Market Participant is not expecting to make ready for dispatch in the Dispatch Interval, but expects to be able to make ready for dispatch in the Dispatch Interval if given notice before the relevant Start Decision Cutoff, allowing for expected operating conditions and the effect of any Outages that have not been rejected for the Registered Facility. To avoid doubt, Available Capacity is not limited by the expected availability of intermittent fuels for an Intermittent Generating System such as wind.

AZ: Means the ratio of excess Reserve Capacity to the Reserve

Capacity Requirement for a Reserve Capacity Cycle that is determined to be sufficiently high for the Reserve Capacity Price to be zero.

Bank Bill Rate: The rate set by AEMO:

$a$ at approximately 10:00am on any given Business Day to apply for that day; or

$b$ if the relevant day is not a Business Day, or AEMO does not set a rate for that day, on the previous Business Day on which a rate was set under paragraph (a),

(based on an industry standard market indicator, details of which must be published by AEMO).

Base ESS Quantity: For a Dispatch Interval and a SESSM Award where

there is a non-zero SESSM Availability Payment, the quantity of the relevant Frequency Co-optimised Essential System Service which the Facility would have been capable of providing if not granted the SESSM Award, and which must be offered in addition to the SESSM Availability Quantity.

Benchmark Reserve Capacity Price: In respect of a Reserve Capacity

Cycle, the price published by the Economic Regulation Authority under clause 4.16.1.

Bilateral Contract: A contract formed between any two persons for

the sale of electricity by one of those persons to the other.

Bilateral Submission: A submission by a Market Participant to AEMO

made in accordance with clause 6.2.

Bilateral Submission Cutoff: Means 8:50 AM on the Scheduling Day for

the Trading Day, or such other time as may be notified by AEMO under clause 6.4.6B.

Bilateral Submission Results Window: For a point in time in the

24-hour period starting at 8:00 AM on a Scheduling Day, the period of eight consecutive Trading Days starting with the Trading Day for the Scheduling Day.

BRCP Cap Factor: Means the ratio of the Reserve Capacity Price to

the Benchmark Reserve Capacity Price for a Reserve Capacity Cycle if there was to be no excess Reserve Capacity in that Reserve Capacity Cycle.

Business Day: A day that is not a Saturday, Sunday, or a public

holiday throughout Western Australia. For the purpose of clauses 9.3.4 and 9.15.7, a Business Day is a day that is not a Saturday, Sunday, or a public holiday (including a bank holiday) throughout Western Australia and/or Sydney (New South Wales).

Calendar Hour: A period of one hour, commencing on the hour.

Candidate Fixed Price Facility: Means a Facility that has been

nominated to be classified as a Fixed Price Facility in accordance with clause 4.14.1B.

Capacity Adjusted Forced Outage Quantity: Means, the quantity, in

MW, of the derating of a Facility or Separately Certified Component in a Dispatch Interval or Trading Interval from the Reserve Capacity Obligation Quantity for the Facility or Separately Certified Component as determined by AEMO in accordance with:

$a$ for a Separately Certified Component in a Dispatch Interval, the formula in clause 3.21.7;

$b$ for a Separately Certified Component in a Trading Interval, the formula in clause 3.21.7A;

$c$ for a Facility in a Trading Interval, the formula in clause 3.21.7B; and

$d$ for a Facility in a Dispatch Interval, the formula in clause 3.21.7C.

Capacity Adjusted Planned Outage Quantity: Means, the quantity, in

MW, of the derating of a Facility or Separately Certified Component in a Dispatch Interval or Trading Interval from the Reserve Capacity Obligation Quantity for the Facility or Separately Certified Component as determined by AEMO in accordance with:

$a$ for a Separately Certified Component in a Dispatch Interval, the formula in clause 3.21.8;

$b$ for a Separately Certified Component in a Trading Interval, the formula in clause 3.21.8A;

$c$ for a Facility in a Trading Interval, the formula in clause 3.21.8B; and

$d$ for a Facility in a Dispatch Interval, the formula in clause 3.21.8C.

Capacity Cost Refund: Has the meaning given in clause 4.26.2E.

Capacity Credit: A notional unit of Reserve Capacity provided by a

Facility during a Capacity Year. The total number of Capacity Credits provided by a Facility is determined in accordance with section 4.20. Each Capacity Credit is equivalent to 1MW of Reserve Capacity. The Capacity Credits to be provided by a Facility are held by the Market Participant registered in respect of that Facility. The number of Capacity Credits to be provided by a Facility may be reduced in certain circumstances under the WEM Rules, including under clause 4.25.4 or adjusted under clause 4.25.6.

Capacity Credit Allocation: The allocation of a number of Capacity Credits held by a Market Participant for a Facility to a Market Customer for a Trading Month for settlement purposes through the allocation process in sections 9.4 and 9.5.

Capacity Credit Allocation: The allocation of a number of Capacity

Credits held by a Market Participant for a Facility to a Market Participant for a Trading Day for settlement purposes through the allocation process in section 4.30.

Capacity Credit Allocation Submission: A submission from a Market

Participant to AEMO made in accordance with clauses 4.30.1 and 4.30.3 to allocate Capacity Credits to a single Market Participant.

Capacity Shortfall: Has the meaning given in clause 4.26.2D.

Capacity Year: A period of 12 months commencing at the start of the Trading Day which commences on 1 October and ending on the end of the Trading Day ending on 1 October of the following calendar year.

Category A: The class of WEM Rules classified as Category A civil

penalty provisions in the WEM Regulations for the purposes of the imposition of civil penalties under the Regulations.

Category B: The class of WEM Rules classified as Category B civil

penalty provisions in the WEM Regulations for the purposes of the imposition of civil penalties under the Regulations.

Category C: The class of WEM Rules classified as Category C civil

penalty provisions in the WEM Regulations for the purposes of the imposition of civil penalties under the Regulations.

CC Uplift Quantity: Has the meaning given in clause 4.1A.4.

Central Dispatch Process: The process managed by AEMO for the

dispatch of Registered Facilities for energy and Essential System Services described in clause 7.2.1.

Certified Reserve Capacity: For a Facility, and in respect of a

Reserve Capacity Cycle, is the quantity of Reserve Capacity that AEMO has assigned to the Facility for the Reserve Capacity Cycle in accordance with clause 4.11, as adjusted under these WEM Rules including clause 4.14.8. Certified Reserve Capacity assigned to a Facility registered by a Market Participant is held by that Facility.

Charge Level: An Equipment Limit indicating the current level of

stored energy in MWh in an Electric Storage Resource, as provided to AEMO in a real-time data feed in accordance with section 2.36A.

Chief Executive Officer: In respect of a Rule Participant, the chief

executive officer of the relevant Rule Participant, or if that Rule Participant has no chief executive officer, then the individual nominated by the Rule Participant and holding a similar position to that of chief executive officer of the Rule Participant.

Civil Penalty: Means an amount imposed under a provision of these

WEM Rules that has been specified in Regulations or falls within a class specified in WEM Regulations as a civil penalty provision as provided for under section 124(2)(h) of the Electricity Industry Act.

Civil Penalty Amount: Means an amount imposed in respect of a breach

of a provision of the WEM Rules or the WEM Regulations, that has been specified in Schedule 1 of the WEM Regulations as a civil penalty provision.

Co-ordinated Universal Time: Co-ordinated Universal Time is

determined by the International Bureau of Weights and Measures and maintained under section 8AA of the National Measurement Act 1960 of the Commonwealth.

Cold Season: The period commencing at the start of the Trading Day

beginning on 1 April and ending at the end of the Trading Day finishing on the following 1 October.

Commercial Operation: The status determined by AEMO that:

$a$ under clause 4.13.10B a Facility (other than a Demand Side Programme); or

$b$ under clause 4.13A.25 a Demand Side Programme,

is operating in the Wholesale Electricity Market.

Commissioning Tests: Has the meaning given in clause 3.21A.5.

Commissioning Test Period: The proposed period during which a

Commissioning Test Plan will be conducted, as provided to AEMO under clause 3.21A.7(d).

Commissioning Test Plan: The information submitted to AEMO in

accordance with clause 3.21A.7.

Common Requirements: In respect of each Technical Requirement, means

each requirement as specified in Appendix 12 that is common to both the Ideal Generator Performance Standard and Minimum Generator Performance Standard.

Conditional Certified Reserve Capacity: Has the meaning given in

clause 4.9.5.

Confidential Information: Market Information classified as

confidential by an Information Manager under clause 10.2.3 or the Coordinator under section 10.5.

Congestion Information Resource: An information resource comprising

the information described in clause 2.27B.3.

Congestion Information Resource Objective: Has the meaning given in

clause 2.27B.1.

Congestion Rental: Means, in respect of a Registered Facility, for a

Dispatch Interval and for a set of Network Constraints, the value calculated by AEMO in accordance with clause 7.14.1.

Constrained Portfolio: For a Constraint Equation, a set comprising

all the Registered Facilities within a single Portfolio that are located behind the relevant Network Constraint.

Constrained Uplift Payment Ratio: Has the meaning given in clause

2.16C.2.

Constraint: Means:

$a$ a Network Constraint; and

$b$ a limitation or requirement affecting the capability of a Load or Energy Producing System such that it would represent a risk to Power System Security or Power System Reliability if the limitation or requirement was removed.

Constraint Equation: A mathematical representation of a Constraint

on the SWIS.

Constraint Set: A group of Constraint Equations that respond to a

particular condition or set of conditions.

Constraints Library: The collection of:

$a$ Constraint Equations and Constraint Sets that AEMO is required to develop and maintain in accordance with section 2.27A or clause 5.7.3;

$b$ supporting information, including:

i. Limit Advice, including Limit Equations and Limit Advice Inputs;

ii. the Operating Margin forming part of each Constraint Equation; and

iii. any other information specified in the WEM Procedure referred to in clause 2.27A.10; and

$c$ for each Reserve Capacity Cycle:

i. the information provided by each Network Operator under clause 4.4B.5;

ii. the Preliminary RCM Constraint Equations; and

iii. the final RCM Constraint Equations used by AEMO in the Network Access Quantity Model for determining Network Access Quantities under Appendix 3.

Consumption Contributing Quantity: For a Market Participant for a

Trading Interval, has the meaning given in clause 9.5.7.

Consumption Deviation Application: An application submitted by a

Market Participant to AEMO under clause 4.26.2CB(a) or clause 4.28.9A, notifying AEMO and providing evidence that the consumption of a Load was affected.

Contestable Customer: A person that may purchase electrical energy

from any retailer, including Synergy.

Contingency Event: Has the meaning given in clause 3.8A.1.

Explanatory Note

The amendments to the definitions for 'Contingency Lower Offset' and 'Contingency Raise Offset' reflect how these quantities are used in the Dispatch Algorithm. Rather than a multiplicative factor, these are offsets calculated by AEMO based on system conditions and an assessment of the largest risk. The dispatch process takes a number of inputs to determine whether more or less Contingency Reserve Raise is required, such as load relief, the level of inertia and the size of the largest contingency itself.

Contingency Lower Offset: For each Dispatch Interval or Pre-Dispatch

Interval, the offset determined by AEMO in accordance with the WEM Procedure referred to in clause 7.2.5, when determining the quantity of Contingency Reserve Lower required to maintain the SWIS frequency in accordance with the Frequency Operating Standards taking into account the size of the Largest Credible Load Contingency, and where:

$a$ a negative offset quantity indicates additional Contingency Reserve Lower is required; and

$b$ a positive offset quantity indicates less Contingency Reserve Lower is required.

Contingency Raise Offset: For each Dispatch Interval or Pre-Dispatch

Interval, the offset determined by AEMO in accordance with the WEM Procedure referred to in clause 7.2.5 when determining the quantity of Contingency Reserve Raise required to maintain the SWIS frequency in accordance with the Frequency Operating Standards considering the Largest Credible Supply Contingency, and where:

$a$ a negative offset quantity indicates additional Contingency Reserve Raise is required; and

$b$ a positive offset quantity indicates less Contingency Reserve Raise is required.

Contingency Reclassification Conditions: Means the conditions that

AEMO determines give rise to the need to reclassify a Non-Credible Contingency Event as a Credible Contingency Event.

Contingency Reserve: Has the meaning given in clause 3.9.4.

Contingency Reserve Lower: Has the meaning given in clause 3.9.6.

Contingency Reserve Lower Market Clearing Price: The Market Clearing

Price for Contingency Reserve Lower.

Contingency Reserve Lower Offer Price Ceiling: The price, in dollars

per MW per hour, determined in accordance with clause 2.26.2B, and as may be indexed in accordance with clause 2.26.2U, that is the maximum price that may be associated with a Real-Time Market Submission or Standing Real-Time Market Submission for the provision of Contingency Reserve Lower.

Contingency Reserve Raise: Has the meaning given in clause 3.9.5.

Contingency Reserve Raise Market Clearing Price: The Market Clearing

Price for Contingency Reserve Raise.

Contingency Reserve Raise Offer Price Ceiling: The price, in dollars

per MW per hour, determined in accordance with clause 2.26.2B, and as may be indexed in accordance with clause 2.26.2U, that is the maximum price that may be associated with a Real-Time Market Submission or Standing Real-Time Market Submission for the provision of Contingency Reserve Raise.

Contract Maximum Demand: Has the meaning given in Appendix 3 of the

Electricity Networks Access Code 2004.

Controlled Circumstances: Circumstances where AEMO expects or

requires SWIS Frequency to vary as a result of a test or the process of dispatch.

Coordinator: The Coordinator referred to in section 4 of the Energy

Coordination Act 1994.

Coordinator’s Website: A website or portion of a website maintained

by, or on behalf of, the Coordinator.

Coordinator Transfer Date: Means 8:00AM on the date the amending

rules made under the Electricity Industry (Wholesale Electricity Market) Regulations 2004 (WA), regulation 7(4) giving effect to the transfer of functions from the Rule Change Panel to the Coordinator commence operation.

Corporations Act: The Corporations Act 2001 (Cwlth).

Credible Contingency Event: Has the meaning given in clause 3.8A.2.

Credible Contingency Event Frequency Band: Has the meaning given in

clause 3B.2.3.

Credit Limit: In respect of a relevant Rule Participant, the amount

determined by AEMO in accordance with clause 2.37.4.

Credit Support: Has the meaning given in clause 2.38.4.

Cure Notice: Has the meaning given in clause 9.19.4(a).

Customer: Means a person to whom electricity is sold for the purpose

of consumption.

De-registration Notice: means the notice issued by AEMO under clause

2.32.7E(b).

Declared Sent Out Capacity: Has the meaning given in Appendix 3 of

the Electricity Networks Access Code 2004.

Deemed DSM Dispatch: The quantity (in MWh) for a Demand Side

Programme for a Trading Interval equal to the least of:

$a$ half of the Facility’s Capacity Credits;

$b$ the requested decrease in consumption specified under clause 7.13.1(eG); and

$c$ the greater of zero and the difference between:

i. half of the Relevant Demand set in clause 4.26.2CA; and

ii. the Demand Side Programme Load measured in the Trading Interval, adjusted to add back any Further DSM Consumption Decrease.

Default Levy: The amount, in respect of a given Rule Participant and

in the circumstance of a particular Payment Default, determined by AEMO in accordance with clause 9.20.6.

Degenerate Solution: Occurs where, according to the Dispatch

Algorithm, more than one combination of Dispatch Targets and ESS Enablement Quantities will maximise the value of Real-Time Market trading while taking into account the various constraints in section 7.2.

Delegate: Means a person appointed by AEMO under clause 2.1A.3 to

perform a function on its behalf that is, in AEMO's opinion, competent to exercise the relevant function.

Demand Side Management: A type of capacity held in respect of a

Facility connected to the SWIS; specifically, the capability of a Facility connected to the SWIS to reduce its consumption of electricity through the SWIS, as measured at the connection point of the Facility to the SWIS.

Demand Side Programme: Means a Facility registered in accordance

with clause 2.29.5A.

Demand Side Programme Capacity Cost Refund: Has the meaning given in

clause 4.26.3A.

Demand Side Programme Load: Has the meaning given in clause 9.5.4.

DER Generation Information: Standing data in relation to:

$a$ a Small Generating Unit; or

$b$ Storage Works with an export capacity of less than 5 MW.

DER Register: The register established and maintained by AEMO in

accordance with clause 3.24.

DER Register Information: Information contained in the DER Register.

DER Register Report: The report of aggregated DER Register

Information required to be developed and published by AEMO under clause 3.24.12.

DER Roadmap: The distributed energy resources roadmap delivered by

the Energy Transformation Taskforce pursuant to the Western Australian Government’s Energy Transformation Strategy and published by the Minister on 4 April 2020.

DER Roadmap Actions: Any activities undertaken by AEMO to implement

the DER Roadmap that have been endorsed by the Minister as Wholesale Electricity Market and Constrained Network Access Reform and includes any and all such activities undertaken after 31 December 2019 irrespective of the date they were endorsed.

DER Roadmap Implementation Costs: Any costs incurred by AEMO after

31 December 2019 in respect of DER Roadmap Actions.

Disconnected Microgrid: Means a part of the SWIS that is not an

Embedded System, that is designed to be disconnected from the remainder of the SWIS, and that has disconnected from the remainder of the SWIS, and is being operated independently from the SWIS by a Network Operator.

Dispatch Algorithm: Means, the algorithm used in the Central

Dispatch Process developed by AEMO in accordance with section 7.2.

Dispatch Cap: The total MW level of Injection or Withdrawal that

must not be exceeded by a Semi-Scheduled Facility at the end of the Dispatch Interval.

Dispatch Criteria: Means the criteria under clause 7.6.1.

Explanatory Note

The definition for 'Dispatch Forecast' is amended as a consequence of introducing the concepts of Unconstrained Injection Forecasts and Unconstrained Withdrawal Forecasts, and clarifies how the Dispatch Algorithm uses these quantities to determine an overall Dispatch Forecast for Non‑Scheduled Facilities and Semi-Scheduled Facilities.

Dispatch Forecast: The total MW level of Injection or Withdrawal

expected to be reached by a Semi-Scheduled Facility or Non-Scheduled Facility at the end of the Dispatch Interval which is:

$a$ for a Non-Scheduled Facility, the Market Participant’s Unconstrained Injection Forecast or Unconstrained Withdrawal Forecast, as applicable, for the Non‑Scheduled Facility for the Dispatch Interval, as may be replaced by AEMO under clause 7.2.4A; and

$b$ for a Semi-Scheduled Facility:

i. if AEMO has specified a Dispatch Target for the Semi-Scheduled Facility for the Dispatch Interval, that Dispatch Target;

ii. otherwise, if the Semi-Scheduled Facility is expected to be Injecting at the end of the Dispatch Interval, the lesser of:

1. the Dispatch Cap for the Semi-Scheduled Facility for the Dispatch Interval; and

2. the Market Participant’s Unconstrained Injection Forecast for the Semi-Scheduled Facility for the Dispatch Interval, as may be replaced by AEMO under clause 7.2.4A; and

iii. otherwise, the greater of:

1. the Dispatch Cap for the Semi-Scheduled Facility for the Dispatch Interval; and

2. the Market Participant’s Unconstrained Withdrawal Forecast for the Semi-Scheduled Facility for the Dispatch Interval, as may be replaced by AEMO under clause 7.2.4A.

Dispatch Inflexibility Profile: Means, the parameters that indicate

a Registered Facility’s MW capacity and time related dispatch inflexibilities in accordance with clause 7.4.44 for a Fast Start Facility.

Dispatch Input: Any value, excluding the values made, or required to

be made, by Market Participants in a Real-Time Market Submission, that is used by the Dispatch Algorithm, including:

$a$ measurements of power system status;

$b$ the Forecast Unscheduled Operational Demand;

$c$ Constraint Equations; and

$d$ software setup for the Dispatch Algorithm.

Dispatch Instruction: Has the meaning given in clause 7.6.5.

Dispatch Interval: Means each 5 minute period commencing at 0, 5,

10, 15, 20, 25, 30, 35, 40, 45, 50 and 55 minutes past the hour.

Dispatch Quantity: The value specified for the Capacity Year in the

Statement of Opportunities Report most recently published before the start of the Capacity Year.

Dispatch Schedule: A forecast of the Market Clearing Prices,

Dispatch Targets, Dispatch Caps, Dispatch Forecasts and Essential System Services Enablement Quantities for each Dispatch Interval in the Dispatch Schedule Horizon.

Dispatch Schedule Horizon: The next 24 Dispatch Intervals after a

Dispatch Interval.

Explanatory Note

The definition for 'Dispatch Target' is amended to remove the reference to Demand Side Programmes, which have specific Dispatch Instruction arrangements and no longer receive “Dispatch Targets”.

Dispatch Target: For a Scheduled Facility or Semi-Scheduled

Facility, the level of Injection or Withdrawal to be reached at the end of a Dispatch Interval.

Dispute Participants: The parties to a relevant dispute described in

clause 2.18.2.

Distribution Loss Factor: A factor representing the average

electrical losses incurred when electricity is transmitted through a distribution network.

Distribution Loss Factor Class: A group of one or more connection

points with common characteristics assigned a common Distribution Loss Factor.

Draft Rule Change Report: The draft report described in clause 2.7.7

and published by the Coordinator under clause 2.7.6(a) in relation to a Rule Change Proposal.

Draw Upon: In relation to Credit Support or Reserve Capacity

Security held by AEMO in relation to a Rule Participant, means that AEMO:

$a$ in relation to a Security Deposit, applies the Security Deposit to satisfy amounts owing by the relevant Rule Participant; or

$b$ in relation to other Credit Support, exercises its rights under the Credit Support, including by drawing or claiming an amount under it.

Droop Response: A fast, automatic and localised control scheme for

generation facilities, wherein power output is proportionally adjusted to counteract frequency deviations.

DSM Reserve Capacity Security: The reserve capacity security to be

provided for a Demand Side Programme that:

$a$ has the meaning given in clause 4.13A.6; and

$b$ is as calculated and re-calculated under section 4.13A.

Explanatory Note

The following definitions are added to support the new arrangements for Demand Side Programme submissions, dispatch and publications:

DSP Constrained Withdrawal Quantity and DSP Unconstrained Withdrawal Quantity;
DSP Forecast Capacity and DSP Forecast Reduction;
DSP Schedule, DSP Pre-Dispatch Schedule and DSP Week-Ahead Schedule; and
DSP Withdrawal Profile Submission.

The definition of DSP Ramp Rate Limit deleted because ramp rates are no longer required for Demand Side Programmes.

DSP Constrained Withdrawal Quantity: A Market Participant’s estimate

of the absolute value of the average MW Withdrawal of its Demand Side Programme in a Dispatch Interval, taking into account any information about the potential or actual dispatch of the Demand Side Programme that is provided by AEMO in Market Advisories under clause 7.11.6(cA), Dispatch Instructions under clause 7.6.15 or notifications under clause 4.25.9(h).

DSP Forecast Capacity: An estimate of the potential reduction in the

absolute value of Withdrawal of a Demand Side Programme in a Dispatch Interval if the Demand Side Programme was fully dispatched by AEMO in accordance with the Reserve Capacity Obligations for the Demand Side Programme, determined by AEMO in accordance with clause 7.8A.3.

DSP Forecast Reduction: An estimate of the expected reduction in the

absolute value of Withdrawal of a Demand Side Programme in a Dispatch Interval based on DSP Withdrawal Profile Submissions provided by the Market Participant, determined by AEMO in accordance with clause 7.8A.4.

DSP Pre-Dispatch Schedule: Has the meaning given in clause 7.8A.1.

DSP Schedule: A DSP Week-Ahead Schedule or a DSP Pre-Dispatch

Schedule.

DSP Unconstrained Withdrawal Quantity: A Market Participant’s

estimate of the absolute value of the average MW Withdrawal of its Demand Side Programme in a Dispatch Interval, assuming that the Demand Side Programme does not receive a notification under clause 4.25.9(h) or Dispatch Instruction under clause 7.6.15 that affects its Withdrawal in the Dispatch Interval.

DSP Week-Ahead Schedule: Has the meaning given in clause 7.8A.1.

DSP Withdrawal Profile Submission: A submission made by a Market

Participant to AEMO which provides a DSP Unconstrained Withdrawal Quantity and DSP Constrained Withdrawal Quantity for a Demand Side Programme for a Dispatch Interval.

Early Certified Reserve Capacity: Reserve Capacity which is

certified and assigned to a new Facility by AEMO for a future Reserve Capacity Cycle under clause 4.28C.

Economic Regulation Authority: The body established under section

4(1) of the Economic Regulation Authority Act (WA).

Electric Storage Resource: A system or resource capable of receiving

and storing energy for later production of electric energy.

Electric Storage Resource Obligation Duration: The eight contiguous

Electric Storage Resource Obligation Intervals which apply each Trading Day and commence at the time published by AEMO in accordance with clause 4.11.3A.

Electric Storage Resource Obligation Interval: A Trading Interval,

that AEMO has determined in accordance with the WEM Procedure referred to in clause 4.11.3A, in which a non‑zero Reserve Capacity Obligation Quantity is applied to an Electric Storage Resource.

Electric Storage Resource Obligation Quantity: The specific amount

of capacity required to be provided in a Trading Interval as part of a Reserve Capacity Obligation for an Electric Storage Resource set by AEMO in accordance with clauses 4.12.14 and 4.12.14A as adjusted from time to time in accordance with these WEM Rules, including under clause 4.12.6.

Electrical Location: The zone substation at which the Transmission

Loss Factor for a Registered Facility is defined.

Electricity Corporations Act: Means the Electricity Corporations Act

2005 (WA).

Electricity Industry Act: Means the Electricity Industry Act 2004

(WA).

Electricity Review Board: The Board within the meaning of the

Electricity Industry Act.

Eligible Services: Has the meaning given in clause 4.24.3.

Embedded System: Means a Network connected at a connection point on

the SWIS which is owned, controlled or operated by a person who is not a Network Operator or AEMO.

Emergency Operating State: The state of the SWIS defined in clause

3.5.1.

Enablement Limit: Enablement Maximum or Enablement Minimum.

Enablement Losses: For a Registered Facility providing a Frequency

Co-optimised Essential System Service in a Dispatch Interval, an estimate of the difference between the revenue received for providing energy and the Frequency Co‑optimised Essential System Service in the Dispatch Interval and the cost of providing those services, determined in accordance with clauses 9.10.3C, 9.10.3D, 9.10.3E, 9.10.3F or 9.10.3G as applicable.

Enablement Maximum: In relation to a Real-Time Market Offer for a

Frequency Co-optimised Essential System Service, the level of Injection or Withdrawal above which no response is specified as being available.

Enablement Minimum: In relation to a Real-Time Market Offer for a

Frequency Co-optimised Essential System Service, the level of Injection or Withdrawal below which no response is specified as being available.

Energy Market Clearing Price: The Market Clearing Price for energy.

Energy Market Commencement: The date and time at which the first

Trading Day commences, as published by the Minister in the Government Gazette.

Energy Offer Caps: The Energy Offer Price Floor and the Energy Offer

Price Ceiling.

Energy Offer Price Ceiling: The price in $/MWh determined in

accordance with clause 2.26.2, and as may be indexed in accordance with clause 2.26.2U, that is the maximum price that may be associated with a Portfolio Supply Curve or Portfolio Demand Curve forming part of a STEM Submission or Standing STEM Submission, and with a Real-Time Market Submission or Standing Real-Time Market Submission for energy by a Registered Facility.

Energy Offer Price Floor: The price in $/MWh determined in

accordance with clauses 2.26.2D to 2.26.2K, and as may be indexed in accordance with clause 2.26.2U, that is the minimum price that may be associated with a Portfolio Supply Curve or Portfolio Demand Curve forming part of a STEM Submission or Standing STEM Submission, and with a Real-Time Market Submission or Standing Real‑Time Market Submission for energy by a Registered Facility.

Energy Producing System: One or more electricity producing units,

such as generation systems or Electric Storage Resources, located behind a single network connection point or electrically connected behind two or more shared network connection points.

Energy Storage Constraints: limitations on the Injection or

Withdrawal capability of a Registered Facility based on the Charge Level of associated Electric Storage Resources.

Energy Uplift Payment: Is the Energy Uplift Payment in respect of a

Facility and, in relation to a:

$a$ Trading Interval, has the meaning given in clause 9.9.7; and

$b$ Dispatch Interval, has the meaning given in clause 9.9.8.

Energy Uplift Price: Is the Energy Uplift Price in respect of a

Facility and Dispatch Interval, has the meaning given in clause 9.9.10.

Energy Uplift Quantity: Is the Energy Uplift Quantity in respect of

a Facility and Dispatch Interval, has the meaning given in clause 9.9.11.

Environmental Approval: In respect of a Facility is a licence,

consent, certificate, notification, declaration or other authorisation required under any law relating to the protection or conservation of the environment for the lawful construction of the Facility or the development of the site on which the Facility is to be constructed.

Explanatory Note

The definition of EOI Facility Variant is intended to apply in situations where a proponent may submit multiple Expressions of Interest under the Reserve Capacity Expressions of Interest process for different permutations of a single intended facility. That is, the proponent does not intend for all Expressions of Interest submitted to progress to the certification of Reserve Capacity, but rather a single permutation. Each of the related Expressions of Interest are “EOI Facility Variants”.

EOI Facility Variant: An Expression of Interest that is associated

with one or more other Expressions of Interest and that, on the basis of the information provided in clause 4.4.1, relates to the same Facility.

EOI Quantity: Means the quantity, in MW, at which a Registered

Facility was Injecting or Withdrawing as at the end of a Dispatch Interval.

Equipment Limit: Has the meaning given in clause 3.2.1.

Equipment List: Means the list maintained by AEMO under clause

3.18A.1.

Equipment List Facility: Means a Facility or item of equipment that

is included on the Equipment List.

Equivalent Planned Outage Hours: Means, in respect of a Facility,

the sum of the “Planned Outage Hours” and the “Equivalent Planned Derated Hours” for the Facility as calculated in accordance with the WEM Procedure specified in clause 4.9.10.

ERA Transfer Date: Means 8:00 AM on 1 July 2016.

ESR Charge Shortfall: The MW quantity of capacity of a Scheduled

Facility or Semi-Scheduled Facility that is subject to a capacity refund in a Trading Interval due to the inadequate Charge Level of an Electric Storage Resource, calculated in accordance with clause 4.26.1E.

Essential System Service: A service, including each service

described in section 3.9, that is required to maintain Power System Security and Power System Reliability, facilitate orderly trading in electricity and ensure that electricity supplies are of an acceptable quality.

Essential System Service Enablement Quantity: the quantity of a

Frequency Co-optimised Essential System Service to be provided by a Registered Facility in a Dispatch Interval.

Essential System Service Standards: The standards referred to in

these WEM Rules for Essential System Services, including those set out in sections 3.7 and 3.10.

Explanatory Note

Commitment decisions are made by Market Participants, but Market Participants may wish to consider the interaction between minimum enablement quantities and the cost of providing ESS. AEMO will calculate estimated Enablement Losses and provide the information for Market Participants to consider in constructing their offers.

Estimated Enablement Losses: For a Registered Facility in a Dispatch

Interval is:

EL = Max(0,LF*EM * (LFAOP – MCP))

Where:

EM is the Enablement Minimum;

LF is the Loss Factor for the Registered Facility.

LFAOP is the Loss Factor Adjusted Price in the Price-Quantity Pair for energy in the Real-Time Market Submission which corresponds to the Enablement Minimum Quantity; and

MCP is the Energy Market Clearing Price in that Dispatch Interval based on the Market Schedules published by AEMO.

Estimated FCESS Uplift Payment: For a Scheduled Facility or

Semi-Scheduled Facility in a Dispatch Interval is:

\[\text{EstimatedFCESSUpliftPayment} = \text{Max}(\text{0},\frac{\text{5}}{\text{60}} \times \text{LF} \times \text{Max}\left( \text{0},\\\text{EM} \right) \times \left( \text{LFAOP} - \text{MCP} \right))\]

where:

$a$ 5/60 represents the period of a Dispatch Interval in hours;

$b$ LF is the Loss Factor for the Registered Facility;

$c$ EM is the greatest Enablement Minimum in a Real-Time Market Submission for a Frequency Co-optimised Essential System Service for the Registered Facility in the Dispatch Interval for which the Registered Facility had an Essential System Service Enablement Quantity greater than zero;

$d$ LFAOP is the Loss Factor Adjusted Price in the Price-Quantity Pair which corresponds to EM in the Real-Time Market Submission for energy for the Registered Facility in the Dispatch Interval; and

$e$ MCP is the Energy Market Clearing Price in the Dispatch Interval based on the Market Schedules published by AEMO.

Excess Allocation Price: For a Market Participant is as calculated

in accordance with clause 9.8.3(i).

Exempt Transmission Connected Generating System: Has the meaning

given in clause 3A.3.1.

Existing Facility Load for Scheduled Generation: Means the MWh

quantity determined for a Trading Interval under step 7 of the Relevant Level Methodology.

Existing Transmission Connected Generating System: Means a

Transmission Connected Generating System for which an Arrangement for Access has been executed prior to the Tranche 1 Commencement Date other than an Exempt Transmission Connected Generating System.

Expression of Interest: In respect of a Reserve Capacity Cycle, a

response to the Request for Expressions of Interest provided to AEMO in accordance with section 4.2.

External Administrator: Means an administrator, controller, managing

controller or restructuring practitioner (each as defined in the Corporations Act), trustee, provisional liquidator, liquidator or any other person (however described) holding or appointed to an analogous office or acting or purporting to act in an analogous capacity.

External Constraint: Means an event impacting the operation of the

whole of the SWIS, or any significant part of it.

Extreme Frequency Tolerance Band: Has the meaning given in clause

3B.2.5.

EZ: Means the ratio of excess Reserve Capacity to the Reserve

Capacity Requirement for a Reserve Capacity Cycle at which no additional resources should enter the market under a very wide range of market conditions.

EZ BRCP Factor: Means the ratio of the Reserve Capacity Price to the

Benchmark Reserve Capacity Price for a Reserve Capacity Cycle if the ratio of excess Reserve Capacity to the Reserve Capacity Requirement for a Reserve Capacity Cycle was equal to EZ in that Reserve Capacity Cycle.

Facility: Has the meaning given in clause 2.29.1B, which can be an

unregistered Facility or Registered Facility.

Facility: Has the meaning given in clause 2.29.1B, which can be an

unregistered facility or Registered Facility.

Facility Capacity Rebate: For a Scheduled Facility, Semi-Scheduled

Facility or a Demand Side Programme, the rebate determined for a Trading Month m, as calculated in accordance with clause 4.26.6.

Facility Classes: Any one of the classes of Facility specified in

clause 2.29.1A.

Facility Contingency: Means a Credible Contingency Event associated

with the unexpected automatic or manual disconnection of, or the unplanned change in output of, one or more operating energy producing units or Facilities.

Facility Daily Reserve Capacity Price: The Facility Monthly Reserve

Capacity Price for a Facility as determined in accordance with clause 4.29.1A, divided by the number of Trading Days in the relevant Trading Month.

Facility Monthly Reserve Capacity Price: Means the dollar price per

Capacity Credit per Trading Month calculated in respect of a Facility in accordance clause 4.29.1A.

Facility Performance Factor: For a Registered Facility and a

Frequency Co-optimised Essential System Service in a Dispatch Interval or Pre-Dispatch Interval, the ratio between the Essential System Service Enablement Quantity and the Registered Facility’s Contribution to meeting the requirement for that Frequency Co-optimised Essential System Service, where:

$a$ a ratio of one denotes that one MW of the relevant Frequency Co-optimised Essential System Service enabled at the Registered Facility contributes one MW to meeting the requirement for that Frequency Co-optimised Essential System Service; and

$b$ a ratio of less than one denotes that one MW of the relevant Frequency Co-optimised Essential System Service enabled at the Registered Facility contributes less than one MW to meeting the requirement for that Frequency Co-optimised Essential System Service.

Facility Reserve Capacity Deficit Refund: Has the meaning given in

clause 4.26.1A.

Explanatory Note

The quantity of Contingency Reserve Raise that a Facility is cleared for is not a part of setting the Contingency Reserve Requirement under the Dispatch Algorithm. This is due to the fact that the Dispatch Algorithm ensures that any Credible Contingency of a Facility can be covered by all other Facilities and their Contingency Raise allocations. The amendment to the definition for 'Facility Risk' will ensure that cost recovery is more reflective of the requirement.

Facility Risk: Means, for a Facility, the sum of energy and

Regulation Raise cleared from the relevant Facility in that Dispatch Interval.

Facility SESSM Refund: Means, for a Dispatch Interval, Registered

Facility and an Essential System Service, the amount refunded by a Market Participant to whom the Facility is registered, for failing to meet their obligations under each relevant SESSM Award.

Facility Speed Factor: A parameter τ that defines the

approximation of the response curve of a Facility to a Contingency Event, in the form:

\[response(t) = \\reserve\*\left( 1 - e^{\frac{- t}{\tau}} \right)\]

Facility Sub-Metering: Metering arrangements sufficient to calculate

the contribution of each Separately Certified Component and associated Parasitic Loads to the Injection or Withdrawal of energy for a Facility, which may include use of Meter Data Submissions where each Separately Certified Component is not individually metered.

Facility Technology Types: Means any one of the types of

technologies specified in clause 2.29.1.

Facility Tolerance Range: Means the amount, in MW, determined by

AEMO under clause 2.13.17(b)(iii) in relation to a specific Facility, as varied under clause 2.13.20, as applicable.

Fast Start Facility: A Scheduled Facility or Semi-Scheduled Facility

that is capable of:

$a$ synchronizing and changing its rate of Injection or Withdrawal within 30 minutes of receiving a Dispatch Instruction from AEMO; and

$b$ shutting down within 60 minutes from the time the Dispatch Instruction to synchronise was issued.

Fast Track Rule Change Process: The process for dealing with Rule

Change Proposals set out in clause 2.6.

FCESS Accreditation Shortfall: Means, for a Frequency Co-optimised

Essential System Service in a Dispatch Interval, a difference between the actual or forecast required quantity and the total accredited capability accounting for where Facility response capability is accredited to provide more than one Frequency Co-optimised Essential System Service, as identified under clause 3.11.1.

FCESS Clearing Price Ceiling: The maximum Market Clearing Price for

a Frequency Co‑optimised Essential System Service in a Dispatch Interval, which is equal to:

EOPC − EOPF + FCESSOPC

where:

$a$ EOPC is the Energy Offer Price Ceiling in the Dispatch Interval;

$b$ EOPF is the Energy Offer Price Floor in the Dispatch Interval; and

$c$ FCESSOPC is the relevant FCESS Offer Price Ceiling in the Dispatch Interval.

FCESS Offer Price Ceilings: The set of price limits comprising the

Contingency Reserve Raise Offer Price Ceiling, the Contingency Reserve Lower Offer Price Ceiling, the RoCoF Control Service Offer Price Ceiling, the Regulation Raise Offer Price Ceiling and the Regulation Lower Offer Price Ceiling.

FCESS Participation Shortfall: Means, for a Frequency Co-optimised

Essential System Service in a Dispatch Interval, a difference between the actual or forecast required quantity and the total capability offered as In-Service, as identified under clause 3.11.2(b).

FCESS Uplift Payment: A payment made to a Market Participant as

compensation for Enablement Losses incurred by a Registered Facility providing one or more Frequency Co‑optimised Essential System Services, determined in accordance with:

$a$ clause 9.10.3B, for a Trading Interval; and

$b$ clause 9.10.3H, for a Dispatch Interval.

Final Annual Consolidated Outage Intention Plan: Means the final

consolidated outline of Outages Market Participants and Network Operators expect to occur in a calendar year as accepted by AEMO and developed and published by AEMO in accordance with clause 3.19.9.

Final Contingency Reserve Lower Market Clearing Price: The

Contingency Reserve Lower Market Clearing Price as published or revised under section 7.13.

Final Contingency Reserve Raise Market Clearing Price: The

Contingency Reserve Raise Market Clearing Price as published or revised under section 7.13.

Final Energy Market Clearing Price: The Energy Market Clearing Price

as published or revised and republished under section 7.13.

Final Network Access Quantity: Means, in respect of a Facility for a

Reserve Capacity Cycle, the value recorded by AEMO for the Facility in accordance with Appendix 3 for the Reserve Capacity Cycle.

Final Regulation Lower Market Clearing Price: The Regulation Lower

Market Clearing Price as published or revised under section 7.13.

Final Regulation Raise Market Clearing Price: The Regulation Raise

Market Clearing Price as published or revised under section 7.13.

Final RoCoF Control Service Market Clearing Price: The RoCoF Control

Service Market Clearing Price as published or revised under section 7.13.

Final Reference Trading Price: The Reference Trading Price as

published or revised under section 7.13.

Final Rule Change Report: In respect of a Rule Change Proposal to

which the Fast Track Rule Change Process applies, the report described in clause 2.6.4 and published by the Coordinator in accordance with clause 2.6.3A(b). In respect of a Rule Change Proposal to which the Standard Rule Change Process applies, the report described in clause 2.7.8 and published by the Coordinator in accordance with clause 2.7.7A(b).

Financial Penalty: Means a Civil Penalty Amount.

Financial Year: A period of 12 months commencing on 1 July.

Fixed Assessment Period: A period of at least seven consecutive

Trading Days in which the Constraint Equation relevant to the identification of a Constrained Portfolio under clause 2.16B.2(b) has continuously bound within a Rolling Test Window. A Rolling Test Window may contain multiple Fixed Assessment Periods.

Fixed Price Facility: Means a Candidate Fixed Price Facility that

was assigned Capacity Credits for a Reserve Capacity Cycle in which it nominated in accordance with clause 4.14.1B to be classified as a Fixed Price Facility.

Fixed Price Reserve Capacity Cycle: Means, for a Fixed Price

Facility, which is either:

$a$ the Reserve Capacity Cycle in which the Fixed Price Facility was first assigned Capacity Credits; or

$b$ any of the subsequent four Reserve Capacity Cycles.

Forced Outage: Has the meaning given in clause 3.21.1.

Forecast Capital Expenditure: With respect to AEMO, the predicted

sum of capital expenditure required for a Review Period as determined by the Economic Regulation Authority in accordance with section 2.22A.

Forecast Operational Demand: For a Dispatch Interval or Pre-Dispatch

Interval, AEMO’s estimate of the total Injection required, in MW, from Scheduled Facilities, Semi-Scheduled Facilities and Non-Scheduled Facilities at the end of the interval, as determined by the Dispatch Algorithm for a Reference Scenario of a Market Schedule.

Forecast Operational Withdrawal: For a Dispatch Interval or

Pre-Dispatch Interval, AEMO’s estimate of the total Withdrawal, in MW, from Scheduled Facilities, Semi-Scheduled Facilities and Non-Scheduled Facilities (excluding Registered Facilities that are not required to specify Price-Quantity Pairs for Withdrawals under clause 7.4.46A) at the end of the interval, as determined by the Dispatch Algorithm for a Reference Scenario of a Market Schedule.

Forecast Unscheduled Operational Demand: For a Dispatch Interval or

Pre-Dispatch Interval, AEMO’s estimate, determined in accordance with section 7.3, of the total Injection required, in MW, from Scheduled Facilities, Semi-Scheduled Facilities and Non-Scheduled Facilities at the end of the interval, to serve demand that does not relate to:

$a$ Withdrawals by Non-Scheduled Facilities; or

$b$ Withdrawals scheduled by the Dispatch Algorithm for Scheduled Facilities or Semi-Scheduled Facilities.

Frequency Band: Means the Credible Contingency Event Frequency Band,

Extreme Frequency Tolerance Band, Island Separation Frequency Band, Normal Operating Frequency Band or Normal Operating Frequency Excursion Band.

Frequency Co-optimised Essential System Service: Means an Essential

System Service as defined in clause 3.9.1 to clause 3.9.7.

**Frequency Co-optimised Essential System Service Accreditation

Parameters**: Means the information in respect of a Facility accredited to provide Frequency Co-optimised Essential System Services that is required to be included in the Standing Data for the Facility as set out in clause 2.34A.6.

Frequency Operating Standards: Means the SWIS Frequency outcomes set

out in Chapter 3B and Appendix 13.

Fuel Declaration: A declaration included with a STEM Submission or

Standing STEM Submission and which includes the information described in clause 6.6.2A(a).

Fully Co-Optimised Network Constraint Equation: A Constraint

Equation formulation to address a Network Constraint that allows AEMO, through direct physical representation, to control all the variables within the Constraint Equation that can be determined through the Central Dispatch Process excluding variables for which control would not materially enhance the security of the power system due to the small size of their coefficients.

Gate Closure: The latest point in time before the start of a

Dispatch Interval that a Market Participant may submit a revised Real-Time Market Submission for that Dispatch Interval, other than for the purposes specified in clause 7.4.35, as determined by AEMO under clauses 7.4.30 or 7.4.32 and published on the WEM Website.

Generation Capacity Cost Refund: Has the meaning given in clause

4.26.3.

Generation Centre: A geographically concentrated area containing a

generating system or generating systems with significant combined generating capability.

Generation Reserve Capacity Deficit Refund: Has the meaning given in

clause 4.26.1I.

Generator Monitoring Plan: Means a monitoring plan for a

Transmission Connected Generating System in respect of the Registered Generator Performance Standards that apply to the Transmission Connected Generating System.

Generator Monitoring Plan Requirements: The requirements relating to

the content of a Generator Monitoring Plan set out in the WEM Procedure referred to in clause 3A.6.2 as may be amended from time to time.

Generator Register: Means a register required to be established and

maintained by a Network Operator in accordance with clause 3A.7.1.

Explanatory Note

The definition of GIA Facility is amended to ensure that it only captures Facilities that were treated as Constrained Access Facilities for the purpose of certification of Reserve Capacity for one or more Reserve Capacity Cycles.

GIA Facility: A Facility that was a Constrained Access Facility (as

previously defined in the WEM Rules) for the purpose of certification of Reserve Capacity in one or more Reserve Capacity Cycles.

GST: means Goods and Services Tax and has the meaning given in the

GST Act.

GST Act: means the A New Tax System (Goods and Services Tax) Act

1999 (Cth).

High Breakpoint: Means, for a Facility providing a Frequency

Co-optimised Essential System Service, the MW energy dispatch level above which the Facility cannot provide the maximum quantity of that Frequency Co-optimised Essential System Service which it is capable of providing.

Highest Network Access Quantity: The Network Access Quantity

determined for a Facility in accordance with clause 4.15.14.

Hot Season: The period commencing at the start of the Trading Day

beginning on 1 December and ending at the end of the Trading Day finishing on the following 1 April.

Ideal Generator Performance Standard: Means the ideal generator

performance standard in respect of a Technical Requirement as specified in Appendix 12.

IMO: The former Independent Market Operator that was abolished by

the Electricity Industry (Independent Market Operator) Repeal Regulations 2018 (which also repealed the Electricity Industry (Independent Market Operator) Regulations 2004).

Impacted Participant: Has the meaning given in clause 3.18C.1(b).

Impacting Participant: Has the meaning given in clause 3.18C.1(a).

IMS: Mean the Information Management System.

Explanatory Note

The definition for 'In-Service Capacity' is amended to clarify that it does not relate specifically to synchronisation, and includes decisions Market Participants make around equipment under their control within the Facility. The clarification regarding the availability of intermittent fuels is included to support the proposed changes to the way in which Semi-Scheduled Facilities and Non-Scheduled Facilities provide their Injection forecasts to AEMO.

In-Service Capacity: For a Registered Facility in a Dispatch

Interval, Injection or Withdrawal capacity that the Market Participant expects to be ready for dispatch in the Dispatch Interval, allowing for expected operating conditions, commitment and control intentions and the effect of any Outages that have not been rejected for the Registered Facility. To avoid doubt, In-Service Capacity is not limited by the expected availability of intermittent fuels for an Intermittent Generating System such as wind.

Explanatory Note

The definition for 'Indicative Individual Reserve Capacity Requirement' is amended to clarify that the values determined for a Market Participant are only disclosed to that Market Participant.

Indicative Individual Reserve Capacity Requirement: Means the

estimate of a Market Participant’s Individual Reserve Capacity Requirement determined and provided to that Market Participant by AEMO in accordance with clause 4.28.6.

Indicative Network Access Quantity: An estimate of a Network Access

Quantity for a Facility for a future Reserve Capacity Cycle to which an application for Early Certified Reserve Capacity has been made under section 4.28C.2, as determined by AEMO in accordance with Appendix 3 and as may be adjusted in accordance with clause 4.28C.7AA.

Individual Intermittent Load Reserve Capacity Requirement: Means the

Individual Reserve Capacity Requirement for an Intermittent Load to which clause 1.48.2 applies for a Trading Month determined in accordance with Appendix 4A.

Individual Reserve Capacity Requirement: The MW quantity determined

by AEMO in respect of a Market Participant, in accordance with clause 4.28.7 and, if applicable, as revised in accordance with clause 4.28.11A.

Individual Reserve Capacity Requirement Contribution: Means the

contribution of an Associated Load to a Market Participant’s Indicative Individual Reserve Capacity Requirement determined in accordance with Step 11 of Appendix 5.

Explanatory Note

The definition of ‘Inertia’ will include some wind farms, but not batteries. As battery technology develops further to be able to reliably provide an inertial-equivalent service, this definition will be reviewed.

Inertia: The kinetic energy (at nominal frequency) that is extracted

from the rotating mass of a machine coupled to the power system to compensate an imbalance in the system frequency.

Inertia Requirements: Means, the required levels of Inertia to

assist in reasonably maintaining frequency in an Island in accordance with the Frequency Operating Standards, the process by which is set out in the WEM Procedure referred to in clause 3.2.7.

Inflexible: Means that a Registered Facility is only able to be

dispatched in a Dispatch Interval:

$a$ in accordance with its Dispatch Inflexibility Profile, or

$b$ for the fixed level of Injection or Withdrawal specified in clause 7.6.31(a)(ii).

Information Manager: The party responsible for managing Market

Information, in accordance with clauses 10.2.11 and 10.2.12.

Information Stakeholder: Has the meaning given in clause 10.2.7A.

Initial Network Access Quantity: The Network Access Quantity

determined for a Facility in accordance with section 4.1A.1.

Initial Time: Is the earlier of the Energy Market Commencement and

the start of the Trading Day commencing on 1 October 2007.

Injection: The quantity of power or energy sent into a Network, as

measured at:

$a$ for a Registered Facility with a single defined network connection point, the network connection point;

$b$ for a Registered Facility with multiple network connection points with the same Electrical Location, the Electrical Location; and

$c$ for a Registered Facility with network connection points at more than one Electrical Location, the Reference Node,

which is measured in instantaneous MW unless specified as MWh over a time period, and represented as a positive number or zero.

Interim Approval to Generate Notification: Means the notification

issued by the Network Operator to a Market Participant in accordance with section 3A.8, which may or may not be subject to and contain conditions, granting interim approval to a Transmission Connected Generating System to generate electricity.

Interim Annual Consolidated Outage Intention Plan: Means the interim

consolidated outline of Outages Market Participants and Network Operators expect to occur in a calendar year as accepted by AEMO and developed and published by AEMO in accordance with clause 3.19.4.

Intermediary: Has the meaning given in clause 2.28.16A.

Intermediate Season: The interval commencing at the start of the

Trading Day beginning on 1 October and ending at the end of the Trading Day finishing on the following 1 December of the same year.

Intermittent Generating System: Any generating system whose output

is not reasonably controllable by AEMO, and whose output is dependent on a fuel resource that cannot be directly stored or stockpiled and whose availability is difficult to predict.

Intermittent Load: A type of Load or part of a Load defined under

clause 2.30B.1.

Intermittent Load Refund: Has the meaning given in clause 4.28A.1.

Internal Constraint: In relation to a Facility, an event that is not

an External Constraint and which adversely impacts the sent out capacity of the Facility.

Interruptible Load: A Facility relating to one or more

Non-Dispatchable Loads, where consumption can be curtailed automatically in response to a change in system frequency, and registered as such in accordance with clause 2.29.5.

Interval Meter Deadline: The date determined in accordance with

clause 9.3.1(a).

Intervention Constraint: A Constraint Equation used to implement a

direction in the Dispatch Algorithm pursuant to an AEMO Intervention Event.

Intervention Dispatch Interval: A Dispatch Interval declared by AEMO

to be an Intervention Dispatch Interval in accordance with clauses 7.11A.1 or 7.11C.10.

Invoice: An invoice requesting payment for transactions under these

WEM Rules issued under Chapter 9. An Invoice may relate to Settlement Statements or adjusted Settlement Statements as the case may be.

Invoicing Date: The Business Day, determined in accordance with

clause 9.3.1(c), on which AEMO releases Invoices for original Settlement Statements for a Trading Week and each Business Day, determined in accordance with clause 9.3.1(h), on which AEMO releases Invoices for adjusted Settlement Statements for the Adjustment Process for that Trading Week, respectively.

Irregular Price Offer: A price described in clauses 2.16C.6(c) or

2.16C.6(d).

Island: Means a part of the SWIS that includes interconnected Energy

Producing Systems (or other energy sources and loads), for which all of the connection points with the SWIS have been disconnected, provided that the part:

$a$ is smaller than the remainder of the SWIS that it has disconnected from; and

$b$ contains Energy Producing Systems (or other energy sources) capable of supplying the Load in accordance with the Frequency Operating Standards within the part of the SWIS that has been disconnected,

but does not include an Embedded System or Disconnected Microgrid.

Island Separation Frequency Band: Has the meaning given in clause

3B.2.4.

Key Project Dates: Means the dates most recently provided to AEMO

under clause 4.10.1(c)(iii) or in reports provided under clause 4.27.10, clause 3.15A.40 or clause 3.15A.42.

Explanatory Note

The determination of the Contingency Raise/Lower requirements must allow for non-registered components and other system related factors. The amendments to the definition for 'Largest Credible Load Contingency' and 'Largest Credible Supply Contingency' will ensure the definitions are not restrictive in how the requirements are set.

Largest Credible Load Contingency: Means the highest magnitude

possible MW change resulting in an increase in SWIS frequency that could occur in a Dispatch Interval or Pre-Dispatch Interval due to a single Credible Contingency Event based on the output of the Dispatch Algorithm.

Largest Credible Supply Contingency: Means the maximum possible net

MW change resulting in a decrease in SWIS frequency that could occur in a Dispatch Interval or Pre-Dispatch Interval due to a single Credible Contingency Event based on the output of the Dispatch Algorithm, accounting for any associated change in overall demand as a result of the same Credible Contingency Event.

Largest Network Risk: Means, for a Dispatch Interval, the maximum MW

value across all Network Risks.

Last Correct Dispatch Interval: Means the most recent Dispatch

Interval preceding the Affected Dispatch Interval that is not itself an Affected Dispatch Interval.

Liquid Fuel: Means distillate, fuel oil, liquid petroleum gas, or

liquefied natural gas.

Limit Advice: Has the meaning given in clause 2.27A.2.

Limit Advice Inputs: Information used in the development of Limit

Advice including:

$a$ the rating for each transmission system element or equipment comprising the transmission system, including any part of the distribution system that is used for the transmission of electricity as part of the secure operation of the transmission system or the SWIS; and

$b$ the Limit Margin forming part of each Limit Equation.

Limit Equation: Means a mathematical expression defining the power

transfer capability across a particular Network element or group of Network elements.

Limit Margin: A margin applied by a Network Operator when

formulating a Limit Equation, or a Network Limit where a Limit Equation is not appropriate, to account for uncertainty.

Linearly Derating Capacity: The maximum capacity, in MW, of an

Electric Storage Resource that can be guaranteed to be available over the Electric Storage Resource Obligation Duration, being the minimum of:

$a$ the nameplate capacity; and

$b$ the maximum Charge Level capability (in MWh) divided by 4 hours, being the maximum sustainable MW capacity, which could be delivered continuously across the Electric Storage Resource Obligation Duration.

Load: One or more electricity consuming resources or devices, other

than Electric Storage Resources, located behind a single network connection point or electrically connected behind two or more shared network connection points.

Load Following Service: Has the meaning given in clause 3.9.1.

Load Forecast: An expectation of the demand levels in the SWIS or in

a region of the SWIS in future Trading Intervals.

Load Relief: The expected change in load in response to a change in

power system frequency.

Local Black Start Procedures: The procedures developed by a Market

Participant under clause 3.7.13 in accordance with the guidelines published by AEMO under clause 3.7.12.

Long Term PASA: A PASA study conducted in accordance with clause 4.5

in order to determine the Reserve Capacity Target for each year in the Long Term PASA Study Horizon and prepare the Statement of Opportunities Report for a Reserve Capacity Cycle.

Long Term PASA Study Horizon: The ten year period commencing on 1

October of Year 1 of a Reserve Capacity Cycle.

Loss Factor: Means a factor representing network losses between any

given node and the Reference Node where the Loss Factor at the Reference Node is 1, expressed as the product of a Transmission Loss Factor and a Distribution Loss Factor and determined in accordance with clause 2.27.5.

Loss Factor adjusted: In respect of a quantity of electricity, means

that quantity multiplied by any applicable Loss Factor.

Loss Factor Adjusted Price: Means, in respect of any price, that

price divided by any applicable Loss Factor for the relevant Facility.

Loss Factor Class: A Transmission Loss Factor Class or a

Distribution Loss Factor Class.

Low Breakpoint: Means, for a Facility providing a Frequency

Co-optimised Essential System Service, the MW energy dispatch level below which the Facility cannot provide the maximum quantity of that Frequency Co-optimised Essential System Service which it is capable of providing.

Low Reserve Condition: Means each of the conditions of the power

system described in clause 3.17.1(a) to 3.17.1(c) which may result in a Low Reserve Condition Declaration.

Low Reserve Condition Declaration: Has the meaning given to that

term in clause 3.17.1.

Low Reserve Condition Report: Means a report published by AEMO

pursuant to clause 3.17.2 in respect of Low Reserve Condition Declarations.

MAC Secretariat: The services, facilities and assistance made

available by the Coordinator to the Market Advisory Committee.

Mandatory Routine Maintenance: Means Outage Facility Maintenance of

a routine nature that must be undertaken by a specific point in time, or by the time that a specific measure of usage is reached, as required by applicable legislation or in accordance with the Outage Facility’s asset management plan.

Margin Call: The amount determined in accordance with clause 2.42.3.

Margin Call Notice: A notification by AEMO to a Market Participant

that the Market Participant’s Trading Margin is less than zero, and requiring the payment of a Margin Call.

Market Advisory: Has the meaning given in clause 7.11.1.

Market Advisory Committee: An advisory body to the Coordinator,

Economic Regulation Authority and AEMO comprising industry representatives established under clause 2.3.1.

Market Auditor: An auditor appointed by AEMO under clause 2.14.1.

Market Clearing Price: The price for a Market Service in a Dispatch

Interval as determined in accordance with section 7.11B.

Market Fees: The fee rates and other fees payable by Rule

Participants to AEMO as determined by AEMO in accordance with section 2.24 and, for Market Participant Market Fees, Market Participant Coordinator Fees and Market Participant Regulator Fees, as calculated for each Market Participant in accordance with section 9.12.

Market Information: Any information or document that is required to

be produced, provided or exchanged under these WEM Rules or a WEM Procedure.

Market Participant: A Rule Participant that is registered in

accordance with section 2.28.

Market Participant Coordinator Fees: The fees, the rates of which

are determined by AEMO in accordance with section 2.24, and calculated as payable by Market Participants in accordance with clause 9.12.4A to AEMO for the services provided by the Coordinator in undertaking her or his functions under these WEM Rules and the WEM Regulations.

Market Participant Market Fees: The fees payable by Market

Participants to AEMO the rate of which is determined by AEMO in accordance with section 2.24, and as calculated for each Market Participant in accordance with clause 9.12.3.

Explanatory Note

The definition for 'Regulator Fees' is amended by the Governance Amendments to remove the reference to the RCP. However, as the definition is deleted and replaced with "Market Participant Regulator Fees" by the Tranches 2 and 3 Amendments, this companion version of the WEM Rules only shows the Tranches 2 and 3 Amendments as those amending rules (made by the Minister at the date this companion version was prepared) will be commenced last. Please refer to the Governance Amendments to see the changes to the definition for "Regulator Fees" that will commence on 1 July 2021 and apply until the relevant provisions of the Tranches 2 and 3 Amendments commence. Further amendments to the replacement definition for "Market Participant Regulator Fees" have been made by the Tranche 6 Amendments to, among other things, delete the reference to the RCP.

Market Participant Regulator Fees: The fees, the rates of which are

determined by AEMO in accordance with section 2.24, and calculated as payable by Market Participants in accordance with clause 9.12.4 to AEMO for the services provided by the Economic Regulation Authority in undertaking its Wholesale Electricity Market related functions and other functions under these WEM Rules.

Market Price Limits: The set of price limits comprising the Energy

Offer Price Ceiling, the Energy Offer Price Floor, the Contingency Reserve Raise Offer Price Ceiling, the Contingency Reserve Lower Offer Price Ceiling, the RoCoF Control Service Offer Price Ceiling, the Regulation Raise Offer Price Ceiling and the Regulation Lower Offer Price Ceiling.

Market Schedule: A Dispatch Schedule, Pre-Dispatch Schedule or

Week-Ahead Schedule.

Market Service: Energy or any of the Frequency Co-optimised

Essential System Services.

Market Surveillance Data Catalogue: The catalogue developed by AEMO

under clause 2.16.2.

Material Constrained Portfolio: Has the meaning given in clause

2.16C.2(b).

Material Portfolio: Has the meaning given in clause 2.16C.1(b).

Maximum Capability: Means, the Facility’s MW energy dispatch

capability between the Low Breakpoint and the High Breakpoint.

Maximum Consumption Capability: For a Market Participant, the

maximum cumulative MWh quantity that the Market Participant is permitted to include in a Portfolio Demand Curve for a Trading Interval, determined in accordance with clause 6.3A.3(f).

Maximum Contingency Reserve Block Size: The largest quantity of

Contingency Reserve that may be offered by a relevant Registered Facility at one price, as set by AEMO in a WEM Procedure.

Maximum Downwards Ramp Rate: The Market Participant’s best estimate,

in MW per minute, on a linear basis, of a Facility’s physical ability to decrease the magnitude of Injection or increase the magnitude of Withdrawal on the receipt of a Dispatch Instruction.

Maximum Facility Refund: The total amount of the Capacity Credit

payments paid or to be paid under these WEM Rules to a Market Participant in relation to a Facility and in relation to a Capacity Year assuming that:

$a$ AEMO acquires all of the Capacity Credits held by the Market Participant in relation to its Facility; and

$b$ the cost of each Capacity Credit so acquired is determined in accordance with clause 4.28.2(d).

Maximum Facility Supply Capability: The MWh contribution of a

Scheduled Facility, Semi-Scheduled Facility or Non-Scheduled Facility over a Dispatch Interval or Trading Interval to the Maximum Supply Capability of a Market Participant, determined in accordance with clauses 6.3A.3(c) (for a Dispatch Interval) and 6.3A.3(d) (for a Trading Interval).

Maximum Participant Generation Refund: The total amount of the

Capacity Credit payments paid or to be paid under these WEM Rules to a Market Participant in relation to its Facilities (other than Facilities with a Facility Class or indicative Facility Class of Demand Side Programme) and in relation to a Capacity Year assuming that:

$a$ AEMO acquires all of the Capacity Credits held by the Market Participant in relation to those Facilities; and

$b$ the cost of each Capacity Credit so acquired is determined in accordance with clause 4.28.2(d).

Maximum Supply Capability: For a Market Participant is, the maximum

cumulative MWh quantity that the Market Participant is permitted to include in a Portfolio Supply Curve for a Trading Interval, determined as calculated in accordance with clause 6.3A.3(e).

Maximum Upwards Ramp Rate: The Market Participant’s best estimate,

in MW per minute, on a linear basis, of a Facility’s physical ability to increase the magnitude of Injection or decrease the magnitude of Withdrawal on the receipt of a Dispatch Instruction.

Medium Term PASA: A PASA covering the period in clause 3.16.1(a).

Meter Data Submission: A submission of meter data by a Metering Data

Agent to AEMO in accordance with clause 8.4.

Meter Dispute: Has the meaning given in clause 8.6.1(e).

Meter Registry: A registry maintained by a Metering Data Agent

containing information about meters and the persons with which those meters are associated including the information listed in clause 8.3.1.

Metered Schedule: Has the meaning given in clause 9.5.2 and clause

9.5.3, as the case may be.

Metering Data Agent: The person identified under clause 8.1.2 or

clause 8.1.4.

Metering Protocol: A combination of the Metering Data Rules as

specified by the Economic Regulation Authority and a Network Operator’s metering requirements as a condition of access. The metering requirement means in the context of a “covered network” (as that term is defined in the Access Code) the “Metering Rules” as defined in the Access Code while when used in the context of a network which is not a “covered network” (as that term is defined in the Access Code) means any commercial arrangement for metering energy.

The definition of the Metering Protocol is subject to finalisation of the Metering Rules arrangements.

Minimum Capacity Credits Quantity: The minimum quantity of Capacity

Credits a Market Participant requires to be assigned to a Facility or upgrade to the Facility for a Reserve Capacity Cycle for the Facility or upgrade to the Facility to participate in the Reserve Capacity Cycle.

Explanatory Note

The definition for 'Minimum Consumption' is amended to remove the reference to Standing Data, because this information is not Standing Data and is maintained through the Associated Loads processes set out in section 2.29, not the Standing Data update processes in section 2.34.

Minimum Consumption: For an Associated Load means the amount

specified under clause 2.29.5B(c) as the amount below which the Associated Load does not wish to be curtailed in the course of dispatching the Demand Side Programme.

Minimum Frequency Keeping Capacity: Has the meaning given in clause

3.10.1(a).

Minimum Generator Performance Standard: Means the minimum generator

performance standard in respect of a Technical Requirement as specified in Appendix 12.

Minimum RoCoF Control Requirement: Is:

$a$ the smallest quantity of scheduled or dispatched RoCoF Control Service in a Dispatch Interval or a Pre-Dispatch Interval that is necessary to maintain the SWIS frequency in accordance with the Frequency Operating Standards; and

$b$ zero, where the SWIS frequency can be maintained in accordance with the Frequency Operating Standards without explicit enablement of RoCoF Control Service.

Minimum Transaction Cost: Means the dollar amount published by AEMO

in accordance with clause 9.18.4(b).

Minister: The Minister responsible for administering the Electricity

Industry Act.

Multiple Contingency Event: Means, in relation to the SWIS Frequency

Operating Standards, when an additional Contingency Event occurs before the SWIS Frequency has been able to Recover from the previous Contingency Event.

MW: Means megawatt.

MWh: Means megawatt-hour.

MWs: Means megawatt-second.

National Electricity Rules: The rules so named having effect under

the National Electricity Law as that law applies in Western Australia.

NCESS: See Non-Co-optimised Essential System Service.

NCESS Contract: A contract procured by AEMO or a Network Operator

for the provision of an NCESS.

NCESS Service Specification: A service specification prepared by

AEMO or a Network Operator in accordance with clause 3.11B.5.

NCESS Submission: A submission in accordance with clause 3.11B.8.

Explanatory Note

The definition for 'Near Binding Constraint Equation' is added to clarify the publication requirements in section 7.13. The definition is intended to capture where the available head-room in a constraint indicates that it is close to operating on one of the control Facilities included in the Constraint Equation.

Near Binding Constraint Equation: For a Constraint Equation used in

the Central Dispatch Process, where the absolute value of difference between the value of the left hand side and the value of the right hand side of the Constraint Equation is less than 20 times the absolute value of the largest coefficient on the left hand side of the Constraint Equation.

Negotiated Generator Performance Standard: Means a standard or

technical level of performance in respect of a Technical Requirement that represents a variation from the Ideal Generator Performance Standard but is no less than the Minimum Generator Performance Standard that has been approved and registered in accordance with the process in Chapter 3A.

Negotiation Criteria: Means the criteria that must be met in respect

of each Technical Requirement as specified in Appendix 12 if a Market Participant submits a Proposed Negotiated Generator Performance Standard.

Net Bilateral Position: Means in relation to a Market Participant,

the amount calculated under clause 6.9.2.

Net Contract Position: In respect of a Market Participant for a

Trading Interval is calculated in accordance with clause 6.9.13.

Net STEM Refund: Has the meaning given in clause 4.26.3.

Net STEM Shortfall: Has the meaning given in clause 4.26.2AA.

Net Trading Quantity: In respect of a Trading Interval and for a

Market Participant has the meaning given in clause 9.9.5.

Network: A transmission system or distribution system registered as

a Network under clause 2.29.3.

Network Access Quantity: The quantity, in MW, that is determined for

a Facility pursuant to clause 4.15.1.

Network Access Quantity Model: A model to be developed and

maintained by AEMO pursuant to clause 4.15.6 and to be used by AEMO for determining Network Access Quantities for Facilities in accordance with the processes in Appendix 3.

Explanatory Note

The definition of Network Access Quantity Model Inputs is further amended to require AEMO to publish adjusted Indicative Network Access Quantities for each applicable step in Appendix 3. This is because Indicative Network Access Quantities, like preliminary Network Access Quantities, can be adjusted in each step of the process.

Network Access Quantity Model Inputs: Means, in respect of the

relevant Reserve Capacity Cycle:

$a$ the preliminary Network Access Quantity determined by AEMO for a Facility and, where applicable, the adjusted Indicative Network Access Quantity determined for a Facility that is classified as an Indicative NAQ Facility under Appendix 3, for each applicable step in Appendix 3;

$b$ each of the assumptions and parameters used by AEMO in the Network Access Quantity Model;

$c$ each RCM Constraint Equation that is used in the Network Access Quantity Model; and

$d$ RCM Limit Advice used in the Network Access Quantity Model.

Network Augmentation Funding Facility: For a Reserve Capacity Cycle,

a Facility or upgrade to a Facility that a Market Participant has nominated to be classified as a Network Augmentation Funding Facility for the Reserve Capacity Cycle in an application for certification of Reserve Capacity under clause 4.10.1(m), and which AEMO has classified as a Network Augmentation Funding Facility for the Reserve Capacity Cycle.

Network Augmentation Works: Means any wires, apparatus, equipment,

plant or buildings used, or to be used, for, or in connection with, or to control, the transfer of electricity that directly results in an increase in the capacity of a part of the transmission system or distribution system.

Network Constraint: A limitation or requirement in a part of a

Network that may impact one or more Registered Facilities in the Central Dispatch Process, such that it would be unacceptable to transfer electricity across that part of the Network at a level or in a manner outside the limit or requirement.

Network Contingency: Means a Credible Contingency Event associated

with the unexpected disconnection of one or more major items of Network equipment, but excludes from that meaning the loss of output from a Facility arising as a result of failure of generating equipment at the Facility or the loss of the network connection point associated with the Facility.

Network Limit: A limitation or requirement affecting the capability

to transfer power in a part of a Network, such that it would be unacceptable to transfer electricity across that part of the Network at a level or in a manner outside the limit or requirement.

Network Operator: A person who registers as a Network Operator, in

accordance with clauses 2.28.2, 2.28.3 or 2.28.4.

Network Opportunity Map: Has the meaning given in Chapter 6A of the

Access Code.

Network Quality and Reliability of Supply Code: The *Electricity

Industry (Network Quality and Reliability of Supply) Code 2005*.

Network Risk: Means, for a Network Contingency in a Dispatch

Interval, the sum in MW of the Facility Risks for any Registered Facilities less the forecast consumption of any relevant Loads that are connected to the part of the Network affected by that Network Contingency, and that would lose the ability to Inject or Withdraw from the Network as a result of that Network Contingency.

New Facility Load for Scheduled Generation: Means, for a new or

upgraded Facility that has applied to be assigned Certified Reserve Capacity under clause 4.11.2(b), the MWh quantity determined for a Trading Interval under step 11 of the Relevant Level Methodology for that Facility and the relevant Reserve Capacity Cycle.

New Information: Has the meaning given in clause 2.29.5LA.

New RCM Transition Date: The date on which AEMO publishes the

timetable referred to in section 1.36A.

New WEM Commencement Day: The date and time specified by the

Minister as the New WEM Commencement Day, as published in the Government Gazette.

Nominated Excess Capacity: In respect of a Facility containing an

Intermittent Load, the maximum quantity of Injection (in MW) that the Market Participant intends the Facility to make in any Dispatch Interval, which must not be exceeded in more than 120 Dispatch Intervals within any continuous 12-month period.

Non-Business Day: A day that is a Saturday, Sunday, or a public

holiday throughout Western Australia.

Non-Co-optimised Essential System Service: An Essential System

Service procured under section 3.11B.

Non-Credible Contingency Event: Has the meaning given in clause

3.8A.3.

Non-Dispatchable Load: A Facility of the type defined in clause

2.29.1B(c) which is not a Registered Facility and that may be associated with a Demand Side Programme or an Interruptible Load.

Non-Intermittent Generating System: A generation system which is not

an Intermittent Generating System, including, without limitation, thermal generators fuelled by coal, natural gas, or distillate.

Non-Liquid Fuel: Means all fuels other than Liquid Fuel.

Non-Scheduled Facility: A Facility that can be self-scheduled by its

operator (with the exception that AEMO can direct it to decrease its output subject to its physical capabilities), and which is registered as such in accordance with clause 2.29.4G.

Non-Temperature Dependent Load: A Non-Dispatchable Load accepted by

AEMO as a Non-Temperature Dependent Load under clause 4.28.9.

Non-Thermal Network Limit: Means a Network Limit that is not Thermal

Network Limit.

Normal Operating Frequency Band: Has the meaning given in clause

3B.2.1.

Normal Operating Frequency Excursion Band: Has the meaning given in

clause 3B.2.2.

Explanatory Note

New definition for ‘Not In-Service Capacity’ is used in clause 4.26.2AA.5(b)(ii).

Currently a Market Participant must submit in its Balancing Submissions prices and quantities at which it is willing to dispatch its Facilities. If plant is unavailable this must be declared and be accompanied by either a planned or forced outage declaration. As a result there will be direct financial consequences for the Market Participant in the RCM. All plant which is declared “available” would be subject to receiving a dispatch instruction if it is in merit. Again, there will be consequences for the Market Participant if it is unable to respond to a Dispatch Instruction.

However, under the new changes to the availability declarations, a declaration “Available but not in service” could allow a Market Participant to avoid being dispatched while still declaring it is available in its real time market submissions. Even if it is in merit it will not be issued a dispatch instructions unless it changes its status to in service.

To replicate the current treatment of Market Participants in like circumstances in the new WEM, capacity which was in merit but was declared available but not in service is to be excluded when calculating the shortfall in the Real-Time Market for a Facility.

Not In-Service Capacity: Means, for a Scheduled Facility or a

Semi-Scheduled Facility in a Dispatch Interval, the sent-out capacity, in MW, that was expected to be dispatched in the Reference Scenario of the relevant Market Schedule at the Start Decision Cutoff, but was not offered as In-Service Capacity, as calculated in clause 7.13A.1.

Not In-Service Capacity Refund Quantity: The MW quantity of Not

In-Service Capacity of a Scheduled Facility or Semi-Scheduled Facility that is subject to a capacity refund in a Trading Interval, calculated in accordance with clause 4.26.1D.

Notice of Disagreement: A notice issued by a Rule Participant under

clause 9.16.1 to AEMO indicating a disagreement with a Settlement Statement.

Notice of Dispute: A notice issued under clause 2.19.1 and

containing the information described in clause 2.19.3.

Notice of Intention to Cancel Capacity Credits: A notice issued by

AEMO under clause 4.20.8 and containing the information required under clause 4.20.9.

Notional Wholesale Meter: A notional interval meter representing

Non-Dispatchable Loads without interval meters that are served by Synergy.

Off-Peak Trading Interval: A Trading Interval occurring between 10

PM and 8 AM.

Offending Rule Participant: Is a Rule Participant liable for a

Financial Penalty.

Offer Construction Guideline: The guideline published by the

Economic Regulation Authority under clause 2.16D.1(a), which may be amended in accordance with clause 2.16D.2.

Operating Margin: A margin applied by AEMO when formulating a

Constraint Equation to account for uncertainty.

Operating Protocol: A protocol developed between AEMO and a Network

Operator in accordance with section 3.1A.

Operating Zone: A part or parts of the SWIS able to be practically

monitored and incorporating elements that are likely to impact Power System Security or Power System Reliability.

Explanatory Note

The definition for 'Operational System Load Estimate' has been deleted and definitions for 'Operational Demand', 'Operational Demand Estimate', 'Operational Withdrawal' and 'Operational Withdrawal Estimate' added to support revised arrangements for calculating and reporting actual system demand values.

Operational Demand: For a Dispatch Interval, the total Injection, in

MW, from all Scheduled Facilities, Semi-Scheduled Facilities and Non-Scheduled Facilities that are Injecting at the end of the Dispatch Interval.

Operational Demand Estimate: For a point in time, AEMO’s estimate of

the total Injection, in MW, from all Scheduled Facilities, Semi-Scheduled Facilities and Non-Scheduled Facilities that are Injecting at that time.

Operational Withdrawal: For a Dispatch Interval, the total

Withdrawal, in MW, from all Scheduled Facilities, Semi-Scheduled Facilities and Non-Scheduled Facilities (excluding Registered Facilities that are not required to specify Price-Quantity Pairs for Withdrawals under clause 7.4.46A) that are Withdrawing at the end of the Dispatch Interval.

Operational Withdrawal Estimate: For a point in time, AEMO’s

estimate of the total Withdrawal, in MW, from all Scheduled Facilities, Semi-Scheduled Facilities and Non‑Scheduled Facilities (excluding Registered Facilities that are not required to specify Price-Quantity Pairs for Withdrawals under clause 7.4.46A) that are Withdrawing at that time.

Opportunistic Maintenance: Means, an Outage Plan with an Outage

Period of less than 24 hours submitted in accordance with clause 3.18B.8(b)(ii).

Oscillation Control Constraint Equations: Constraint Equations that

provide for stability in the Dispatch Algorithm outputs where a significant change to the Dispatch Target or ESS Enablement Quantities of a Registered Facility would result in only a small change in the value of Real-Time Market trading described in clause 7.2.2.

Outage: Has the meaning given in clause 3.18.3.

Outage Capability: The capability of the Facility for which an

Outage occurs, which includes, but is not limited to, energy production, consumption, or transfer of energy, or the provision of any Essential System Service.

Outage Commencement Interval: The Dispatch Interval specified in an

Outage Plan or revision in which the Outage is proposed to commence.

Outage Compensation: Means the amount determined by AEMO as payable

to a Market Participant in accordance with clause 3.18H.5.

Outage Completion Interval: The Dispatch Interval specified in an

Outage Plan or revision in which the Outage is proposed to be completed.

Outage Contingency Plan: Part of an Outage Plan specifying

contingency plans for returning the relevant item of equipment to service before the end of the Outage Period.

Outage Evaluation: The evaluation of an Outage Plan by AEMO in

accordance with clause 3.18E.5.

Outage Evaluation Criteria: The criteria AEMO is required to

consider in undertaking an Outage Evaluation as set out in clause 3.18E.8.

Outage Facility: An Equipment List Facility or a Self-scheduling

Outage Facility.

Outage Facility Maintenance: Means an Outage for the purpose of:

$a$ an upgrade of Outage Facility equipment; or

$b$ all maintenance in respect of an Outage Facility, including but not limited to preventative maintenance, corrective maintenance, plant inspections and tests, that would reasonably be required in accordance with good electricity industry practice.

Outage Intention Plan: Means the outline of Outages a Market

Participant or Network Operator expects to occur in a calendar year submitted to AEMO annually in accordance with section 3.19.

Explanatory Note

The definition for 'Outage Period' is amended to simplify the wording and clarify how the period is defined relative to the Outage Commencement Interval and Outage Completion Interval.

Outage Period: In respect of an Outage Plan, the period of time

between the start of the Outage Commencement Interval and the end of the Outage Completion Interval.

Outage Plan: Has the meaning given in clause 3.18B.1 as may be

revised in accordance with clause 3.18D.1.

Outage Plan First Submission Date: The date on which an Outage Plan

is first submitted to AEMO.

Outage Quantity: The quantity, in MW, of the derating of a

Separately Certified Component in a Dispatch Interval as a result of a Planned Outage or Forced Outage for energy, determined in accordance with clause 3.21.6.

Outage Recall Direction: Means a direction given by AEMO to a Market

Participant or Network Operator to return an Outage Facility to service from a Planned Outage in accordance with the Outage Contingency Plan, or take other measures contained in the relevant Outage Contingency Plan in accordance with clause 3.20.1.

Explanatory Note

The following definitions have been added to support the requirement for mandatory information to be included in an Outage Plan and published on the WEM Website where an Outage is required to be temporarily returned to service at different times throughout its duration:

Outage Return To Service Commencement Interval;
Outage Return To Service Completion Interval; and
Outage Return To Service Period.

Outage Return To Service Commencement Interval: The first Dispatch

Interval in an Outage Return To Service Period.

Outage Return To Service Completion Interval: The last Dispatch

Interval in an Outage Return To Service Period.

Outage Return To Service Period: A period of time within the Outage

Period of an Outage Plan, during which the relevant Outage Capability is intended to be returned to service, which starts at the start of its Outage Return To Service Commencement Interval and ends at the end of its Outage Return To Service Completion Interval.

Outstanding Amount: The amount calculated in accordance with clause

2.40.1.

Panel Regulations: Means the *Energy Industry (Rule Change Panel)

Regulations 2016*.

Parasitic Load: A Load where consumption is auxiliary to the

production of energy from an Energy Producing System.

Participant Capacity Rebate: For a Market Participant holding

Capacity Credits associated with a Scheduled Facility, Semi-Scheduled Facility or a Demand Side Programme, the rebate determined for a Trading Interval, as calculated in accordance with clause 4.26.4.

PASA: See Projected Assessment of System Adequacy.

Payment Default: Any failure to make a payment in respect of an

Invoice in accordance with section 9.18 or clause 9.20.8 or pay any other amount owing under these WEM Rules by the time it is due.

Peak Trading Interval: A Trading Interval occurring between 8 AM and

10 PM.

Per-Dispatch Interval Availability Payment: For a SESSM Award, the

SESSM Availability Payment divided by the number of Dispatch Intervals in the SESSM Award Duration for which the SESSM Availability Quantity is greater than zero.

Planned Outage: An Outage Plan that has been approved by AEMO.

Planning Criterion: Has the meaning given in clause 4.5.9.

Portfolio: A set comprising one or more Scheduled Facilities,

Semi-Scheduled Facilities and Non-Scheduled Facilities identified by the Economic Regulation Authority in accordance with clause 2.16B.1(a).

Portfolio Demand Curve: A curve describing the STEM Price at which a

Market Participant will purchase different levels of energy from the market having the form given in clause 6.6.2A(e).

Portfolio Supply Curve: A curve describing the STEM Price at which a

Market Participant will provide the market with different levels of energy supply having the form given in clause 6.6.2A(d).

Potential Relevant Generator Modification: Has the meaning given in

clause 3A.13.1.

Power System Adequacy: Means the ability of the SWIS to supply all

demand at the time, allowing for Outages, taking into account the assessment methodologies and criteria in the WEM Procedure referred to in clause 3.3.2.

Power System Reliability: Means the safe scheduling, operation and

control of the SWIS in accordance with the Power System Reliability Principles.

Power System Reliability Principles: Has the meaning given to that

term in clause 3.3.3.

Power System Security: Means the safe scheduling, operation and

control of the SWIS in accordance with the Power System Security Principles.

Power System Security Principles: Has the meaning given to that term

in clause 3.4.3.

Power System Stability: Means when the SWIS will return to an

acceptable steady-state operating condition following a disturbance.

Power System Stability Requirements: Means, the requirements

identified to maintain Power System Stability, as determined by the processes specified in the WEM Procedure referred to in clause 3.2.7.

Power Transfer Capability: Means the maximum permitted power

transfer through a transmission system or distribution system or part thereof.

Pre-Dispatch Interval: A period of 30 minutes commencing on the hour

or half hour during a Trading Day, and where identified by a time, the 30 minute period starting at that time.

Pre-Dispatch Schedule: Means a forecast of Market Clearing Prices,

Dispatch Targets, Dispatch Caps, Dispatch Forecasts and Essential System Services Enablement Quantities for each Pre-Dispatch Interval in the Pre-Dispatch Schedule Horizon.

Pre-Dispatch Schedule Horizon: The next 96 Pre-Dispatch Intervals

after a Pre-Dispatch Interval.

Preliminary RCM Constraint Equation: Means a RCM Constraint Equation

developed by AEMO pursuant to section 4.4B and published by AEMO in accordance with, and by the time specified in, clause 4.4B.6.

Price-Quantity Pair: In the context of:

$a$ Reserve Capacity Offers, Supply Portfolio Curves and STEM Offers, a quantity that will be provided to AEMO by a Market Participant for a price equalling or exceeding the specified price. In the context of Demand Portfolio Curves and STEM Bids, a quantity that will be purchased from AEMO by a Market Participant for a price equalling or less than the specified price.;

$b$ Real-Time Market Submissions the specified non-Loss Factor adjusted MW quantity at which a Market Participant is prepared to provide a Market Service from a Registered Facility as at the end of a Dispatch Interval and the non-Loss Factor Adjusted Price at which the Market Participant is prepared to provide that quantity by the end of the Dispatch Interval, where the price is:

i. in $ per MWh for energy;

ii. in $ per MW per hour for Contingency Reserve Raise, Contingency Reserve Lower, Regulation Raise and Regulation Lower; and

iii. in $ per MWs per hour for RoCoF Control Service.

Priority Project: Has the meaning given in the Electricity Networks

Access Code.

Procedural Decision: Has the meaning given in regulation 41(1) of

the WEM Regulations.

Procedural Review: Means a review by the Electricity Review Board of

a Procedural Decision in accordance with the WEM Regulations.

Procedure Amendment: The specific wording of a proposed or accepted

change to a WEM Procedure.

Procedure Change Process: The process for amending a WEM Procedure

as set out in sections 2.10 and 2.11.

Procedure Change Proposal: A proposal developed by the Coordinator,

AEMO, the Economic Regulation Authority or a Network Operator to initiate a Procedure Change Process.

Procedure Change Report: A final report prepared by the Coordinator,

AEMO, the Economic Regulation Authority or a Network Operator in relation to a Procedure Change Proposal, containing the information described in clause 2.10.13.

Procedure Change Submission: A submission made in relation to a

Procedure Change Proposal submitted in accordance with clause 2.10.7.

Projected Assessment of System Adequacy (PASA): An assessment

undertaken by AEMO to assess future risks to Power System Security and Power System Reliability.

Proposed Generator Performance Standard: Means a standard or

technical level of performance in respect of a Technical Requirement proposed to apply to a Transmission Connected Generating System that has not been approved and registered in accordance with the process in Chapter 3A.

Proposed Negotiated Generator Performance Standard: Means a Proposed

Generator Performance Standard that is not an Ideal Generator Performance Standard but is no less than the Minimum Generator Performance Standard.

Protected Provision: A chapter or clause of the WEM Rules,

identified in clause 2.8.13.

Prudential Obligations: In respect of a Rule Participant, the

obligations set out in clauses 2.37 to 2.43.

Public Information: Market Information that is not confidential and

may be made available to any person.

Ramp Rate Limit: Means the Market Participant’s best estimate, in MW

per minute, on a linear basis, of a Facility’s physical ability to increase or decrease its output from the commencement of a Trading Interval, and includes a DSP Ramp Rate Limit.

RCM Constraint Equation: Means a Constraint Equation developed by

AEMO in accordance with section 4.4B.

RCM Limit Advice: Means Limit Advice for a Thermal Network Limit at

an ambient temperature of 41°C.

Ready Reserve Standard: Has the meaning given in clause 3.18.11A.

Real-Time Market: Means the mandatory gross pool market operated

under Chapter 7 that determines the dispatch and Essential System Service Enablement Quantity of Registered Facilities in each Dispatch Interval based on submitted prices and quantities.

Real-Time Market Bid: A bid in a Real-Time Market Submission or

Standing Real-Time Market Submission submitted by a Market Participant to AEMO for a Registered Facility to Withdraw energy via the Central Dispatch Process.

Real-Time Market Offer: An offer in a Real-Time Market Submission or

Standing Real-Time Market Submission submitted by a Market Participant to AEMO for a Registered Facility to supply a Market Service via the Central Dispatch Process.

Real-Time Market Offer Shortfall: Has the meaning given in clause

4.26.1G.

Real-Time Market Reserve Capacity Deficit: Has the meaning given in

clause 4.26.1B.

Real-Time Market Submission: A notice submitted by a Market

Participant to AEMO setting out the parameters under which it intends to have a Registered Facility participate in the Real-Time Market, in accordance with clauses 7.4.39, 7.4.40, 7.4.41, 7.4.42 and 7.4.44.

Real-Time Market Submission Acceptance Horizon: The point in time

before a Dispatch Interval after which a Market Participant may submit Real-Time Market Submissions for a Registered Facility for that Dispatch Interval.

Real-Time Market Timetable: The timetable documented by AEMO under

clause 7.1.2(a) for the operation of the Real-Time Market, which must include the timelines referred to in clause 7.1.3.

Reassessment Fee: A fee determined by AEMO under clause 2.24.2.

Recover: Means, in relation to SWIS Frequency Operating Standards,

the time at which the SWIS Frequency returns to the applicable Normal Operating Frequency Band, provided it does not go outside that range at any time over the following 1 minute.

Rectification Plan: Means a plan submitted by a Market Participant

responsible for a Transmission Connected Generating System in respect of a Transmission Connected Generating System, an alternative Rectification Plan proposed by AEMO or amended Rectification Plan under section 3A.11.

Reference Node: Is:

$a$ up to the New WEM Commencement Day, the Muja 330 kV bus-bar; and

$b$ on and from the New WEM Commencement Day, the Southern Terminal 330 kV bus-bar,

(relative to which Loss Factors are defined and Constraint Equations are formulated).

Reference Scenario: The Scenario that represents AEMO’s best

estimate of future dispatch and market outcomes.

Reference Trading Price: Means, for a Trading Interval, the price

determined in accordance with clause 7.11A.1(b).

Refund Exempt Planned Outage Count: In respect of a Separately

Certified Component of a Scheduled Facility or Semi-Scheduled Facility and a period of time, the sum over all Trading Intervals in that period of:

$a$ if no Capacity Credits were associated with the Separately Certified Component in the Trading Interval, zero; or

$b$ otherwise:

i. if the Trading Interval occurs before 8:00 AM on 1 June 2016, zero;

ii. if the Trading Interval occurs on or after 8:00 AM on 1 June 2016 and before New WEM Commencement Day, the total MW quantity of Refund Exempt Planned Outage determined for the relevant Scheduled Generator (or Scheduled Generators) in the Trading Interval under the WEM Rules that were in force immediately before New WEM Commencement Day, divided by the number of Capacity Credits associated with the Scheduled Generator (or Scheduled Generators) in the Trading Interval; or

iii. if the Trading Interval occurs on or after New WEM Commencement Day, the total Refund Exempt Planned Outage Quantity determined by AEMO for the Separately Certified Component in the Trading Interval under clauses 4.26.1C or 4.26.1CA, divided by the number of Capacity Credits associated with the Separately Certified Component in the Trading Interval.

Explanatory Note

The term ‘Refund Exempt Planned Outage’ is replaced with ‘Refund Exempt Planned Outage Quantity’ to clarify that AEMO’s determinations apply to Capacity Adjusted Planned Outage Quantities rather than Planned Outages.

Refund Exempt Planned Outage Quantity: A Capacity Adjusted Planned

Outage Quantity for a Separately Certified Component of a Scheduled Facility or Semi‑Scheduled Facility in a Trading Interval for which a Facility Reserve Capacity Deficit Refund is not payable, as determined by AEMO under clauses 4.26.1C or 4.26.1CA.

Explanatory Note

The term ‘Refund Payable Planned Outage’ is replaced with ‘Refund Payable Planned Outage Quantity’ to clarify that AEMO’s determinations apply to Capacity Adjusted Planned Outage Quantities rather than Planned Outages.

Refund Payable Planned Outage Quantity: A Capacity Adjusted Planned

Outage Quantity for a Separately Certified Component of a Scheduled Facility or Semi‑Scheduled Facility in a Trading Interval for which a Facility Reserve Capacity Deficit Refund is payable, as determined by AEMO under clauses 4.26.1C or 4.26.1CA.

Registered Facility: In respect of a Rule Participant, a Facility

registered by that Rule Participant with AEMO in a Facility Class under Chapter 2.

Registered Generator Performance Standard: Means:

$a$ in respect of a Transmission Connected Generating System other than an Existing Transmission Connected Generating System, an Ideal Generator Performance Standard or a Negotiated Generator Performance Standard that has been approved and registered in accordance with the process in Chapter 3A; and

$b$ in respect of an Existing Transmission Connected Generating System, the standard or technical level of performance in respect of a Technical Requirement that is an Agreed Generator Performance Standard under section 1.40 and deemed to be a Registered Generator Performance Standard under clause 1.40.31.

Registration Correction Notice: Means a notice issued by AEMO under

clauses 2.32.7B or 2.32.7BA.

Regulation: Has the meaning defined in clause 3.9.1.

Regulations: Any regulations made under the Electricity Industry Act

2004 (WA) including the WEM Regulations, AEMO Regulations and the Electricity Industry (Independent Market Operator) Repeal Regulations 2018.

Regulation Lower: Has the meaning defined in clause 3.9.3.

Regulation Lower Market Clearing Price: The Market Clearing Price

for Regulation Lower.

Regulation Lower Offer Price Ceiling: The price, in dollars per MW

per hour, determined in accordance with clause 2.26.2B, and as may be indexed in accordance with clause 2.26.2U, that is the maximum price that may be associated with a Real-Time Market Submission or Standing Real-Time Market Submission for the provision of Regulation Lower.

Regulation Raise: Has the meaning defined in clause 3.9.2.

Regulation Raise Market Clearing Price: The Market Clearing Price

for Regulation Raise.

Regulation Raise Offer Price Ceiling: The price, in dollars per MW

per hour, determined in accordance with clause 2.26.2B, and as may be indexed in accordance with clause 2.26.2U, that is the maximum price that may be associated with a Real-Time Market Submission or Standing Real-Time Market Submission for the provision of Regulation Raise.

Relevant Demand: The consumption, expressed in MW, of a Demand Side

Programme as determined in clause 4.26.2CA.

Relevant Generator Modification: Means a Potential Relevant

Generator Modification that the Network Operator declares to be a Relevant Generator Modification under clause 3A.13.4.

Relevant Level: Means the MW quantity determined by AEMO in

accordance with the Relevant Level Methodology.

Relevant Level Methodology: Means the method of determining the

Relevant Level specified in Appendix 9.

Relevant Settlement Adjustment Date: Means, for a Trading Week, any

of Settlement Adjustment Date 1, Settlement Adjustment Date 2 or Settlement Adjustment Date 3, as the case may be.

Relevant Settlement Statement: Has the meaning given in clause

9.3.6.

Reliable Operating State: The state of the SWIS defined in clause

3.3.1.

Explanatory Note

The definition for 'Remaining Available Capacity' is amended to clarify that the quantities that need to be entered will depend on the Facility Class, Facility Technology Type and the Market Service affected by the Outage. For example, Remaining Available Capacity for RoCoF Service will be in terms megawatt seconds. The detailed requirements will be provided in the WEM Procedure referred to in clause 3.18.4.

Remaining Available Capacity: For each Dispatch Interval included in

an Outage, the remaining capability of a Facility or Facility Technology Type of a Facility, as relevant, to provide an Outage Capability, in units as described in the WEM Procedure referred to in clause 3.18.4.

Repaid Amount: Has the meaning given in clause 9.20.2(a).

Explanatory Note

The defined term 'Repaid Amount Levy' is introduced to enable AEMO to disgorge, repay or pay a Repaid Amount and recover the payment form Market Participants through a levy in line with the provisions for the Default Levy without having to draw on its own funds or short pay any Market Participants.

The new defined term is introduced in conjunction with amendments to clause 9.20.2(b) and introduction of new clauses 9.20.2A to 9.20.2C.

Repaid Amount Levy: The amount, in respect of a given Market

Participant and in the circumstance of a particular Repaid Amount, determined by AEMO in accordance with clause 9.20.2A.

Representative: In relation to a person means a representative of

that person, including an employee, agent, officer, director, auditor, adviser, partner, consultant, joint venturer or sub-contractor, of that person.

Request for Expression of Interest: In respect of a Reserve Capacity

Cycle, the request for expression of interest made available in accordance with clause 4.2.2.

Required Level: The level of output (expressed in MW) required to be

met by a Facility as determined in clauses 4.11.3B, 4.11.3BB, 4.11.3BC or 4.11.3BD, as applicable.

Reserve Capacity: Capacity associated with a Facility. Capacity may

be:

$a$ the capacity of Energy Producing Systems to produce electricity and send it out into a Network forming part of the SWIS; or

$b$ Demand Side Management, being the capability of a Facility registered by the Market Participant at a connection point to a Network forming part of the SWIS to reduce the consumption of electricity at that connection point.

Reserve Capacity Cycle: The cycle of events described in clause 4.1.

Reserve Capacity Deficit: Has the meaning given in clause 4.26.1A.

Reserve Capacity Information Pack: A package of information,

including the information described in clause 4.7.3, pertaining to a Reserve Capacity Cycle.

Reserve Capacity Mechanism: Chapter 4 of the WEM Rules.

Reserve Capacity Obligations: For a Market Participant holding

Capacity Credits, determined in accordance with clause 4.12.1 or clause 4.28C.

Reserve Capacity Obligation Quantity: The specific amount of

capacity required to be provided in a Dispatch Interval or Trading Interval as part of a Reserve Capacity Obligation set by AEMO in accordance with clauses 4.12.4 to 4.12.6.

Reserve Capacity Performance Improvement Report: A report including

the information specified in clause 4.27.4A of the WEM Rules, provided by a Market Participant to AEMO under clause 4.27.5(b) in response to a request made under clause 4.27.3(b).

Reserve Capacity Performance Report: A report including the

information specified in clause 4.27.4 of the WEM Rules, provided by a Market Participant to AEMO under clause 4.27.5(a) in response to a request made under clause 4.27.3(a).

Reserve Capacity Price: In respect of a Reserve Capacity Cycle, the

price for Reserve Capacity determined in accordance with clause 4.29.1, where this price is expressed in units of dollars per Capacity Credit per year.

Reserve Capacity Price Factors: Means the BRCP Cap Factor, the EZ

BRCP Factor, EZ and AZ used in the formula specified in clause 4.29.1(b)(iv).

Reserve Capacity Requirement: Has the meaning given in clause 4.6.1.

Reserve Capacity Security: The reserve capacity security to be

provided for a Facility (other than a Demand Side Programme) that:

$a$ has the meaning given in clause 4.13.5; and

$b$ is as calculated and re-calculated under section 4.13 and section 4.28C.

Reserve Capacity Target: In respect of a Capacity Year, AEMO’s

estimate of the total amount of Energy Producing Systems' capacity or Demand Side Management capacity required in the SWIS to satisfy the Planning Criterion for that Capacity Year determined in accordance with clause 4.5.10(b).

Reserve Capacity Test: Means a test of the Reserve Capacity

associated with a Facility as conducted under section 4.25.

Restoration Profile: The profile over time of the expected change in

Withdrawal by the Loads associated with an Interruptible Load after activation in response to a Contingency Event, from the time the Interruptible Load begins to restore Load until the Facility has returned to normal operations.

Review Period: In the case of the first Review Period, the 3 year

period commencing on 1 July in the calendar year following the calendar year in which Energy Market Commencement occurs. For each subsequent Review Period, the 3 year period commencing on the third anniversary of the commencement of the previous Review Period.

Reviewable Decision: Decisions made by the Coordinator, AEMO, the

Economic Regulation Authority or a Network Operator, that are listed in Schedule 2 of the WEM Regulations, in respect of which an eligible person may apply to the Electricity Review Board for a review of a decision in accordance with the WEM Regulations.

RoCoF Causer: Means the set of Rule Participants identified in

accordance with Appendix 2B that must pay for the RoCoF Control Service.

RoCoF Control Requirement: Means the quantity of RoCoF Control

Service scheduled or dispatched in a Dispatch Interval or Pre-Dispatch Interval which is the sum of the Minimum RoCoF Control Requirement and the Additional RoCoF Control Requirement.

**RoCoF Control Service or Rate of Change of Frequency Control

Service**: Has the meaning defined in clause 3.9.7.

RoCoF Control Service Market Clearing Price: The Market Clearing

Price for RoCoF Control Service.

RoCoF Control Service Offer Price Ceiling: The price, in dollars per

MWs per hour, determined in accordance with clause 2.26.2B, and as may be indexed in accordance with clause 2.26.2U, that is the maximum price that may be associated with a Real-Time Market Submission or Standing Real-Time Market Submission for the provision of RoCoF Control Service.

RoCoF Limit: Means a limit on the average frequency rate of change

over a particular time period.

RoCoF Ride Through Capability: Is the highest RoCoF Limit at which

the Facility can operate safely and reliably, expressed over the same timeframe specified in the RoCoF Safe Limit.

RoCoF Ride-Through Cost Recovery Limit: Means the limit set by AEMO

under clause 2.34A.12I that is used to determine the set of RoCoF Causers that must pay for the RoCoF Control Service under Appendix 2B.

RoCoF Safe Limit: Means the RoCoF Limit referred to in Appendix 13.

RoCoF Upper Limit: Means the maximum RoCoF expected on the SWIS if

Contingency Reserve was solely used to maintain SWIS frequency after a Contingency Event.

Rolling Test Window: A rolling consecutive three-month period of

Trading Days, with a successive three-month period beginning on the first Trading Day after the last Trading Day falling within the immediately prior three-month period.

Rule Change Panel: Has the meaning given to it in the Panel

Regulations.

Rule Change Proposal: A proposal made in accordance with clause 2.5

proposing that the Coordinator makes Amending Rules.

Rule Participant: Any person registered as a Rule Participant in

accordance with Chapter 2 and AEMO.

Satisfactory Operating State: The state of the SWIS defined in

clause 3.4.1.

Scenario: Means a set of inputs used to generate forecast Dispatch

Targets and Market Clearing Prices and the set of resulting outputs.

Scheduled Facility: A Facility that can respond to a Dispatch Target

from AEMO such that it can maintain its Injection or Withdrawal within its Tolerance Range for a specified period and is registered as such in accordance with clauses 2.29.4G and 2.29.4I.

Scheduling Day: In respect of a Trading Day, the calendar day

immediately preceding the calendar day on which the Trading Day commences.

Season: As the context requires, any of the Cold Season,

Intermediate Season or Hot Season.

Secure Operating State: The state of the SWIS defined in clause

3.4.2.

Secure Operational Voltage Envelope: Means the voltage limits for

the secure operation of an Operating Zone as determined by AEMO under clause 3.1A.9.

Security Deposit: Means a cash deposit made with AEMO (on terms

acceptable to AEMO in its absolute discretion) by or on behalf of a Rule Participant.

Security Limit: Any technical limit on the operation of the SWIS as

a whole, or a region of the SWIS, necessary to maintain the Power System Security, including both static and dynamic limits, and limits to allow for and to manage contingencies.

Security Provider: Means a person or entity which meets the

Acceptable Credit Criteria and which itself is not a Rule Participant.

Self-Scheduling Outage Facility: A Facility that is included on the

Self-Scheduling Outage Facility List.

Self-Scheduling Outage Facility List: The list maintained by AEMO

under clause 3.18A.6.

Semi-Scheduled Facility: A Facility that can reduce the value of its

Injection or increase the value of its Withdrawal to comply with a Dispatch Cap issued by AEMO and is registered as such in accordance with clauses 2.29.4G and 2.29.4I.

Sent Out Metered Schedule: Means the Metered Schedule converted to

sent out MWh quantities using applicable Loss Factors.

Separately Certified Component: Any component of a Scheduled

Facility or Semi-Scheduled Facility which AEMO has assessed separately in the determination of Certified Reserve Capacity for the Facility, and for which AEMO assigned Capacity Credits for any Trading Interval in the Capacity Year.

Separation Event: Means a Credible Contingency Event that results in

the formation of an Island.

Service Fee Settlement Amount: Means the amounts determined in

accordance with section 9.13.

SESSM: Means the mechanism to procure Frequency Co-optimised

Essential System Services under section 3.15A.

SESSM Availability Payment: Means the dollar amount payable to the

Market Participant for offering the SESSM Availability Quantity of Frequency Co-optimised Essential System Service into the market according to the SESSM Service Specification.

SESSM Availability Quantity: Means the MW or MWs quantity of a

Frequency Co-optimised Essential System Service to be made available in a Dispatch Interval under a SESSM Award.

SESSM Availability Requirement: For a SESSM Award, the percentage of

Dispatch Intervals in the SESSM Service Timing in which the Facility must include the sum of the SESSM Availability Quantity and the Base ESS Quantity in its Real-Time Market Submissions for the relevant Frequency Co-optimised Essential System Service from an Available Capacity or In-Service Capacity or be required to pay a Facility SESSM Refund calculated under Appendix 2C.

SESSM Award: Means the acceptance of an offer by AEMO to provide

Frequency Co-optimised Essential System Services by a Market Participant in accordance with a SESSM Submission through the SESSM.

SESSM Award Duration: Means the period over which obligations and

payments under a SESSM Submission apply and must be no longer than three years.

SESSM Offer Cap: Means the price referred to in clause 3.15A.20(c).

SESSM Service Commencement Date: Means the date a Frequency

Co-optimised Essential System Service procured through the SESSM is required to commence.

SESSM Service Quantity Profile: Means the MW or MWs quantity of

Frequency Co-optimised Essential System Service sought through the SESSM for each Dispatch Interval in the SESSM Service Timing (which may be zero at some times of the year or in some hours of the day).

SESSM Service Specification: for a Frequency Co-optimised Essential

System Service being procured under the SESSM, as set out in clause 3.15A.6.

SESSM Service Timing: Means the time period and Dispatch Intervals

during which a Frequency Co-optimised Essential System Service procured through the SESSM is required to be provided.

SESSM Submission: Means a submission made by a Market Participant in

respect of a Facility to provide Frequency Co-optimised Essential System Services in accordance with clause 3.15A.21 through the SESSM.

Settlement Adjustment Date 1: Has the meaning given in clause

9.3.7(a).

Settlement Adjustment Date 2: Has the meaning given in clause

9.3.7(b).

Settlement Adjustment Date 3: Has the meaning given in clause

9.3.7(c).

Settlement Date: The Business Day, determined under clause 9.3.1(d),

on which all amounts payable under these WEM Rules are settled for the relevant Trading Week for an original Settlement Statement or, in respect of any adjusted Settlement Statement for that Trading Week, the Business Day, determined under clause 9.3.1(i), on which all amounts payable under these WEM Rules are settled for the relevant adjusted Settlement Statement.

Settlement Disagreement Deadline: Has the meaning given in clause

9.16.2.

Settlement Statement: Means an original settlement statement issued

under clause 9.3.3(a) in relation to a Trading Week and containing the information described in clause 9.14 and, in respect of the Adjustment Process, each adjusted settlement statement in relation to that Trading Week issued under clause 9.15.1(b) and containing the information described in clause 9.15.3, respectively.

Settlement Statement Date: The Business Day, determined in

accordance with clause 9.3.1(b) on which AEMO releases original Settlement Statements for a Trading Week, and each Business Day, determined in accordance with clause 9.3.1(h) on which AEMO releases adjusted Settlement Statements for the Adjustment Process for that Trading Week, respectively.

Shared Reserve Capacity Cost: The amount determined in accordance

with clause 4.28.4.

Short Term Energy Market (STEM): A forward market operated under

Chapter 6 in which Market Participants can purchase electricity from, or sell electricity to, AEMO.

Short Term PASA: A PASA covering the period in clause 3.16.1(b).

Explanatory Note

The definition of Small Aggregation as a Facility Technology Type will be reviewed holistically with both the policy intent for facility aggregation (at both transmission and distribution level) as well as how DER is to participate in the WEM in the future. However, for the purposes of the RCM, the definition of Small Aggregation as set out below suffices to enable distributed energy resources to aggregate behind the same TNI and participate in the RCM. These small aggregations are expected to be registered as Non-Scheduled Facilities.

The definition of System Size considers contracted access to the market which estimates the impact of a facility on the market. This definition also explicitly references the charge and discharge capability of Electric Storage Resources and this avoids the need to specify single cycle changes. System Size is used in sections 2.28 and 2.29 of the Tranches 2 and 3 Amendments in the context of energy producing systems at unregistered facilities and therefore the definition has changed Facility to facility to account for both registered and unregistered facilities. The definition of System Size uses the term energy producing equipment instead of energy producing system to denote the fact that the system comprises the entirety of all generating and storage equipment at the facility.

Small Aggregation: One or more Facilities connected to the

distribution system and located at the same Electrical Location.

Small Generating Unit: An Energy Producing System which has a rated

capacity of less than 10MW.

South West interconnected system (SWIS): Has the meaning given in

the Electricity Industry Act.

Stable: Means when the SWIS will return to an acceptable

steady-state operating condition following a disturbance.

Stabilise: Means, in relation to SWIS Frequency Operating Standards,

when the SWIS Frequency has remained above or below the required level for at least 20 seconds.

Standard Rule Change Process: The process for dealing with Rule

Change Proposals set out in clause 2.7.

Standing Bilateral Submission: A submission by a Market Participant

to AEMO made in accordance with section 6.2A.

Standing Data: Data maintained by AEMO under clause 2.34.1.

Standing DSP Withdrawal Profile Submission: A default DSP Withdrawal

Profile Submission for a Demand Side Programme for Dispatch Intervals starting at specified times on Trading Days of a specified type.

Standing Enablement Maximum: In relation to a Facility and a

Frequency Co-optimised Essential System Service, the maximum level of Injection or Withdrawal for which a response will be available for a Frequency Co-optimised Essential System Service.

Standing Enablement Minimum: In relation to a Facility and a

Frequency Co-optimised Essential System Service, the minimum level of Injection or Withdrawal for which a response will be available for a Frequency Co-optimised Essential System Service.

Standing High Breakpoint: For a Facility and a Frequency

Co-optimised Essential System Service, the maximum level of generation (in MW) above which the Facility cannot provide its maximum quantity of that Frequency Co-optimised Essential System Service.

Standing Low Breakpoint: For a Facility and a Frequency Co-optimised

Essential System Service, the minimum level of generation (in MW) below which the Facility cannot provide its maximum quantity of that Frequency Co-optimised Essential System Service.

Standing Maximum Downwards Ramp Rate: The Facility’s maximum

physical ability, in MW per minute, on a linear basis, to decrease the magnitude of Injection or increase the magnitude of Withdrawal on the receipt of a Dispatch Instruction.

Standing Maximum Upwards Ramp Rate: The Facility’s maximum physical

ability, in MW per minute, on a linear basis, to increase the magnitude of Injection or decrease the magnitude of Withdrawal on the receipt of a Dispatch Instruction.

Standing Real-Time Market Submission: A default Real-Time Market

Submission for a Registered Facility and Market Service for Dispatch Intervals starting at specified times on Trading Days of a specified type.

Standing STEM Submission: A submission by a Market Participant to

AEMO made in accordance with clause 6.3C.

Explanatory Note

The definition for 'Start Decision Cutoff' is amended to clarify that the time is relative to the Dispatch Interval in the relevant Real-Time Market Submission, and that the concept of Available Capacity is not just related to synchronisation but relates generally to a decision to make capacity ready for dispatch.

Start Decision Cutoff: For a Registered Facility and Dispatch

Interval, the latest time before the start of the Dispatch Interval at which a Market Participant could decide to change a quantity of Available Capacity to In-Service Capacity so as to make the capacity ready for dispatch in that Dispatch Interval, as reflected in its Real-Time Market Submission.

Statement of Corporate Intent: The statement of corporate intent as

agreed by the Minister or otherwise deemed to apply by Division 2 of Part 5 of the Electricity Corporations Act.

Statement of Opportunities Report: A report prepared in accordance

with clause 4.5.13 presenting the results of the Long Term PASA study, including a statement of required investment if Power System Security and Power System Reliability are to be maintained.

STEM: See Short Term Energy Market.

STEM Auction: The process, described in clause 6.9, used to clear

the STEM.

STEM Bid: A bid to purchase energy from AEMO via the STEM Auction

for a Trading Interval.

STEM Clearing Price: Has the meaning given in clause 6.9.7.

STEM Clearing Quantity: Has the meaning given in clause 6.9.8.

STEM Offer: An offer to provide energy through the STEM Auction for

a Trading Interval determined by AEMO in accordance with clause 6.9.3.

STEM Reserve Capacity Obligation Quantity: An estimate of the

Reserve Capacity Obligation Quantity for a Scheduled Facility or Semi-Scheduled Facility, or a Separately Certified Component of a Scheduled Facility or Semi-Scheduled Facility, for a Dispatch Interval that is determined by AEMO on the Scheduling Day for the relevant Trading Day in accordance with clause 6.3A.3(h).

STEM Results Deadline: Means 11:30 AM on the Scheduling Day for the

Trading Day, or such other time as may be notified by AEMO under clause 6.4.6B.

STEM Submission: A submission by a Market Participant to AEMO made

in accordance with clause 6.3B containing the information set out in, and in the format prescribed by, clause 6.6.

STEM Submission Cutoff: Means 10:50 AM on the Scheduling Day for the

Trading Day, or such other time as may be notified by AEMO under clause 6.4.6B.

STEM Submission Information Window: For a Scheduling Day, the period

of eight consecutive Trading Days starting with the Trading Day for the Scheduling Day.

STEM Submission Results Window: For a point in time in the 24-hour

period starting at 8:30 AM on a Scheduling Day, the period of eight consecutive Trading Days starting with the Trading Day for the Scheduling Day.

Storage Works: Has the meaning given to it in the Electricity

Industry Act.

Supplementary Capacity Contract: An agreement under which a service

provider agrees to supply one or more Eligible Services to AEMO, entered into in accordance with section 4.24

Suspension Event: An event described in clause 9.19.

Suspension Notice: A notice issued by AEMO in accordance with

section 2.32 or clause 9.19.7 that a Market Participant is suspended from trading in the Wholesale Electricity Market.

SWIS: See the South West interconnected system.

SWIS Frequency: Means the frequency of the SWIS, or an Island (as

applicable).

SWIS Frequency Operating Standards: Means the standards set out in

Table 1, Appendix 13.

SWIS Operating Standards: The standards for the operation of the

SWIS including the frequency and time error standards and voltage standards set out in clause 3.1.

SWIS Operating State: One or any of the Reliable Operating State,

Satisfactory Operating State, Secure Operating State or Emergency Operating State.

Synergy: The body corporate established under section 4(1)(a) of the

Electricity Corporations Act.

System Inertia: The total Inertia provided by Registered Facilities,

Loads, Network equipment and other equipment connected to the SWIS.

System Operation Function: The functions referred to in clauses

2.1A.1A, 2.1A.2(cA) and 2.1A.2(iA), together with any function conferred on AEMO under these WEM Rules in respect of system operation.

System Restart Plan: The plan described in clause 3.7.4.

System Restart Service: The ability of a Registered Facility with an

energy producing system to start without requiring energy to be supplied from a Network to assist in the re-energisation of the SWIS in the event of a system shut down or major supply disruption.

System Restart Service Contract: A contract between AEMO and a

Market Participant for the provision of a System Restart Service to AEMO by that Market Participant’s Registered Facility.

System Restart Service Provider: A Market Participant who provides

System Restart Service to AEMO under a System Restart Service Contract.

System Restart Standard: The standard, determined by AEMO under

clause 3.7.1 and described in clause 3.7.2, for procurement of System Restart Services.

System Size: In respect of a Facility, a quantity equalling the sum

of:

$a$ the minimum of:

i. the Declared Sent Out Capacity of the Facility; and

ii. the sum over all energy producing equipment comprising the Energy Producing System at the Facility (calculated for each individual piece of energy equipment), of each energy producing equipment’s maximum MW output; and

$b$ if the Facility contains no Electric Storage Resource, then zero, otherwise the minimum of:

i. the Contract Maximum Demand in MW of the Facility, where the Contract Maximum Demand is a positive quantity; and

ii. negative one multiplied by the sum over all Electric Storage Resources in the Energy Producing System at the Facility (calculated for each individual Electric Storage Resource), of each Electric Storage Resource’s maximum MW consumption quantity (where that consumption quantity is negative).

System Strength: Is a measure of how resilient the voltage waveform

is to disturbances such as those caused by a sudden change in Load or an Energy Producing System, the switching of a Network element, tapping of transformers and other types of faults.

System Strength: Is a measure of how resilient the voltage waveform

is to disturbances such as those caused by a sudden change in Load or an Energy Producing System, the switching of a Network element, tapping of transformers and other types of faults.

System Strength Requirements: Means, the requirements identified to

maintain sufficient System Strength on the SWIS, as determined by the processes specified in the WEM Procedure referred to in clause 3.2.7.

Targeted Reserve Capacity Cost: The cost defined under clause

4.28.1(a).

Technical Envelope: The limits for the operation of the SWIS in each

SWIS Operating State as established and modified by AEMO in accordance with clause 3.2.6.

Technical Requirement: Means each Technical Requirement for a

Transmission Connected Generating System specified in Appendix 12.

Technical Rules: has the meaning given in section 1.3 of the Access

Code.

Technical Rules Change Proposal: Means a proposal made in accordance

with the procedure developed pursuant to section 12.50A of the Access Code and submitted to the Economic Regulation Authority proposing that the Technical Rules be amended.

Technical Rules Committee: Means the committee established under

section 12.16 of the Access Code.

Temperature Dependent Load: A Non-Dispatchable Load that is not a

Non-Temperature Dependent Load.

Test: Means a Commissioning Test or a Reserve Capacity Test.

Test Plan: Means a plan approved under Chapter 3 in relation to a

Test.

Thermal Network Limit: Means a Network Limit that describes the

maximum capacity for electrical throughput of a particular Network element due to temperature or related effects.

Tolerance Range: Means the amount, in MW, determined by AEMO under

clause 2.13.16 of the WEM Rules.

Total Amount: Has the meaning given in clause 9.20.3.

Total Sent Out Generation: Means, for a Trading Interval, the sum

over all Scheduled Facilities, Semi-Scheduled Facilities and Non-Scheduled Facilities of each Facility’s Sent Out Metered Schedule for the Trading Interval or zero (whichever is higher for that Facility).

Trading Conduct Guideline: The guideline published by the Economic

Regulation Authority under clause 2.16D.1(b), which may be amended in accordance with 2.16D.2.

Trading Day: A period of 24 hours commencing at 8:00 AM on any day

after Energy Market Commencement, except where AEMO declares that part of a Trading Day is to be treated as a full Trading Day under clause 9.1.2, in which case that part is a Trading Day.

Trading Interval: A period of 30 minutes commencing on the hour or

half-hour during a Trading Day.

Trading Interval Capacity Cost Refund: The refund a Market

Participant holding Capacity Credits incurs in a Trading Interval, as calculated in accordance with clause 4.26.2F.

Trading Interval Refund Rate: The refund rate applicable in a

Trading Interval, and in respect of a Facility, as calculated in accordance with clause 4.26.1(a).

Trading Limit: Has the meaning given in clause 2.39.1.

Trading Margin: Has the meaning given in clause 2.41.1.

Trading Month: A period from the beginning of a Trading Day

commencing on the first day of a calendar month to the end of the Trading Day that finishes on the first day of the following calendar month.

Trading Week: A period of seven days commencing at 8:00 AM on the

day of the week on which the New WEM Commencement Day commences.

Tranche 1 Commencement Date: Means the Trading Day commencing at

8:00 AM on 1 February 2021.

Transitional Facility: Means a Facility (other than a Demand Side

Programme) that was assigned Capacity Credits for the 2018 Reserve Capacity Cycle.

Transitional Procedure: A procedure that, in accordance with these

WEM Rules, is:

$a$ required to be developed prior to the New WEM Commencement Day; and

$b$ deemed to be a WEM Procedure from the New WEM Commencement Day, or such other date as specified in these WEM Rules.

Transitional Reserve Capacity Cycle: Means either:

$a$ the 2019 Reserve Capacity Cycle; or

$b$ any of the subsequent Reserve Capacity Cycles up to and including the 2028 Reserve Capacity Cycle.

Explanatory Note

This definition for 'Transmission Connected Generating System' is amended to clarify the unregistered Energy Producing Systems serving Intermittent Loads are also subject to Generator Performance Standards.

Transmission Connected Generating System: Means generating works

connected to a transmission system in the SWIS, including an unregistered Energy Producing System supplying an Intermittent Load.

Transmission Loss Factor: A factor representing the average marginal

electrical losses incurred when electricity is transmitted through a transmission network.

Transmission Loss Factor Class: A group of one or more connection

points with common characteristics assigned a common Transmission Loss Factor.

Transmission Node: A location on a transmission system identified

for the purposes of aggregating transfer of electricity through that part of the transmission system.

Transmission Node Identifier: The code identifying the relevant

Transmission Node.

Transmission System Plan: A plan prepared and published by a Network

Operator in respect of its Network in accordance with section 4.5B.

Trigger Event: Means one or more circumstances specified in a

Negotiated Generator Performance Standard, the occurrence of which requires a Market Participant responsible for a Transmission Connected Generating System to undertake required actions to achieve an agreed outcome and or achieve an agreed higher level of performance than the existing Registered Generator Performance Standard applicable in respect of one or more Technical Requirements.

UFLS Requirements: The functional requirements for the SWIS under

frequency load shedding system published by AEMO in accordance with section 3.6, and as may be amended from time to time in accordance with section 3.6.

UFLS Specification: The document referred to in clause 3.6.5

containing the Network Operator's design specification for its under frequency load shedding system in respect of its Network, which must meet the UFLS Requirements.

Unconstrained Injection Forecast: The expected MW level of Injection

at the end of a Dispatch Interval for a Semi-Scheduled Facility or Non-Scheduled Facility, assuming that the Facility will not be subject to a Dispatch Instruction or direction from AEMO that limits its Injection, and allowing for expected conditions, commitment and control intentions and the effect of any Outages that have not been rejected for the Facility.

Unconstrained Withdrawal Forecast: The expected MW level of

Withdrawal at the end of a Dispatch Interval for a Semi-Scheduled Facility or Non-Scheduled Facility, assuming that the Facility will not be subject to a Dispatch Instruction or direction from AEMO that limits its Withdrawal, and allowing for expected conditions, commitment and control intentions and the effect of any Outages that have not been rejected for the Facility.

Uplift Payment Mispricing Trigger: For a Facility and a Dispatch

Interval, the value calculated in clause 9.9.9.

Verification Test: Means a test conducted under clause 4.25A.

Week-Ahead Schedule: A forecast of Market Clearing Prices, Dispatch

Targets Dispatch Caps, Dispatch Forecasts and Essential System Services Enablement Quantities for each Pre-Dispatch Interval in the Week-Ahead Schedule Horizon.

Week-Ahead Schedule Horizon: The next 336 Pre-Dispatch Intervals

after a Pre-Dispatch Interval.

WEM Procedure: The procedures developed by AEMO, the Economic

Regulation Authority, the Coordinator and a Network Operator, as applicable, in accordance with section 2.9 as amended in accordance with the Procedure Change Process.

WEM Regulations: Means the Electricity Industry (Wholesale

Electricity Market) Regulations 2004.

WEM Rules: These rules relating to the Wholesale Electricity Market

and to the operation of the SWIS.

WEM Technical Standard: A provision of the WEM Rules, identified in

clause 2.8.14.

WEM Website: Has the meaning given in the Regulations, and includes

any website operated by AEMO to carry out its functions under these WEM Rules.

Western Australian Government’s Energy Transformation Strategy:

Means the Western Australian Government’s Energy Transformation Strategy as announced on 6 March 2019 to be delivered by the Energy Transformation Taskforce in accordance with its Terms of Reference (as may be amended).

Western Power: The body corporate established by section 4(1)(b) of

the Electricity Corporations Act.

Western Power Corporation: The body corporate established under the

Electricity Corporation Act (1994) as Western Power Corporation.

Western Standard Time: Co-ordinated Universal Time + 8 hours.

Whole of System Plan: A plan prepared and published by the

Coordinator in accordance with section 4.5A.

Wholesale Electricity Market: The market established under section

122 of the Electricity Industry Act.

Wholesale Electricity Market and Constrained Network Access Reform:

Means:

$a$ any proposed change to the operation of the Wholesale Electricity Market or related network access arrangements, or the regulatory regime applying to the Wholesale Electricity Market (including the Electricity Industry Act, the Regulations and these WEM Rules); and

$b$ any related activity undertaken by AEMO in connection with implementation of the DER Roadmap,

that has been endorsed by the Minister (whether or not legislation has been made to implement it).

Wholesale Market Objectives: The market objectives set out in

Section of 122(2) of the Electricity Industry Act and repeated in clause 1.2.1.

Withdrawal: The quantity of power or energy received from a Network,

as measured:

$a$ for a Scheduled Facility, Semi-Scheduled Facility or Non-Scheduled Facility with a single defined network connection point, at the network connection point;

$b$ for a Scheduled Facility, Semi-Scheduled Facility or Non-Scheduled Facility with multiple network connection points with the same Electrical Location, at the Electrical Location;

$c$ for a Scheduled Facility, Semi-Scheduled Facility or Non-Scheduled Facility with network connection points at more than one Electrical Location, at the Reference Node;

$d$ for a Non-Dispatchable Load, at the network connection point; and

$e$ for a Demand Side Programme, as the sum of the Withdrawal quantities of each Associated Load of the Demand Side Programme,

which is measured in instantaneous MW unless specified as MWh over a time period, and is represented as a negative number or zero.

Working Group: A working group as established under clause 2.3.17 of

these WEM Rules.

Explanatory Note

Appendix 1 has been redrafted to:

use the new registration taxonomy;
rearrange the lists within the Appendix in the following order:
- lists of items required as a pre-condition of Rule Participant registration;
- lists of items required as a pre-condition for Facility registration in a specific Facility Class; and
- list of items that are not required as pre-conditions for registration;
include new Standing Data items required to support the new market arrangements;
remove Standing Data items that are no longer required;
remove items that are not maintained using the Standing Data processes set out in section 2.34 (e.g. the Capacity Credits held by a Facility); and
clarify the requirements for some existing Standing Data items.
remove the start-up costs and minimum generation costs, because this information is available to the ERA through other sources and is unsuitable for Standing Data due to its complexity and volatility; and
add new items relating to maximum sent out capacities that are required to support outage management processes.

Appendix 1: Standing Data

This Appendix describes the Standing Data to be maintained by AEMO for use by AEMO in market processes and in dispatch processes.

Standing Data required to be provided as a pre-condition of Market Participant registration and which Market Participants are to update as necessary, is described in Appendix 1(a).

Standing Data required to be provided as a pre-condition of Facility registration and which Rule Participants are to update as necessary, is described in Appendix 1(b) to 1(f).

Standing Data not required to be provided as a pre-condition of Facility registration but which AEMO is required to maintain, and which Rule Participants are to update as necessary, includes the data described in Appendix 1(g) to 1(i).

$a$ For each Market Participant, the maximum Loss Factor adjusted quantity of energy, in units of MWh, that could be consumed during a Trading Interval by the Market Participant’s Registered Facilities and Non-Dispatchable Loads.

$b$ For a Scheduled Facility:

i. the total nameplate capacity of the Facility’s Energy Producing System, expressed in MW;

ii. the nameplate capacity of each Facility Technology Type in the Facility, excluding Loads;

iii. the System Size;

iv. if the Facility is a Small Aggregation;

v. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Facility under optimal conditions, expressed in MW;

vA. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from Non-Intermittent Generating Systems in the Facility under optimal conditions, expressed in MW;

vB. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from Intermittent Generating Systems in the Facility under optimal conditions, expressed in MW;

vC. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from Electric Storage Resources in the Facility under optimal conditions, expressed in MW;

vD. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply across the Electric Storage Resource Obligation Duration to the relevant Network from Electric Storage Resources in the Facility under optimal conditions, expressed in MW;

vi. the maximum Withdrawal capacity of the Facility under optimal conditions, expressed in MW;

vii. the dependence of sent out capacity on temperature at the location of the Facility;

viii. the method to be used for determining the ambient temperature at the site of the Facility (where if no method is specified, a constant temperature of 41 degrees Celsius will be assumed);

ix. if the Facility has a Separately Certified Component that is a Non‑Intermittent Generating System, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Non‑Intermittent Generating System when it is operated normally at an ambient temperature of:

1. 41 degrees Celsius; and

2. 45 degrees Celsius;

x. if the Facility has a Separately Certified Component that is a Non‑Intermittent Generating System, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Non‑Intermittent Generating System under optimal conditions, expressed in MW;

xA. if the Facility has a Separately Certified Component that is an Intermittent Generating System, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Intermittent Generating System under optimal conditions, expressed in MW;

xi. if the Facility has a Separately Certified Component that is an Electric Storage Resource, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Electric Storage Resource when it is operated normally at an ambient temperature of:

1. 41 degrees Celsius; and

2. 45 degrees Celsius;

xii. if the Facility has a Separately Certified Component that is an Electric Storage Resource, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply across the Electric Storage Resource Obligation Duration to the relevant Network from the Electric Storage Resource under optimal conditions, expressed in MW;

xiii. if the Facility has a Separately Certified Component that is an Electric Storage Resource, the minimum Charge Level capability of the Electric Storage Resource;

xiv. details of the fuel or fuels that each Non-Intermittent Generating System in the Facility can use, including dual fuel capabilities and the process for changing fuels;

xv. the dependence of capacity on the type of fuel used by each Non-Intermittent Generating System in the Facility for each fuel described in Appendix 1(b)(xiv);

xvi. details of any potential energy limits of the Facility;

xvii. if the Facility is a Fast Start Facility;

xviii. the minimum time to synchronisation for the Facility from each of the following states, if applicable:

1. cold;

2. warm; and

3. hot,

and the number of hours that must have elapsed since the Facility last ran for it to be considered in each of these states;

xix. the minimum time before each Facility Technology Type in the Facility can be restarted after it is shut down, excluding Loads;

xx. the minimum stable loading level of the Facility, expressed in sent out MW;

xxi. the minimum dispatchable loading level of the Facility, expressed in sent out MW;

xxii. the minimum physical response time before the Facility can begin to respond to a Dispatch Instruction, when the Facility is running;

xxiii. any output range between minimum dispatchable loading level and nameplate capacity in which the Facility is incapable of stable or safe operation;

xxiv. the minimum load at the connection point of the Facility that will automatically trip off if the Facility fails, expressed in MW;

xxv. sub-transient, transient and steady state impedances (positive, negative and zero sequence) for the Facility;

xxvi. the Standing Maximum Upwards Ramp Rate;

xxvii. the Standing Maximum Downwards Ramp Rate;

xxviii. the emergency upwards ramp rate;

xxix. the emergency downwards ramp rate;

xxx. the overload Injection capacity of the Facility, if any, expressed in MW;

xxxi. the overload Withdrawal capacity of the Facility, if any, expressed in MW;

xxxii. the AGC capabilities of the Facility;

xxxiii. the black start capability of the Facility;

xxxiv. the short circuit capability of Facility equipment;

xxxv. evidence that the communication and control systems required by section 2.35 are in place and operational;

xxxvi. the single line diagram for the Facility, including the locations of transformers, switches, operational and settlement meters;

xxxvii. the network node or nodes at which the Facility can connect;

xxxviii. the Transmission Node Identifier;

xxxix. the National Meter Identifier of each metering point for the Facility, where applicable; and

xl. the Metering Data Agent for the Facility.

$c$ For a Semi-Scheduled Facility:

i. the total nameplate capacity of the Facility’s Energy Producing System, expressed in MW;

ii. the nameplate capacity of each Facility Technology Type in the Facility, excluding Loads;

iii. the System Size;

iv. if the Facility is a Small Aggregation;

v. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Facility under optimal conditions, expressed in MW;

vA. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from Non-Intermittent Generating Systems in the Facility under optimal conditions, expressed in MW;

vB. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from Intermittent Generating Systems in the Facility under optimal conditions, expressed in MW;

vC. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from Electric Storage Resources in the Facility under optimal conditions, expressed in MW;

vD. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply across the Electric Storage Resource Obligation Duration to the relevant Network from Electric Storage Resources in the Facility under optimal conditions, expressed in MW;

vi. the maximum Withdrawal capacity of the Facility under optimal conditions, expressed in MW;

vii. the dependence of sent out capacity on temperature at the location of the Facility, if applicable;

viii. the method to be used for determining the ambient temperature at the site of the Facility (where if no method is specified, a constant temperature of 41 degrees Celsius will be assumed);

ix. if the Facility has a Separately Certified Component that is a Non‑Intermittent Generating System, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Non-Intermittent Generating System when it is operated normally at an ambient temperature of:

1. 41 degrees Celsius; and

2. 45 degrees Celsius;

x. if the Facility has a Separately Certified Component that is a Non‑Intermittent Generating System, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Non‑Intermittent Generating System under optimal conditions, expressed in MW;

xA. if the Facility has a Separately Certified Component that is an Intermittent Generating System, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Intermittent Generating System under optimal conditions, expressed in MW;

xi. if the Facility has a Separately Certified Component that is an Electric Storage Resource, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Electric Storage Resource when it is operated normally at an ambient temperature of:

1. 41 degrees Celsius; and

2. 45 degrees Celsius;

xii. if the Facility has a Separately Certified Component that is an Electric Storage Resource, the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply across the Electric Storage Resource Obligation Duration to the relevant Network from the Electric Storage Resource under optimal conditions, expressed in MW;

xiii. if the Facility has a Separately Certified Component that is an Electric Storage Resource, the minimum Charge Level capability of the Electric Storage Resource;

xiv. details of the fuel or fuels that each Non-Intermittent Generating System in the Facility can use, including dual fuel capabilities and the process for changing fuels;

xv. the dependence of capacity on the type of fuel used by each Non‑Intermittent Generating System in the Facility for each fuel described in Appendix 1(c)(xiv);

xvi. if the Facility is a Fast Start Facility;

xvii. the minimum time to synchronisation for the Facility from each of the following states, if applicable:

1. cold;

2. warm; and

3. hot,

and the number of hours that must have elapsed since the Facility last ran for it to be considered in each of these states;

xviii. the minimum time before each Facility Technology Type in the Facility can be restarted after it is shut down, excluding Loads;

xix. the minimum stable loading level of the Facility, expressed in sent out MW;

xx. the minimum dispatchable loading level of the Facility, expressed in sent out MW;

xxi. the minimum physical response time before the Facility can begin to respond to a Dispatch Instruction, when the Facility is running;

xxii. any output range between minimum dispatchable loading level and nameplate capacity in which the Facility is incapable of stable or safe operation, if applicable;

xxiii. the minimum load at the connection point of the Facility that will automatically trip off if the Facility fails, expressed in MW;

xxiv. sub-transient, transient and steady state impedances (positive, negative and zero sequence) for the Facility;

xxv. the Standing Maximum Upwards Ramp Rate;

xxvi. the Standing Maximum Downwards Ramp Rate;

xxvii. the emergency upwards ramp rate, if applicable;

xxviii. the emergency downwards ramp rate, if applicable;

xxix. the overload Injection capacity of the Facility, if any, expressed in MW;

xxx. the overload Withdrawal capacity of the Facility, if any, expressed in MW;

xxxi. the short circuit capability of Facility equipment;

xxxii. evidence that the communication and control systems required by section 2.35 are in place and operational;

xxxiii. the single line diagram for the Facility, including the locations of transformers, switches, operational and settlement meters;

xxxiv. the network node or nodes at which the Facility can connect;

xxxv. the Transmission Node Identifier;

xxxvi. the National Meter Identifier of each metering point for the Facility, where applicable; and

xxxvii. the Metering Data Agent for the Facility.

$d$ for a Non-Scheduled Facility:

i. the total nameplate capacity of the Facility’s Energy Producing System, expressed in MW;

ii. the nameplate capacity of each Facility Technology Type in the Facility, excluding Loads;

iii. the System Size;

iv. if the Facility is a Small Aggregation;

v. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from the Facility under optimal conditions, expressed in MW;

vA. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from Non-Intermittent Generating Systems in the Facility under optimal conditions, expressed in MW;

vB. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from Intermittent Generating Systems in the Facility under optimal conditions, expressed in MW;

vC. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply to the relevant Network from Electric Storage Resources in the Facility under optimal conditions, expressed in MW;

vD. the maximum sent out capacity, net of embedded and Parasitic Loads, that can be available for supply across the Electric Storage Resource Obligation Duration to the relevant Network from Electric Storage Resources in the Facility under optimal conditions, expressed in MW;

vi. the maximum Withdrawal capacity of the Facility under optimal conditions, expressed in MW;

vii. the dependence of sent out capacity on temperature at the location of the Facility, if applicable;

viii. details of the fuel or fuels that each Non-Intermittent Generating System in the Facility can use, including dual fuel capabilities and the process for changing fuels;

ix. the minimum dispatchable loading level of the Facility, expressed in sent out MW;

x. the minimum physical response time before the facility can begin to respond to a direction from AEMO to change its output when the Facility is running;

xi. the minimum load at the connection point of the Facility that will automatically trip off if the Facility fails, expressed in MW;

xii. sub-transient, transient and steady state impedances (positive, negative and zero sequence) for the Facility;

xiii. the Standing Maximum Upwards Ramp Rate;

xiv. the Standing Maximum Downwards Ramp Rate;

xv. the emergency upwards ramp rate, if applicable;

xvi. the emergency downwards ramp rate, if applicable;

xvii. the overload Injection capacity of the Facility, if any, expressed in MW;

xviii. the overload Withdrawal capacity of the Facility, if any, expressed in MW;

xix. the short circuit capability of equipment;

xx. evidence that the communication and control systems required by section 2.35 are in place and operational;

xxi. the single line diagram for the, including the locations of transformers, switches, operational and settlement meters;

xxii. the network node or nodes at which the Facility can connect;

xxiii. the Transmission Node Identifier;

xxiv. the National Meter Identifier of each metering point for the Facility, where applicable; and

xxv. the Metering Data Agent for the Facility.

$e$ For an Interruptible Load:

i. evidence that the communication and control systems required by section 2.35 are in place and operational;

ii. details of the real-time telemetry capabilities;

iii. the short circuit capability of Facility equipment;

iv. the single line diagram for the Facility, including the locations of transformers, switches, operational and settlement meters, if applicable;

v. the network nodes at which the Associated Loads of the Facility can connect; and

vi. the Transmission Node Identifier.

$f$ For a Demand Side Programme:

i. the maximum number of hours per day that the Facility will be available to provide Reserve Capacity if issued a Dispatch Instruction;

ii. the Trading Intervals where the Demand Side Programme can be curtailed;

iii. any restrictions on the availability of the Demand Side Programme;

iv. the minimum notice period required for dispatch under clause 7.6.15 of the Facility;

v. evidence that the communication and control systems required by clause 2.35 are in place and operational; and

vi. details of the real-time telemetry capabilities of the Facility.

$g$ For a Market Participant serving Non-Dispatchable Loads containing Intermittent Loads:

i. the identity of the metering points measuring the Intermittent Loads;

ii. for each metering point identified in Appendix 1(g)(i), the maximum allowed level of Intermittent Load;

iii. for each metering point identified in Appendix 1(g)(i), the maximum level of net consumption at that meter which is not separately metered and which is not Intermittent Load; and

iv. for each metering point identified in Appendix 1(g)(i), the separately metered Energy Producing Systems and Loads behind that meter which are not to be included in the definition of that Intermittent Load.

$h$ For each Facility accredited to provide a Frequency Co‑optimised Essential System Service, the Frequency Co-optimised Essential System Service Accreditation Parameters.

$i$ For each Facility accredited for RoCoF Ride-Through Capability, the RoCoF Ride-Through Capability of the Facility determined by AEMO.

Appendix 2: [Blank]

Explanatory Note

This runway calculation does not include Intermittent Loads. Intermittent Loads will be added to the runway calculation in a future tranche of Amending Rules once the registration framework is finalised.

1.1 This Appendix 2A sets out the steps that are to be followed by AEMO in determining TotalRunwayShare(p,DI), being the allocation share of Market Participant p in Dispatch Interval DI for the costs of procuring:

(a) Contingency Reserve Raise (see clause 9.10.30); and

(b) Additional RoCoF Control Requirement component of RoCoF Control Service (see clause 9.10.34)

by use of a "modified runway allocation method" for each Dispatch Interval allocating the share of the costs above to Market Participants based on their Facility Risk (see Glossary) in the Dispatch Interval.

1.2 The cost of procuring Contingency Reserve Raise and Additional RoCoF Control Requirement component of RoCoF Control Service (jointly referred to as the relevant Essential System Service) is allocated to Registered Facilities with a Facility Risk greater than 10MW (see Clause 2.3 of this Appendix 2A).

1.3 The cost of procuring the relevant Essential System Service is split into two components (see clause 5.1 of this Appendix 2A):

(a) A Network Component - this is calculated in clause 5.1(a) of this Appendix 2A:

(i) This component is zero if the Largest Credible Supply Contingency is not set by a Network Contingency. It is also zero if the Largest Network Risk equals the Largest Facility Risk (i.e. a Facility Contingency and Network Contingency are tied as the Largest Credible Supply Contingency).

(ii) This component is non-zero if the Largest Credible Supply Contingency is set by a Network Contingency and is not set by a Facility Contingency as the Largest Credible Supply Contingency. In this case, the share Network Component is calculated as the ratio of

(A) the difference between the Largest Network Risk and the Largest Facility Risk; and

(B) the Largest Network Risk.

(iii) This ensures that causers of Network Contingencies only pay:

(A) when their Network Contingency sets the Contingency Reserve Raise Requirement;

(B) a delta - in that their cost allocation is based on the additional relevant Essential System Service procured as a result of their Network Contingency setting the Contingency Reserve Raise Requirement.

For example, if Largest Network Risk = 300 (set by region A) and Largest Facility Risk = 240 (set by generator X), then the causers of the Region A Network Contingency would pay (300-240)/300 = 20% of the relevant Essential System Service costs in a given Dispatch Interval.

(iv) If two or more Network Contingencies set the Largest Credible Supply contingency, then each tied Network Contingency is allocated an equal share of the Network Component.

For example, if two Network Contingencies were tied with Largest Network Risk = 300 (set by region A and region B) in the example above, then the causers of the each Network Contingency would pay 20%/2 = 10% of the relevant Essential System Service costs in a given Dispatch Interval.

(b) A Facility Component (see clause 5.1(b) of this Appendix 2A) which equals one minus the Network Component calculated above. This component equals 100% if a Facility Contingency sets the Largest Credible Supply Contingency.

1.4 Appendix 2A calculates runway shares for Registered Facilities separately for:

(a) Facilities deemed to be causers of Facility Contingencies (see Section 3 of this Appendix 2A: Applicable Facility Shares, and clause 3.3 of this Appendix 2A, which calculates the runway shares)

(b) Facilities deemed to be causers of Network Contingencies (see Section 4 of this Appendix A: Network Contingency Shares, and clause 4.5 of this Appendix 2A, which calculates the runway shares)

Runway shares are calculated by ranking each Facility’s Facility Risk value, and allocating them a share based on their rank (similar to the calculation in Appendix 2 of the current WEM Rules).

1.5 Once the runway shares above have been calculated, participant cost shares (TotalRunwayShare(p,DI)) are calculated in clause 5.3 of this Appendix 2A by taking into account:

(a) The Facility Component and Network Component ratios calculated in clause 5.1 of this Appendix 2A

(b) The number of Network Contingencies tied as the Largest Credible Supply Contingency (if any) in clause 5.2 of this Appendix 2A

(c) The facility runway shares and the network runway shares calculated in clauses 3.3 and 4.5 of this Appendix 2A respectively.

Appendix 2A is also amended to include unregistered Energy Producing Systems serving Intermittent Loads. If the Market Participant responsible for the Non-Dispatchable Load portion of a Facility containing an Intermittent Load is different from the Market Participant responsible for the Registered Facility component, the runway share will be allocated to:

the Registered Facility when total facility export is greater than the output of any one behind the meter unit; or
the Non-Dispatchable Load when the output of any one behind the meter unit is greater than total Facility export.

Appendix 2A: Runway share calculation method

1. Interpretation and calculation of a Market Participant's Total Runway Share

1.1 Where anything is to be determined, calculated or done in this Appendix 2A, then except where otherwise stated, AEMO will determine, calculate or do, as the case may be, those things.

1.2 AEMO must calculate a Market Participant's total runway share of procuring Contingency Reserve Raise and the Additional RoCoF Requirement component of RoCoF Control Service in Dispatch Interval DI by following each of the steps set out in the rest of this Appendix 2A.

1.3 Each electricity producing unit in an Energy Producing System supplying an Intermittent Load to which clause 2.1(c) of this Appendix 2A applies is treated as a separate Facility for the purposes of this Appendix 2A.

Explanatory Note

In this section we identify which facilities will be included for the purposes of cost allocation.

All Registered Facilities with a Facility Risk value greater than or equal to 10MW in Dispatch Interval DI are included in ApplicableFacilities(DI).

Facilities containing Intermittent Loads may be included as a Registered Facility (if registered), or individual components of the Energy Producing System serving the load. Even where the Facility is registered, it may still be included as individual components if:

an unplanned outage of one or more behind the meter units would result in an increase in withdrawal from the transmission network; or
any one of the behind the meter units is producing more energy than is being exported to the transmission network.

Where a Facility serving an Intermittent Load is registered, but only components are included in ApplicableFacilities(DI), the registered Facility will be included in the set AdditionalApplicableFacilities(DI), so it can be included in the Network Contingency cost recovery in section 4. For example, a Registered Facility injecting 20MW to the transmission network, with a behind the meter unit generating 40MW.

2. Define Facility Sets and Facility Contingencies

2.1 Determine Facilities(DI) as the set of all:

$a$ Scheduled Facilities and Semi-Scheduled Facilities that do not contain an Intermittent Load in Dispatch Interval DI;

$b$ Scheduled Facilities, Semi-Scheduled Facilities, Non-Scheduled Facilities and Non-Dispatchable Loads that contain an Intermittent Load in Dispatch Interval DI, where:

i. in AEMO’s reasonable opinion, the information provided under clause 2.30B.3(g) establishes that if a Contingency Event or an event behind the relevant connection point affects the Energy Producing System supplying the Intermittent Load, the net Injection or Withdrawal of the Facility will change by less than 10 MW; or

ii. the Facility Risk for the Facility in Dispatch Interval DI as published under clause 7.13.1E(g)(i) is greater than the highest instantaneous output (in MW) of any electricity producing unit in the Energy Producing System supplying the Intermittent Load as provided under clause 2.30B.3(h); and

$c$ electricity producing units in Energy Producing Systems supplying Intermittent Loads which are not part of a Facility included in Facilities(DI) under clause 2.1(b) of this Appendix 2A, and for which, in AEMO’s reasonable opinion, the information provided under clause 2.30B.3(g) does not establish that if a Contingency Event or an event behind the relevant connection point affects the Energy Producing System the net Injection or Withdrawal of the Facility will change by less than 10 MW.

2.1A Determine AdditionalIMLFacilities(DI) as the set of all Scheduled Facilities, Semi-Scheduled Facilities, Non-Scheduled Facilities and Non-Dispatchable Loads that contain an Intermittent Load in Dispatch Interval DI and are not included in Facilities(DI).

2.2 For each member in Facilities(DI) or AdditionalIMLFacilities(DI), f, calculate the FacilityRisk(f,DI) to be:

$a$ where f is a member of AdditionalIMLFacilities(DI) or was included in Facilities(DI) under clauses 2.1(a) or 2.1(b) of this Appendix 2A, the Facility Risk for f in Dispatch Interval DI as published under clause 7.13.1E(g)(i); or

$b$ where f was included in Facilities(DI) under clause 2.1(c) of this Appendix 2A, the MWh output or consumption of the electricity producing unit in the Dispatch Interval immediately prior to Dispatch Interval DI as published under clause 7.13.1E(a)(v), multiplied by 12 to convert to MW.

2.3 Determine ApplicableFacilities(DI), which comprises those members f of Facilities(DI) for which:

FacilityRisk(f,DI) ≥ 10MW

2.4 Determine AdditionalApplicableFacilities(DI), which comprises those members f of AdditionalIMLFacilities(DI) for which:

FacilityRisk(f,DI) ≥ 10MW

Explanatory Note

This section calculates the facility runway shares for Facilities deemed to be causers of Facility Contingencies (i.e. all members of ApplicableFacilities(DI)).

Each Facility is ranked in ascending order of their Facility Risk value and allocated a runway share based on that rank.

For example, if we are ranking two facilities:

If Facility A has the highest Facility Risk value (at 250 MW), FacilityMW(rank=2,DI) equals 250 MW.
If Facility B has the lowest Facility Risk value (at 200MW), FacilityMW(rank=1,DI) equals 200MW.
Facility B is allocated: (200-0)/(250*(2+1-1)) = 80%/2 = 40% of the relevant Essential System Service costs
Facility A is allocated: (250-200)/(250*(1+1-1)) + (200-0)/(250*(2+1-1)) = 20% + 40% = 60% of the relevant Essential System Service costs

3. Applicable Facility Shares

3.1 Rank the Facilities in the set ApplicableFacilities(DI) in Dispatch Interval DI in the ascending order of the value of FacilityRisk(f,DI) as determined in clause 2.2 of this Appendix 2A. If two or more Facilities in that set have the same FacilityRisk(f,DI) value, AEMO shall rank those Facilities, as between each other, in ascending alphabetical order of the name of the Facilities recorded by AEMO in accordance with clause 2.34B.1(f). The Facility with the lowest FacilityRisk(f,DI) value will have rank(f, DI) = 1, and the Facility with the highest FacilityRisk(f,DI) value will have rank(f, DI) = n, where n is the number of Facilities in the set ApplicableFacilities(DI).

3.2 Calculate LargestFacilityRisk(DI), which is the FacilityRisk(f,DI) of the Facility which has the rank(f,DI) = n as determined in clause 3.1 of this Appendix 2A.

3.3 Determine for each Registered Facility f, its runway share of the FacilityComponent(DI) ) of procuring Contingency Reserve Raise and the Additional RoCoF Control Requirement of RoCoF Control Service as follows:

\[\text{FacilityRunwayShare}\left( \text{f,DI} \right)\text{=}\sum\_{\text{i=1}}^{\text{Rank}\left( \text{f,DI} \right)}\frac{\text{FacilityMW}\left( \text{i,DI} \right)\\ - \text{\\FacilityMW}\left( \text{i\\} - \text{1,\\DI} \right)}{\text{FacilityMW}\left( \text{n,DI} \right)\text{\\×\\}\left( \text{n\\+\\1} - \text{i} \right)}\]

where:

$a$ FacilityMW(i,DI) is the FacilityRisk(x,DI) value of Facility x with rank(x,DI) = i in Dispatch Interval DI, where FacilityMW(0,DI)=0, and x∈ApplicableFacilities(DI);

$b$ Rank(f,DI) is the rank of Facility f in Dispatch Interval DI as determined in clause 3.1 of this Appendix 2A; and

$c$ n is the number of Facilities in the set ApplicableFacilities(DI) in Dispatch Interval DI.

Explanatory Note

This section calculates the Network Contingency runway shares for Registered Facilities deemed to be causers of Network Contingencies.

We define sets to denote:

Applicable Network Contingencies whose causers we want to recover costs from (ApplicableNetworkContingencies(DI))
For each member of ApplicableNetworkContingencies(DI) (denoted by nc), we define the set of Registered Facilities to be the causers of that Network Contingency as CauserFacilities(nc, DI)

Each Registered Facility that is a member of CauserFacilities(nc, DI) is ranked in ascending order of their Facility Risk value and allocated a runway share based on that rank (for Network Contingency nc). Membership of CauserFacilities(nc,DI) is restricted to registered Facilities, as behind the meter components serving Intermittent Loads are not relevant for network risks, which are set basd on the net generation lost if the network trip occurred.

4. Network Contingency Shares

4.1 Determine NetworkContingencies(DI), which is the set of Network Contingencies that are taken into account when setting the Contingency Reserve Raise requirement under clause 7.2.4 in Dispatch Interval DI.

4.2 For each member in NetworkContingencies(DI), nc, calculate NetworkRisk(nc,DI) in Dispatch Interval DI as follows:

$a$ NetworkRisk(nc,DI) equals the Network Risk in Dispatch Interval DI as published by AEMO in clause 7.13.1E(g)(ii)(1), if nc sets the Largest Credible Supply Contingency in Dispatch Interval DI; and

$b$ NetworkRisk(nc,DI) = 0 otherwise.

4.3 Determine ApplicableNetworkContingencies(DI), which comprises those members nc of NetworkContingencies(DI) for which:

NetworkRisk(nc,DI) > 0MW

4.4 Calculate m(DI), as the number of members of ApplicableNetworkContingencies(DI).

4.5 For each member in ApplicableNetworkContingencies(DI), nc, perform the following steps:

$a$ from the information published under clause 7.13.1E(g)(ii), determine the set of Registered Facilities whose Facility Risks are included in the Network Risk associated with Network Contingency nc as CauserFacilities(nc,DI), where CauserFacilities(nc,DI) is a subset of the union of ApplicableFacilities(DI) and AdditionalApplicableFacilities(DI) as defined in clauses 2.3 and 2.4 of this Appendix 2A;

$b$ rank the Registered Facilities in CauserFacilities(nc,DI) in the ascending order of the value of FacilityRisk(f,DI) as determined in clause 2.2 of this Appendix 2A. If two or more Registered Facilities in CauserFacilities(nc,DI) have the same FacilityRisk(f,DI) value in Dispatch Interval DI, AEMO shall rank those Registered Facilities, as between each other, in ascending alphabetical order of the name of the Registered Facility recorded by AEMO in accordance with clause 2.34B.1(f). The Registered Facility with the lowest FacilityRisk(f,DI) value will have rank(nc,f,DI) = 1, and the Registered Facility with the highest FacilityRisk(f,DI) value will have a rank(nc,f,DI) = n_nc, where n_nc is the number of Registered Facilities in the set CauserFacilities(nc,DI); and

$c$ determine for each Registered Facility f, which is a member of CauserFacilities(nc,DI), its runway share of the Network Contingency component (attributable to Network Contingency nc) of procuring Contingency Reserve Raise and the Additional RoCoF Control Requirement component of RoCoF Control Service in Dispatch Interval DI as follows:

NetworkRunwayShare(nc,f,DI)=

\[\sum\_{\text{i=1}}^{\text{Rank}\left( \text{nc,f,DI} \right)}\frac{\text{NetworkMW}\left( \text{nc,i,DI} \right) - \text{NetworkMW}\left( \text{nc,i} - \text{1,DI} \right)}{\text{NetworkMW}\left( \text{nc,}\text{n}\_{\text{nc}}\text{,DI} \right)\text{\\×\\}\left( \text{n}\_{\text{nc\\}}\text{+\\1} - \text{i} \right)}\]

where:

i. NetworkMW(nc,i,DI) is the FacilityRisk(x,DI) value of Registered Facility x with rank(nc,x,DI) = i in Dispatch Interval DI, where NetworkMW(nc,0,DI) =0, and x∈CauserFacilities(nc,DI);

ii. Rank(nc,f,DI) is the rank of Registered Facility f∈CauserFacilities(nc,DI) as determined in clause 4.5(b) of this Appendix 2A; and

iii. n_nc is the number of Registered Facilities in the set CauserFacilities(nc,DI) as determined in clause 4.5(b) of this Appendix 2A.

5. Cost Shares

Explanatory Note

This clause divides the cost of the relevant Essential System Services into a:

component attributable to Network Contingencies (NetworkComponent(DI))
component attributable to Facility Contingencies (FacilityComponent(DI))

5.1 Calculate the cost shares associated with the Network Contingency and Facility Contingency components of procuring Contingency Reserve Raise and the Additional RoCoF Control Requirement of RoCoF Control Service as follows:

$a$ calculate the cost share associated with the Network Contingency component in Dispatch Interval DI as follows:

NetworkComponent(DI) =

\[\frac{\text{Max}\left( \text{0,LargestNetworkRisk}\left( \text{DI} \right) - \text{LargestFacilityRisk}\left( \text{DI} \right) \right)}{\text{LargestNetworkRisk}\\\left( \text{DI} \right)}\]

where:

i. LargestNetworkRisk(DI) is the Largest Network Risk in Dispatch Interval DI; and

ii. LargestFacilityRisk(DI) is the largest Facility Risk in Dispatch Interval DI as calculated in clause 3.2 of this Appendix 2A; and

$b$ calculate the cost share associated with the Facility Contingency component in Dispatch Interval DI as follows:

FacilityComponent(DI) = 1 − NetworkComponent(DI)

Explanatory Note

This clause accounts for multiple Network Contingencies being tied as the Largest Credible Supply Contingency by dividing each causer Registered Facility’s network runway share (for a given Network Contingency) by the total number of tied Network Contingencies.

5.2 Determine for each Registered Facility f associated with each Applicable Network Contingency nc its cost share of procuring the Network Contingency component of Contingency Reserve Raise and the Additional RoCoF Control Requirement of RoCoF Control Service (attributable to Network Contingency nc) in Dispatch Interval DI as follows:

\[NetworkShare(nc,f,DI) = \frac{1}{m(DI)} \times NetworkRunwayShare(nc,f,DI)\]

where:

$a$ m(DI) is determined in clause 4.4 of this Appendix 2A; and

$b$ NetworkRunwayShare(nc, f, DI) is determined in clause 4.5(c) of this Appendix 2A.

Explanatory Note

Finally, participant cost shares (TotalRunwayShare(p,DI)) are calculated in this clause taking into account:

the Registered Facility Component and Network Component ratios calculated in clause 5.1 of this Appendix 2A; and
The facility runway shares and the network runway shares calculated in clauses 3.3 of this Appendix 2A and 4.5 of this Appendix 2A respectively.

Clause 5.3(b) is amended to redefine the NetworkRunwayShare(nc,f,DI) variable as NetworkShare(nc,f,DI).

5.3 Determine Market Participant p’s total runway share of procuring Contingency Reserve Raise and the Additional RoCoF Requirement component of RoCoF Control Service in Dispatch Interval DI as follows:

TotalRunwayShare(p,DI) = FacilityComponentShare(p,DI) +

NetworkComponentShare(p,DI)

where:

$a$ FacilityComponentShare(p,DI) is calculated as follows:

FacilityComponentShare(p,DI)=FacilityComponent(DI)×

\[\sum\_{\text{f}\text{∈}\text{ApplicableFacilities}\left( \text{p,DI} \right)}^{}{\text{FacilityRunwayShare}\left( \text{f,DI} \right)}\]

where:

i. FacilityComponent(DI) is the cost share associated with the Facility Contingency component of procuring Contingency Reserve Raise and the Additional RoCoF Requirement component of RoCoF Control Service in Dispatch Interval DI calculated in clause 5.1(b) of this Appendix 2A;

ii. ApplicableFacilities(p,DI) is a subset of ApplicableFacilities(DI) defined in clause 2.3 of this Appendix 2A, which denotes Registered Facilities in ApplicableFacilities(DI) which are registered to Market Participant p and electricity producing units in ApplicableFacilities(DI) which are in Energy Producing Systems supplying Intermittent Loads for which Market Participant p is responsible; and

iii. FacilityRunwayShare(f,DI) is Facility f’s runway share of the Facility Contingency component of procuring Contingency Reserve Raise and the Additional RoCoF Control Requirement component of RoCoF Control Service in Dispatch Interval DI as calculated in clause 3.3 of this Appendix 2A; and

$b$ NetworkComponentShare(p,DI) is calculated as follows:

NetworkComponentShare(p,DI) = NetworkComponent(DI) ×

\[\sum\_{\text{nc}\text{∈}\text{ApplicableNetworkContingencies(DI)}}^{}{\sum\_{\text{f}\text{∈}\text{CauserFacilities(nc,p,DI)}}^{}\text{NetworkShare(nc,f,DI)}}\]

where:

i. NetworkComponent(DI) is the cost share associated with the Network Contingency component of procuring Contingency Reserve Raise and the Additional RoCoF Requirement component of RoCoF Control Service in Dispatch Interval DI calculated in clause 5.1(a) of this Appendix 2A;

ii. ApplicableNetworkContingencies(DI) is the subset of Network Contingencies determined in clause 4.3 of this Appendix 2A;

iii. CauserFacilities(nc,p,DI) is a subset of CauserFacilities(nc,DI) identified in clause 4.5(a) of this Appendix 2A, which denotes Registered Facilities in CauserFacilities(nc,DI) registered to Market Participant p; and

iv. NetworkShare(nc,f,DI) is Registered Facility f’s cost share associated with Network Contingency nc in Dispatch Interval DI as calculated in clause 5.2 of this Appendix 2A.

Explanatory Note

1.1 The Minimum RoCoF Control Requirement component of the RoCoF Control Service costs (abbreviated to RoCoF cost in this section) in a Trading Interval are to be shared across three causer groups in equal shares:

(a) Network Causer group: Network Operators (this group has one member only);

(b) Injection Causer group: Registered Facilities with generation systems or storage systems (i.e. energy producing systems); and

(c) Offtake Causer group: Non-Dispatchable Loads and Registered Facilities comprising only Scheduled Loads (end-users).

1.2 Members of each group can exempt themselves by indicating to AEMO that the RoCoF Ridethrough Capability of their facilities are greater than or equal to the RoCoF Safe Limit.

1.3 The RoCoF costs will be allocated to those causers who cannot exempt themselves.

1.4 If all facilities in a causer set are exempt then the RoCoF cost is allocated equally to the remaining sets. This is represented by the parameter (1/n(t)) in clause 2.4 in this Appendix 2B.

1.5 A Registered Facility which is able to inject (i.e. generate energy) is only included in the Injection Causer group if it does not have an exemption and has a non-zero metered schedule in the given trading interval. The cost share of injectors who are causers will be based on their share of Injection/Withdrawal during the Trading Interval.

1.6 Loads are deemed to be Non-Dispatchable Loads who are served by a retailer or Registered Facilities comprising only Scheduled Loads. These Load facilities are only included in the Offtake Causer group if they do not have an exemption and have a non-zero metered schedule in the given trading interval. It is expected that the Retailer would indicate to AEMO whether their loads have a RoCoF Ridethrough Capability greater than or equal to the RoCoF Safe Limit. The cost share of Load facilities who are causers will also be based on their share of Injection/Withdrawal during the Trading Interval.

Appendix 2B: Minimum RoCoF Control Service cost recovery method

1. Interpretation

1.1 Where anything is to be determined, calculated or done in this Appendix 2B, then except where otherwise stated, AEMO will determine, calculate or do, as the case may be, those things.

2. Cost recovery calculations for Minimum RoCoF Control Requirement

2.1 AEMO must calculate a Rule Participant’s share of the Minimum RoCoF Control Requirement component of the RoCoF Control Service cost in Trading Interval t by following each of the steps set out in the rest of this Appendix 2B.

Explanatory Note

Injection Causer: These are generators whose RoCoF ridethrough capability is lower than the RoCoF Safe Limit. As per above, the expectation is that most generators will be able to exempt themselves by indicating a high RoCoF ridethrough capability. Transitional rules will be drafted outlining a process for Market Participants to demonstrate their ride-through capability.

Note that a battery is deemed an Injection Causer and not an Offtake Causer.

Offtake Causer: Loads that are unable to demonstrate their ride-through capability will be captured in this group. Transitional rules will be drafted outlining a process for Market Participants to demonstrate their ride-through capability. This group will likely comprise of Non-Dispatchable Loads that are unable to demonstrate ride-through against the RoCoF Safe Limit.

A given facility can only be a member of one Causer Group. That is, facilities would not change between causer groups depending on whether they are injecting or consuming. Causer Group membership is determined by the type of facility (in terms of equipment, technical characteristics, etc.) as opposed to whether the facility is generating or consuming.

A clause X will be inserted (likely in standing data) dealing with RoCoF exemption by the registration or transition rules workstream at a later time. This clause would be tied to the relevant causer’s RoCoF ridethrough capability vis a vis the RoCoF Safe Limit; in that if the ride-through capability is greater than or equal to the safe limit, the facility is exempt from paying the Minimum RoCoF Control Requirement component of RoCoF Control Service cost.

Clause 2.2(c) is amended to reflect the revised registration taxonomy.

Clause 2.2 is further amended to:

reflect that Western Power is the only Network Operator who may be required to pay for the cost of Minimum RoCoF Control Service;
to give effect to the intent that every a facility cannot change between being an Injection Causer and an Offtake Causer; and
improve consistency and readability of the drafting.

2.2 For each Trading Interval t, define the set of RoCoF Causers(t), being each of:

$a$ Network Causer(t): the set of Networks registered to Western Power which are RoCoF Causers under clause 2.34A.12J in Trading Interval t;

$b$ Injection Causer(t): the set of Scheduled Facilities, Semi-Scheduled Facilities or Non-Scheduled Facilities that are recorded in Standing Data as including an Energy Producing System, which have a non-zero Metered Schedule in Trading Interval t and which are RoCoF Causers under clause 2.34A.12J in Trading Interval t; and

$c$ Offtake Causer(t): the set of:

i. all Scheduled Facilities, Semi-Scheduled Facilities or Non-Scheduled Facilities which comprise only Loads; and

ii. all Non-Dispatchable Loads (including Synergy’s Notional Wholesale Meter where Synergy is the Market Participant),

which have non-zero Metered Schedules in Trading Interval t and which are RoCoF Causers under clause 2.34A.12J in Trading Interval t.

Explanatory Note

The following two clauses calculate the number of RoCoF Causer sub-sets are to be allocated a portion of the Minimum RoCoF Control Requirement component of RoCoF Control Service cost.

2.3 For each Trading Interval t, define a Causer Factor for each subset of RoCoF Causers(t) as follows:

$a$ $\text{NetworkCauserFactor}\left( \text{t} \right)\text{\\=}\left\\ \begin{array}{r} \text{0\\if\\the\\Network\\Causer}\left( \text{t} \right)\text{\\subset\\is\\empty} \\ \text{1~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~\\otherwise} \\ \end{array} \right.\\$;

$b$ $\text{InjectionCauserFactor}\left( \text{t} \right)\text{\\=}\left\\ \begin{array}{r} \text{0\\if\\the\\Injection\\Causer}\left( \text{t} \right)\text{\\subset\\is\\empty} \\ \text{1~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~\\otherwise} \\ \end{array} \right.\\$; and

$c$ $\text{OfftakeCauserFactor}\left( \text{t} \right)\text{\\=}\left\\ \begin{array}{r} \text{0\\if\\the\\Offtake\\Causer}\left( \text{t} \right)\text{\\subset\\is\\empty} \\ \text{1~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~\\otherwise} \\ \end{array} \right.\\$

2.4 Determine the total number of causer groups n(t) in Trading Interval t as follows:

n(t) = NetworkCauserFactor(t) + InjectionCauserFactor(t) + OfftakeCauserFactor(t)

where:

$a$ NetworkCauserFactor(t) is the Causer Factor for the subset Network Causer(t) in Trading Interval t as calculated in clause 2.3(a) of this Appendix 2B.

$b$ InjectionCauserFactor(t) is the Causer Factor for the subset Injection Causer(t) in Trading Interval t as calculated in clause 2.3(b) of this Appendix 2B.

$c$ OfftakeCauserFactor(t) is the Causer Factor for the subset Offtake Causer(t) in Trading Interval t as calculated in clause 2.3(c) of this Appendix 2B.

Explanatory Note

Western Power (as Network Operator) will be allocated a 1/n(t) share of the cost if its network does not exempt itself by demonstrating for all of its Network that the RoCoF Ride Through Capability of its Network is greater than or equal to the RoCoF Safe Limit. If it does meet the standard, its cost share must be zero.

Clause 2.5 is further amended to:

reflect that Western Power is the only Network Operator who may be required to pay for the cost of Minimum RoCoF Control Service; and
improve consistency and readability of the drafting.

2.5 Determine Western Power’s share of the Minimum RoCoF Control Requirement component of the RoCoF Control Service cost in Trading Interval t as follows:

\[\text{WPShare(t)\\=\\}\frac{\text{1}}{\text{n}\left( \text{t} \right)}\text{×\\NetworkCauserFactor}\left( \text{t} \right)\]

where:

$a$ NetworkCauserFactor(t) is the Causer Factor for the subset Network Causer(t) in Trading Interval t as calculated in clause 2.3(a) of this Appendix 2B; and

$b$ n(t) is the total number of causer groups in Trading Interval t as calculated in clause 2.4 of this Appendix 2B.

Explanatory Note

All Registered Facilities with energy producing systems with RoCoF Ridethrough Capability lower than the RoCoF Safe Limit will be allocated a 1/n(t) share of the cost. A given Registered Facility’s share of the 1/n share will be based on their share of the generation/consumption in the relevant Trading Interval as denoted by the absolute value of its Metered Schedules.

The intent here is to charge a generator/injector who is a causer when they are injecting and off taking.

2.6 For each Registered Facility, f, which is a member of Injection Causer(t), determine its share of the Minimum RoCoF Control Requirement component of RoCoF Control Service cost in Trading Interval t as follows:

InjectionShare(f,t) =

\[\frac{\text{1}}{\text{n}\left( \text{t} \right)}\text{×\\InjectionCauserFactor}\left( \text{t} \right)\text{\\×\\}\frac{\left| \text{MeteredSchedule}\left( \text{f,t} \right) \right|}{\sum\_{\text{i}\text{∈}\text{InjectionCauser}\left( \text{t} \right)}^{}\left| \text{MeteredSchedule}\left( \text{i,t} \right) \right|}\]

where:

$a$ n(t) is the total number of causer groups in Trading Interval t as calculated in clause 2.4 of this Appendix 2B;

$b$ InjectionCauserFactor(t) is the Causer Factor for the subset Injection Causer(t) in Trading Interval t as calculated in clause 2.3(b) of this Appendix 2B;

$c$ MeteredSchedule(f,t) is the value of the Metered Schedule for Registered Facility f which is a member of the subset Injection Causer(t), such subset as defined in clause 2.2(b) of this Appendix 2B, in Trading Interval t;

$d$ i∈InjectionCauser(t) denotes all Registered Facilities in the subset Injection Causer(t), such subset as defined in clause 2.2(b) of this Appendix 2B, in Trading Interval t; and

$e$ MeteredSchedule(i,t) is the value of the Metered Schedule for Registered Facility i in the subset Injection Causer(t), such subset as defined in clause 2.2(b) of this Appendix 2B, in Trading Interval t.

Explanatory Note

Loads are charged a 1/n(t) share of the cost in proportion to their share of generation/consumption in the relevant Trading Interval as denoted by the absolute value of their Metered Schedules.

2.7 For each facility that is a member of Offtake Causer(t), determine in Trading Interval t:

OfftakeShare(l,t) =

\[\frac{\text{1}}{\text{n}\left( \text{t} \right)}\text{×\\OfftakeCauserFactor}\left( \text{t} \right)\text{\\×\\}\frac{\left| \text{MeteredSchedule}\left( \text{l,t} \right) \right|}{\sum\_{\text{i}\text{∈}\text{OfftakeCauser}\left( \text{t} \right)}^{}\left| \text{MeteredSchedule}\left( \text{i,t} \right) \right|}\]

where:

$a$ n(t) is the total number of causer groups in Trading Interval t as calculated in clause 2.4 of this Appendix 2B.

$b$ OfftakeCauserFactor(t) is the Causer Factor for the subset Offtake Causer(t) in Trading Interval t as calculated in clause 2.3(c) of this Appendix 2B.

$c$ MeteredSchedule(l,t) is the value of the Metered Schedule for member l of the subset Offtake Causer(t), such subset as defined in clause 2.2(c) of this Appendix 2B in Trading Interval t;

$d$ i∈OfftakeCauser(t) denotes all members of the subset Offtake Causer(t), as defined in clause 2.2(c) of this Appendix 2B in Trading Interval t; and

$e$ MeteredSchedule(i,t) is the value of the Metered Schedules for a member i of the subset Offtake Causer(t), such subset as defined in clause 2.2(c) of this Appendix 2B in Trading Interval t.

Explanatory Note

Rule Participant p’s share of the Minimum RoCoF Control Requirement component of the RoCoF Control Service cost is the sum of the shares over all its facilities (covering both injection and offtake).

2.8 Determine Rule Participant p’s share of Minimum RoCoF Control Requirement component of RoCoF Control Service cost in Trading Interval t as follows:

\[\text{MinRCSShare}\left( \text{p,t} \right)\text{\\=}\sum\_{\text{f}\text{∈}\text{p}}^{}{\text{InjectionShare}\left( \text{f,t} \right)}\text{+}\sum\_{\text{l}\text{∈}\text{p}}^{}{\text{OfftakeShare}\left( \text{l,t} \right)\text{\\+\\NOShare}\left( \text{p,t} \right)}\]

where:

$a$ InjectionShare(f,t) is, for each Registered Facility which is a member of Injection Causer(t), the Registered Facility f’s share of the Minimum RoCoF Control Requirement component of the RoCoF Control Service cost in Trading Interval t as calculated in clause 2.6 of this Appendix 2B;

$b$ f∈p denotes all Registered Facilities which are a member of Injection Causer(t) and registered to Rule Participant p;

$c$ OfftakeShare(l,t) is the share of the Minimum RoCoF Control Requirement component of the RoCoF Control Service cost in Trading Interval t for each facility which is a member of Offtake Causer(t), as calculated in clause 2.7 of this Appendix 2B;

$d$ l∈p denotes all facilities which are members of Offtake Causer(t) and associated with Rule Participant p; and

$e$ NOShare(p,t) is, for Western Power, WPShare(t), as calculated in clause 2.5 of this Appendix 2B, and for all other Rule Participants, zero.

.

Explanatory Note

A Market Participant who fails to make their capacity available for ESS (under a SESSM Award with a non-zero Availability Payment) must pay a refund. This means a Market Participant who has been awarded a SESSM with a zero Availability Payment (i.e. an award made to an existing Facility in response to a trigger for inefficient market outcomes), will pay no refunds if they fail to offer the required Availability Quantity.
The refund is levied on the amount of capacity not made available; for example if a facility was supposed to provide 50 MW, and only provided 20 MW, then the refund will be charged on the 30 MW that was not provided.
The refund itself is a product of the capacity not made available, the Per-Dispatch Interval Availability Payment and a refund factor which equals 3.

If the refund factor equalled 1 then the Market Participant would refund exactly what they were paid as part of ESS Settlement.
To incentivise a Market Participant to make their facility available, the refund factor has been set to a value greater than 1

The methodology uses a concept similar to the Refund Exempt Outage Count used in the Reserve Capacity Refund calculations to take into account the fact that a SESSM Award will specify a SESSM Minimum Availability Requirement (in %). This SESSM Minimum Availability Requirement implies that there is a maximum number of Dispatch Intervals for a SESSM Award during which a Market Participant can be less than fully available.
Additionally, refunds are capped so that AEMO never recovers from a Market Participant more than the maximum that a participant could potentially have been paid under a given SESSM Award over the SESSM Service Timing (given the relevant SESSM Minimum Availability Requirement).

For more information, see Section 3.15A which defines many of the terms used below, and also facilitates interpretation of the various quantities introduced.

Appendix 2C is amended to reflect the changes made to SESSM Award holder obligations under clause 7.4.5.

Other minor changes have been made to the appendix to:

add missing variable definitions and remove an unused variable definition;
correct typographical errors; and
apply standard formatting and clause numbering conventions.

Appendix 2C: SESSM refund calculation method

1. Interpretation

1.1 Where anything is to be determined, calculated or done in this Appendix 2C, then except where otherwise stated, AEMO will determine, calculate or do, as the case may be, those things.

2. Supplementary Essential System Service Mechanism refund calculation methodology

2.1 AEMO must calculate the refund payable by a Market Participant in respect of their Registered Facility for not meeting the SESSM Availability Requirements set out in the relevant SESSM Awards by following each of the steps set out in the rest of this Appendix 2C.

Explanatory Note

This section defines the various availability parameters that form part of a SESSM Award. These parameters are defined in the Glossary.

Where AEMO has made a SESSM Award a (to a Market Participant in respect of a Facility to provide a Frequency Co-optimised Essential System Service (FCESS)):

The BaseQuantity(a,DI) or the Base ESS Quantity, denotes the MW or MWs quantity of Essential System Service the Facility was already accredited for at the time of making the SESSM Submission that resulted in award a. The Base Quantity can be different in different Dispatch Intervals. For example:

Facility X has been accredited for 25MW of Contingency Reserve Raise (with no SESSM triggered). A SESSM is triggered and Facility X has now been awarded an Availability Quantity of 15 MW in all Dispatch Intervals (under award a). The Base ESS Quantity or Base Quantity(a, DI) = 25MW.
Facility Y is a new Facility, and is applying under a SESSM to provide FCESS. Y is awarded an Availability Quantity of 10MW in all Dispatch Intervals, under award a1. The Base Quantity(a, DI) = 0 MW for all Dispatch Intervals (because it was not accredited previously). At a later stage, it undergoes an upgrade, and under SESSM Award a2, it is awarded an additional Availability Quantity (over and above a1) of 5MW in all Dispatch Intervals. Base Quantity(a2,DI) = 10 MW, which is the maximum that Y was accredited for under award a1 (at the time they were awarded a2).

The AvailabilityQuantity(a,DI) or Availability Quantity, denotes the MW or MWs quantity of the ESS the Facility must offer in addition to the Base ESS Quantity in a given Dispatch in at least MinAvailability(a)% (see below) of the time during the SESSM Service Timing. The Availability Quantity can be different in different Dispatch Intervals. The Market Participant must offer the sum of the relevant Availability Quantity and Base ESS Quantity (for a given SESSM Award a):

In the example above, Facility X, must offer 25MW (Base ESS Quantity) + 15MW (Availability Quantity) = 40 MW in all Dispatch Intervals

In the second example, above:

 Under award a1, Y must provide offer 0MW (Base ESS Quantity) + 10MW (Availability Quantity) = 10 MW in all Dispatch Intervals.

 Under award a2, Y must provide offer 10MW (Base ESS Quantity) + 5MW (Availability Quantity) = 15 MW in all Dispatch Intervals

The AvailabilityPayment(a,DI) or Per-Dispatch Interval Availability Payment, is the price per Dispatch Interval that the Market Participant will be paid for offering the Availability Quantity in a given Dispatch Interval. The Availability Payment is zero in intervals where the Availability Quantity is zero, and is a flat $/Dispatch Interval figure in Dispatch Intervals where Availability Quantity is non-zero.
MinAvailability(a) or SESSM Minimum Availability Requirement, denotes the % of relevant Dispatch Intervals that the Market Participant must make the sum of the AvailabilityQuantity(a,DI) and BaseQuantity(a,DI) available (i.e. the Market Participant must make all of that quantity available at least MinAvailability % of the applicable Dispatch Intervals).

2.2 Where AEMO has made a SESSM Award a in respect of a Registered Facility to provide a specific Frequency Co-optimised Essential System Service, that award specifies the following terms (which terms are applicable to the rest of this Appendix 2C):

$a$ the BaseQuantity(a,DI), which is the Base ESS Quantity for SESSM Award a in Dispatch Interval DI;

$b$ the AvailabilityQuantity(a,DI), which is the SESSM Availability Quantity for SESSM Award a in Dispatch Interval DI ;

$c$ the AvailabilityPayment(a,DI), which is:

i. the Per-Dispatch Interval Availability Payment for SESSM Award a in Dispatch Interval DI if AvailabilityQuantity(a,DI) is greater than zero; or

ii. if otherwise, zero; and

$d$ MinAvailability(a), which is the SESSM Availability Requirement for SESSM Award a.

Explanatory Note

Clause 2.3 of this Appendix 2C determines MaxUnavailability(a) or the maximum number of Dispatch Intervals for a SESSM Award (a) during which a Market Participant can be less than fully available

Clause 2.4 of this Appendix 2C determines PaymentCap(a) or the maximum that a Market Participant could potentially been paid under a given SESSM Award over the SESSM Service Timing (given the relevant SESSM Minimum Availability Requirement).

2.3 For each Registered Facility that is providing a Frequency Co-optimised Essential System Service under a SESSM Award a, and for the duration of that SESSM Award a:

$a$ determine N(a) to be the number of Dispatch Intervals in the SESSM Service Timing where AvailabilityQuantity(a,DI) is greater than zero;

$b$ determine the maximum number of Dispatch Intervals for which the Registered Facility providing a Frequency Co-optimised Essential System Service under SESSM Award a may be unavailable during the SESSM Service Timing, as follows:

MaxUnavailability(a) = FLOOR(N(a) × (1−MinAvailability(a)))

where:

i. the FLOOR() function rounds any non-integer figure down to the nearest integer; and

ii. MinAvailability(a) is the percentage determined under clause 2.2(d) of this Appendix 2C; and

$c$ determine the total SESSM Availability Payments that would be made over the SESSM Service Timing if it met its SESSM Availability Requirement under SESSM Award a:

\[\text{PaymentCap}\left( \text{a} \right)\text{\\=}\sum\_{\text{DI}\text{∈}\text{a}}^{}{\text{AvailabilityPayment}\left( \text{a,DI} \right)}\]

where:

i. DI∈a denotes all Dispatch Intervals in the SESSM Service Timing; and

ii. AvailabilityPayment(a,DI) is the quantity determined under clause 2.2(c) of this Appendix 2C.

Explanatory Note

AEMO must determine whether or not a Facility under a SESSM Award has made their capacity available in a given Dispatch Interval. As noted above, a Market Participant must offer the sum of the relevant Availability Quantity and Base ESS Quantity (for a given SESSM Award a).

The calculation of the effective FCESS offer quantity for a Facility subject to a SESSM Award in a Dispatch Interval (ESSOffer(f,c,DI)) is amended to reflect the proposed changes to SESSM Award holder obligations under clause 7.4.5. Under the revised drafting:

by default, ESSOffer(f,c,DI) is equal to the total quantity offered by the Market Participant for Facility f and FCESS c in Dispatch Interval DI in its Real-Time Market Submission (clause 2.4(a));
however, AEMO may estimate a lower quantity if the Facility is subject to an Outage during the Dispatch Interval and AEMO considers the quantities in the Real-Time Market Submission did not accurately reflect the actual capability of the Facility during that Dispatch Interval; and
if the Market Participant fails to meet its obligations under new clause 7.4.5(c), i.e. it does not update its Real-Time Market Submission to offer FCESS capacity that is projected to be required as In-Service Capacity, then AEMO will set ESSOffer(f,c,DI) to its reasonable estimate of the actual In-Service capability of the Facility in the Dispatch Interval.

2.4 For each Dispatch Interval DI determine whether a Registered Facility f was available (in respect of its obligations under SESSM Award a to provide Frequency Co-optimised Essential System Service c):

\[\text{IsAvailable(a,DI)\\=}\left\\ \begin{array}{r} \text{1\\if\\ESSOffer}\left( \text{f,c,DI} \right)\text{\\≥\\(BaseQuantity(a,DI)\\+\\AvailabilityQuantity(a,DI))\\} \\ \text{or\\AvailabilityQuantity}\left( \text{a,DI} \right)\text{\\=\\0,} \\ \text{0\\otherwise} \\ \end{array} \right.\\\]

where:

$a$ ESSOffer(f,c,DI) is:

i. the sum of the quantities offered in the relevant Market Participant’s Real-Time Market Submission in respect of Registered Facility f to provide Frequency Co-optimised Essential System Service c in Dispatch Interval DI; or

ii. if:

1. Registered Facility f is subject to a Planned Outage or a Forced Outage in Dispatch Interval DI; and

2. in AEMO’s view, the sum of the quantities offered in the relevant Market Participant’s Real-Time Market Submission in respect of Registered Facility f does not accurately reflect the Facility’s capability to provide Frequency Co-optimised Essential System Service c in Dispatch Interval DI,

then, AEMO’s reasonable estimate of Registered Facility f’s capability in MW or MWs, as the case may be, to provide Frequency Co-optimised Essential System Service c in Dispatch Interval DI, if that quantity is lower than the quantity specified in clause 2.4(a)(i) of this Appendix 2C; or

iii. if the relevant Real-Time Market Submission:

1. did not present the relevant Essential System Service Enablement Quantity as In-Service Capacity in accordance with clause 7.4.5(c)(i); or

2. did not offer sufficient capacity as In-Service for energy to allow the Registered Facility to be dispatched for energy between its enablement limits in accordance with clause 7.4.5(c)(ii),

then AEMO’s reasonable estimate of Registered Facility f’s capability in MW or MWs, as applicable, that was In-Service Capacity in respect of Frequency Co-optimised Essential System Service c in Dispatch Interval DI, if that quantity is lower than the quantities specified in clauses 2.4(a)(i) or (if applicable) 2.4(a)(ii) of this Appendix 2C;

$b$ BaseQuantity(a,DI) is the quantity determined under clause 2.2(a) of this Appendix 2C; and

$c$ AvailabilityQuantity(a,DI) is the quantity determined under clause 2.2(b) of this Appendix 2C.

Explanatory Note

AEMO must calculate the cumulative number of Dispatch Intervals (since the start of the SESSM Service Timing) that the relevant facility has not been available for (denoted SESSMOutageCount(a,DI)).

2.5 Calculate the number of Dispatch Intervals the Registered Facility providing Frequency Co-optimised Essential System Services under SESSM Award a has been unavailable for, from the first Dispatch Interval in the SESSM Service Timing up to and including Dispatch Interval DI:

\[\text{SESSMOutageCount}\left( \text{a,}\text{DI} \right)\text{=}\sum\_{\text{i=1}}^{\text{DI}}\left( \text{1} - \text{IsAvailable}\left( \text{a,i} \right) \right)\]

where:

$a$ IsAvailable(a,i) means Registered Facility was available in respect of its obligations under SESSM Award a to provide Frequency Co-optimised Essential System Service c in Dispatch Interval i; and

$b$ i is a Dispatch Interval in the SESSM Service Timing.

Explanatory Note

The refund (SESSMRefund(a,DI)) is a product of the capacity not made available, the Per-Dispatch Interval Availability Payment and a refund factor. The calculations takes the following into account:

SESSMOutageCount(a,DI)) (see clause 2.5 of this Appendix 2C) has to be greater than MaxUnavailability (a) (see clause 2.3(b) of this Appendix 2C), before the Market Participant starts paying refunds.
The refund is levied on the amount of capacity not made available.
Refunds are capped so that AEMO never recovers from a Market Participant more than the maximum that a participant could potentially been paid under a given SESSM Award over the SESSM Service Timing (given the relevant SESSM Minimum Availability Requirement).
The refund factor has been set to 3, so that the Market Participant refunds their payment, and pays an additional amount.

The piece-wise equation for SESSMRefund(a, DI) in clause 2.6 has been amended from commas to 'or' in the conditional part of the equation.

2.6 Calculate the refund due in Dispatch Interval DI for the relevant Registered Facility providing Frequency Co-optimised Essential System Services under SESSM Award a, as follows:

SESSMRefund(a,DI)=

\[\left\\ \begin{array}{r} \begin{array}{r} \text{0\\if\\SESSMOutageCount}\left( \text{a,DI} \right)\text{\\≤\\MaxUnavailability}\left( \text{a} \right)\text{\\or} \\ \\\sum\_{\text{i=1}}^{\text{DI-1}}{\text{SESSMRefund}\left( \text{a,i} \right)}\text{≥\\}\text{PaymentCap}\left( \text{a} \right)\text{\\or} \\ \text{AvailabilityQuantity(a,DI)\\=\\0,} \\ \\ \\ \text{min}\left( \begin{array}{r} \text{AvailabilityPayment}\left( \text{a,DI} \right)\text{\\×\\SESSMRefundFactor×SESSMShortfall}\left( \text{a,DI} \right)\text{,} \\ \text{PaymentCap}\left( \text{a} \right)\\ - \\\sum\_{\text{i=1}}^{\text{DI-1}}{\text{SESSMRefund}\left( \text{a,}\text{i} \right)} \\ \end{array} \right)\text{otherwise} \\ \end{array} \\ \end{array} \right.\\\]

where:

$a$ SESSMOutageCount(a,DI) is the quantity determined under clause 2.5 of this Appendix 2C;

$b$ MaxUnavailability(a) is the number of Dispatch Intervals determined in clause 2.3(b) of this Appendix 2C;

$c$ SESSMRefund(a,i) is the refund due in Dispatch Interval i for the relevant Registered Facility providing Frequency Co-optimised Essential System Services under SESSM Award a;

$d$ PaymentCap(a) is the quantity determined under clause 2.3(c) of this Appendix 2C;

$e$ SESSMRefundFactor is 3;

$f$ [Blank]

$g$ AvailabilityQuantity(a,DI) is the quantity determined under clause 2.2(b) of this Appendix 2C;

$h$ AvailabilityPayment(a,DI) is the quantity determined under clause 2.2(c) of this Appendix 2C; and

$i$ SESSMShortfall(a,DI) is the quantity determined under clause 2.7 of this Appendix 2C.

Explanatory Note

Clause 2.7(a) of this Appendix C calculates the availability payment that is payable to a Facility in a given Dispatch Interval for providing FCESS under each SESSM Award to which it is subject. These availability payments are inputs into the FCESS Payable equations in clauses 9.10.6, 9.10.10, 9.10.14, 9.10.22 and 9.10.23 of the WEM Rules.
Clause 2.7(b) of this Appendix C calculates the SESSM refund that is due from a Facility in a given Dispatch Interval for failing to meet availability obligations under each SESSM Award to which it is subject. These SESSM refunds are inputs into the FCESS Payable equations in clauses 9.10.6, 9.10.10, 9.10.14, 9.10.22 and 9.10.23 of the WEM Rules.

2.7 Calculate the SESSM shortfall for each SESSM Award for each Dispatch Interval as follows:

SESSMShortfall(a,DI) =

\[\text{max}\left( \text{0,}\frac{\text{AvailabilityQuantity}\left( \text{a,DI} \right)\\ - \text{\\max}\left( \text{0,ESSOffer}\left( \text{f,c,DI} \right)\\ - \text{\\}\text{BaseQuantity}\left( \text{a,DI} \right) \right)}{\text{AvailabilityQuantity}\left( \text{a,DI} \right)} \right)\]

where:

$a$ AvailabilityQuantity(a,DI) is the quantity determined under clause 2.2(b) of this Appendix 2C;

$b$ ESSOffer(f,c,DI) is the quantity determined under clause 2.4(a) of this Appendix 2C; and

$c$ BaseQuantity(a,DI) is the quantity determined under clause 2.2(a) of this Appendix 2C.

2.8 Calculate the Per-Dispatch Interval Facility Availability Payments and Facility SESSM Refunds for Registered Facility f, as follows:

$a$ calculate the Per-Dispatch Interval Facility Availability Payments for Registered Facility f in respect of each Frequency Co-optimised Essential System Service in Dispatch Interval DI as follows:

$\text{R}\text{R\\AvailabilityPayment(f,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ARR}}^{}{\text{AvailabilityPayment}\left( \text{a,DI} \right)}$;

$\text{R}\text{L\\AvailabilityPayment(f,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ARL}}^{}{\text{AvailabilityPayment}\left( \text{a,DI} \right)}$;

$\text{C}\text{R\\AvailabilityPayment(f,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ACR}}^{}{\text{AvailabilityPayment}\left( \text{a,DI} \right)}$;

$\text{C}\text{L\\AvailabilityPayment(f,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ACL}}^{}{\text{AvailabilityPayment}\left( \text{a,DI} \right)}$;

$\text{RC}\text{S\\AvailabilityPayment(a,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ARCS}}^{}{\text{AvailabilityPayment}\left( \text{a,DI} \right)}$;

where:

i. a∈ARR is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide Regulation Raise in Dispatch Interval DI;

ii. a∈ARL is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide Regulation Lower in Dispatch Interval DI;

iii. a∈ACR is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide Contingency Reserve Raise in Dispatch Interval DI;

iv. a∈ACL is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide Contingency Reserve Lower in Dispatch Interval DI;

v. a∈ARCS is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide RoCoF Control Service in Dispatch Interval DI; and

vi. AvailabilityPayment(a,DI) is the quantity determined under clause 2.2(c) of this Appendix 2C; and

$b$ calculate the Facility SESSM Refunds for Registered Facility f in respect of each Frequency Co-optimised Essential System Service in Dispatch Interval DI, as follows:

$\text{R}\text{R\\SESSMRefund(f,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ARR}}^{}{\text{SESSMRefund}\left( \text{a,}DI \right)}$;

$\text{R}\text{L\\SESSMRefind(f,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ARL}}^{}{\text{SESSMRefund}\left( \text{a,}DI \right)}$;

$\text{C}\text{R\\SESSMRefund(f,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ACR}}^{}{\text{SESSMRefund}\left( \text{a,}DI \right)}$;

$\text{C}\text{L\\SESSMRefund(f,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ACL}}^{}{\text{SESSMRefund}\left( \text{a,DI} \right)}$; and

$\text{RC}\text{S\\SESSMRefund(f,DI)}\_{\text{\\}}\text{=}\sum\_{\text{a}\text{∈}\text{ARCS}}^{}{\text{SESSMRefund}\left( \text{a,}DI \right)}$,

where:

i. SESSMRefund(a,DI) is the quantity determined under clause 2.6 of this Appendix 2C;

ii. a∈ARR is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide Regulation Raise in Dispatch Interval DI;

iii. a∈ARL is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide Regulation Lower in Dispatch Interval DI;

iv. a∈ACR is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide Contingency Reserve Raise in Dispatch Interval DI;

v. a∈ACL is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide Contingency Reserve Lower in Dispatch Interval DI; and

vi. a∈ARCS is the set of SESSM Awards awarded to the Market Participant to whom Registered Facility f is registered to provide RoCoF Control Service in Dispatch Interval DI.

Explanatory Note

Appendix 3 is amended to:

remove the Reserve Capacity Auction; and
prescribe the prioritisation order for determining Network Access Quantities (NAQ) for Facilities for a Reserve Capacity Cycle (RCC).

This Appendix should be read in conjunction with new proposed section 4.15 – Network Access Quantity.

The Wholesale Electricity Market Amendment (Reserve Capacity Pricing Reforms) Rules 2019 that commenced on 22 February 2020 introduced new provisions for assigning Capacity Credits in scenarios where no new Facilities wish to receive a fixed Reserve Capacity Price (Scenario 1) and where one or more new Facilities wish to receive a fixed Reserve Capacity Price (Scenario 2).

The NAQ determination process has been designed to accommodate the changes to the prioritisation order that was introduced by the Reserve Capacity Mechanism (RCM) pricing reforms.

Scenario 1 – there are no nominated Fixed Price Facilities

If the Reserve Capacity Requirement (RCR) is not met after an NAQ is determined for all existing and committed Facilities, AEMO will determine a NAQ for proposed Facilities, applying a new prioritisation order, until the RCR is achieved or there are no Facilities left.

In accordance with the new prioritisation order, AEMO will not select a proposed Facility where the NAQ determined for the Facility is less than a specified minimum quantity of Capacity Credits (the quantity of which is based on the facility's NAQ) for the Facility to participate in the RCM.

For the purposes of determining an NAQ for each Facility, using the NAQ Model to be developed by AEMO in accordance with section 4.15, AEMO will be required to determine a preliminary NAQ for each Facility and then adjust (which can only be upwards in a subsequent step) that preliminary NAQ as preliminary NAQs for other Facilities are progressively determined in the priority order.

Scenario 2 – there are nominated Fixed Price Facilities

The process for Scenario 2 is similar to Scenario 1 with some modifications to reflect the existing priority order with respect to Facilities that wish to receive a fixed Reserve Capacity Price.

Specifically, unless there is a shortfall in an Availability Class, NAQs will be determined for Facilities wishing to receive a fixed Reserve Capacity Price only if the NAQs determined for new market price Facilities and existing capacity providers is less than the RCR + 3%.

Where there is a shortfall in an Availability Class, NAQs will be determined for new Facilities that wish to receive a fixed Reserve Capacity Price that are committed and proposed Facilities, in accordance with a prioritisation order that includes other Facilities, until the shortfall is fully covered or there are no Facilities left in the NAQ Model without a preliminary NAQ (excluding Facilities where the preliminary NAQ is less than the specified minimum quantity of Capacity Credits for the facility to participate in the RCM).

However, Appendix 3 is also amended by the Miscellaneous Amendments No. 1. As Appendix 3 is amended to reflect the amendments contained in the Tranches 2 and 3 Amendments, as those amending rules (made by the Minister at the date this companion version was prepared) will be commenced last, please refer to the Miscellaneous Amendments No. 1 to see the changes to Appendix 3 that will commence on 1 March 2022 and apply until the Tranches 2 and 3 Amendments to Appendix 3 commence.

Appendix 3: Determination of Network Access Quantities

The objectives of this appendix are:

To prevent AEMO determining Network Access Quantities (and assigning Capacity Credits) for Facilities that have been assigned Certified Reserve Capacity that have insufficient access to the Network and availability to usefully address the Reserve Capacity Requirement. A single algorithm is used for testing of Certified Reserve Capacity and for determining whether, in respect of a Reserve Capacity Cycle, a Network Access Quantity will be determined for any new Candidate Fixed Price Facilities for the current Reserve Capacity Cycle. The process is:
where the Facilities, for which Capacity Credits for the current > Reserve Capacity Cycle are being sought, do not include a > Candidate Fixed Price Facility, set out in Part A; and
where the Facilities, for which Capacity Credits for the current > Reserve Capacity Cycle are being sought, include a Candidate Fixed > Price Facility, set out in Part B.

Explanatory Note

Where AEMO has received an application from a Market Participant for Early Certified Reserve Capacity under section 4.28C, AEMO will determine a preliminary NAQ (where the Facility is also a Network Augmentation Funding Facility) or an Indicative NAQ for the Facility. A Facility to which Early Certified Reserve Capacity has been assigned will only be assigned a Final NAQ (and Capacity Credits) in Year 1 of the RCC to which the application for Early Certified Reserve Capacity relates, and subsequently receive the same treatment as other Facilities holding Capacity Credits and a NAQ.

To determine, using the Network Access Quantity Model:
whether a Network Access Quantity will be determined for a new > Facility, or Facility Upgrade, for the current Reserve Capacity > Cycle and, if so, to determine a Network Access Quantity for that > Facility or Facility Upgrade;
a preliminary Network Access Quantity or an Indicative Network > Access Quantity for an Early CRC Facility, as applicable; and
a Network Access Quantity (which may be zero) for other NAQ > Facilities for the current Reserve Capacity Cycle.

Terms defined in this Appendix 3 are defined for the purposes of this Appendix 3 alone and must not be used to infer the meaning of those words, or other words, in these WEM Rules. Terms which are defined in the WEM Rules will apply to this Appendix unless defined in this Appendix.

Explanatory Note

AEMO may be required to use multiple Constraint Sets within the NAQ Model. Currently, only steps that involve the addition of Network Augmentation Funding Facilities explicitly include a reference to add the “applicable Constraint Set”. However, the addition of other Facilities may also require changes to the Constraint Sets used in the NAQ Model.

Appendix 3 is amended to replace the explicit references to adding Constraint Sets in specific steps with a general requirement for AEMO to use the applicable Constraint Sets in the NAQ Model for the Facilities assessed in each step of Appendix 3.

AEMO must use the applicable Constraint Sets in the Network Access Quantity Model for the Facilities assessed in each step of this Appendix 3.

In this Appendix 3:

Q[a] is the quantity associated with Availability Class “a” in > clauses 4.5.12(b) or 4.5.12(c);
CR[a] is the capacity requirement associated with Availability > Class "a";
Z is the total preliminary Network Access Quantity determined for > Facilities where the capacity is associated with Availability > Class 1;

Explanatory Note

The definition of the capacity requirement of Availability Class 1 is amended to remove the superfluous minus sign after Q[1].

The definition of the capacity requirement of Availability Class 2 is amended to remove a superfluous right-hand bracket after Q[2].

the “capacity requirement” of:

Availability Class 1 is CR[1] = Q[1]; and
Availability Class 2 is CR[2] = max(0, Q[2]) – max(0, Z – CR[1]);

"current Reserve Capacity Cycle" means the Reserve Capacity Cycle > for which the processes in this Appendix are being undertaken to > procure Reserve Capacity for the Capacity Year for that Reserve > Capacity Cycle;
"Early CRC Facility" is a Facility for which:

an application for Early Certified Reserve Capacity has been made under section 4.28C to deliver Reserve Capacity for a future Reserve Capacity Cycle; and
pursuant to that application, AEMO has assigned Early Certified Reserve Capacity to the Facility in accordance with section 4.28C;

Explanatory Note

The NAQ for new capacity upgrades to existing Facilities are determined separately to the NAQ for the parent Facility. Accordingly, the intent of the definition of 'Facility Upgrade' is to calculate the quantity of the increase in the capacity of the Facility by reference to the difference between the parent Facility's nameplate capacity prior to the upgrade and the total Certified Reserve Capacity assigned to the parent Facility including the upgrade.

Regardless of whether a Market Participant intends to increase the nameplate capacity of a Facility in the future or in the past 12 months, the increase should be considered a Facility Upgrade for the purposes of Appendix 3. The definition of Facility Upgrade is therefore amended to remove the implication that the increase in nameplate capacity needs to occur in the future.

"Facility Upgrade" means, for a NAQ Facility, an increase in the > nameplate capacity of the NAQ Facility, being the difference > between:

the nameplate capacity specified under clause 4.10.1(dA), for the NAQ Facility, as provided in the Reserve Capacity Cycle immediately preceding the current Reserve Capacity Cycle; and
the nameplate capacity specified under clause 4.10.1(dA), for the NAQ Facility as provided in the current Reserve Capacity Cycle;

"future Reserve Capacity Cycle" means a Reserve Capacity Cycle that > is subsequent to the current Reserve Capacity Cycle;

Explanatory Note

An Early CRC Facility during an "intervening" RCC is to be classified as an Indicative NAQ Facility, except for Early CRC Facilities that are also Network Augmentation Funding Facilities as the associated augmentation works will not yet be constructed. An "intervening" RCC is the RCC after the first RCC when the application for Early CRC is assessed under Step 13 of Part A or Part B (and an Indicative NAQ is determined for the Facility) and prior to the RCC when a Final NAQ is determined for the Early CRC Facility (and Capacity Credits are assigned to the Facility). This will apply to Early CRC Facilities for which an application for Early Certified Reserve Capacity is made two years before the commencement of Year 1 of the RCC in which the Facility's Reserve Capacity is to be delivered. Early CRC Facilities that are first assigned Early CRC in the RCC immediately prior to the RCC in which is to be delivered will be classified as an NAQ Facility in that subsequent RCC.

"Indicative NAQ Facility" means an Early CRC Facility for which an > Indicative Network Access Quantity was determined for the Facility > under Step 13(c)(ii) in the Reserve Capacity Cycle immediately > preceding the current Reserve Capacity Cycle, but does not > include:

an Early CRC Facility that is also a Network Augmentation Funding Facility; or
an NAQ Facility;

Explanatory Note

To enable an Early CRC Facility to be assigned a Final NAQ for the RCC to which the application for Early CRC relates (i.e. the RCC in which the Facility's Reserve Capacity will be delivered), the Facility will be classified as an NAQ Facility, in that RCC, which means it will be assessed for a preliminary NAQ at Step 3A in that RCC.

Appendix 3 has been further amended to give priority under the NAQ framework to Facilities with an NCESS contract.

“NAQ Facility” means:

a Facility for which a Final Network Access Quantity has been determined in a previous Reserve Capacity Cycle and the Facility has been assigned Certified Reserve Capacity for the current Reserve Capacity Cycle;
an Early CRC Facility where the current Reserve Capacity Cycle is the Reserve Capacity Cycle in which the Facility will first deliver Reserve Capacity; or
a Facility that has been assigned Certified Reserve Capacity and is subject to an NCESS Contract for the current Reserve Capacity Cycle,

but excludes a Facility for which AEMO has received a notice under section 4.4A.1 that the Facility is expected to retire in the Capacity Year to which the current Reserve Capacity Cycle relates and the notice has not been withdrawn under clause 4.4A.6;

Explanatory Note

AEMO's determination of preliminary NAQs at each relevant step of this Part A is subject to the NAQ rules. These rules reflect the principles that once an NAQ is determined it cannot be reduced in a subsequent step (i.e. the Facility's priority cannot be displaced by a Facility with a lower prioritisation), and must not exceed the quantity of CRC assigned to the Facility for the RCC.

“NAQ rules” means:

the preliminary Network Access Quantity determined for a Facility under a step in Part A or Part B, as applicable, cannot be reduced, but can be increased, in a subsequent step; and
the maximum preliminary Network Access Quantity that can be determined for a Facility at the end of a step in Part A or Part B, as applicable, cannot exceed the Certified Reserve Capacity assigned to the Facility for the current Reserve Capacity Cycle;

Explanatory Note

Where a Facility is first added to the NAQ Model at a step, AEMO determines a preliminary NAQ for the Facility. The NAQ is "preliminary" as it may be adjusted (upwards only) in a subsequent step. After all relevant steps are completed, the preliminary NAQ is the Final NAQ for the Facility.

“preliminary Network Access Quantity” is the Network Access Quantity > first determined by AEMO for a Facility in a step, as may be > adjusted by AEMO in a subsequent step;

“prioritisation order” means, where two or more Facilities are tied > with respect to the selection criteria such that assigning a > preliminary Network Access Quantity to all but one of them would > result in the total preliminary Network Access Quantity assigned > to those Facilities exceeding the total capacity requirement of > the Availability Class, then those tied Facilities are to be > selected according to the following rules until the tie is > resolved:

the ratio of a Facility’s preliminary Network Access Quantity to Certified Reserve Capacity from highest to lowest; then
the combination of the Certified Reserve Capacity for Facilities that will minimise the excess of the total Network Access Quantities to be assigned to the Facilities to achieve the capacity requirement for the Availability Class; then
in the order of the time Expression of Interest submissions were received by AEMO, with the Facility to which the earlier submission relates being selected first; then
in the order of the time the applications for Certified Reserve Capacity were received by AEMO, with the Facility to which the earlier application relates being selected first.

Part A No Candidate Fixed Price Facility

Step 1: Calculate the capacity requirement of Availability Class 1.

Explanatory Note

All Facilities that were assigned an NAQ or Indicative NAQ (which does not include an Early CRC Facility that is also a Network Augmentation Funding Facility) in the RCC immediately preceding the current RCC are added to the NAQ Model at Step 2.

An Early CRC Facility that is also a Network Augmentation Funding Facility is only added to Step 2 in the RCC that relates to the Capacity Year for which the Early CRC NAFF capacity is to be delivered.

Step 2: Let the Network Access Quantity Model contain:

$a$ NAQ Facilities for Availability Class 1 and Availability Class 2; and

$b$ Indicative NAQ Facilities.

Explanatory Note

For the 2022 RCC, in which NAQs are to be first determined for Facilities, AEMO must determine preliminary NAQs for existing and committed Facilities that are not GIA Facilities, prior to determining preliminary NAQs for all other Facilities in accordance with the processes in this Appendix.

At Steps 3A, 3B and 3C, AEMO is required to determine a "preliminary NAQ" for Facilities for which an NAQ was determined in the RCC immediately preceding the current RCC, and for Early CRC Facilities where the current RCC relates to the RCC in which the Facility's Reserve Capacity will be delivered.

The intent of classifying the NAQ as "preliminary" is because as other groups of Facilities are added to the NAQ Model and NAQs determined for them in a subsequent step, an earlier NAQ determination may need to be adjusted (upwards only). The intent is at the end of all relevant steps, the preliminary NAQ (as may have been adjusted) is recorded as the Final NAQ for the Facility. The Final NAQ for a Facility determines the number of Capacity Credits assigned to the Facility for the RCC.

The intent of Step 3A is for AEMO to determine a preliminary NAQ for each Facility by assessing whether the existing NAQ determined for the Facility in the RCC immediately preceding the current RCC is in order for the current RCC (0 to min(CRC, current NAQ). In other words:

verify that the Facility has been assigned Certified Reserve Capacity in the current RCC (equal to or greater than the NAQ determined for the Facility in the RCC immediately preceding the current RCC; then
if the amount of CRC assigned to the Facility in the current RCC is lower than the NAQ in 1, reduce the NAQ to the amount specified to be bilaterally traded for the Facility in the current RCC; then
check whether there has been any organic changes in the network that reduces the transfer capability of the network and, reduce the NAQ for affected Facilities accordingly.

The intent of Steps 3B and 3C is for AEMO to determine whether there is NAQ available to NAQ Facilities up to their Highest NAQ (PNAQ to min(CRC, HNAQ)) and then up to the Certified Reserve Capacity assigned to the Facility (PNAQ to CRC) respectively.

AEMO is also required to determine (and adjust (upwards only) in a subsequent step) an Indicative NAQ for Early CRC Facilities (excluding Early CRC Facilities that are also Network Augmented Funding Facilities) where the RCC is the "intervening" year for these Facilities.

Step 3: For:

$a$ the 2022 Reserve Capacity Cycle, AEMO must:

i. undertake the processes in Steps 3A, 3B and 3C excluding:

1. each NAQ Facility that is also a GIA Facility; and

2. each Indicative NAQ Facility; then

ii. repeat Steps 3A, 3B and 3C with all NAQ Facilities and Indicative NAQ Facilities in accordance with the processes set out in those steps; and

$b$ subsequent Reserve Capacity Cycles, go to Step 3A.

Explanatory Note:

Step 3A of Part A of Appendix 3 is amended to:

specify that for Indicative NAQ Facilities the Indicative Network Access Quantity is adjusted; and
reflect that Early CRC Facilities with an Indicative Network Access Quantity do not have Certified Reserve Capacity but Early Certified Reserve Capacity.

Step 3A: Subject to the NAQ rules, using the Network Access Quantity Model determine the preliminary Network Access Quantity for each NAQ Facility and, where applicable, Indicative Network Access Quantity for each Indicative NAQ Facility, which is a value up to the minimum of:

$a$ the Network Access Quantity determined for the NAQ Facility or Indicative NAQ Facility in the Reserve Capacity Cycle immediately preceding the current Reserve Capacity Cycle, which, for an Early CRC Facility is deemed to be:

i. for an Early CRC Facility is deemed to be:

1. for an Early CRC Facility that is also a Network Augmentation Funding Facility, the preliminary Network Access Quantity determined for the Facility at Step 13(c)(i) in a previous Reserve Capacity Cycle; or

2. for each other Early CRC Facility, the Indicative Network Access Quantity determined for the Facility in the Reserve Capacity Cycle immediately preceding the current Reserve Capacity Cycle; and

ii. for an NAQ Facility subject to an NCESS Contract, that was not assigned a Network Access Quantity in the Reserve Capacity Cycle immediately preceding the current Reserve Capacity Cycle, is deemed to be the Certified Reserve Capacity for the NAQ Facility; and

$b$ the Certified Reserve Capacity for the NAQ Facility or Early Certified Reserve Capacity for the Indicative NAQ Facility,

then go to Step 3B.

Step 3B: Using the Network Access Quantity Model and, subject to the NAQ Rules, adjust the preliminary Network Access Quantity determined for an NAQ Facility under a prior step to a value up to the Highest Network Access Quantity for the NAQ Facility where this is greater than the preliminary Network Access Quantity determined for the NAQ Facility in a prior step and, where applicable, adjust the Indicative Network Access Quantity determined under a prior step for an Indicative NAQ Facility up to the Early Certified Reserve Capacity for the Indicative NAQ Facility,

then go to Step 3C.

Explanatory Note

Step 3C of Part A of Appendix 3 is amended reflect that Early CRC Facilities with an Indicative Network Access Quantity do not have Certified Reserve Capacity but Early Certified Reserve Capacity.

Step 3C: Using the Network Access Quantity Model and, subject to the NAQ rules, adjust the preliminary Network Access Quantity determined for an NAQ Facility or Indicative Network Access Quantity for an Indicative NAQ Facility under a prior step to a value up to a value equal to the Certified Reserve Capacity for the NAQ Facility or Early Certified Reserve Capacity for an Indicative NAQ Facility, excluding, for the NAQ Facility, any associated Facility Upgrade, where this is greater than the preliminary Network Access Quantity determined in a prior step.

Explanatory Note

At Step 4, AEMO is required to add new committed Facilities that have committed to funding network augmentations and the applicable Constraint Sets to the NAQ Model and determine a preliminary NAQ for each of these Facilities.

Where applicable, AEMO is also required to adjust (upwards only) any preliminary NAQs for Facilities determined under previous steps and any Indicative NAQs for Indicative NAQ Facilities.

Step 4: Add all new committed Network Augmentation Funding Facilities (as defined in section 4.10A) to the Network Access Quantity Model, then using the Network Access Quantity Model and, subject to the NAQ rules:

$a$ determine the preliminary Network Access Quantity for each such Network Augmentation Funding Facility; and

$b$ where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step or the Indicative Network Access Quantity for an Indicative NAQ Facility.

To avoid doubt, an Early CRC Facility that is also a Network Augmentation Funding Facility is not a Network Augmentation Funding Facility for the purposes of this Step 4.

Explanatory Note

At Step 5, AEMO is required to add any remaining committed Facilities associated with Availability Class 1 (i.e. existing committed Facilities are already dealt with as NAQ Facilities at Step 3A or Network Augmentation Funding Facilities at Step 4) and committed Facility upgrades to the NAQ Model and determine a preliminary NAQs foreach of these Facilities.

Committed Availability Class 2 Facilities are also added at this Step 5 but are not counted towards the Availability Class 1 target. All new committed Early CRC Facilities are excluded at this Step 5.

Where applicable, AEMO is also required to adjust (upwards only) any preliminary NAQs for Facilities determined under previous steps and any Indicative NAQs for Indicative NAQ Facilities.

Step 5: Add to the Network Access Quantity Model:

$a$ any remaining committed Facilities associated with Availability Class 1 and Availability Class 2, excluding any new Early CRC Facilities; and

$b$ any committed Facility Upgrade for an NAQ Facility, then:

$c$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each such Facility or Facility Upgrade; and

ii. where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step or the Indicative Network Access Quantity for an Indicative NAQ Facility.

Explanatory Note

At Step 6, AEMO is required to add any remaining proposed Facilities and proposed Facility upgrades associated with Availability Class 1, excluding any new Early CRC Facilities, to the NAQ Model.

AEMO is required to determine a preliminary NAQ for each of these Facilities and only select Facilities where the preliminary NAQ for the Facility is not less than the minimum number of capacity credits nominated by the Market Participant under clause 4.14.1D that are required for the Facility to participate in the RCM. Any Facilities not selected are removed from the NAQ Model and added back in at Step 9(a).

Where applicable, AEMO is also required to adjust (upwards only) any preliminary NAQs for Facilities determined under previous steps and any Indicative NAQs for Indicative NAQ Facilities.

The Indicative Network Access Quantity for any Indicative NAQ Facility is excluded from the calculation testing whether the capacity requirement is met. This is because, the capacity for Indicative NAQ Facilities will not be available for the Capacity Year that relates to the current RCC.

Step 6: If the sum of the preliminary Network Access Quantity determined for each Facility that is associated with Availability Class 1 under all prior steps does not fully cover the capacity requirement of Availability Class 1, then:

$a$ add all remaining Facilities and Facility Upgrades, excluding any new Early CRC Facilities, associated with Availability Class 1 to the Network Access Quantity Model; then

$b$ using the Network Access Quantity Model and, subject to the NAQ rules, determine the preliminary Network Access Quantity for each Facility added in Step 6(a); then

$c$ select Facilities, subject to, where applicable, the preliminary Network Access Quantity determined for a Facility being not less than the Minimum Capacity Credits Quantity for the Facility (as specified under clause 4.14.1D), until the capacity requirement of Availability Class 1 is fully covered, applying the prioritisation order, if required, or until there are no Facilities left to be selected; then

$d$ remove any Facilities not selected under Step 6(c) from the Network Access Quantity Model; then

$e$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each Facility selected under Step 6(c); and

ii. where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step or the Indicative Network Access Quantity for an Indicative NAQ Facility.

Explanatory Note

At Step 11, AEMO is required to record each preliminary NAQ as the Final NAQ for each Facility. To avoid Facilities for which a preliminary NAQ was determined at Step 6(b) but the Facility was not accepted at Step 6(c) being considered at Step 11, only Facilities selected under Step 6(c) will be deemed to be Facilities for which a preliminary NAQ has been determined.

For the purposes of Step 11, Facilities that have not been selected under Step 6(c) will not be treated as a Facility for which a preliminary Network Access Quantity has been determined.

Step 7: If a preliminary Network Access Quantity has been determined for each Facility in the Network Access Quantity Model associated with Availability Class 1 (except for any Facilities that were not selected due to the preliminary Network Access Quantity determined for the Facility being less than the Minimum Capacity Credits Quantity for the Facility as specified under clause 4.14.1D) but the capacity requirement of Availability Class 1 has not been covered, then record the difference as the capacity shortfall for Availability Class 1.

Step 8: Calculate the capacity requirement of Availability Class 2.

Explanatory Note

At Step 9, AEMO is required to determine whether the capacity requirement for Availability Class 2 has been covered by preliminary NAQs determined for Facilities under all previous steps.

If the capacity requirement has not been covered, AEMO will continue to add Facilities to the NAQ Model and determine preliminary NAQs for Facilities until the capacity requirement is covered or there are no Facilities left in the NAQ Model for which a preliminary NAQ has not been determined

The Facilities added to the NAQ Model at this step are proposed Availability Class 2 and any Facilities that were not selected under a previous step because the preliminary NAQ determined for them under the relevant step was less than the minimum quantity of Capacity Credits nominated for the facility under clause 4.14.1D to participate in the RCM.

Where applicable, AEMO is also required to adjust (upwards only) any preliminary NAQs for Facilities determined under previous steps and any Indicative NAQs for Indicative NAQ Facilities.

Step 9: If the sum of the preliminary Network Access Quantity determined for each Facility that is associated with Availability Class 2 under all prior steps does not fully cover the capacity requirement of Availability Class 2, then:

$a$ add all remaining Facilities associated with Availability Class 2 to the Network Access Quantity Model and any Facilities that were removed from the Network Access Quantity Model at Step 6(d); then

$b$ using the Network Access Quantity Model and, subject to the NAQ rules, determine the preliminary Network Access Quantity for each Facility added at Step 9(a); then

$c$ select Facilities, subject to, where applicable, the preliminary Network Access Quantity determined for a Facility being not less than the Minimum Capacity Credits Quantity for the Facility (as specified under clause 4.14.1D), in order of decreasing availability until the capacity requirement of Availability Class 2 is fully covered, applying the prioritisation order, if required, or until there are no Facilities left to be selected; then

$d$ remove any Facilities not selected under Step 6(c) from the Network Access Quantity; then

$e$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each Facility selected under Step 9(c); and

ii. where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step or Indicative Network Access Quantity for an Indicative NAQ Facility.

For the purposes of Step 11, Facilities that have not been selected under Step 9(c) will not be treated as a Facility for which a preliminary Network Access Quantity has been determined.

Step 10: If a preliminary Network Access Quantity has been determined for each Facility in the Network Access Quantity Model associated with Availability Class 2 (except for any Facilities that were not selected due to the preliminary Network Access Quantity determined for the Facility being less than the Minimum Capacity Credits Quantity for the Facility as specified under clause 4.14.1D) but the capacity requirement of Availability Class 2 has not been covered, then record the difference as the capacity shortfall for Availability Class 2.

Explanatory Note

At Step 11(a), AEMO is required to record any adjusted Indicative Network Access Quantity for an Indicative NAQ Facility.

At Step 11(b), AEMO is required to record the preliminary NAQ determined for a Facility as the Final NAQ for the Facility. Under clause 4.15.2, the Final NAQ determined for a Facility through the processes in this Appendix 3 is the NAQ for the Facility for the RCC.

Step 11: Record:

$a$ for an Indicative NAQ Facility, if the Indicative Network Access Quantity has been adjusted under this Part A, the adjusted Indicative Network Access Quantity; and

$b$ for each other Facility, the preliminary Network Access Quantity determined under this Part A as the Final Network Access Quantity for the Facility.

Step 12: For each Availability Class report the capacity shortfall, which indicates the amount to be procured through the supplementary capacity process in section 4.24.

Explanatory Note

At Step 13, AEMO is required to add Facilities for which an application for Early Certified Reserve Capacity has been made under section 4.28C in the current RCC for a future RCC, and pursuant to that application, AEMO has assigned Early Certified Reserve Capacity to the Facility in accordance with section 4.28C, to the NAQ Model.

AEMO is required to determine a preliminary NAQ (where the Facility is also a Network Augmentation Funding Facility) or an Indicative NAQ (for other new Facilities) for each of these Facilities. The Indicative NAQ must not exceed the quantity of Early Certified Reserve Capacity set for the Facility in accordance with clause 4.28C.7.

Step 13: Add the Facilities referred to in Step 13(a) and (b) (each comprising a "group") in the order specified to the Network Access Quantity Model, except that before adding the next group of Facilities to the Network Access Quantity Model, undertake the applicable determination in Step 13(c) for that group of Facilities before adding the next group of Facilities and repeating Step 13(c) for that subsequent group of Facilities:

$a$ new Early CRC Facilities that are also Network Augmentation Funding Facilities; then

$b$ any other new Early CRC Facilities; then

$c$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each Facility in the group of Facilities described in Step 13(a); and

ii. determine the Indicative Network Access Quantity for each Facility in the group of Facilities described in Step 13(b).

Step 14: End.

Explanatory Note

Part B applies where one or more Facilities wish to be classified as Fixed Price Facilities. The processes for determining NAQs for Availability Class 1 and Availability Class 2 Facilities are amended to reflect the priority order for assigning Capacity Credits to Facilities that wish to be classified as Fixed Price Facilities.

Part B Candidate Fixed Price Facility

Step 1: Calculate the capacity requirement of Availability Class 1.

Step 2: Let the Network Access Quantity Model contain:

$a$ NAQ Facilities for Availability Class 1 and Availability Class 2; and

$b$ Indicative NAQ Facilities.

Step 3: For:

$a$ the 2022 Reserve Capacity Cycle, AEMO must:

i. undertake the processes in Steps 3A, 3B and 3C excluding:

1. each NAQ Facility that is also a GIA Facility; and

2. each Indicative NAQ Facility; then

ii. repeat Steps 3A, 3B and 3C with all NAQ Facilities and Indicative NAQ Facilities in accordance with the processes set out in those steps; and

$b$ subsequent Reserve Capacity Cycles, go to Step 3A.

Step 3A: Subject to the NAQ rules, using the Network Access Quantity Model determine the preliminary Network Access Quantity for each NAQ Facility and, where applicable, Indicative Network Access Quantity for each Indicative NAQ Facility, which is a value up to the minimum of:

$a$ the Network Access Quantity determined for the NAQ Facility or Indicative NAQ Facility in the Reserve Capacity Cycle immediately preceding the current Reserve Capacity Cycle, which, for an Early CRC Facility is deemed to be:

i. for an Early CRC Facility is deemed to be:

1. for an Early CRC Facility that is also a Network Augmentation Funding Facility, the preliminary Network Access Quantity determined for the Facility at Step 13(c)(i) in a previous Reserve Capacity Cycle; or

2. for each other Early CRC Facility, the Indicative Network Access Quantity determined for the Facility in the Reserve Capacity Cycle immediately preceding the current Reserve Capacity Cycle; and

ii. for an NAQ Facility subject to an NCESS Contract, that was not assigned a Network Access Quantity in the Reserve Capacity Cycle immediately preceding the current Reserve Capacity Cycle, is deemed to be the Certified Reserve Capacity for the NAQ Facility; and

$b$ the Certified Reserve Capacity for the NAQ Facility or Early Certified Reserve Capacity for the Indicative NAQ Facility,

then go to Step 3B.

Step 3B: Using the Network Access Quantity Model and, subject to the NAQ Rules, adjust the preliminary Network Access Quantity determined for an NAQ Facility under a prior step to a value up to the Highest Network Access Quantity for the NAQ Facility where this is greater than the preliminary Network Access Quantity determined for the NAQ Facility in a prior step and, where applicable, adjust the Indicative Network Access Quantity determined under a prior step for an Indicative NAQ Facility up to the Early Certified Reserve Capacity for the Indicative NAQ Facility,

then go to Step 3C.

Explanatory Note

Step 3C of Part A of Appendix 3 is amended reflect that Early CRC Facilities with an Indicative Network Access Quantity don’t have Certified Reserve Capacity but Early Certified Reserve Capacity.

Step 3C: Using the Network Access Quantity Model and, subject to the NAQ rules, adjust the preliminary Network Access Quantity determined for an NAQ Facility or Indicative Network Access Quantity for an Indicative NAQ Facility under a prior step to a value up to a value equal to the Certified Reserve Capacity for the NAQ Facility or Early Certified Reserve Capacity for an Indicative NAQ Facility, excluding, for the NAQ Facility any associated Facility Upgrade, where this is greater than the preliminary Network Access Quantity determined in a prior step.

Step 4: Add all new committed Network Augmentation Funding Facilities (as defined in section 4.10A) to the Network Access Quantity Model, then using the Network Access Quantity Model and, subject to the NAQ rules:

$a$ determine the preliminary Network Access Quantity for each such Network Augmentation Funding Facility; and

$b$ where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step or the Indicative Network Access Quantity for an Indicative NAQ Facility.

To avoid doubt, an Early CRC Facility that is also a Network Augmentation Funding Facility is not a Network Augmentation Funding Facility for the purposes of this Step 4.

Step 5: Add to the Network Access Quantity Model:

$a$ any remaining committed Facilities associated with Availability Class 1 and Availability Class 2, excluding:

i. any new Early CRC Facilities; and

ii. any committed Candidate Fixed Price Facilities; and

$b$ any committed Facility Upgrade for an NAQ Facility, then:

$c$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each such Facility, or Facility Upgrade; and

ii. where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step or the Indicative Network Access Quantity for an Indicative NAQ Facility.

Explanatory Note

Consistent with the current WEM Rules, an NAQ will only be determined for Facilities that wish to be classified as a Fixed Price Facility if the preliminary NAQs determined for existing Facilities and new operating or committed market prices Facilities is less than the Reserve Capacity Requirement plus 3%.

The Indicative Network Access Quantity for any Indicative NAQ Facility is excluded from the calculation testing whether the capacity requirement is met. This is because, the capacity for Indicative NAQ Facilities will not be available for the Capacity Year that relates to the current RCC.

Step 6: If the sum of the preliminary Network Access Quantity determined for each Facility under all prior steps is:

$a$ less than the Reserve Capacity Requirement plus 3%, then go to Step 6A; or

$b$ equal to or more than the Reserve Capacity Requirement plus 3%, then go to Step 6C.

Explanatory Note

At Step 6A, AEMO is required to add new committed Candidate Fixed Price Facilities to the NAQ Model and determine a preliminary NAQ for each of these Facilities.

AEMO is also required to adjust (upwards only) any preliminary NAQs for Facilities determined under previous steps and any Indicative NAQs for Indicative NAQ Facilities.

Step 6A: Add all committed Candidate Fixed Price Facilities associated with Availability Class 1 and Availability Class 2 to the Network Access Quantity Model, then, using the Network Access Quantity Model and, subject to the NAQ rules:

$a$ determine the preliminary Network Access Quantity for each committed Candidate Fixed Price Facility; and

$b$ where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step or the Indicative Network Access Quantity for an Indicative NAQ Facility.

Explanatory Note

At Step 6B, AEMO is required to determine whether the capacity requirement for Availability Class 1 has been covered. If it has been covered AEMO will go to Step 7.

However, if the capacity requirement for Availability Class 1 has not yet been covered, at Step 6B, AEMO is required to add proposed market price Facilities and proposed Facilities that wish to be classified as fixed price Facilities that are associated with Availability Class 1 to the NAQ Model.

The intent at this step is that AEMO:

adds the Facilities described at (i) as the first group of Facilities to the NAQ Model; then
determines a preliminary NAQ for each of the Facilities in that group; then
selects Facilities, subject to any minimum quantity of Capacity Credits nominated for a Facility being met, until the capacity requirement is covered; then
removes any Facilities not selected from the NAQ Model; then
determines a preliminary NAQ for the selected Facilities; and
where applicable, adjusts any preliminary NAQs and any Indicative NAQs for Indicative NAQ Facilities determined for Facilities under previous steps ; then
if the capacity requirement is not yet covered, adds the Facilities described at (ii) as the next group of Facilities to the NAQ Model; then
determines a preliminary NAQ for the Facilities in that next group; then
selects Facilities, subject to any minimum quantity of Capacity Credits nominated for a Facility being met, until the capacity requirement is covered; then
removes any Facilities not selected from the NAQ Model; then
determines a preliminary NAQ for the selected Facilities; and
where applicable, adjusts any preliminary NAQs and any Indicative NAQs for Indicative NAQ Facilities for Indicative NAQ Facilities determined for Facilities under previous steps.

The Indicative Network Access Quantity for any Indicative NAQ Facility is excluded from the calculation testing whether the capacity requirement is met. This is because, the capacity for Indicative NAQ Facilities will not be available for the Capacity Year that relates to the current RCC.

AEMO will apply the 'prioritisation order' to resolve any tied Facilities.

Step 6B: If the sum of the preliminary Network Access Quantity determined for each Facility that is associated with Availability Class 1 under all prior steps does not fully cover the capacity requirement of Availability Class 1, then:

$a$ add the Facilities referred to in Step 6B(a)(i) and (ii) (each comprising a "group") in the order specified to the Network Access Quantity Model, except that before adding the next group of Facilities to the Network Access Quantity Model, undertake Steps 6B(b), 6B(c), 6B(d) and 6B(e)(i) for that group of Facilities, and Step 6B(e)(ii) in respect to the Facilities referred to in Step 6B(e)(ii), before adding the next group of Facilities, if required, and repeating Steps 6B(b), 6B(c), 6B(d) and 6B(e)(i) for that subsequent group of Facilities, and Step 6B(e)(ii) in respect to the Facilities referred to in Step 6B(e)(ii):

i. any remaining Facilities associated with Availability Class 1 that are not committed or Candidate Fixed Price Facilities; then

ii. Candidate Fixed Price Facilities associated with Availability Class 1 that are not committed; then

$b$ using the Network Access Quantity Model and, subject to the NAQ rules, determine the preliminary Network Access Quantity for each Facility in that group of Facilities; then

$c$ select Facilities from that group of Facilities, subject to, where applicable, the preliminary Network Access Quantity determined for a Facility in that group of Facilities being not less than the Minimum Capacity Credits Quantity for the Facility (as specified under clause 4.14.1D), until the capacity requirement of Availability Class 1 is fully covered, applying the prioritisation order, if required, or until there are no Facilities left to be selected; then

$d$ remove any Facilities not selected under Step 6B(c) from that group of Facilities from the Network Access Quantity Model; then

$e$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each Facility selected under Step 6B(c); and

ii. where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step (other than a step in this Step 6B) or the Indicative Network Access Quantity for an Indicative NAQ Facility,

then go to Step 7.

For the purposes of Step 11, Facilities that have not been selected under Step 6B(c) will not be treated as a Facility for which a preliminary Network Access Quantity has been determined.

Explanatory Note

At Step 6C, AEMO is required to determine whether the capacity requirement for Availability Class 1 has been covered. If it has been covered AEMO will go to Step 7.

However, if the capacity requirement for Availability Class 1 has not yet been covered, at Step 6C, AEMO is required to add the following groups of Facilities to the NAQ Model in the following order, and determine a preliminary NAQ for each of those Facilities until the capacity requirement is covered or there are no Facilities left for which a preliminary NAQ has not been determined:

proposed market price Facilities; then
committed Facilities that wish to be classified as a Fixed Price Facility and are associated with Availability Class 1; then
proposed Facilities that wish to be classified as a Fixed Price Facility and are associated with Availability Class 1.

Again, the Indicative Network Access Quantity for any Indicative NAQ Facility is excluded from the calculation testing whether the capacity requirement is met. This is because, the capacity for Indicative NAQ Facilities will not be available for the Capacity Year that relates to the current RCC.

AEMO will apply the 'prioritisation order' to resolve any tied Facilities.

See the Explanatory Note to Step 6B regarding the intent with respect to processing and determining preliminary NAQs in groups, etc.

Step 6C: If the sum of the preliminary Network Access Quantity determined for each Facility that is associated with Availability Class 1 under all prior steps does not fully cover the capacity requirement of Availability Class 1, then:

$a$ add the Facilities referred to in Step 6C(a)(i), (ii) and (iii) (each comprising a "group") in the order specified to the Network Access Quantity Model, except that before adding the next group of Facilities to the Network Access Quantity Model, undertake Steps 6C(b), 6C(c), 6C(d) and 6C(e)(i) for that group of Facilities, and Step 6C(e)(ii) in respect to the Facilities referred to in Step 6C(e)(ii), before adding the next group of Facilities, if required, and repeating Steps 6C(b), 6C(c), 6C(d) and 6C(e)(i) for that subsequent group of Facilities (as applicable), and Step 6C(e)(ii) in respect to the Facilities referred to in Step 6C(e)(ii):

i. Facilities associated with Availability Class 1 that are not committed or Candidate Fixed Price Facilities; then

ii. committed Candidate Fixed Price Facilities associated with Availability Class 1; then

iii. Candidate Fixed Price Facilities associated with Availability Class 1 that are not committed; then

$b$ using the Network Access Quantity Model and, subject to the NAQ rules, determine the preliminary Network Access Quantity for each Facility in that group of Facilities; then

$c$ select Facilities from that group of Facilities subject to, where applicable, the preliminary Network Access Quantity for a Facility in that group of Facilities being not less than the Minimum Capacity Credits Quantity for the Facility (as specified under clause 4.14.1D), until the capacity requirement of Availability Class 1 is fully covered, applying the prioritisation order, if required, or until there are no Facilities left to be selected; then

$d$ remove any Facilities not selected from the group of Facilities under Step 6C(c) from the Network Access Quantity Model; then

$e$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each Facility selected under Step 6C(c); and

ii. where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step (other than a step in this Step 6C) or the Indicative Network Access Quantity for an Indicative NAQ Facility,

For the purposes of Step 11, Facilities that have not been selected under Step 6C(c) will not be treated as a Facility for which a preliminary Network Access Quantity has been determined.

Step 7: If a preliminary Network Access Quantity has been determined for all Facilities in the Network Access Quantity Model associated with Availability Class 1 (except for any Facilities that were not selected due to the preliminary Network Access Quantity determined for the Facility being less than the Minimum Capacity Credits Quantity for the Facility as specified under clause 4.14.1D) but the capacity requirement of Availability Class 1 has not been covered, then record the difference as the capacity shortfall for Availability Class 1.

Step 8: Calculate the capacity requirement for Availability Class 2.

Step 9: Based on the Facilities for which a preliminary Network Access Quantity has been determined under all prior steps (except for any facilities that were not selected due to the preliminary Network Access Quantity determined for the Facility being less than the Minimum Capacity Credits Quantity for the Facility as specified under clause 4.14.1D), determine if there is a shortfall for Availability Class 2. Go to Step 11 if there is no shortfall, otherwise go to:

$a$ Step 9A if no committed Candidate Fixed Price Facility was added to the Network Access Quantity Model at Step 6A; or

$b$ Step 9B if committed Candidate Fixed Price Facilities were added to the Network Access Quantity Model at Step 6A.

Explanatory Note

If the capacity requirement for Availability Class 2 has not yet been covered, AEMO is required to add the following groups of Facilities to the NAQ Model in the following order and determine a preliminary NAQ for each of those Facilities until the capacity requirement is covered or there are no Facilities left for which a preliminary NAQ has not been determined:

committed Facilities that wish to be classified as a Fixed Price Facility associated with Availability Class 1; then
committed Facilities that wish to be classified as a Fixed Price Facility associated with Availability Class 2; then
any proposed market price Facilities associated with Availability Class 1 for which a preliminary NAQ was not determined for the Facility under a previous step to cover the capacity requirement for Availability Class 1; then
proposed market price Facilities associated with Availability Class 2; then
proposed Facilities that wish to be classified as a Fixed Price Facility associated with Availability Class 1; then
proposed Facilities that wish to be classified as a Fixed Price Facility associated with Availability Class 2.

Again, the Indicative Network Access Quantity for any Indicative NAQ Facility is excluded from the calculation testing whether the capacity requirement is met. This is because, the capacity for Indicative NAQ Facilities will not be available in the current RCC.

AEMO will apply the 'prioritisation order' to resolve any tied Facilities.

See the Explanatory Note to Step 6B regarding the intent with respect to processing and determining preliminary NAQs in groups, etc.

Step 9A: Add the Facilities referred to in Step 9A(a), (b), (c), (d), (e) and (f) (each comprising a "group") in the order specified to the Network Access Quantity Model, except that before adding the next group of Facilities to the Network Access Quantity Model, undertake Steps 9A(g), 9A(h), 9A(i) and 9A(j)(i) for that group of Facilities, and Step 9A(j)(ii) in respect to the Facilities referred to in Step 9A(j)(ii), before adding the next group of Facilities, if required, and repeating Steps 9A(g), 9A(h), 9A(i) and 9A(j)(i) (as applicable) for that subsequent group of Facilities, and Step 9A(j)(ii) in respect to the Facilities referred to in Step 9A(j)(ii):

$a$ any remaining committed Candidate Fixed Price Facilities associated with Availability Class 1 and any Facilities that were removed from the Network Access Quantity Model at Step 6C(d); then

$b$ committed Candidate Fixed Price Facilities associated with Availability Class 2; then

$c$ any remaining Facilities associated with Availability Class 1 that are not committed or Candidate Fixed Price Facilities; then

$d$ Facilities that are not committed or Candidate Fixed Price Facilities associated with Availability Class 2; then

$e$ any remaining Candidate Fixed Price Facilities associated with Availability Class 1 that are not committed; then

$f$ Candidate Fixed Price Facilities associated with Availability Class 2 that are not committed; then

$g$ using the Network Access Quantity Model and, subject to the NAQ rules, determine the preliminary Network Access Quantity for each Facility in that set of Facilities; then

$h$ select Facilities from that group of Facilities, subject to, where applicable, the preliminary Network Access Quantity for a Facility in that group of Facilities being not less than the Minimum Capacity Credits Quantity for the Facility (as specified under clause 4.14.1D), until the capacity requirement of Availability Class 2 is fully covered, applying the prioritisation order, if required, or until there are no Facilities left to be selected; then

$i$ remove any Facilities not selected under Step 6C(h) from the Network Access Quantity Model; then

$j$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each Facility selected under Step 9A(h); and

ii. where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step (other than a step in this Step 9A) , or the Indicative Network Access Quantity for an Indicative NAQ Facility ; then

go to Step 10.

For the purposes of Step 11, Facilities that have not been selected under Step 9A(h) will not be treated as a Facility for which a preliminary Network Access Quantity has been determined.

Explanatory Note

If the capacity requirement for Availability Class 2 has not yet been covered and any committed Facilities that wish to be classified as a Fixed Price Facility were added at Step 6A, AEMO is required to add the following Facilities in the following order and determine a preliminary NAQ for each of those Facilities until the capacity requirement is covered or there are no Facilities left for which a preliminary NAQ has not been determined:

any proposed market price Facilities associated with Availability Class 1 for which a preliminary NAQ was not determined for the Facility under a previous step to cover the capacity requirement for Availability Class 1; then
proposed market price Facilities associated with Availability Class 2; then
proposed Facilities that wish to be classified as a Fixed Price Facility associated with Availability Class 1; then
proposed Facilities that wish to be classified as a Fixed Price Facility associated with Availability Class 2.

Again, the Indicative Network Access Quantity for any Indicative NAQ Facility is excluded from the calculation testing whether the capacity requirement is met. This is because, the capacity for Indicative NAQ Facilities will not be available in the current RCC.

AEMO will apply the 'prioritisation order' to resolve any tied Facilities.

See the Explanatory Note to Step 6B regarding the intent with respect to processing and determining preliminary NAQs in groups, etc.

Step 9B: Add the Facilities referred to in Step 9B(a), (b), (c) and (d) (each comprising a "group") in the order specified to the Network Access Quantity Model, except that before adding the next group of Facilities to the Network Access Quantity Model, undertake Steps 9B(e), 9B(f), 9B(g) and 9B(h)(i) for each group of Facilities, and Step 9B(h)(ii) in respect to any other Facilities referred to in Step 9B(h)(ii), before adding the next group of Facilities, if required, and repeating Steps 9B(e), 9B(f), 9B(g) and 9B(h)(i) for that subsequent group of Facilities, and Step 9B(h)(ii) in respect of any other Facilities referred to in Step 9B(h)(ii):

$a$ any remaining Facilities that are not committed or Candidate Fixed Price Facilities associated with Availability Class 1 and any Facilities that were removed from the Network Access Quantity Model at Step 6B(d); then

$b$ Facilities that are not committed or Candidate Fixed Price Facilities associated with Availability Class 2; then

$c$ any remaining Candidate Fixed Price Facilities associated with Availability Class 1 that are not committed; then

$d$ Candidate Fixed Price Facilities associated with Availability Class 2 that are not committed; then

$e$ using the Network Access Quantity Model and, subject to the NAQ rules, determine the preliminary Network Access Quantity for each Facility in that set of Facilities; then

$f$ select Facilities from that set of Facilities, subject to, where applicable, the preliminary Network Access Quantity for a Facility being not less than the Minimum Capacity Credits Quantity for the Facility (as specified under clause 4.14.1D) until the capacity requirement of Availability Class 2 is fully covered, applying the prioritisation order, if required, or until there are no Facilities left to be selected; then

$g$ remove any Facilities not selected under Step 9B(f) from the Network Access Quantity Model; then

$h$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each such Facility selected under Step 9B(f); and

ii. where applicable, adjust the preliminary Network Access Quantity determined for a Facility under a prior step (other than a step in this Step 9B) or Indicative Network Access Quantity for an Indicative NAQ Facility.

For the purposes of Step 11, Facilities that have not been selected under Step 9B(f) will not be treated as a Facility for which a preliminary Network Access Quantity has been determined.

Step 10: If a preliminary Network Access Quantity has been determined for all Facilities in the Network Access Quantity Model associated with Availability Class 1 and Availability Class 2 (except for any Facilities that were not selected due to the preliminary Network Access Quantity determined for the Facility being less than the Minimum Capacity Credits Quantity for the Facility as specified under clause 4.14.1D) but the capacity requirement of Availability Class 2 has not been covered, then record the difference as the capacity shortfall for Availability Class 2.

Step 11: Record:

$a$ for an Indicative NAQ Facility, if the Indicative Network Access Quantity has been adjusted under this Part B, the adjusted Indicative Network Access Quantity; and

$b$ for each other Facility, the preliminary Network Access Quantity determined under this Part B as the Final Network Access Quantity for the Facility.

Step 12: For each Availability Class report the capacity shortfall, which indicates the amount to be procured through the supplementary capacity process in section 4.24.

Step 13: Add the Facilities referred to in Step 13(a) and (b) (each comprising a "group") in the order specified to the Network Access Quantity Model, except that before adding the next group of Facilities to the Network Access Quantity Model, undertake the applicable determination in Step 13(c) for that group of Facilities before adding the next group of Facilities and repeating Step 13(c) for that subsequent group of Facilities:

$a$ new Early CRC Facilities that are also Network Augmentation Funding Facilities; then

$b$ any other new Early CRC Facilities; then

$c$ using the Network Access Quantity Model and, subject to the NAQ rules:

i. determine the preliminary Network Access Quantity for each Facility in the group of Facilities described in Step 13(a); and

ii. determine the Indicative Network Access Quantity for each Facility in the group of Facilities described in Step 13(b).

Step 14: End.

Appendix 4: [Blank]

Explanatory Note

Appendix 4A is amended to ensure that Individual Intermittent Load Reserve Capacity Requirements are only calculated for Intermittent Loads which existed before New WEM Commencement Day.

Appendix 4A: Individual Intermittent Load Reserve Capacity Requirements

This Appendix describes how the Individual Intermittent Load Reserve Capacity Requirement for Intermittent Load k for Trading Month n is determined.

The Individual Intermittent Load Reserve Capacity Requirement is only to be determined for Intermittent Loads that are and continue to be deemed to be Intermittent Loads under clause 1.48.2.

Define:

MaxL(k) is the nominated load level for Intermittent Load k to apply for Trading Month n as specified in clause 4.28.8(c);
RM is the reserve margin for the Reserve Capacity Cycle defined as negative one plus the ratio of the Reserve Capacity Requirement for the relevant Capacity Year as described in clause 4.6.1 and the expected peak demand for the relevant Capacity Year as described in clause 4.6.2;

Calculate Req(k), which equals MaxL(k) multiplied by RM.

When setting the Individual Intermittent Load Reserve Capacity Requirement for an Intermittent Load k for a Trading Month n in accordance with Appendix 5:

If, at the time AEMO determines the Indicative Individual Reserve Capacity Requirements for Trading Month n, Intermittent Load k is registered and operating or AEMO reasonably expects it to be registered and operating during Trading Month n (based on information provided to AEMO in accordance with clause 4.28.8(c)), then set the Individual Intermittent Load Reserve Capacity Requirement for Intermittent Load k equal to Req(k).
If, at the time AEMO determines the Indicative Individual Reserve Capacity Requirements for Trading Month n, AEMO reasonably expects Intermittent Load k not to be registered or operating during Trading Month n (based on information provided to AEMO in accordance with clause 4.28.8(c)), then set the Individual Intermittent Load Reserve Capacity Requirement for Intermittent Load k equal to zero.

Explanatory Note

Appendix 5 is amended so that the calculation of the IRCR for a Market Participant with an Electric Storage Resource does not include any Trading Intervals where AEMO has issued a direction under clause 7.7.5 in respect of the Electric Storage Resource.

Appendix 5 is amended to clarify the treatment of Intermittent Loads, and differentiate between Intermittent Loads registered before and after the New WEM Commencement Day. The treatment of existing Intermittent Loads is unchanged.

Appendix 5: Individual Reserve Capacity Requirements

This Appendix presents the method that must be used by AEMO to determine, for a Trading Month n:

Individual Reserve Capacity Requirement Contributions as required for the determination of Relevant Demands under clause 4.26.2CA;
Indicative Individual Reserve Capacity Requirements as required under clause 4.28.6;
Individual Reserve Capacity Requirements as required under clause 4.28.7; and
revised Individual Reserve Capacity Requirements as required under clause 4.28.11A.

AEMO must perform Steps 1 to 10A to determine the Indicative Individual Reserve Capacity Requirements, Individual Reserve Capacity Requirements or revised Individual Reserve Capacity Requirements for Trading Month n.

AEMO must perform Step 11 as required to determine the Individual Reserve Capacity Requirement Contribution of an individual metered Associated Load for Trading Month n, using as input the relevant values calculated by AEMO when it determined the Indicative Individual Reserve Capacity Requirements for Trading Month n.

For the purpose of this Appendix:

1. All references, apart from those in Step 5A, to meters are interval meters.

2. The Notional Wholesale Meter is to be treated as a registered interval meter measuring Temperature Dependent Load. This meter is denoted by Temperature Dependent Load meter v=v*.

3. The New Notional Wholesale Meter, determined in accordance with Step 5A, is to be treated as a registered interval meter measuring Temperature Dependent Load.

4. A meter measuring a Facility containing an Intermittent Load, that is and continues to be deemed to be an Intermittent Load under clause 1.48.2, is to be included in these calculations as if it were two meters, one representing the Intermittent Load and included in the set indexed by w, and one representing other load at the Facility and included in the set indexed by u or v as applicable, with metered consumption calculated according to clause 2.30B.10 and clause 11 of this Appendix 5.

5. A meter measuring a Facility containing an Intermittent Load, for which an application was approved under clause 2.30B.6 on or after New WEM Commencement Day, is to be included in these calculations as a single meter representing a Non-Dispatchable Load and included in the set indexed by u or v as applicable, with metered consumption calculated according to clause 2.30B.11 and clause 12 of this Appendix 5.

6. The meter registration data to be used in the calculations is to be the most current complete set of meter registration data as at the time of commencing the calculations.

7. The 12 Peak SWIS Trading Intervals to be used in the calculations are the 12 Peak SWIS Trading Intervals determined and published by AEMO under clause 4.1.23A for the Hot Season preceding the start of the Capacity Year in which Trading Month n falls (the “preceding Hot Season”).

8. The 4 Peak SWIS Trading Intervals for a Trading Month to be used in the calculations are the 4 Peak SWIS Trading Intervals determined and published by AEMO under clause 4.1.23B for that Trading Month.

9. When calculating the Indicative Individual Reserve Capacity Requirements it is assumed that all meters registered to a Market Participant on the day of calculation will remain registered to that Market Participant for the entirety of Trading Month n.

10. A meter measuring a Scheduled Facility, Semi-Scheduled Facility or Non-Scheduled Facility not containing an Intermittent Load is to be included in these calculations and included in the set indexed by u or v as applicable, with metered consumption calculated in accordance with clause 12 of this Appendix 5.

11. Each meter measuring an Aggregated Facility is to be included as a separate meter and included in the set indexed by u or v as applicable, with metered consumption calculated in accordance with clause 12 of this Appendix 5.

12. Metered consumption for meter m, in Trading Interval t, is zero when AEMO issues a direction under clause 7.7.5 in respect of an Electric Storage Resource associated with m for a Dispatch Interval within t, otherwise it is -1 x min(0, SOMS(m, t)), where SOMS(m, t) is the Sent Out Metered Schedule of m in t.

Step 1: Calculate:

RR = min(RCR, CC)

FL = FL_RCR × RR / RCR

where:

RCR is the Reserve Capacity Requirement for the relevant Reserve Capacity Cycle

CC is the total number of Capacity Credits assigned for Trading Month n at the time of the calculation

FL_RCR is the peak demand associated with the Reserve Capacity Requirement for the relevant Reserve Capacity Cycle as specified in clause 4.6.2

Step 2: For each meter, u, measuring Non-Temperature Dependent Load that was registered with AEMO for all of the 12 Peak SWIS Trading Intervals determine NTDL(u), where:

NTDL(u) is the contribution to the system peak load of meter u during the preceding Hot Season where this contribution is double the median value of the metered consumption during the 12 Peak SWIS Trading Intervals

Step 3: For each meter, v, measuring Temperature Dependent Load that was registered with AEMO for all of the 12 Peak SWIS Trading Intervals determine TDL(v), where:

TDL(v) is the contribution to the system peak load of meter v during the preceding Hot Season where this contribution is double the median value of the metered consumption during the 12 Peak SWIS Trading Intervals

Step 4: For each Intermittent Load meter w set its Individual Intermittent Load Reserve Capacity Requirement, IILRCR(w), to equal the amount defined in accordance with Appendix 4A.

Step 5: Identify meters that were not registered with AEMO during one or more of the 12 Peak SWIS Trading Intervals but which were registered by the end of Trading Month n.

For a new meter u that measures Non-Temperature Dependent Load set NMNTCR(u) to be 1.1 times the MW figure formed by doubling the median value of the metered consumption for that meter during the 4 Peak SWIS Trading Intervals of Trading Month n-3.

For a new meter v that measures Temperature Dependent Load set NMTDCR(v) to be 1.3 times the MW figure formed by doubling the median value of the metered consumption for that meter during the 4 Peak SWIS Trading Intervals of Trading Month n-3.

Step 5A:

Find the MW figure formed by doubling the median value of the metered consumption for the Notional Wholesale Meter v*, during the 4 Peak SWIS Trading Intervals of Trading Month n-3 (“Median Notional Wholesale Meter”).

Divide the Median Notional Wholesale Meter by the number of non-interval or accumulation meters that existed at the end of Trading Month n-3 (“Average Non - Interval Meter”).

Subtract the number of non-interval or accumulation meters disconnected between the end of the preceding Hot Season and the end of Trading Month n-3 from the number of non-interval or accumulation meters connected between the end of the preceding Hot Season and the end of Trading Month n-3 (“Non-Interval Meter Growth”).

Multiply the Non-Interval Meter Growth and the Average Non-Interval Meter. (“New Notional Wholesale Meter”).

For the New Notional Wholesale Meter set NMTDCR(v) equal to be 1.3 times the New Notional Wholesale Meter.

Step 6: Calculate the values of d(u,i) for Non-Temperature Dependent Load, d(v,i) for Temperature Dependent Loads and d(w,i) for Intermittent Loads such that:

d(u,i) has a value of zero if meter u measures Intermittent Load or was not registered to Market Participant i during Trading Month n, otherwise it has a value equal to the number of full Trading Days the meter was registered to Market Participant i in Trading Month n divided by the number of days in Trading Month n.
d(v,i) has a value of zero if meter v measures Intermittent Load or was not registered to Market Participant i during Trading Month n, otherwise it has a value equal to the number of full Trading Days the meter was registered to Market Participant i in Trading Month n divided by the number of days in Trading Month n.
d(w,i) has a value of zero if meter w was not registered to Market Participant i during Trading Month n, otherwise it has a value of one if Market Participant i nominated capacity for the Intermittent Load measured by meter w in accordance with clause 4.28.8(c), with the exception that if the Intermittent Load was for Load at a meter registered to Market Participant i for only part of Trading Month n, then it has a value equal to the number of full Trading Days that meter was registered to Market Participant i in Trading Month n divided by the number of days in Trading Month n.

Step 7: Identify the set NM of all those new meters v that measured consumption that was measured by meter v=v* during the preceding Hot Season and set TDLn(v) for meter v=v* to equal:

TDLn(v*) = TDL(v*) – Sum(v∈NM, NMTDCR(v))

Step 8: For each Market Participant i, calculate:

ILRCR(i) = Sum(IILRCR(w) × d(w,i))

Step 8A: Calculate:

NRR = RR – Sum(i, ILRCR(i))

NTDL_Ratio = NRR / FL

Step 8B: For each Market Participant i, calculate:

NTDLRCR(i) = Sum(NTDL(u) × d(u,i)) × NTDL_Ratio

Step 8C: Calculate:

TDL_Ratio = (NRR ‑ Sum(i, NTDLRCR(i))) /
Sum(i, Sum(MTDL(v) × d(v,i)))

where

MTDL(v) = TDL(v) for all v except v* and
MTDL(v) = TDLn(v*) for v=v*

Step 8D: For each Market Participant i, calculate:

TDLRCR(i) = (Sum MTDL(v) × d(v,i)) × TDL_Ratio

Step 9: For each Market Participant i, calculate

X(i) = Sum(i, ILRCR(i) + NTDLRCR(i) + TDLRCR(i)) + Sum(u, NMNTCR(u) × d(u,i)) + Sum(v, NMTDCR(v) × d(v,i))

Step 10: Calculate:

Total_Ratio = RR / Sum(i, X(i))

Step 10A: For each Market Participant i, set the Indicative Individual Reserve Capacity Requirement or Individual Reserve Capacity Requirement, as applicable, for Trading Month n to:

X(i) × Total_Ratio

Step 11: The Individual Reserve Capacity Requirement Contribution of an individual metered Associated Load for Trading Month n of a Capacity Year is determined as follows:

$a$ for meter u at a connection point measuring Non-Temperature Dependent Load that was registered with AEMO for all of the 12 Peak SWIS Trading Intervals equals (NTDL(u) x NTDL_Ratio x Total_Ratio);

$b$ for meter v at a connection point measuring Temperature Dependent Load that was registered with AEMO for all of the 12 Peak SWIS Trading Intervals equals (TDL(v) x TDL_Ratio x Total_Ratio);

$c$ for meter u at a new connection point identified in Step 5 measuring Non-Temperature Dependent Load equals (NMNTCR(u) x Total_Ratio); and

$d$ for meter v at a new connection point identified in Step 5 measuring Temperature Dependent Load equals (NMTDCR(v) x Total_Ratio).

Explanatory Note

Appendix 5A is amended to clarify that Registered Facilities can be assessed for NTDL status, and to reflect the new registration taxonomy.

Appendix 5A is amended to require AEMO to assess the NTDL status of non-aggregated Scheduled Facilities, Semi-Scheduled Facilities and Non-Scheduled Facilities (which may be served by multiple network connection points/NMIs) the same way as for Aggregated Facilities, i.e. on a per-connection point/NMI basis. The current drafting requires AEMO to process non-aggregated Registered Facilities on a per-Facility basis, which is unwarranted and would impose additional IT costs on AEMO.

Appendix 5A is also amended to:

clarify that Scheduled Facilities, Semi-Scheduled Facilities and Non-Scheduled Facilities are the only Registered Facilities to which applications for NTDL assessment apply; and
correct clause references in the introduction and in Step 2.

Appendix 5A: Non-Temperature Dependent Load Requirements

This Appendix specifies how AEMO must determine whether or not to accept a Load measured by an interval meter nominated in accordance with clauses 4.28.8(a) or 4.28.8C as a Non-Temperature Dependent Load for the purposes of clause 4.28.9.

For the purpose of this Appendix:

AEMO must use the current set of meter data (as at the time when it commences its calculations);
the 4 Peak SWIS Trading Intervals in a Trading Month are the 4 Peak SWIS Trading Intervals determined and published by AEMO under clause 4.1.23B for that Trading Month; and

AEMO must treat each connection point measured by an interval meter measuring a Scheduled Facility, Semi-Scheduled Facility or Non‑Scheduled Facility as if it were a separate Non-Dispatchable Load.

AEMO must perform the following steps (in sequential order) when determining whether or not to accept a Load measured by an interval meter nominated in accordance with clauses 4.28.8(a) or 4.28.8C as a Non-Temperature Dependent Load for the purposes of clause 4.28.9:

Step 1:

If, in accordance with clause 4.28.8(a), the Market Participant provides AEMO in Trading Month n-2 with the identity of an interval meter associated with that Market Participant which measures a Load that it nominates as a Non-Temperature Dependent Load from Trading Month n;
If the identity of the interval meter is provided by the date and time specified in clause 4.1.23; and
If the Load was treated as a Non-Temperature Dependent Load in Trading Month n-8,

then AEMO must accept the Load as a Non-Temperature Dependent Load if:

$a$ the median value of the metered consumption for the Load, calculated for the set of Trading Intervals defined as the 4 Peak SWIS Trading Intervals in each of the Trading Months starting from the start of Trading Month n-11 to the end of Trading Month n-3, exceeded 1.0 MWh; and

$b$ the metered consumption for the Load did not deviate downwards from the median value in paragraph (a) by more than 10% for more than 10% of the time during the period from the start of Trading Month n-11 to the end of Trading Month n-3, except during Trading Intervals for which:

i. the metered consumption was 0 MWh; or

ii. consumption was reduced at the request of AEMO; or

iii. AEMO has accepted a Consumption Deviation Application for the Load under clause 4.28.9D.

Step 2:

If, in accordance with clauses 4.28.8(a) or 4.28.8C, the Market Participant provides AEMO in Trading Month n-2 with the identity of an interval meter associated with that Market Participant which measures a Load that it nominates as a Non-Temperature Dependent Load from Trading Month n;
If the Load was not treated as a Non-Temperature Dependent Load in Trading Month n-1; and
If the Load was not treated as a Non-Temperature Dependent Load for any of the Trading Months in the Capacity Year in which Trading Month n falls,

then AEMO must accept the Load as a Non-Temperature Dependent Load for Trading Month n if:

$a$ the median value of the metered consumption for the Load during the 4 Peak SWIS Trading Intervals in Trading Month n-3 exceeded 1.0 MWh; and

$b$ the metered consumption for the Load did not deviate downwards from the median value in paragraph (a) by more than 10% for more than 10% of the time during Trading Month n-3, except during Trading Intervals for which:

i. the metered consumption was 0 MWh; or

ii consumption was reduced at the request of AEMO; or

iii. AEMO has accepted a Consumption Deviation Application for the Load under clause 4.28.9D.

Step 3:

If a Load was not accepted under Step 1 as a Non-Temperature Dependent Load for Trading Month n; and
If the Load was accepted under Step 2, or previously under this Step 3, as a Non-Temperature Dependent Load for Trading Month n-1,

then AEMO must accept the Load as a Non-Temperature Dependent Load for Trading Month n if:

$a$ the median value of the metered consumption for the Load, calculated for the set of Trading Intervals defined as the 4 Peak SWIS Trading Intervals in each of the Trading Months commencing at the start of the Trading Month for which metered consumption was used by AEMO to accept the Load as a Non-Temperature Dependent Load under Step 2 to the end of Trading Month n-3, exceeded 1.0 MWh; and

$b$ the metered consumption for the Load did not deviate downwards from the median value in paragraph (a) by more than 10% for more than 10% of the time during the period from the start of the Trading Month for which metered consumption was used by AEMO to accept the Load as a Non-Temperature Dependent Load under Step 2 to the end of Trading Month n-3, except during Trading Intervals for which:

i. the metered consumption was 0 MWh; or

ii. consumption was reduced at the request of AEMO; or

iii. AEMO has accepted a Consumption Deviation Application for the Load under clause 4.28.9D.

Step 4:

Otherwise, AEMO must treat a Load as a Temperature Dependent Load.

Explanatory Note

Appendix 6(b) and Appendix 6(c) are amended to implement an alternative to the use of Participant Interval Minimum STEM Price and Participant Interval Maximum STEM Price. Under the alternative approach:

if the minimum STEM Price Curve quantity is equal to the maximum STEM Price Curve quantity for every price between the Minimum STEM Price and the Alternative Maximum STEM Price (i.e. there are no entries in the STEM Price Curve with a non-zero quantity range) then the STEM Price Curve entry for the Minimum STEM Price or Alternative Maximum STEM Price (as applicable) is adjusted to cover the Net Bilateral Position; and
otherwise, the lowest-price or highest-price entry (as applicable) in the STEM Price Curve which has a non-zero quantity range is adjusted to cover the Net Bilateral Position.

Appendix 6: STEM Price Curve Determination

The first part of this appendix describes a process for converting a Market Participant’s Portfolio Supply Curve and Portfolio Demand Curve into a single STEM Price Curve and to then convert a Market Participant’s STEM Price Curve into STEM Bids and STEM Offers relative to its Net Bilateral Position.

For each Market Participant and for each Trading Interval in the Trading Day except those for which AEMO has recorded that the Market Participant has not made a STEM Submission:

$a$ Determine for every price between the Energy Offer Price Floor and the Energy Offer Price Ceiling:

i. the maximum cumulative quantity the Market Participant is prepared to sell into the STEM from all of its Price-Quantity Pairs in its Portfolio Supply Curve;

ii. the minimum cumulative quantity the Market Participant is prepared to sell into the STEM from all of its Price-Quantity Pairs in its Portfolio Supply Curve;

iii. the maximum cumulative quantity the Market Participant is prepared to buy from the STEM from all of its Price-Quantity Pairs in its Portfolio Demand Curve;

iv. the minimum cumulative quantity the Market Participant is prepared to buy from the STEM from all of its Price-Quantity Pairs in its Portfolio Demand Curve;

v. the STEM Price Curve quantity for that price where:

1. the minimum STEM Price Curve quantity for that price equals the value in Appendix 6(a)(ii) less the value in Appendix 6(a)(iii);

2. the maximum STEM Price Curve quantity for that price equals the value in Appendix 6(a)(i) less the value in Appendix 6(a)(iv); and

3. the STEM Price Curve for that price includes all quantities between those in Appendix 6(a)(v)(1) and Appendix 6(a)(v)(2).

$b$ If the minimum of the quantities determined under Appendix 6(a)(v)(1) for the Market Participant for the Trading Interval is greater than the Net Bilateral Position of the Market Participant in the Trading Interval then:

i. if, for every price between the Energy Offer Price Floor and the Energy Offer Price Ceiling, the quantity determined under Appendix 6(a)(v)(1) is equal to the quantity determined under Appendix 6(a)(v)(2), then amend the STEM Price Curve for the Energy Offer Price Floor to include all quantities between the Net Bilateral Position of the Market Participant and the quantity determined for the Energy Offer Price Floor under Appendix 6(a)(v)(2); and

ii. otherwise, amend the STEM Price Curve for the lowest price for which the quantity determined under Appendix 6(a)(v)(1) is not equal to the quantity determined under Appendix 6(a)(v)(2), to include all quantities between the Net Bilateral Position of the Market Participant and the quantity determined for the price under Appendix 6(a)(v)(2).

$c$ If the maximum of the quantities determined under Appendix 6(a)(v)(2) for the Market Participant for the Trading Interval is less than the Net Bilateral Position of the Market Participant then:

i. if, for every price between the Energy Offer Price Floor and the Energy Offer Price Ceiling, the quantity determined under Appendix 6(a)(v)(1) is equal to the quantity determined under Appendix 6(a)(v)(2), then amend the STEM Price Curve for the Energy Offer Price Ceiling to include all quantities between the quantity determined for the Energy Offer Price Ceiling under Appendix 6(a)(v)(1) and the Net Bilateral Position of the Market Participant; and

ii. otherwise, amend the STEM Price Curve for the highest price for which the quantity determined under Appendix 6(a)(v)(1) is not equal to the quantity determined under Appendix 6(a)(v)(2), to include all quantities between the quantity determined for the price under Appendix 6(a)(v)(1) and the Net Bilateral Position of the Market Participant.

$d$ If the Net Bilateral Position equals the minimum STEM Price Curve quantity then there are no STEM Bids, otherwise:

i. for the STEM Price Curve between the minimum STEM Price Curve quantity and the Net Bilateral Position of that Market Participant identify each price for which more than one STEM Price Curve quantity is defined;

ii. for each price identified in Appendix 6(d)(i) identify the minimum STEM Price Curve quantity for which that price applies, such that the STEM Price Curve quantity lies between the minimum STEM Price Curve quantity and the Net Bilateral Position;

iii. for each price identified in Appendix 6(d)(i) identify the maximum STEM Price Curve quantity for which that price applies, such that the STEM Price Curve quantity lies between the minimum STEM Price Curve quantity and the Net Bilateral Position;

iv. for each price identified in Appendix 6(d)(i) set a Price-Quantity Pair price equal to that price;

v. for each price identified in Appendix 6(d)(i) set a Price-Quantity Pair quantity equal to the quantity defined in Appendix 6(d)(iii) less the quantity defined in Appendix 6(d)(ii); and

vi. set the Market Participant’s STEM Bids to be the set of Price-Quantity Pairs defined in Appendix 6(d)(iv) and Appendix 6(d)(v) where each Price-Quantity Pair means that the Market Participant is prepared to buy a quantity of energy from the STEM for that Price-Quantity Pair equal to:

1. 0 MWh if the STEM Clearing Price is greater than the Price-Quantity Pair price;

2. the Price-Quantity Pair quantity if the STEM Clearing Price is less than the Price-Quantity Pair price; and

3. an amount between 0 MWh and the Price-Quantity Pair quantity if the STEM Clearing Price equals the Price-Quantity Pair price.

$e$ If the Net Bilateral Position equals the maximum STEM Price Curve quantity then there are no STEM Offers, otherwise:

i. for the STEM Price Curve between the Net Bilateral Position of that Market Participant and the maximum STEM Price Curve quantity identify each price for which more than one STEM Price Curve quantity is defined;

ii. for each price identified in Appendix 6(e)(i) identify the minimum STEM Price Curve quantity for which that price applies, such that the STEM Price Curve quantity lies between the Net Bilateral Position and the maximum STEM Price Curve quantity;

iii. for each price identified in Appendix 6(e)(i) identify the maximum STEM Price Curve quantity for which that price applies, such that the STEM Price Curve quantity lies between the minimum STEM Price Curve quantity and the Net Bilateral Position;

iv. for each price identified in Appendix 6(e)(i) set a Price-Quantity Pair price equal to that price;

v. for each price identified in Appendix 6(e)(i) set a Price-Quantity Pair quantity equal to the quantity defined in Appendix 6(e)(iii) less the quantity defined in Appendix 6(e)(ii); and

vi. set the Market Participant’s STEM Offers to be the set of Price-Quantity Pairs defined in Appendix 6(e)(iv) and Appendix 6(e)(v) where each Price-Quantity Pair means that the Market Participant is prepared to sell a quantity of energy into the STEM for that Price-Quantity Pair equal to:

1. 0 MWh if the STEM Clearing Price is less than the Price-Quantity Pair price;

2. the Price-Quantity Pair quantity if the STEM Clearing Price is greater than the Price-Quantity Pair price; and

3. an amount between 0 MWh and the Price-Quantity Pair quantity if the STEM Clearing Price equals the Price-Quantity Pair price.

Appendix 7: [Blank]

Appendix 8: [Blank]

Explanatory Note

Appendix 9 is amended as follows:

Where an upgrade to a Facility comprises a component that is not being certified for Reserve Capacity using the Relevant Level Methodology, the ‘Full Operation Date’ for a Candidate Facility that is also a component of that Facility remains unaffected.
Where a Candidate Facility is a component of a Facility that also contains a component that is not being certified for Reserve Capacity using the Relevant Level Methodology, the quantity of sent out electricity that is determined or estimated for the Candidate Facility under the Relevant Level Methodology must exclude any generation or consumption associated with the other component as measured by Facility Sub-Metering.
The requirement for AEMO to publish the information previously in 10.5.1(f)(x) has been moved to new step 21.

Appendix 9: Relevant Level Determination

Part A: Introduction

Interpretations and Definitions

A.1. This Appendix 9 presents the methodology for determining the Relevant Levels for Candidate Facilities for a given Reserve Capacity Cycle.

A.2. In this Appendix 9:

$a$ a Candidate Facility is a Facility, or a component of a Facility, for which:

i. a Market Participant has applied for:

1. Certified Reserve Capacity for the relevant Reserve Capacity Cycle under section 4.9;

2. Conditional Certified Reserve Capacity for a future Reserve Capacity Cycle under section 4.9, where AEMO is required under clause 4.9.7A to process the application at the time it processes applications for Certified Reserve Capacity for the relevant Reserve Capacity Cycle; or

3. Early Certified Reserve Capacity for a Reserve Capacity Cycle under clause 4.28C.2, where AEMO is required to process the application at the time it processes applications for Certified Reserve Capacity for the relevant Reserve Capacity Cycle;

ii. the Market Participant’s application includes all supporting information required under section 4.10 or clause 4.28C.5 (as applicable); and

iii. the Certified Reserve Capacity, Conditional Certified Reserve Capacity or Early Certified Reserve Capacity (as applicable) is required to be determined in accordance with clause 4.11.2(b);

$b$ the full operation date of a Candidate Facility for the relevant Reserve Capacity Cycle (“Full Operation Date”) is:

i. the date provided under clause 4.10.1(c)(iii)(7) or revised in accordance with clause 4.27.11A, where at the time the application for certification of Reserve Capacity is made the Candidate Facility is yet to enter service; or

ii. the date most recently provided for a Reserve Capacity Cycle under clause 4.10.1(k) otherwise; and

$c$ a Candidate Facility will be considered to be:

i. a new Candidate Facility if the five-year period identified in Step 1(a) of this Appendix 9 commenced before 8:00 AM on the Full Operation Date for the Facility (“New Candidate Facility”); or

ii. an existing Candidate Facility (“Existing Candidate Facility”) otherwise.

A.3. AEMO must determine the Relevant Levels for Candidate Facilities for a given Reserve Capacity Cycle by following each of the steps set out in Part B of this Appendix 9.

Part B: Process Steps

Determining Existing Facility Load for Scheduled Generation

Step 1: Identify:

$a$ the five year period ending at 8:00 AM on 1 April of Capacity Year 1 of the relevant Reserve Capacity Cycle;

$b$ any 12 month period, from 1 April to 31 March, occurring during the five year period identified in Step 1(a), where the 12 Trading Intervals with the highest Existing Facility Load for Scheduled Generation in that 12 month period have not previously been determined under this Appendix 9; and

$c$ any 12 month period, from 1 April to 31 March, occurring during the five year period identified in Step 1(a), where the 12 Trading Intervals with the highest Existing Facility Load for Scheduled Generation in that 12 month period have previously been determined under this Appendix 9.

Step 2: Determine the quantity of electricity (in MWh) sent out by each Candidate Facility:

$a$ using Facility Sub-Metering, where the Candidate Facility is a component of a Facility for which Facility Sub-Metering is required to be installed; and

$b$ using Sent Out Metered Schedules, where the Candidate Facility is not a component of a Facility for which Facility Sub-Metering is required to be installed,

for each of the Trading Intervals in the period identified in Step 1(b).

Step 3: For each Candidate Facility, identify any Trading Intervals in the period identified in Step 1(b) where:

$a$ the Candidate Facility, other than a Facility in the Balancing Portfolio, was directed to restrict its output under a Dispatch Instruction as provided in a schedule under clause 7.13.1(c); or

$b$ the Candidate Facility, if in the Balancing Portfolio, was instructed by AEMO to deviate from its Dispatch Plan or change its commitment or output as provided in a schedule under clause 7.13.1C(d); or

$c$ the Candidate Facility was affected by a Consequential Outage; or

$d$ the Candidate Facility was directed to restrict its output under an Operating Instruction issued in accordance with a NCESS Contract, as provided in a schedule under clause 7.13.1(cC).

Step 4: For each Candidate Facility and Trading Interval identified in Step 3(a):

$a$ identify the actual quantity as determined in Step 2 if:

i. AEMO has made a revised estimate of the maximum quantity in accordance with clause 7.7.5A(c) and the WEM Procedure specified in clause 7.7.5A; and

ii. the revised estimate of the maximum quantity is lower than the actual quantity as determined in Step 2;

$b$ identify the actual quantity as determined in Step 2 if:

i. Step 4(a) does not apply; and

ii. the estimated maximum quantity determined by AEMO under clause 7.13.1(eF) is lower than the actual quantity as determined in Step 2; and

$c$ if Steps 4(a) and 4(b) do not apply:

i. identify the revised estimate of the maximum quantity determined by AEMO in accordance with the WEM Procedure specified in clause 7.7.5A; or

ii. if there is no revised estimate, identify the estimate determined by AEMO under clause 7.13.1(eF).

Step 5: For each Candidate Facility and Trading Interval identified in Step 3(b) use:

$a$ the estimate recorded by AEMO under clause 7.13.1C(e); and

$b$ the quantity determined for the Candidate Facility and Trading Interval in Step 2,

to estimate the quantity of energy (in MWh) that would have been sent out by the Candidate Facility had it not complied with AEMO’s instruction to change its commitment or output during the Trading Interval.

Step 6: For each Candidate Facility and Trading Interval identified in Step 3(c) use:

$a$ the Unadjusted Consequential Outage Quantity for the Candidate Facility for the Trading Interval;

$b$ the quantity determined for the Candidate Facility and Trading Interval in Step 2; and

$c$ the information recorded by AEMO under clause 7.13.1C(a),

to estimate the quantity of energy (in MWh) that would have been sent out by the Candidate Facility had it not been affected by the Consequential Outage during the Trading Interval.

Step 6A: For each Candidate Facility and Trading Interval identified in Step 3(d) use:

$a$ the schedule of Operating Instructions determined by AEMO under clause 7.13.1(cC);

$b$ the quantity determined for the Candidate Facility and Trading Interval in Step 2; and

$c$ the information recorded by AEMO under clause 7.13.1C(a),

to estimate the quantity of energy (in MWh) that would have been sent out by the Candidate Facility had it not been subject to an Operating Instruction during the Trading Interval.

Step 7: Determine for each Trading Interval in each 12 month period identified in Step 1(b) the Existing Facility Load for Scheduled Generation (in MWh) as:

(Total_Generation + DSP_Reduction + Interruptible_Reduction + Involuntary_Reduction) – CF_Generation

where

Total_Generation is the Total Sent Out Generation of all Registered Facilities;

DSP_Reduction is the total quantity of Deemed DSM Dispatch for all Demand Side Programmes for that Trading Interval;

Interruptible_Reduction is the total quantity by which all Interruptible Loads reduced their consumption in accordance with the terms of an Ancillary Service Contract, as recorded by AEMO under clause 7.13.1C(c);

Involuntary_Reduction is the total quantity of energy not served due to involuntary load shedding (manual and automatic), as recorded by AEMO under clause 7.13.1C(b); and

CF_Generation is the total sent out generation of all Candidate Facilities, as determined in Step 2 or estimated in Steps 4, 5, 6 or 6A as applicable.

Step 8: Determine for each 12 month period identified in Step 1(b) the 12 Trading Intervals, occurring on separate Trading Days, with the highest Existing Facility Load for Scheduled Generation.

Step 9: Identify, for each 12 month period identified in Step 1(c), the following:

$a$ the Existing Facility Load for Scheduled Generation previously determined under this Appendix 9 for each Trading Interval in the 12 month period;

$b$ subject to Step 9A, the sent out generation (in MWh) for each Candidate Facility and for each Trading Interval in that 12 month period, where that sent out generation was used to determine the CF_Generation (which is one of the variables used to determine the Existing Facility Load for Scheduled Generation in Step 7) for that Trading Interval; and

$c$ the 12 Trading Intervals occurring on separate Trading Days that were previously determined to have the highest Existing Facility Load for Scheduled Generation in the 12 month period.

Step 9A: For the purposes of Step 9(b), if:

$a$ AEMO has determined a revised estimate of the maximum quantity in accordance with the WEM Procedure specified in clause 7.7.5A;

$b$ the revised estimate relates to a Candidate Facility and a Trading Interval in a 12 month period identified in Step 1(c); and

$c$ AEMO determined the sent out generation for that Candidate Facility and for that Trading Interval in accordance with Step 4 before it revised the estimate,

then AEMO must redetermine the sent out generation for that Candidate Facility and that Trading Interval in accordance with Step 4.

Determining New Facility Load for Scheduled Generation

Step 10: For each New Candidate Facility determine, for each Trading Interval in the period identified in Step 1(a) that falls before 8:00 AM on the Full Operation Date for the Candidate Facility, an estimate of the quantity of energy (in MWh) that would have been sent out by the Candidate Facility in the Trading Interval, if it had been in operation with the configuration proposed under clause 4.10.1(dA) in the relevant application for certification of Reserve Capacity. The estimates must reflect the estimates in the expert report provided for the Candidate Facility under clause 4.10.3, unless AEMO reasonably considers the estimates in the expert report to be inaccurate.

Step11: For each New Candidate Facility determine, for each Trading Interval in the period identified in Step 1(a), the New Facility Load for Scheduled Generation (in MWh) as:

$a$ if the Trading Interval falls before 8:00 AM on the Full Operation Date for the Facility:

EFLSG + Actual_CF_Generation – Estimated_CF_Generation

where

EFLSG is the Existing Facility Load for Scheduled Generation for the Trading Interval, determined in Step 7 or identified in Step 9(a) as applicable;

Actual_CF_Generation is the sent out generation of the New Candidate Facility for the Trading Interval, as identified in Step 9(b), determined in Step 2 or estimated in Steps 4, 5, 6 or 6A as applicable; and

Estimated_CF_Generation is the quantity determined for the New Candidate Facility and the Trading Interval in Step 10;

or

$b$ the Existing Facility Load for Scheduled Generation for the Trading Interval, otherwise.

Step 12: For each New Candidate Facility determine, for each 12 month period identified in Step 1(a), the 12 Trading Intervals, occurring on separate Trading Days, with the highest New Facility Load for Scheduled Generation.

Determining the Facility Average Performance Level

Step 13: For each Existing Candidate Facility, determine the 60 quantities comprising:

$a$ the MWh quantities determined in Step 2 or estimated in Steps 4, 5, 6 or 6A as applicable for each of the Trading Intervals determined in Step 8, multiplied by 2 to convert to units of MW; and

$b$ the MWh quantities determined in Step 9(b) for each of the Trading Intervals identified in Step 9(c), multiplied by 2 to convert to units of MW.

Step 14: For each New Candidate Facility, determine the 60 quantities comprising:

$a$ the MWh quantities identified in Step 9(b), determined in Step 2 or estimated in Steps 4, 5, 6 or 6A as applicable for each of the Trading Intervals identified in Step 12 that fall after 8:00 AM on the Full Operation Date for the Candidate Facility, multiplied by 2 to convert to units of MW; and

$b$ the MWh quantities determined in Step 10 for each of the Trading Intervals identified in Step 12 that fall before 8:00 AM on the Full Operation Date of the Candidate Facility, multiplied by 2 to convert to units of MW.

Step 15: Determine the average performance level (in MW) for each Candidate Facility f (“Facility Average Performance Level”) as the mean of the 60 quantities determined for Candidate Facility f in Step 13 or Step 14 as applicable.

Determine the Facility Adjustment Factor

Step 16: Determine the variance (in MW) for each Candidate Facility f (“Facility Variance”) as the variance of the MW quantities determined for Candidate Facility f in Step 13 or Step 14 as applicable.

Step 17: Determine the facility adjustment factor (in MW) for each Candidate Facility f (“Facility Adjustment Factor”) in accordance with the following formula:

Facility Adjustment Factor = min(G x Facility Variance (f), Facility Average Performance Level (f) / 3 + K x Facility Variance (f))

Where

G = K + U / Facility Average Performance Level (f)

K is determined in accordance with the following table:

Reserve Capacity Cycle	Capacity Year	K value
2012	2014/15	0.001
2013	2015/16	0.002
2014	2016/17	0.003
2015 onwards	From 2017/18 onwards	To be determined by the Economic Regulation Authority in accordance with clause 4.11.3C.

U is determined in accordance with the following table:

Reserve Capacity Cycle	Capacity Year	U
2012	2014/15	0.211
2013	2015/16	0.422
2014	2016/17	0.635
2015 onwards	From 2017/18 onwards	To be determined by the Economic Regulation Authority in accordance with clause 4.11.3C.

Determining the Relevant Level for a Candidate Facility

Step 18: Determine the Relevant Level for each Candidate Facility f (in MW) in accordance with the following formula:

Relevant Level (f) = max(0, Facility Average Performance Level (f) - Facility Adjustment Factor (f))

Publication of information

Step 19: Publish on the WEM Website by 1 June of Year 1 of the relevant Reserve Capacity Cycle on a provisional basis:

$a$ a forecast of the Trading Intervals that may be identified in Step 8; and

$b$ a forecast of the Existing Facility Load for Scheduled Generation quantities that may be determined in Step 7.

Step 20: Publish on the WEM Website within three Business Days after the date specified in clause 4.1.11 (as modified or extended) for the relevant Reserve Capacity Cycle:

$a$ the Trading Intervals identified in Step 8; and

$b$ the Existing Facility Load for Scheduled Generation quantities determined in Step 7.

Step 21: Publish on the WEM Website the following information identified for a Reserve Capacity Cycle under the Relevant Level Methodology:

$a$ the Existing Facility Load for Scheduled Generation for each Trading Interval in the five year period determined under Step 1(a) of Appendix 9; and

$b$ the 12 Trading Intervals occurring on separate Trading Days with the highest Existing Facility Load for Scheduled Generation for each 12 month period in the five year period.

Appendix 10: Relevant Demand Determination

This Appendix sets out the 5th percentile methodology for determining the Relevant Demand for each Demand Side Programme, for use in clause 4.26.2CA(a).

The Relevant Demand value is to be re-calculated for each Demand Side Programme for each Trading Day.

Step 1

Identify the 200 Calendar Hours in the previous Capacity Year with the highest Total Sent Out Generation. The Calendar Hours do not have to be contiguous.

Step 2

For each Demand Side Programme, for each Calendar Hour identified in Step 1, for each of the Demand Side Programme’s Associated Loads, identify the quantity (expressed in MWh)[4] equal to—

$a$ unless paragraphs (b) or (c) apply, the Associated Load’s metered consumption for the two Trading Intervals in the Calendar Hour; or

$b$ unless paragraph (c) applies, if the Associated Load’s metered consumption is not available or is considered by AEMO to be inappropriate, a quantity determined by AEMO based on—

i. available Meter Data Submissions; or

ii. Load information provided by the Market Participant; or

iii. other relevant information; or

$c$ if AEMO has accepted a Consumption Deviation Application for the Associated Load under clause 4.26.2CB(b), AEMO’s estimate of what the consumption of the Associated Load would have been if it had not been affected.

Step 3

For each Demand Side Programme, for each Calendar Hour identified in Step 1, sum the values determined under Step 2 across all the Demand Side Programme’s Associated Loads.

Step 4

For each Demand Side Programme, rank the 200 values determined under Step 3 from lowest to highest.

The Demand Side Programme’s Relevant Demand is the tenth lowest value.

Appendix 11: [Blank]

Explanatory Note

Appendix 12 lists each of the Technical Requirements for Transmission Connected Generating Systems and sets out the Ideal Generator Performance Standard, Minimum Generator Performance Standard and any applicable Common Requirements for each Technical Requirement. These standards will apply to new Transmission Connected Generating Systems which connect to the Network. Existing Transmission Connected Generating Systems will be subject to a transitional regime.

Subsequent amendments make corrections and provide additional clarity. A summary of the changes are set out below.

Modifications to definitions

Credible Contingency Event – definition changed to match current Technical Rule definition and usage, and accompanying clause changes.
Settling Time – definition changed to address typographical errors.

Voltage and Reactive Power Control

Inclusion of clarifying wording in the footnotes and tables to provide consistency in interpretation.

Active Power Control

Inclusion of clarifying clause to ensure consistency of understanding and application of sections A12.5 and A12.6 requirements in relation to active power ramping under different conditions.

Inertia and Frequency Control

Movement of repeated requirements in both Ideal and Minimum Standards to the Common Requirements section for ease of application.
Clarity that tripping schemes will not be normally accepted to meet this standard going forward.
Improved definition of droop response.
Improved clarity on required frequency response under the Ideal Standard.
Introduction of a clear Minimum Standard, allowing for different technology types.

Disturbance Ride-Through

Clarifying that where an agreed tripping scheme does exist, it will not breach this standard.

Appendix 12: Transmission Connected Generating System Generator Performance Standards

This Appendix lists each of the Technical Requirements for Transmission Connected Generating Systems and sets out the Ideal Generator Performance Standard, Minimum Generator Performance Standard and any applicable Common Requirements for each Technical Requirement.

Each Technical Requirement may specify Negotiation Criteria which must be met if a Market Participant responsible for a Transmission Connected Generating System submits a Proposed Negotiated Generator Performance Standard.

If a Technical Requirement specifies Common Requirements, these apply whether an Ideal Generator Performance Standard or Negotiated Generator Performance Standard is intended to apply to a Transmission Connected Generating System in respect of a Technical Requirement.

Use of defined terms in this Appendix 12

Terms defined in Part A12.1 of this Appendix 12 are defined for the purposes of this Appendix alone and must not be used to infer the meaning of those words, or other words, in these WEM Rules. Terms which are defined in these WEM Rules will apply to this Appendix unless defined in this Appendix or the context otherwise requires.

Where the terms Scheduled Generator and Non-Scheduled Generator are used in this Appendix, in relation to generating works that are proposed to be connected to a transmission system and is yet to be registered under these WEM Rules as a Facility or a Facility that is undergoing an upgrade that may impact its Facility Class, these terms are to be used as they will ultimately apply to the relevant Facility.

The measurement location for each of the following terms, where they are used in this Appendix, is as specified in the relevant clause or, where applicable, by the relevant Network Operator in consultation with AEMO and recorded in the relevant Generator Performance Standard:

$a$ Rated Maximum Active Power;

$b$ Rated Maximum Apparent Power;

$c$ Maximum Continuous Current;

$d$ Rated Minimum Active Power;

$e$ Temperature Dependency Data; and

$f$ Generator Performance Chart.

When producing electric power, Electricity Storage which is part of a Generating System will be considered as Generation and must meet the Technical Requirements of Appendix 12.

Where the term 'Technical Rules' is used in this Appendix then the reference to the Technical Rules is to the Technical Rules of Western Power for the SWIS.

Where terms defined in Technical Rules are used in this Appendix, then any references to 'power system' in those definitions should be read as the SWIS.

For ease of reference, a list of the Technical Requirements that apply to Transmission Connected Generating Systems contained in this Appendix is set out below.

Appendix 12 Part	Technical Requirement
A12.2.	Active Power Capability
A12.3.	Reactive Power Capability
A12.4.	Voltage and Reactive Power Control
A12.5.	Active Power Control
A12.6.	Inertia and Frequency Control
A12.7.	Disturbance Ride Through for a Frequency Disturbance
A12.8.	Disturbance Ride Through for a Voltage Disturbance
A12.9.	Disturbance Ride Through for Multiple Disturbances
A12.10.	Disturbance Ride Through for Partial Load Rejection
A12.11.	Disturbance Ride Through for Quality of Supply
A12.12.	Quality of Electricity Generated
A12.13.	Generation Protection Systems
A12.14.	Remote Monitoring Requirements
A12.15.	Remote Control Requirements
A12.16.	Communications Equipment Requirements
A12.17.	Generation System Model

A12.1. Definitions

In this Appendix 12, the following terms are defined:

Active Power: As described in the Technical Rules.

Adequately Damped: As described in the Technical Rules.

Apparent Power: As described in the Technical Rules.

Asynchronous Generating System: Means a Generating System comprised

of Asynchronous Generating Units.

Asynchronous Generating Unit: Means a Generating Unit that is not a

Synchronous Generating Unit.

Communication Standard: Means the requirements for the provision of

information to be provided between Network Operators and AEMO as described in the WEM Procedure referred to in clause 2.36A.1 and as contemplated under section 2.36A.

Connection Point: Means the point on the Network Operator’s Network

where the Network Operator’s Primary Equipment (excluding metering assets) is connected to the Primary Equipment of the Transmission Connected Generating System.

Continuous Uninterrupted Operation: In respect of a Generating

System or operating Generating Unit within a Transmission Connected Generating System that is operating immediately prior to a power system disturbance, means:

$a$ not disconnecting from the SWIS except in accordance with its Registered Generator Performance Standard;

$b$ during the disturbance, contributing active and reactive current as required by its Registered Generator Performance Standard;

$c$ after clearance of any electrical fault that caused the disturbance, only substantially varying its Active Power and Reactive Power as required or permitted by its Registered Generator Performance Standard; and

$d$ not exacerbating or prolonging the disturbance or causing a subsequent disturbance for other connected Equipment, except as required or permitted by its Registered Generator Performance Standard,

with all essential auxiliary and reactive Equipment remaining in service.

Control Centre: Means the facilities used to direct and control the

operation of a Generating System.

Control System: As described in the Technical Rules.

Credible Contingency: An unplanned disconnection of equipment, or

other event, that a Generating System may reasonably be exposed to as described in the Technical Rules.

Critical Fault Clearance Time: As described in the Technical Rules.

Dispatch: Means the process of dispatch as described in these WEM

Rules.

Dispatch Systems Requirements: Means the requirements described in

section 2.35.

Explanatory Note

Amendments are for clarity. An alternative definition for 'Electricity Storage' to that which exists in the WEM Rules is used in this Appendix 12. This is because the GPS definition specifically “excludes” non-dispatchable storage, whereas the WEM Rules definition is quite open-ended, as controllability comes down to how a Facility is registered. This definition maintains, for GPS purposes, a limitation to only storage devices that are dispatchable.

Electricity Storage: Means equipment consisting of Storage Works but

does not include non-dispatchable Active Power energy storage equipment such as a synchronous compensator.

Equipment: As described in the Technical Rules.

Excitation Control System: As described in the Technical Rules.

Frequency Dead Band: The range through which power system frequency

can vary without the frequency control system initiating an active power response.

Generating System: As described in the Technical Rules.

Generating Unit: As described in the Technical Rules.

Generation: As described in the Technical Rules.

Explanatory Note

Clarifications included in the definition for 'Generator Performance Chart' are to show that the data provided covers multiple temperature ranges and is in relation to a specified measurement location, and clarifies that the operating ranges needs to ensure compliance with other Technical Requirements. The definition is further amended following the consultation period for Exposure Draft 2 to provide additional clarity on the meaning of “continuously achievable”.

Generator Performance Chart: Means a chart defining the capability

of a Generating System or Generating Unit to produce Active Power while producing or consuming Reactive Power. The capability is provided for specified ambient conditions and voltage levels at the Measurement Location based on a template provided by the Network Operator. The chart shows the Reactive Power capability continuously achievable while in operation, subject to energy source availability, for a given level of Active Power output for a range of ambient temperatures, while not exceeding limits necessary to prevent damage to Equipment and ensure compliance with other Technical Requirements.

Generator Performance Standard: Means either the Ideal Generator

Performance Standard or Negotiated Generator Performance Standard in respect of a Technical Requirement.

Explanatory Note

The definition for 'Maximum Continuous Current' is revised to provide clarity on how this value is determined. Given this will be based on the specific standards associated with the type of equipment, Western Power and AEMO will provide additional guidance to participants via the guidelines published under clause 3A.4.4 on the relevant standards.

This definition has been further amended following the consultation period for Exposure Draft 2 to confirm that details about the applicable Australian or ISO Standard will be included in the relevant guidelines.

Maximum Continuous Current: Means the maximum current capable of

being injected continuously in accordance with the relevant Australian Standard or ISO Standard for Synchronous Generating Units and Asynchronous Generating Units at the Measurement Location by the Generating System or Generating Units, as applicable, in order to support maintaining voltage on the SWIS during a disturbance, without causing damage to, or maloperation of, Equipment in the Transmission Connected Generating System. The details regarding which relevant Australian Standard or ISO Standard applies is documented in the guidelines published by the Network Operator under clause 3A.4.4.

Explanatory Note

The definition for 'Maximum Temperature' is added for use in definitions and Technical Requirements that require a specific temperature reference, and to provide guidance to Participants on where information will be published under 3A outlining the temperature assessment.

Maximum Temperature: The maximum ambient temperature specified by

AEMO in consultation with the Network Operator, based on an assessment of the physical location of the Generating Units, as described in the guidelines published by AEMO under clause 3A.1.5 and recorded in the temperature dependency data.

Explanatory Note

The definition for 'Measurement Location' is added as the common clauses for some of the GPS allow for the Network Operator and AEMO to agree a location other than the connection point to measure the GPS in reference to.

Measurement Location: The Connection Point, or another measurement

location agreed by AEMO and the Network Operator, as specified for the relevant Technical Requirement.

Nameplate Rating: As described in the Technical Rules.

Nomenclature Standards: As described in the Technical Rules.

Power Factor: As described in the Technical Rules.

Power Station: As described in the Technical Rules.

Primary Equipment: As described in the Technical Rules.

Protection Scheme: As described in the Technical Rules.

Protection System: As described in the Technical Rules.

Explanatory Note

The definition for 'Rated Maximum Active Power' is revised to provide clarity on the temperature and location at which this is measured for use in linking to other Technical Requirements. It also clarifies where this value is recorded.

Rated Maximum Active Power: The maximum Active Power level that a

Generating Unit or Generating System, as applicable, can continuously deliver at the Measurement Location, subject to energy source availability, in accordance with the requirements of Part A12.2 when the ambient temperature is at the Maximum Temperature, as specified in the Temperature Dependency Data.

Explanatory Note

The definition for 'Rated Maximum Apparent Power' is revised to provide clarity on the temperature and location at which this is measured for use in linking to other Technical Requirements.

Rated Maximum Apparent Power: The maximum Apparent Power level that

a Generating Unit or Generating System, as applicable, can continuously deliver at the Measurement Location, subject to energy source availability, when operating at the extent of the Generator Performance Chart provided under Part A12.3 and the ambient temperature is at the Maximum Temperature.

Explanatory Note

The definition for 'Rated Minimum Active Power' is revised to provide clarity on the location at which this is measured for use in linking to other Technical Requirements.

Rated Minimum Active Power: Means

$a$ in relation to a Generating Unit, the minimum amount of Active Power that the Generating Unit can continuously deliver, subject to energy source availability, while maintaining stable operation at the Measurement Location; and

$b$ in relation to a Generating System, the combined minimum amount of Active Power that its in-service Generating Units can continuously deliver, subject to energy source availability, at the Measurement Location while maintaining stable operation.

Reactive Power: As described in the Technical Rules.

Reactive Power Capability: Means the required level of Reactive

Power performance as specified in Part A12.3 of this Appendix 12.

Remote Control Equipment or RCE: As described in the Technical

Rules.

Remote Monitoring Equipment or RME: As described in the

Technical Rules.

Rise Time: In relation to a control system, means the time taken for

an output quantity to rise from its initial value to 90% of the final value induced by a step change of an input quantity, including in response to a disturbance as required under section A12.9.

RoCoF: Means the rate of change of frequency, expressed in Hertz per

second.

Settling Time: In relation to a control system, means the time

measured from initiation of a step change in an input quantity to the time when the magnitude of error between the output quantity and its final settling value remains less than 10% of:

$a$ if the sustained change in the quantity is less than half of the maximum change in that output quantity, half of the maximum change induced in that output quantity; or otherwise

$b$ the sustained change induced in that output quantity.

Static Excitation System: As described in the Technical Rules.

Synchronism: As described in the Technical Rules.

Synchronous Generating System: Means a Generating System comprised

of Synchronous Generating Units.

Synchronous Generating Unit: As described in the Technical Rules.

Tap-Changing Transformer: As described in the Technical Rules.

Explanatory Note

The definition for 'Target Setpoint' is added to provide clarity on how this is used in defining the Technical Requirements.

Target Setpoint: Means a value specifying a desired operating level

for the Generating Unit or Generating System, as applicable, at the relevant location. For example, a desired Active Power, Reactive Power or Power Factor.

Explanatory Note

The definition for 'Temperature Dependency Data' is revised to provide clarity on the location at which this is measured for use in linking to other Technical Requirements.

Temperature Dependency Data: Means a set of data defining the

maximum achievable Active Power of a Generating System or Generating Unit at a particular temperature at the Measurement Location. The data will be provided based on a template provided by the Network Operator. The data shows the Active Power capability achievable for a range of ambient temperatures while meeting all other Technical Requirements.

Total Fault Clearance Time: As described in the Technical Rules.

Transformer: As described in the Technical Rules.

Transmission System: As described in the Technical Rules.

Turbine Control System: As described in the Technical Rules.

A12.2. Technical Requirement: Active Power Capability

Explanatory Note

Section A12.2 is revised to provide clarity on where the requirement is to be measured from, and how Participants are to record the Active Power quantities in the Temperature Dependency Data. Various clauses have also been modified and new clause A12.2.3.6 added to clarify the interaction between the Active Power values in the Temperature Dependency Data and the other Technical Requirements.

A12.2.1. Common Requirements

A12.2.1.1. In relation to the application of this Technical Requirement, the requirements apply at the Connection Point unless otherwise specified in the relevant clause, or the Network Operator or AEMO determines that the Technical Requirement must be measured at a different location for the particular Generating Unit or Generating System, in which case the measurement location must be recorded as part of the relevant Generator Performance Standard.

A12.2.2. Ideal Generator Performance Standard

A12.2.2.1. The Ideal Generator Performance Standard is the same as the Minimum Generator Performance Standard for Active Power capability.

A12.2.3. Minimum Generator Performance Standard

A12.2.3.1. [Blank]

A12.2.3.2. The Generator Performance Standard for Active Power capability must include Temperature Dependency Data up to and including the Maximum Temperature, which must include the Rated Maximum Active Power, and including ambient temperatures above the Maximum Temperature after which the Active Power capability is reduced:

$a$ for the Generating System measured at the Connection Point; and

$b$ for each Synchronous Generating Unit measured at the Generating Unit terminal.

A12.2.3.3. [Blank]

A12.2.3.4. Subject to clause A12.2.3.5 and energy source availability, the Generating Unit or Generating System, as applicable, must be capable of maintaining Continuous Uninterrupted Operation and meeting all other Technical Requirements while achieving and maintaining the relevant Active Power output levels at the temperatures specified in clause A12.2.3.2.

A12.2.3.5. Clause A12.2.3.4 does not apply to the extent that a temporary reduction in Active Power has been agreed to by the Network Operator in order to achieve the required Reactive Power Capability under Maximum Temperature conditions as set out in Part A12.3 of this Appendix 12.

A12.2.3.6. Unless otherwise directed by AEMO or the Network Operator under these WEM Rules, Generating Systems and Generating Units, as applicable, must not exceed the relevant Active Power levels at the temperatures specified in clause A12.2.3.2.

A12.2.4. Negotiation Criteria

A12.2.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.3. Technical Requirement: Reactive Power Capability

Explanatory Note

Section A12.3 is revised to provide clarity on where the requirement is to be measured from and the temperatures and outputs over which the Technical Requirement applies. There is also a consequential change as a result of changes to the Registration framework.

A12.3.1. Common Requirements

A12.3.1.1. In relation to the application of this Technical Requirement, the requirements apply at the Connection Point unless otherwise specified in the relevant clause, or the Network Operator or AEMO determines that the Technical Requirement must be measured at a different location for the particular Generating Unit or Generating System, in which case the measurement location must be recorded as part of the relevant Generator Performance Standard.

A12.3.1.2. The Generator Performance Standard must include a Generator Performance Chart, including data up to and including the Maximum Temperature, and including ambient temperatures above the Maximum Temperature after which the performance is reduced.

A12.3.1.3. There must be no control system limitation, protection system or other limiting device in operation that would prevent the Generating System from providing the Reactive Power output within the area defined in the Generator Performance Chart.

A12.3.1.4. [Blank]

A12.3.1.5. Each Generating System's Connection Point must be capable of permitting the Dispatch of the full Active Power and Reactive Power Capability of the Generating System.

A12.3.2. Ideal Generator Performance Standard

A12.3.2.1. For all operating conditions including temperatures up to and including the Maximum Temperature, each Generating Unit within the Generating System must be capable of supplying or absorbing Reactive Power continuously of at least the amount equal to the product of the Rated Maximum Active Power output of the Generating Unit at nominal voltage and 0.484 while operating at any level of Active Power output between its maximum Active Power output level as specified in the Temperature Dependency Data under Part A12.2, and its Rated Minimum Active Power output level.

Figure A12.3.2.1: Example Reactive Power Capability required to meet Ideal Generator Performance Standard

A12.3.2.2. The required levels of Reactive Power Capability must be able to be delivered continuously for voltages at the Connection Point within the allowable steady state voltage ranges as specified in the Technical Rules.

A12.3.3. Minimum Generator Performance Standard

A12.3.3.1. Subject to clause A12.3.3.3, for all operating conditions including temperatures up to and including the Maximum Temperature, the Generating System must be capable of supplying or absorbing Reactive Power continuously of at least the amount equal to the product of the Rated Maximum Active Power output of the Generating System and 0.329 while operating at any level of Active Power output level between its maximum Active Power output level as specified in the Temperature Dependency Data under Part A12.2, and Rated Minimum Active Power output level.

Figure A12.3.3.1: Example Reactive Power Capability required to meet the Minimum Generator Performance Standard

A12.3.3.2. The Reactive Power Capability may be varied as shown in Figure A12.3.3.2 when the voltage at the Connection Point varies between 0.9 per unit and 1.1 per unit, where the Generating System must be capable of absorbing or supplying Reactive Power continuously when operating anywhere inside the curve specified in Figure A12.3.3.2.

Figure A12.3.3.2: Relaxation of Reactive Power requirement with Connection Point voltage

A12.3.3.3. Transmission Connected Generating Systems containing Intermittent Generating Systems may, with the Network Operator’s agreement, achieve the Reactive Power Capability specified in clause A12.3.3.1 by reducing Active Power output when the ambient temperature exceeds 25 degrees Celsius in their location, with the conditions forming part of the Generator Performance Standard.

A12.3.4. Negotiation Criteria

A12.3.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.4. Technical Requirement: Voltage And Reactive Power Control

Explanatory Note

Section A12.4 is revised to provide clarity on where the requirement is to be measured from and the temperatures and outputs over which the Technical Requirement applies.

A12.4.1. Common Requirements

Explanatory Note

Section A12.4 is revised to provide clarity on where the requirement is to be measured from and the temperatures and outputs over which the Technical Requirement applies.

A12.4.1.1. In relation to the application of this Technical Requirement, the requirements apply at the Connection Point unless otherwise specified in the relevant clause, or the Network Operator or AEMO determines that the Technical Requirement must be measured at a different location for the particular Generating Unit or Generating System, in which case the measurement location must be recorded as part of the relevant Generator Performance Standard.

A12.4.1.2. In relation to the application of this Technical Requirement, unless otherwise specified in the relevant clause, the requirements apply when operating at any Active Power and Reactive Power level as permitted or required under the other Technical Requirements in this Appendix, and at all temperatures up to and including the Maximum Temperature.

A12.4.2. Ideal Generator Performance Standard

Explanatory Note

Various clauses in this section are revised to account for consequential changes of introducing the new common clauses for measurement and temperature, and to include the new defined term Target Setpoint to provide clarity on how the Technical Requirement applies. References to Nameplate Rating have also been replaced with equivalent temperature dependent definitions to provide clarity at which temperature the requirement is defined.

Where reference to an Australian or international standard has been included, Western Power and AEMO will include guidance for Participants on the relevant standards in the guidelines published under clause 3A.4.4.

A12.4.2.1. The Ideal Generator Performance Standard, as it applies to different Generating Systems, is specified in Table A12.4.2.1

Generating System comprised solely of Synchronous Generating Units.

Clause A12.4.2.2 to clause A12.4.2.9 and clause A12.4.2.10 to clause A12.4.2.12.

Generating System comprised solely of Asynchronous Generating Units.

Clause A12.4.2.2 to clause A12.4.2.9 and clause A12.4.2.13 to clause A12.4.2.16.

Generating System comprised of Synchronous Generating Units and Asynchronous Generating Units.

Clause A12.4.2.2 to clause A12.4.2.9 and:

(a) for that part of the Generating System comprised of Synchronous Generating Units, clause A12.4.2.10 to clause A12.4.2.12;

(b) for that part of the Generating System comprised of Asynchronous Generating Units, clause A12.4.2.13 to clause A12.4.2.16.

Table A12.4.2.1: Voltage and Reactive Power Control Ideal Generator Performance Standard

All Generating Systems

A12.4.2.2. The Generating System must have Equipment capabilities and Control Systems, including, if necessary, a power system stabiliser, sufficient to ensure that:

$a$ power system oscillations, for the frequencies of oscillation of the Generating System against any other Generating System or device, are Adequately Damped;

$b$ operation of the Generating System does not degrade the damping of any critical mode of oscillation of the power system; and

$c$ operation of the Generating System does not cause instability (including hunting of Tap-Changing Transformer Control Systems) that would adversely impact other Equipment connected to the SWIS.

A12.4.2.3. Control Systems on Generating Systems that control voltage and Reactive Power must include permanently installed and operational, monitoring and recording equipment for key variables including each input and output, and equipment for testing the Control Systems sufficient to establish their dynamic operational characteristics.

A12.4.2.4. A Generating System must have Control Systems capable of regulating voltage, Reactive Power and Power Factor, with the ability to:

$a$ operate in all control modes; and

$b$ switch between control modes, as demonstrated to the reasonable satisfaction of the Network Operator and AEMO. Where a Generating System has been commissioned with more than one control mode, a procedure for switching between control modes must be agreed with AEMO and the Network Operator as part of the Generator Performance Standard.

A12.4.2.5. A Generating System must have a voltage Control System that:

$a$ regulates voltage to within 0.5% of the Target Setpoint, where that setpoint may be adjusted to incorporate any voltage droop or reactive current compensation agreed with AEMO and the Network Operator;

$b$ regulates voltage in a manner that helps to support network voltages during faults and does not prevent the requirements for voltage performance and stability in the Technical Rules from being achieved;

$c$ allows the voltage to be continuously controllable in the range of at least 95% to 105% of the target voltage (as determined by the Network Operator), without reliance on a Tap-Changing Transformer and subject to the Generator Performance Standards for Reactive Power Capability with the voltage control location agreed with AEMO and the Network Operator; and

$d$ has limiting devices to ensure that a voltage disturbance does not cause a Generating Unit to trip at the limits of its operating capability. The Generating System must be capable of continuous stable operation while under the control of any limiter. Limiters must not detract from the performance of any stabilising circuits and must have settings applied which are coordinated with all Protection Systems.

A12.4.2.6. Where installed, a power system stabiliser must have:

$a$ two washout filters for each input, with ability to bypass one of them if necessary;

$b$ sufficient (and not less than two) lead-lag transfer function blocks (or equivalent number of complex poles and zeros) with adjustable gain and time-constants, to compensate fully for the phase lags due to the Generating Unit;

$c$ monitoring and recording equipment for key variables including inputs, output and the inputs to the lead-lag transfer function blocks; and

$d$ equipment to permit testing of the power system stabiliser in isolation from the power system by injection of test signals, sufficient to establish the transfer function of the power system stabiliser.

A12.4.2.7. A Reactive Power, including a Power Factor, Control System must:

$a$ regulate Reactive Power or Power Factor (as applicable) to within:

$i$ for a Generating System operating in Reactive Power mode, 2% of the Rated Maximum Apparent Power of the Generating System from the Target Setpoint; or

$ii$ for a Generating System operating in Power Factor mode, a Power Factor equivalent to 2% of the Rated Maximum Apparent Power of the Generating System from the Target Setpoint; and

$b$ allow the Reactive Power or Power Factor Target Setpoint to be continuously controllable across the Reactive Power Capability range specified in the relevant Generator Performance Standard.

A12.4.2.8. The structure and parameter settings of all components of the Control System, including the voltage regulator, Reactive Power regulator, power system stabiliser, power amplifiers and all associated limiters, must be approved by the Network Operator and AEMO as part of the Generator Performance Standard.

A12.4.2.9. Each Control System must be Adequately Damped.

Synchronous Generating Systems

A12.4.2.10. Each Synchronous Generating Unit must have an Excitation Control System that:

$a$ is capable of operating the stator continuously at 105% of nominal voltage when operating at the maximum Active Power output specified in the Temperature Dependency Data provided under Part A12.2 for the relevant temperature;

$b$ has an excitation ceiling voltage of at least:

$i$ for a Static Excitation System, 2.3 times; or

$ii$ for other Excitation Control Systems, 1.5 times,

the excitation required to achieve generation at the rated output, rated speed and nominal voltage in accordance with the relevant Australian Standard or ISO Standard for Synchronous Generating Units. The details regarding which relevant Australian Standard or ISO Standard applies is documented in the guidelines published by the Network Operator under clause 3A.4.4;

$c$ has a power system stabiliser with sufficient flexibility to enable damping performance to be maximised, with the stabilising circuit responsive and adjustable over a frequency range from 0.1 Hz to 2.5 Hz; and

$d$ achieves a minimum equivalent gain of 200.[5]

A12.4.2.11. The performance characteristics required for AC exciter, rotating rectifier and Static Excitation Systems are specified in Table A12.4.2.11.

Performance Item	Units	Static Excitation	AC exciter or rotating rectifier	Notes
Generating Unit Field voltage Rise Time: In relation to field voltage rising from rated field voltage to excitation ceiling voltage following the application of a short duration impulse to the voltage reference.	Second	0.05 maximum	0.5 maximum	1 and 2
Settling Time with the Generating Unit unsynchronised following a disturbance equivalent to a 5% step change in the sensed Generating Unit terminal voltage.	Second	1.5 maximum	2.5 maximum	2
Settling Time with the Generating Unit synchronised following a disturbance equivalent to a 5% step change in the sensed Generating Unit terminal voltage. It must be met at all operating points within the Generating Unit capability.	Second	2.5 maximum	5 maximum	2
Settling Time following any disturbance which causes an excitation limiter to operate.	Second	5 maximum	5 maximum	2
Notes: 1. Rated field voltage is that voltage required to give nominal Generating Unit terminal voltage when the Generating Unit is operating at its Rated Maximum Apparent Power. 2. For rotating rectifier excitation system where the field voltage is not accessible for direct measurement, the main exciter field voltage must comply with this clause A12.4.2.11.

Table A12.4.2.11: Synchronous Generating Unit Excitation Control System performance requirements

A12.4.2.12. Where provided, a power system stabiliser must have:

$a$ measurements of rotor speed and Active Power output of the Generating Unit as inputs; and

$b$ an output limiter, which is continually adjustable over the range of –10% to +10% of stator voltage.

Asynchronous Generating Systems

A12.4.2.13. A Generating System, comprised of Asynchronous Generating Units, must have a voltage and Reactive Power Control System that has a power oscillation damping capability with sufficient flexibility to enable damping performance to be maximised, with the stabilising circuit responsive and adjustable over a frequency range from 0.1 Hz to 2.5 Hz. Any power system stabiliser must have measurements of power system frequency and Active Power output of the Generating Unit as inputs.

A12.4.2.14. A Generating System, comprised of Asynchronous Generating Units, must have a control system capable of achieving a minimum equivalent gain of 200.

A12.4.2.15. The performance characteristics required for the voltage and Reactive Power Control Systems of all Asynchronous Generating Systems are specified in Table A12.4.2.15.

Performance Item	Units	Limiting Value	Notes
Rise Time: The controlled parameter (voltage or Reactive Power output) following the application of a 5% step change to the Control System reference.	Second	1.5 maximum	1 and 3
Settling Time of the controlled parameter with the Generating System connected to the Transmission System following a step change in the Control System reference such that it is not large enough to cause saturation of the controlled output parameter. It must be met at all operating points within the Generating Unit’s capability.	Second	2.5 maximum	1, 2 and 3
Settling Time of the controlled parameter with the Generating System connected to the Transmission System following any disturbance that is large enough to cause the maximum value of the controlled output parameter to be just exceeded.	Second	5 maximum	2 and 3
Notes: 1. The step change is 5%, or a lesser value specified by the Network Operator such that it is the largest step change that results in the required Settling Time at the Connection Point. 2. The step change is specified by the Network Operator such that it is the largest step change that results in the required Settling Time at the Connection Point. 3. The step change is to be recorded for future assessment.

Table A12.4.2.15: Asynchronous Generating System Control System performance requirements

A12.4.2.16. The controlled parameters used to meet the requirements specified in Table A12.4.2.15. and measurement of the parameters must be agreed with the Network Operator and AEMO as part of the Generator Performance Standard.

A12.4.3. Minimum Generator Performance Standard

A12.4.3.1. The Minimum Generator Performance Standard for Voltage and Reactive Power Control as it applies to different Generating Systems, is specified in Table A12.4.3.1:

Generating System comprised solely of Synchronous Generating Units.

Clause A12.4.3.2 to clause A12.4.3.6.

Generating System comprised solely of Asynchronous Generating Units.

Clause A12.4.3.2 to clause A12.4.3.5 and clause A12.4.3.7.

Generating System comprised of Synchronous Generating Units and Asynchronous Generating Units.

Clause A12.4.3.2 to clause A12.4.3.5 and:

(a) for that part of the Generating System comprised of Synchronous Generating Units, clause A12.4.3.6;

(b) for that part of the Generating System comprised of Asynchronous Generating Units, clause A12.4.3.7.

Table A12.4.3.1: Voltage and Reactive Power Control Minimum Generator Performance Standard

All Generating Systems

A12.4.3.2. A Generating System must have Equipment capabilities and Control Systems, including, if necessary, a power system stabiliser, sufficient to ensure that:

$a$ power system oscillations, for the frequencies of oscillation of the Generating System against any other Generating System or device, are Adequately Damped;

$b$ operation of the Generating System is Adequately Damped; and

$c$ Control Systems can be sufficiently tested to establish their dynamic operational characteristics.

A12.4.3.3. A Generating System must have a Control System to regulate:

$a$ voltage; or

$b$ either of Reactive Power or Power Factor, with the agreement of AEMO and the Network Operator.

A12.4.3.4. A voltage Control System for a Generating System must:

$a$ regulate voltage to within 2% of the Target Setpoint, where that setpoint may be adjusted to incorporate any voltage droop or reactive current compensation agreed with AEMO and the Network Operator; and

$b$ allow the voltage Target Setpoint to be controllable in the range of at least 98% to 102% of the target voltage (as determined by the Network Operator), subject to the Reactive Power Capability agreed with AEMO and the Network Operator under Part A12.3 of this Appendix 12.

A12.4.3.5. A Generating System’s Reactive Power or Power Factor Control System must:

$a$ regulate Reactive Power or Power Factor (as applicable) to within:

$i$ for a Generating System operating in Reactive Power mode, 5% of the Rated Maximum Apparent Power of the Generating System from the Target Setpoint; or

$ii$ for a Generating System operating in Power Factor mode, a Power Factor equivalent to 5% of the Rated Maximum Apparent Power of the Generating System from the Target Setpoint;

$b$ allow the Reactive Power or Power Factor Target Setpoint to be continuously controllable across the Reactive Power Capability defined in the relevant Generator Performance Standard; and

$c$ have limiting devices to ensure that a voltage disturbance does not cause a Generating Unit to trip at the limits of its operating capability. The Generating System must be capable of stable operation for indefinite periods while under the control of any limiter. Limiters must not detract from the performance of any stabilising circuits and must have settings applied, which are coordinated with all Protection Systems, and must be included as part of the Generator Performance Standard.

Synchronous Generating Systems

A12.4.3.6. Each Synchronous Generating Unit within the Generating System, with an Excitation Control System required to regulate voltage must:

$a$ have excitation ceiling voltage of at least 1.5 times the excitation required to achieve generation at the rated output, rated speed and nominal voltage in accordance with the relevant Australian Standard or ISO Standard for Synchronous Generating Units. The details regarding which relevant Australian Standard or ISO Standard applies is documented in the guidelines published by the Network Operator under clause 3A.4.4; and

$b$ subject to the ceiling voltage requirement, have a Settling Time of less than 7.5 seconds for a 5% voltage disturbance with the Generating Unit synchronised, subject to the Generating Unit operating at a point where such a voltage disturbance would not cause any limiting device to operate.

Asynchronous Generating Systems

A12.4.3.7. A Generating System, comprised of Asynchronous Generating Units, with a voltage Control System must have a Settling Time of less than 7.5 seconds for a 5% voltage disturbance subject to the Generating Unit being electrically connected to the SWIS and operating at a point where such a voltage disturbance would not cause any limiting device to operate.

A12.4.4. Negotiation Criteria

A12.4.4.1. A Proposed Negotiated Generator Performance Standard must be the highest level that the Generating System can reasonably achieve, including by installation of additional dynamic Reactive Power Equipment, and through optimising its Control Systems.

A12.5. Technical Requirement: Active Power Control

Explanatory Note

Section a12.5 has been revised to reflect that the Transmission Connected Generating System is dispatched as a whole, and not the individual elements. The changes to the Ideal Standard now reflect individual Generating System controllability (i.e. capability to respond to fixed targets) within Transmission Connected Generating System, and the overall Transmission Connected Generating System then being subject to dispatch requirements.

The changes to the Minimum Standard reflect controllability and maximum ramp, but do not specifically tie to Facility level dispatch requirements.

A12.5.1. Common Requirements

A12.5.1.1. All Generating Systems must be capable of meeting the Dispatch Systems Requirements.

A12.5.1.2. Any arrangements put in place as part of the Arrangement for Access to limit Active Power output in order to manage constraints on the Network must be included as part of the Generator Performance Standard.

A12.5.1.3. Each Control System must be Adequately Damped.

A12.5.1.4. Any relevant disconnection settings must be included as part of the Generator Performance Standard.

A12.5.1.5. Subject to energy source availability and any other agreement by the Network Operator, where dispatched by AEMO a Generating System must be capable of maintaining its Active Power output consistent with its last received dispatch level in the event RME, RCE or Communications are unavailable.

A12.5.1.6. The requirements in this Part A12.5 do not override any specific Active Power ramping requirements specified in Part A12.6 in response to frequency deviations.

A12.5.1.7. In relation to the application of this Technical Requirement, unless otherwise specified in the relevant clause, the requirements apply when operating at any Active Power and Reactive Power level as permitted or required under the other Technical Requirements in this Appendix, and at all temperatures up to and including the Maximum Temperature.

A12.5.2. Ideal Generator Performance Standard

A12.5.2.1. A Non-Intermittent Generating System within a Transmission Connected Generating System must have an Active Power Control System capable of:

$a$ maintaining and changing its Active Power output in accordance with Target Setpoints;

$b$ ramping its Active Power output linearly from one Target Setpoint to another; and

$c$ in a thermally stable state, changing Active Power output in response to a change in Target Setpoint at a rate not less than 5% of its Rated Maximum Active Power per minute.

A12.5.2.2. Subject to energy source availability, an Intermittent Generating System within a Transmission Connected Generating System must be able to change its Active Power output in accordance with Target Setpoints, and must not change its Active Power output at a rate greater than 10 MW per minute or 15% of the Rated Maximum Active Power per minute, whichever is the lower or as agreed with the Network Operator and AEMO.

A12.5.2.3. A Transmission Connected Generating System must be able to meet the Dispatch Systems Requirements.

A12.5.3. Minimum Generator Performance Standard

A12.5.3.1. A Non-Intermittent Generating System within a Transmission Connected Generating System must have an Active Power Control System capable of maintaining and changing its Active Power output in accordance with a Target Setpoint, and must be capable of changing Active Power generation at a rate not less than 5% of its Rated Maximum Active Power per minute.

A12.5.3.2. Subject to energy source availability, an Intermittent Generating System within a Transmission Connected Generating System must ensure that any change of Active Power output in a 5 minute period does not exceed a value agreed with AEMO and the Network Operator.

A12.5.4. Negotiation Criteria

A12.5.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.6. Technical Requirement: Inertia and Frequency Control

Explanatory Note

Section A12.6 is revised to provide clarity on where the requirement is to be measured from and the temperatures and outputs over which the Technical Requirement applies.

A12.6.1. Common Requirements

A12.6.1.1. All Control Systems must be Adequately Damped.

A12.6.1.2. The recorded maximum ramp rate for the Generating System must be expressed as the change in Active Power (measured in MW) achievable across 6 seconds.

A12.6.1.3. Any relevant disconnection settings must be provided as part of the Generator Performance Standard.

A12.6.1.4. Control Systems on Generating Systems that control Active Power must include permanently installed and operational monitoring and recording equipment for key variables including each input and output, and equipment for testing the Control System sufficient to establish its dynamic operational characteristics.

A12.6.1.5. After having met the relevant requirements for altering and holding Active Power output to arrest and correct changes in power system frequency, the Generating System, or Generating Units where relevant, must adhere to relevant requirements of Part A12.5 when returning to regular Active Power output (subject to any agreements under clause A12.6.1.6).

A12.6.1.6. Unless otherwise agreed by the relevant Network Operator and AEMO, protection or other schemes that disconnect the Generating System or elements of the Generating System, must not be used in order to meet the requirements of this Part A12.6.

A12.6.1.7. A Generating System must:

$a$ have an automatic variable Active Power control characteristic; and

$b$ where the Generating System contains a Generating Unit with a Turbine Control System, it must include equipment for both speed and Active Power control.

A12.6.1.8. All Generating Units, or the Generating System, as applicable, must operate in a mode in which it will automatically alter its Active Power output to arrest and correct changes in power system frequency, unless instructed otherwise or approved for testing purposes by AEMO.

A12.6.1.9. The Frequency Dead Band on each Generating Unit, or the Generating System, as applicable, must be no greater than +/-0.025 Hz around 50.0Hz.

A12.6.1.10. Unless otherwise stated in this Part A12.6, the overall required frequency response of each Generating Unit, or Generating System, as applicable, must be settable and be capable of:

$a$ automatically achieving an increase in Active Power output proportional to a change in power system frequency of not less than 5% of the maximum Active Power specified in the Temperature Dependency Data provided under Part A12.2 for each 0.1 Hz reduction in power system frequency from the lower level of Frequency Dead Band, provided the output is above the Rated Minimum Active Power; and

$b$ automatically achieving a reduction in Active Power output proportional to a change in power system frequency of not less than 5% of the maximum Active Power specified in the Temperature Dependency Data provided under Part A12.2 for each 0.1 Hz increase in power system frequency from the upper level of Frequency Dead Band, provided this does not require operation below the Rated Minimum Active Power.

A12.6.1.11. The frequency response capability described in clause A12.6.1.10:

$a$ must not exhibit any step changes in Active Power as the power system frequency changes, unless otherwise agreed by the relevant Network Operator and AEMO under clause A12.6.1.6;

$b$ must commence responding with a delay no greater than that required to ensure stable operation or to allow for control system latency, as agreed by the relevant Network Operator and AEMO;

$c$ must not increase Active Power output in response to an increase in power system frequency; and

$d$ must not decrease Active Power output in response to a decrease in power system frequency.

A12.6.1.12. In relation to the application of this Technical Requirement, the requirements apply at the Connection Point unless otherwise specified in the relevant clause, or the Network Operator or AEMO determines that the Technical Requirement must be measured at a different location for the particular Generating Unit or Generating System, in which case the measurement location must be recorded as part of the relevant Generator Performance Standard.

A12.6.1.13. In relation to the application of this Technical Requirement, unless otherwise specified in the relevant clause, the requirements apply when operating at any Active Power and Reactive Power level as permitted or required under the other Technical Requirements in this Appendix, and at all temperatures up to and including the Maximum Temperature.

A12.6.2. Ideal Generator Performance Standard

A12.6.2.1. The Ideal Generator Performance Standard requires that control ranges, response times and sustain times, are achieved for Generating Units, or the Generating System, as applicable, such that, subject to energy source availability:

$a$ the required frequency response in clause A12.6.1.10(a) can be complied with for any initial output up to the maximum Active Power specified in the Temperature Dependency Data provided under Part A12.2 for the relevant temperature;

$b$ for Synchronous Generating Systems, for any frequency disturbance where the change in power system frequency is sufficient to change the Active Power of the Generating System by at least 5% of its Rated Maximum Active Power, the Generating Unit or Generating System achieves at least 90% of the required frequency response specified in clause A12.6.1.10 within 6 seconds;

$c$ for Asynchronous Generating Systems, for any frequency disturbance where the change in power system frequency is sufficient to change the Active Power of the Generating System by at least 5% of its Rated Maximum Active Power, the Generating Unit or Generating System achieves at least 90% of the required frequency response specified in clause A12.6.1.10 within 2 seconds;

$d$ the required frequency response specified in clause A12.6.1.10 is sustained for not less than a further 10 seconds beyond the timeframes specified in clause A12.6.2.1(b) and clause A12.6.2.1(c), as applicable, subject to a restoration of power system frequency in which case the Active Power output must be changed in proportion to the power system frequency in accordance with the required frequency response specified in clause A12.6.1.10; and

$e$ each Generating Unit's or Generating System’s, as applicable, capability to sustain response beyond the timeframe specified in clause A12.6.2.1(d) must be included as part of the relevant Generator Performance Standard.

A12.6.3. Minimum Generator Performance Standard

A12.6.3.1. [Blank]

A12.6.3.2. Subject to energy source availability, a Generating System is required to have control ranges and response times for each Generating Unit, or Generating Systems as applicable, such that:

$a$ it is able to comply with the required frequency response specified in clause A12.6.1.10(a), up to 85% of Rated Maximum Active Power output;

$b$ for initial outputs above 85% of Rated Maximum Active Power output, each Generating Unit's or Generating System’s, as applicable, response capability must be agreed with the relevant Network Operator and AEMO, and included as part of the relevant Generator Performance Standard;

$c$ for Synchronous Generating Systems, for any frequency disturbance where the change in frequency is sufficient to change the Active Power of the Generating System by at least 5% of its Rated Maximum Active Power output, the Generating Unit or Generating System achieves at least 60% of the required frequency response specified in clause A12.6.1.10 within 6 seconds, and 90% of the required frequency response specified in clause A12.6.1.10 within 15 seconds;

$d$ for Asynchronous Generating Systems, for any frequency disturbance where the change in frequency is sufficient to change the Active Power of the Generating System by at least 5% of its Rated Maximum Active Power output, the Generating Unit or Generating System achieves at least 60% of the required frequency response specified in clause A12.6.1.10 within 6 seconds, and at least 90% of the required frequency response specified in clause A12.6.1.10 within 15 seconds;

$e$ the required frequency response specified in clause A12.6.1.10 is sustained for not less than a further 10 seconds beyond the latest timeframe specified in clause A12.6.3.2(c) and clause A12.6.3.2(d), as applicable, subject to a restoration of power system frequency in which case the Active Power output must be changed in proportion to the power system frequency in accordance with the required frequency response specified in clause A12.6.1.10; and

$f$ each Generating Unit's or Generating System’s, as applicable, capability to sustain response beyond the timeframe specified in clause A12.6.3.2(e) must be included as part of the relevant Generator Performance Standard.

A12.6.4. Negotiation Criteria

A12.6.4.1. A Negotiated Generator Performance Standard must require that there is no requirement for a Generating System to operate with an Active Power output:

$a$ below its Rated Minimum Active Power in response to a rise in the frequency of the SWIS as measured at the Connection Point;

$b$ above the relevant maximum Active Power output specified in the Temperature Dependency Data provided under Part A12.2 for the relevant temperature, in response to a fall in the frequency of the SWIS as measured at the Connection Point; or

A12.6.4.2. An additional source of Inertia or frequency control may be included within the Generating System. The Control System for the additional source of Inertia or frequency control must be coordinated with the remainder of the Generating System and, together, must meet the performance requirements of the relevant Technical Requirements.

A12.7. Technical Requirement: Disturbance Ride Through for a Frequency Disturbance

Explanatory Note

Section A12.7 is revised to provide clarity on where the requirement is to be measured from and the temperatures and outputs over which the Technical Requirement applies.

A12.7.1. Common Requirements

A12.7.1.1. In relation to the application of this Technical Requirement, the requirements apply at the Connection Point unless otherwise specified in the relevant clause, or the Network Operator or AEMO determines that the Technical Requirement must be measured at a different location for the particular Generating Unit or Generating System, in which case the measurement location must be recorded as part of the relevant Generator Performance Standard.

A12.7.1.2. Any relevant disconnection settings must be provided as part of the Generator Performance Standard.

A12.7.1.3. Where the relevant Network Operator and AEMO have agreed to a protection, or other scheme, that will disconnect the Generating System or elements of the Generating System, in order to satisfy the requirements of Part A12.6, the operation of those schemes based on their agreed parameters will not be taken to be a breach of the requirements of this Part A12.7.

A12.7.1.4. In relation to the application of this Technical Requirement, unless otherwise specified in the relevant clause, the requirements apply when operating at any Active Power and Reactive Power level as permitted or required under the other Technical Requirements in this Appendix.

A12.7.2. Ideal Generator Performance Standard

A12.7.2.1. A Generating System must maintain Continuous Uninterrupted Operation where a power system disturbance causes the frequency to:

$a$ reach 52.5 Hz for a period of up to 6 seconds;

$b$ reach 52 Hz for a period of up to 2 minutes;

$c$ reach 51.5 Hz for a period of up to 5 minutes;

$d$ operate between 49.0 Hz to 51.0 Hz continuously;

$e$ reach 47.5 Hz for a period of up to 15 minutes; or

$f$ reach 47.0 Hz for a period of up to 2 minutes,

as shown in Figure A12.7.2.1.

Figure A12.7.2.1 Frequency variations that a Generating System must ride through to meet the Ideal Generator Performance Standard

A12.7.2.2. A Generating System must maintain Continuous Uninterrupted Operation where a power system disturbance causes the RoCoF to:

$a$ reach 4 Hz/s over 250 milliseconds during the disturbance; or

$b$ reach 3 Hz/s over 1 second during the disturbance.

A12.7.3. Minimum Generator Performance Standard

A12.7.3.1. A Generating System must maintain Continuous Uninterrupted Operation where a power system disturbance causes the frequency to:

$a$ reach 52.0 Hz for a period of up to 2 minutes;

$b$ operate between 49.0 Hz to 51.0 Hz continuously;

$c$ reach 48.0 Hz for a period of at least 15 minutes;

$d$ reach 47.5 Hz for a period of at least 5 minutes; or

$e$ reach 47.0 Hz for a period of at least 10 seconds,

as shown in Figure A12.7.3.1.

Figure A12.7.3.1: Frequency variations that a Generating System must ride through to meet the Minimum Generator Performance Standard

A12.7.3.2. A Generating System must maintain Continuous Uninterrupted Operation where a power system disturbance causes the RoCoF to:

$a$ reach 2 Hz/s over 250 milliseconds during the disturbance; or

$b$ reach 1 Hz/s over 1 second during the disturbance.

A12.7.4. Negotiation Criteria

A12.7.4.1. A Proposed Negotiated Generator Performance Standard for disturbance ride through for a frequency disturbance may be accepted provided the Network Operator and AEMO agree that the frequency would be unlikely to fall below the lower bound of the single contingency event band specified in the Frequency Operating Standard.

A12.8. Technical Requirement: Disturbance Ride Through for a Voltage Disturbance

Explanatory Note

Section A12.8 is revised to provide clarity on where the requirement is to be measured from and the temperatures and outputs over which the Technical Requirement applies.

A12.8.1. Common Requirements

A12.8.1.1. In relation to the application of this Technical Requirement, the requirements apply at the Connection Point unless otherwise specified in the relevant clause, or the Network Operator or AEMO determines that the Technical Requirement must be measured at a different location for the particular Generating Unit or Generating System, in which case the measurement location must be recorded as part of the relevant Generator Performance Standard.

A12.8.1.2. The Generating System and each of its operating Generating Units is required to remain in Continuous Uninterrupted Operation while the Connection Point voltage remains within 90% to 110% of nominal voltage.

A12.8.1.3. Any relevant disconnection settings must be provided as part of the Generator Performance Standard.

A12.8.1.4. In relation to the application of this Technical Requirement, unless otherwise specified in the relevant clause, the requirements apply when operating at any Active Power and Reactive Power level as permitted or required under the other Technical Requirements in this Appendix.

A12.8.2. Ideal Generator Performance Standard

A12.8.2.1. A Generating System must maintain Continuous Uninterrupted Operation where a power system disturbance causes the voltage to vary within the following ranges:

$a$ voltage exceeds 130% of nominal voltage for not more than 0.02 seconds after T(ov);

$b$ voltage does not exceed 120% of nominal voltage for more than 2.0 seconds after T(ov);

$c$ voltage does not exceed 115% of nominal voltage for more than 20.0 seconds after T(ov);

$d$ voltage does not exceed 110% of nominal voltage for more than 20.0 minutes after T(ov);

$e$ voltage remains at 0% of nominal voltage for no more than 450 milliseconds after T(uv);

$f$ voltage does not stay below 70% of nominal voltage for more than 450 milliseconds after T(uv);

$g$ voltage does not stay below 80% of nominal voltage for more than 2.0 seconds after T(uv); and

$h$ voltage does not stay below 90% of nominal voltage for more than 10.0 seconds after T(uv).

Where:

T(ov) means a point in time when the voltage first varied above 110%

of nominal voltage before returning to between 90% and 110% of nominal voltage; and

T(uv) means a point in time when the voltage first varied below 90%

of nominal voltage before returning to between 90% and 110% of nominal voltage.

cid:image001.png@01D69030.1F49AB80

Figure A12.8.2.1: Voltage variations that a Generating System must ride through to meet the Ideal Generator Performance Standard

A12.8.3. Minimum Generator Performance Standard

A12.8.3.1. A Generating System must maintain Continuous Uninterrupted Operation where a power system disturbance causes the voltage to vary within the following ranges:

$a$ voltage does not exceed 120% of nominal voltage after T(ov);

$b$ voltage does not exceed 115% of nominal voltage for more than 0.1 seconds after T(ov);

$c$ voltage does not exceed 110% of nominal voltage for more than 0.9 seconds after T(ov);

$d$ voltage remains at 0% of nominal voltage for no more than 450 milliseconds after T(uv) subject to clause A12.8.3.2;

$e$ voltage does not stay below 70% of nominal voltage for more than 450 milliseconds after T(uv);

$f$ voltage does not stay below 80% of nominal voltage for more than 2.0 seconds after T(uv); and

$g$ voltage does not stay below 90% of nominal voltage for more than 5.0 seconds after T(uv).

Where:

T(ov) means a point in time when the voltage first varied above 110%

of nominal voltage before returning to between 90% and 110% of nominal voltage; and

T(uv) means a point in time when the voltage first varied below 90%

of nominal voltage before returning to between 90% and 110% of nominal voltage.

A12.8.3.2. The duration of the zero percent voltage level may be relaxed through agreement with the Network Operator and AEMO, but shall not be lower than the maximum Total Fault Clearance Time with no circuit breaker fail as specified in the Technical Rules.

cid:0ad65897-9dc1-49f1-b365-5eb6f904f16b A12.8.3.3. Any operational arrangements necessary to ensure the Generating System and each of its operating Generating Units will meet its Generator Performance Standard must be provided as part of the Generator Performance Standard.

Figure A12.8.3.3: Voltage variations that a Generating System must ride through to meet the Minimum Generator Performance Standard

A12.8.4. Negotiation Criteria

A12.8.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.9. Technical Requirement: Disturbance Ride Through for Multiple Disturbances

[Note: This Technical Requirement uses the term 'fault' to include a fault of the relevant type having a metallic conducting path.]

Explanatory Note

Section A12.9 is revised to provide clarity on where the requirement is to be measured from and the temperatures and outputs over which the Technical Requirement applies. The changes also require Participants to advise of any specific temperature limitations in relation to fault current injection that can then be used to support assessment and will be recorded against the Technical Requirement.

Where a Technical Requirement references an Australian or international standard, Western Power and AEMO will include guidance to participants on the relevant standards in the guidelines published under clause 3A.4.4.

The changes to clauses A12.9.2.5 and A.12.9.3.5 provide guidance as to where the initial pre-fault disturbance voltages should be measured from, with the Ideal Standard requiring that the initial level must be within a certain range, and the Minimum Standard allowing for the level to be agreed with Western Power and AEMO as part of negotiation.

A12.9.1. Common Requirements

A12.9.1.1. The Common Requirements for disturbance ride through for multiple disturbances as they apply to different Generating Systems, is specified in Table A12.9.1.1:

Generating System comprised solely of Synchronous Generating Units.

Clause A12.9.1.3, clause A12.9.1.2, clause A12.9.1.4, clause A12.9.1.5, clause A12.9.1.7 and clause A12.9.1.8.

Generating System comprised solely of Asynchronous Generating Units.

Clause A12.9.1.3, clause A12.9.1.2, clause A12.9.1.4, clause A12.9.1.6, clause A12.9.1.7 and clause A12.9.1.8.

Generating System comprised of Synchronous Generating Units and Asynchronous Generating Units.

Clause A12.9.1.3, clause A12.9.1.2, clause A12.9.1.4, clause A12.9.1.7, clause A12.9.1.8 and:

(a) for that part of the Generating System comprised of Synchronous Generating Units, clause A12.9.1.5;

(b) for that part of the Generating System comprised of Asynchronous Generating Units, clause A12.9.1.6.

Table A12.9.1.1: Common Requirements for Disturbance Ride through for Multiple Disturbances

All Generating Systems

A12.9.1.2. Any relevant disconnection settings must be provided as part of the Generator Performance Standard.

A12.9.1.3. The Generator Performance Standard must include any operational arrangements to ensure the Generating System, including all operating Generating Units, will meet their agreed performance levels under abnormal Network or Generating System conditions.

A12.9.1.4. When assessing multiple disturbances, a fault that is re-established following operation of automatic reclose Protection Scheme shall be counted as a separate disturbance.

Synchronous Generating Systems and units

A12.9.1.5. For a Generating System comprised solely of Synchronous Generating Units, the reactive current contribution must equal or exceed 250% of the Maximum Continuous Current of the Generating System. For a Synchronous Generating Unit in any other Generating System, the reactive current contribution must equal or exceed 250% of the Maximum Continuous Current of that Synchronous Generating Unit.

Asynchronous Generating Systems

A12.9.1.6. For a Generating System comprised of Asynchronous Generating Units:

$a$ the reactive current contribution must equal or exceed the Maximum Continuous Current of the Generating System, including all operating Asynchronous Generating Units;

$b$ [Blank]

$c$ the reactive current contribution required may be calculated using phase to phase, phase to ground or sequence components of voltages. The ratio of the negative sequence to positive sequence components of the reactive current contribution must be agreed with AEMO and the Network Operator for the types of disturbances specified in this Technical Requirement; and

$d$ the Generator Performance Standard must record all conditions (which may include temperature) considered relevant by AEMO and the Network Operator under which the reactive current response is required.

Measurement location and temperature limitations

A12.9.1.7. In relation to the application of this Technical Requirement, the requirements apply at the Connection Point unless otherwise specified in the relevant clause, or the Network Operator or AEMO determines that the Technical Requirement must be measured at a different location for the particular Generating Unit or Generating System, in which case the measurement location must be recorded as part of the relevant Generator Performance Standard.

A12.9.1.8. In relation to the application of this Technical Requirement, unless otherwise specified in the relevant clause, the requirements apply when operating at any Active Power and Reactive Power level as permitted or required under the other Technical Requirements in this Appendix, and the Market Participant responsible for the Transmission Connected Generating System must specify any thermal limitations that may limit the output of the Generating System or Generating Unit in relation to this Technical Requirement.

A12.9.2. Ideal Generator Performance Standard

A12.9.2.1. The Ideal Generator Performance Standard as it applies to different Generating Systems, is specified in Table A12.9.2.1:

Generating System comprised solely of Synchronous Generating Units.

Clause A12.9.2.2, clause A12.9.2.3 and clause A12.9.2.4.

Generating System comprised solely of Asynchronous Generating Units.

Clause A12.9.2.2, clause A12.9.2.3 and clause A12.9.2.5 to clause A12.9.2.8.

Generating System comprised of Synchronous Generating Units and Asynchronous Generating Units.

Clause A12.9.2.2 and clause A12.9.2.3 and:

(a) for that part of the Generating System comprised of Synchronous Generating Units, clause A12.9.2.4;

(b) for that part of the Generating System comprised of Asynchronous Generating Units, clause A12.9.2.5 to clause A12.9.2.8.

Table A12.9.2.1: Disturbance Ride through for Multiple Disturbances Ideal Generator Performance Standard

All Generating Systems

A12.9.2.2. A Generating System and each of its operating Generating Units must remain in Continuous Uninterrupted Operation for any disturbances caused by:

$a$ a Credible Contingency;

$b$ a three phase fault in a Transmission System cleared by all relevant primary Protection Systems; and

$c$ a two phase to ground, phase to phase or phase to ground fault in a transmission or distribution system or a three phase fault in a distribution system cleared in:

$i$ the longest time expected to be taken for a relevant breaker fail Protection System to clear the fault; or

$ii$ if a Protection System referred to in clause A12.9.2.2.(c)(i) is not installed, the greater of 450 milliseconds and the longest time expected to be taken for all relevant primary Protection Systems to clear the fault,

provided that the event is not one that would disconnect the Generating Unit from the SWIS by removing Network elements from service or as a result of the operation of an existing inter-trip, Protection Scheme or runback scheme approved by the Network Operator and AEMO.

A12.9.2.3. A Generating System and each of its operating Generating Units must remain in Continuous Uninterrupted Operation for a series of up to 15 disturbances within any 5 minute period.

Synchronous Generating Systems

A12.9.2.4. Subject to any changed power system conditions or energy source availability beyond the operator of the Generating System’s reasonable control, a Generating System comprised of Synchronous Generating Units, in respect of the faults referred to in clause A12.9.2.2, must supply to, or absorb from, the Network:

$a$ to assist the maintenance of power system voltages during the fault, capacitive reactive current of at least the greater of its pre-disturbance reactive current and 4% of the Maximum Continuous Current of the Generating System including all operating Synchronous Generating Units (in the absence of a disturbance) for each 1% reduction (from the level existing just prior to the fault) of Connection Point voltage or another agreed location in the SWIS (including within the Generating System) during the fault;

$b$ after clearance of the fault, Reactive Power sufficient to ensure that the Connection Point voltage or another agreed location in the SWIS (including within the Generating System) is within the range for Continuous Uninterrupted Operation; and

$c$ from 100 milliseconds after clearance of the fault, Active Power of at least 95% of the level existing just prior to the fault.

Asynchronous Generating Systems

A12.9.2.5. Subject to any changed power system conditions or energy source availability beyond the operator of the Generation System’s reasonable control, a Generating System comprised of Asynchronous Generating Units, for the faults referred to in clause A12.9.2.2, must have equipment capable of supplying to, or absorbing from, the Network:

$a$ to assist the maintenance of power system voltages during the fault:

$i$ capacitive reactive current in addition to its pre-disturbance level of at least 4% of the Maximum Continuous Current of the Generating System including all operating Asynchronous Generating Units (in the absence of a disturbance) for each 1% reduction of voltage at the Connection Point below a specified threshold level within the under-voltage range of 85% to 90% of nominal voltage, except where a Generating System is directly connected to the SWIS with no step-up or connection Transformer and voltage at the Connection Point is 5% or lower of nominal voltage; and

$ii$ inductive reactive current in addition to its pre-disturbance level of at least 6% of the Maximum Continuous Current of the Generating System including all operating Asynchronous Generating Units (in the absence of a disturbance) for each 1% increase of voltage at the Connection Point above a specified threshold level within the over-voltage range of 110% to 115% of nominal voltage,

during the disturbance and maintained until Connection Point voltage recovers to between 90% and 110% of nominal voltage, or such other range agreed with the Network Operator and AEMO; and

$b$ from 100 milliseconds after clearance of the fault, Active Power of at least 95% of the level existing just prior to the fault.

A12.9.2.6. The under-voltage and over-voltage range referred to in clause A12.9.2.5(a)(i) and clause A12.9.2.5(a)(ii) may be varied with the agreement of the Network Operator and AEMO (provided the magnitude of the range between the upper and lower bounds remains at 5%).

A12.9.2.7. The reactive current response referred to in clause A12.9.2.5(a)(i) and clause A12.9.2.5(a)(ii) must have a Rise Time of no greater than 40 milliseconds and a Settling Time of no greater than 70 milliseconds and must be Adequately Damped.

A12.9.2.8. Subject to a Generating System's thermal limitations as specified in clause A12.9.1.8 and energy source availability, a Generating System must make available at all times:

$a$ sufficient current to maintain rated output in accordance with the relevant Australian Standard or ISO Standard for Asynchronous Generating Units of the Generating System including all operating Generating Units (in the absence of a disturbance), for all Connection Point voltages above 115% (or otherwise, above the agreed over-voltage range). The details regarding which relevant Australian Standard or ISO Standard applies is documented in the guidelines published by the Network Operator under clause 3A.4.4; and

$b$ the Maximum Continuous Current of the Generating System including all operating Generating Units (in the absence of a disturbance) for all Connection Point voltages below 85% (or otherwise, below the agreed under-voltage range),

despite the amount of reactive current injected or absorbed during voltage disturbances, except that AEMO and the Network Operator may agree limits on active current injection where required to maintain Power System Security and/or the Quality of Supply to other Equipment connected to the SWIS.

A12.9.3. Minimum Generator Performance Standard

A12.9.3.1. The Minimum Generator Performance Standard as it applies to different Generating Systems, is specified in Table A12.9.3.1:

Generating System comprised solely of Synchronous Generating Units.

Clause A12.9.3.2, clause A12.9.3.3 clause A12.9.3.4.

Generating System comprised solely of Asynchronous Generating Units.

Clause A12.9.3.2, clause A12.9.3.3 and clause A12.9.3.5 to clause A12.9.3.8.

Generating System comprised of Synchronous Generating Units and Asynchronous Generating Units.

Clause A12.9.3.2 and clause A12.9.3.3 and:

(a) for that part of the Generating System comprised of Synchronous Generating Units, clause A12.9.3.4;

(b) for that part of the Generating System comprised of Asynchronous Generating Units, clause A12.9.3.5 to clause A12.9.3.8.

Table A12.9.3.1: Disturbance Ride through for Multiple Disturbances Minimum Generator Performance Standard

All Generating Systems

A12.9.3.2. A Generating System and each of its operating Generating Units must remain in Continuous Uninterrupted Operation for any disturbance caused by:

$a$ a Credible Contingency; or

$b$ a single phase to ground, phase to phase or two phase to ground fault or three phase fault in a transmission or distribution system cleared in the longest time expected to be taken for all relevant primary Protection Systems to clear the fault,

provided that the event is not one that would disconnect the Generating Unit from the SWIS by removing Network elements from service or as a result of the operation of an inter-trip, Protection Scheme or runback scheme approved by the Network Operator and AEMO.

A12.9.3.3. A Generating System and each of its operating Generating Units must remain in Continuous Uninterrupted Operation for a series of up to 6 disturbances within any 5 minute period.

Synchronous Generating Systems

A12.9.3.4. After clearance of a fault, a Generating System comprised of Synchronous Generating Units, in respect of the faults referred to in clause A12.9.3.2 must:

$a$ deliver Active Power to the Network, and supply or absorb leading or lagging Reactive Power, sufficient to ensure that the Connection Point voltage or another location in the SWIS (including within the Generating System), as specified by the Network Operator, is within the range for Continuous Uninterrupted Operation agreed under the relevant Generator Performance Standard; and

$b$ return to at least 95% of the pre-fault Active Power output within a period of time agreed by AEMO and the Network Operator.

Asynchronous Generating Systems

A12.9.3.5. Subject to a Generating System's thermal limitations as specified in clause A12.9.1.8 and any changed power system conditions or energy source availability beyond the operator of the Generating System’s reasonable control, a Generating System comprised of Asynchronous Generating Units, for the faults referred to in clause A12.9.3.2, must have equipment capable of supplying to, or absorbing from, the Network:

$a$ to assist the maintenance of power system voltages during the fault:

$i$ capacitive reactive current in addition to its pre-disturbance level of at least 2% of the Maximum Continuous Current of the Generating System including all operating Asynchronous Generating Units (in the absence of a disturbance) for each 1% reduction of voltage at the Connection Point below a specified threshold level agreed by the Network Operator and AEMO within the under-voltage range of 80% to 90% of nominal voltage, except where:

1. voltage at the Connection Point is 15% or lower of nominal voltage; or

2. where the Generating System is directly connected to the SWIS with no step-up or connection Transformer and voltage at the Connection Point is 20% or lower of nominal voltage; and

$ii$ inductive reactive current in addition to its pre-disturbance level of at least 2% of the Maximum Continuous Current of the Generating System including all operating Asynchronous Generating Units (in the absence of a disturbance) for each 1% increase of voltage at the Connection Point above a specified threshold level agreed by the Network Operator and AEMO within the over-voltage range of 110% to 120% of nominal voltage,

during the disturbance and maintained until the Connection Point voltage recovers to between 90% and 110% of nominal voltage, or such other range agreed with the Network Operator and AEMO; and

$b$ returning to at least 95% of the pre-fault Active Power output, after clearance of the fault, within a period of time agreed by the operator, AEMO and the Network Operator.

A12.9.3.6. The under-voltage and over-voltage range referred to in clause A12.9.3.5(a)(i) and clause A12.9.3.5(a)(ii) may be varied with the agreement of the Network Operator and AEMO (provided the magnitude of the range between the upper and lower bounds remains at 10%).

A12.9.3.7. Where AEMO and the Network Operator require the Generating System to sustain a response duration of 2 seconds or less, the reactive current response referred to in clause A12.9.3.5(a)(i) and clause A12.9.3.5(a)(ii) must have a Rise Time of no greater than 40.0 milliseconds and a Settling Time of no greater than 70.0 milliseconds and must be Adequately Damped.

A12.9.3.8. Where AEMO and the Network Operator require the Generating System to sustain a response duration of greater than 2 seconds, the reactive current Rise Time and Settling Time must be as soon as practicable and must be Adequately Damped. The Rise Time and Settling Time must be provided as part of the Generator Performance Standard.

A12.9.4. Negotiation Criteria

A12.9.4.1. A Proposed Negotiated Generator Performance Standard may be accepted if the connection of the Generating System at the proposed performance level would not cause other Generating Systems or Loads to trip as a result of an event, when they would otherwise not have tripped for the same event.

A12.10. Technical Requirement: Disturbance Ride Through for Partial Load Rejection

Explanatory Note

Section A12.10.1 is revised to provide clarity on where the requirement is to be measured from and the temperatures and outputs over which the Technical Requirement applies. There are also some minor wording changes to aid reading and make use of standard defined terms.

A12.10.1. Common Requirements

A12.10.1.1. In relation to the application of this Technical Requirement, the requirements apply at the Connection Point unless otherwise specified in the relevant clause, or the Network Operator or AEMO determines that the Technical Requirement must be measured at a different location for the particular Generating Unit or Generating System, in which case the measurement location must be recorded as part of the relevant Generator Performance Standard.

A12.10.1.2. In relation to the application of this Technical Requirement, unless otherwise specified in the relevant clause, the requirements apply when operating at any Active Power and Reactive Power level as permitted or required under the other Technical Requirements in this Appendix, and at all temperatures up to and including the Maximum Temperature.

A12.10.2. Ideal Generator Performance Standard

A12.10.2.1. A Generating System and each of its operating Generating Units must be capable of Continuous Uninterrupted Operation during and following a sudden reduction in Active Power generation as a result of a Contingency Event, provided that the reduction is less than 30% of the Generating System's Rated Maximum Active Power and the Active Power generation remains above the Generating System's Rated Minimum Active Power output level.

A12.10.3. Minimum Generator Performance Standard

A12.10.3.1. A Generating System must be capable of Continuous Uninterrupted Operation during and following a sudden reduction in Active Power generation as a result of a Contingency Event, provided that the reduction is less than 5% of the Generating System's Rated Maximum Active Power and the Active Power generation remains above the Generating System's Rated Minimum Active Power output level.

A12.10.4. Negotiation Criteria

A12.10.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.11. Technical Requirement: Disturbance Ride Through for Quality of Supply

A12.11.1. Common Requirements

A12.11.1.1. There are no Common Requirements for this Technical Requirement.

A12.11.2. Ideal Generator Performance Standard

A12.11.2.1. The Ideal Generator Performance Standard is the same as the Minimum Generator Performance Standard for Disturbance Ride Through for Quality of Supply.

A12.11.3. Minimum Generator Performance Standard

A12.11.3.1. A Generating System including each of its operating Generating Units and reactive Equipment, must not disconnect from the SWIS as a result of voltage fluctuation, harmonic voltage distortion and voltage unbalance conditions at the Connection Point within the levels specified for flicker, harmonics and negative phase sequence voltage in the Technical Rules.

A12.11.4. Negotiation Criteria

A12.11.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.12. Technical Requirement: Quality of Electricity Generated

Explanatory Note

Section A12.12 is revised to remove the linkages to specified standards that change over time, and instead link to the limits specified by the Network Operator. Western Power will subsequently provide guidance for Participants on the relevant levels in the guidelines published under clause 3A.4.4.

A12.12.1. Common Requirements

A12.12.1.1. A Generating System, when generating and when not generating, must not produce, at any of its Connection Points for generation, voltage imbalance greater than the limits determined by the Network Operator as necessary to achieve the requirements specified for negative phase sequence voltage at the Connection Point in the Technical Rules.

A12.12.2. Ideal Generator Performance Standard

A12.12.2.1. A Generating System, when generating and when not generating, must not produce at any of its Connection Points for generation:

$a$ voltage fluctuation greater than the limits allocated by the Network Operator that are no more onerous than the lesser of the acceptance levels determined in accordance with either of the stage 1 or the stage 2 evaluation procedures defined in AS/NZS 61000.3.7:2001; and

$b$ harmonic voltage distortion greater than emission limits allocated by the Network Operator that are no more onerous than the lesser of the acceptance levels determined in accordance with either of the stage 1 or the stage 2 evaluation procedures defined in AS/NZS 61000.3.6:2001.

A12.12.3. Minimum Generator Performance Standard

A12.12.3.1. A Generating System, when generating and when not generating, must not produce at any of its Connection Points for generation:

$a$ voltage fluctuations greater than limits determined by the Network Operator through the negotiation using the stage 3 evaluation procedure defined in AS/NZS 61000.3.7:2001, with the Market Participant responsible for the Transmission Connected Generating System agreeing to fund any works necessary to mitigate adverse effects from accepting this emission level; and

$b$ Harmonic voltage distortion greater than emission limits determined by the Network Operator through the negotiation using the Stage 3 evaluation procedure defined in AS/NZS 61000.3.6:2001 with the Market Participant responsible for the Transmission Connected Generating System agreeing to fund any works necessary to mitigate adverse effects from accepting this emission level.

A12.12.4. Negotiation Criteria

A12.12.4.1. A Proposed Negotiated Generator Performance Standard must not prevent the Network Operator meeting each SWIS Operating Standard or contractual obligations to existing holders of Arrangements for Access.

A12.13. Technical Requirement: Generation Protection Systems

A12.13.1. Common Requirements

A12.13.1.1. There are no Common Requirements for this Technical Requirement.

A12.13.2. Ideal Generator Performance Standard

A12.13.2.1. The Ideal Generator Performance Standard is the same as the Minimum Generator Performance Standard for Generation Protection Systems.

A12.13.3. Minimum Generator Performance Standard

A12.13.3.1. A Generating System must meet the protection requirements specified in the Technical Rules for both Generating Systems and the Transmission System (where relevant), including the requirement for faults to be cleared within maximum Total Fault Clearance Times specified in the Technical Rules or, where specified, a Critical Fault Clearance Time developed by the Network Operator.

A12.13.3.2. All Protection Schemes must have the relevant level of redundancy as specified in the Technical Rules and must operate to clear faults within the prescribed times.

A12.13.3.3. Anti-islanding protection must be installed and made available to ensure the Generating System is prevented from supplying an isolated portion of the SWIS when it is not secure to do so. The details regarding the performance requirements for anti-islanding systems for Transmission Connected Generating Systems are documented in accordance with the guidelines produced by the Network Operator under clause 3A.4.4.

A12.13.3.4. All Protection Schemes necessary to disconnect the Generating System during abnormal conditions in the power system that would threaten the stability of the Generating System, or risk damage to the Generating System, must be installed and available. The settings of these Protection Schemes must deliver the required performance for disturbance ride through specified in Part A12.7, Part A12.8 and Part A12.9 of this Appendix 12 and form part of the Generator Performance Standard.

A12.13.3.5. All Protection Scheme settings referred to in this Appendix must be made available to the Network Operator and AEMO.

A12.13.4. Negotiation Criteria

A12.13.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.14. Technical Requirement: Remote Monitoring Requirements

A12.14.1. Common Requirements

A12.14.1.1. There are no Common Requirements for this Technical Requirement.

A12.14.2. Ideal Generator Performance Standard

A12.14.2.1. The Ideal Generator Performance Standard is the same as the Minimum Generator Performance Standard for Remote Monitoring Requirements.

A12.14.3. Minimum Generator Performance Standard

A12.14.3.1. The Network Operator or AEMO may require Remote Monitoring Equipment to be installed in order to enable the Network Operator or AEMO to monitor the performance of a Generating Unit (including its dynamic performance) remotely, where this is necessary in real time for control, planning or Power System Security.

A12.14.3.2. All Remote Monitoring Equipment installed, upgraded, modified or replaced (as applicable) under clause A12.14.3.1, must conform to the Communication Standard as it applies Remote Monitoring Equipment and must be compatible with the Network Operator's and AEMO's SCADA system, including the requirements of the Nomenclature Standards.

A12.14.3.3. The Remote Monitoring Equipment must provide for the signals specified in the WEM Procedure described in clause 2.35.4 and such other information required by the Network Operator or AEMO.

A12.14.3.4. The Remote Monitoring Equipment must be kept available at all times, subject to Outages as agreed by AEMO.

A12.14.4. Negotiation Criteria

A12.14.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.15. Technical Requirement: Remote Control Requirements

A12.15.1. Common Requirements

A12.15.1.1. There are no Common Requirements for this Technical Requirement.

A12.15.2. Ideal Generator Performance Standard

A12.15.2.1. The Ideal Generator Performance Standard is the same as the Minimum Generator Performance Standard for Remote Control Requirements.

A12.15.3. Minimum Generator Performance Standard

A12.15.3.1. The Network Operator or AEMO may, for any Generating Unit which may be unattended when connected to the Transmission System, require Remote Control Equipment to be installed in order to enable the Network Operator or AEMO to disconnect a Generating Unit from the Transmission System.

A12.15.3.2. All Remote Control Equipment installed, upgraded, modified or replaced (as applicable) under clause A12.15.3.1 must conform to the Communication Standard and must be compatible with the Network Operator's SCADA system, including the requirements of Nomenclature Standards.

A12.15.3.3. The Remote Control Equipment must be kept available at all times, subject to Outages as agreed by AEMO.

A12.15.4. Negotiation Criteria

A12.15.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.16. Technical Requirement: Communications Equipment Requirements

A12.16.1. Common Requirements

A12.16.1.1. There are no Common Requirements for this Technical Requirement.

A12.16.2. Ideal Generator Performance Standard

A12.16.2.1. The Ideal Generator Performance Standard is the same as the Minimum Generator Performance Standard for Communications Equipment Requirements.

A12.16.3. Minimum Generator Performance Standard

A12.16.3.1. Communications paths must be provided and maintained (with redundancy consistent with the standard developed by AEMO to meet the Communication Standard) between the Remote Monitoring Equipment and Remote Communication Equipment installed at any of its Generating Units to a communications interface at the relevant Power Station and in a location acceptable to the Network Operator. Communications systems between this communications interface and the Network Operator’s Control Centre are the responsibility of the Network Operator, unless otherwise agreed.

A12.16.3.2. A Market Participant responsible for the Transmission Connected Generating System must provide and maintain a speech communication channel (Primary Speech Communication Channel) by means of which routine and emergency control telephone calls may be established between the operator of the Generation System and AEMO or the Network Operator, whichever is applicable.

A12.16.3.3. The Primary Speech Communication Channel must meet any requirements specified in the Communication Standard.

A12.16.3.4. Where the public switched telephone network is to be used as the Primary Speech Communication Channel, a sole-purpose connection must be provided, which must be used only for operational communications.

A12.16.3.5. The communications paths to any applicable Remote Monitoring Equipment or Remote Communication Equipment must be kept available at all times, subject to Outages as agreed by AEMO.

A12.16.3.6. The Primary Speech Communication Channel must be maintained in good working order.

A12.16.4. Negotiation Criteria

A12.16.4.1. There are no Negotiation Criteria for this Technical Requirement.

A12.17. Technical Requirement: Generation System Model

A12.17.1. Common Requirements

A12.17.1.1. There are no Common Requirements for this Technical Requirement.

A12.17.2. Ideal Generator Performance Standard

A12.17.2.1. The Ideal Generator Performance Standard is the same as the Minimum Generator Performance Standard for Generation System Model.

A12.17.3. Minimum Generator Performance Standard

A12.17.3.1. All modelling data described in the WEM Procedure referred to in clause 3A.4.2 must be provided to the Network Operator within the timeframes specified in the WEM Procedure, as updated from time to time.

A12.17.3.2. The modelling data provided must be sufficient to enable the Network Operator or AEMO to predict the output of the Generation System under all power system conditions.

A12.17.3.3. The observed performance of the Generation System must match the predicted performance of the Generation System using the Generation System Model, as assessed by the Network Operator or AEMO.

A12.17.3.4. The relevant Market Participant must provide updates to the Generation System Model in order to meet the requirements of this Technical Requirement in accordance with the timeframes specified in the WEM Procedure referred to in clause 3A.4.2, as updated from time to time.

A12.17.4. Negotiation Criteria

A12.17.4.1. There are no Negotiation Criteria for this Technical Requirement.

Appendix 13: Frequency Operating Standards System Frequency Outcomes

**TABLE 1 – SUMMARY OF SYSTEM FREQUENCY OUTCOMES FOR THE SOUTH WEST

INTERCONNECTED SYSTEM**

Condition	Contain Band (Hz)	Stabilise (Hz)	Recover (Hz)
Normal Operating Frequency Band	49.8 to 50.2 Hz (99% of the time over any rolling 30-day period)	N/A	N/A
Normal Operating Frequency Excursion Band	49.7 to 50.3 Hz	49.8 to 50.2 Hz within 5 minutes	N/A
Credible Contingency Event Frequency Band	48.75 to 51 Hz	For over-frequency events: below 50.5 Hz within 2 minutes	49.8 to 50.2 Hz within 15 minutes
Island Separation Frequency Band	48.75 to 51 Hz	For over-frequency events: below 50.5 Hz within 2 minutes	49.8 to 50.2 Hz within 15 minutes
Extreme Frequency Tolerance Band	47 to 52 Hz (reasonable endeavours)	48.0 to 50.5 Hz within 5 minutes (reasonable endeavours) and: For under-frequency events: above 47.5 Hz within 10 seconds (reasonable endeavours). For over-frequency events: below 51.5 Hz within 1 minute; and below 51 Hz within 2 minutes (reasonable endeavours)	49.8 to 50.2 Hz within 15 minutes (reasonable endeavours)
Rate of Change of Frequency Safe Limit	0.25 Hz over any 500 millisecond period	N/A	N/A

**TABLE 2 – SUMMARY OF SYSTEM FREQUENCY OUTCOMES FOR ISLANDS WITHIN THE

SOUTH WEST INTERCONNECTED SYSTEM**

Condition	Contain (Hz)	Recover (Hz)
Normal Operating Frequency Band	49.5 to 50.5 Hz (reasonable endeavours)	N/A
Credible Contingency Event Frequency Band	48.75 to 51 Hz (reasonable endeavours)	49.5 to 50.5 Hz (as soon as practicable)
Island Separation Frequency Band	48.75 to 51 Hz (reasonable endeavours)	49.5 to 50.5 Hz (as soon as practicable)
Extreme Frequency Tolerance Band	47 to 52 Hz (reasonable endeavours)	49.5 to 50.5 Hz (as soon as practicable)
Rate of Change of Frequency Safe Limit	0.25 Hz over any 500 millisecond period (reasonable endeavours)	N/A

Notes

This is a compilation of the Wholesale Electricity Market Rules. When this compilation was prepared, provisions referred to in the following table had not come into operation and were therefore not included in this compilation.

Provision that has not come into operation

Citation	Gazettal	Commencement
Amending Rules 2016, Schedule B, Part 4	31 May 2016, p. 1709	8:00am on the day fixed by the Minister by order published in the Gazette

Version history

Date	Amendment	Rule Change Reference
15 December 2006	All rules amended and published in the Government Gazette up to 15 December 2006.
13 March 2007	Minister amended clause 6.3B.1B(new).	Electricity Industry (Wholesale Electricity Market) Regulations 2004 (WA), regulation 6(2).
10 May 2007	IMO amended clauses 7.9.1, 7.9.2, 7.9.4, 7.9.5, 7.9.6, 7.9.8, 7.9.11, and 7.9.12.	RC_2007_01
1 July 2007	IMO amended clause 4.26.2.	RC_2007_05
1 September 2007	IMO amended Appendix 5.	RC_2007_11
3 September 2007	Updated the Glossary.
1 October 2007	IMO amended clauses 6.17.6, 7.7.5A and 7.7.5B.	RC_2007_02
1 October 2007	IMO amended clauses 3.16.9, 3.17.9, 3.18.11 and 3.19.6.	RC_2007_03
4 October 2007	IMO amended clauses 3.21.7 (new), 7.13.1 and 7.13.1A (new).	RC_2007_15
4 October 2007	IMO amended clauses 3.18.6, 3.21.4, 3.21.5 (new), 3.21.6 (new), 6.3A.2, 7.3.4 and 7.13.1.	RC_2007_16
15 October 2007	IMO amended clauses 2.28.16 and 2.28.16B (new).	RC_2007_04
25 October 2007	IMO amended clauses 6.4.6 (new), 6.5A.1 and 6.12.1.	RC_2007_06
1 November 2007	IMO amended clauses 4.26.1, 4.26.3 and the Glossary.	RC_2007_08
	IMO amended clauses 1.4.1 and the Glossary.	RC_2007_17
	IMO amended clauses 2.37.1, 3.19.1, 3.21.6, 4.24.13, 6.5.1, 10.5.1 and the Glossary.	RC_2007_20
20 November 2007	IMO amended clause 2.13.10.	RC_2007_07
1 December 2007	IMO amended clause 4.12.6.	RC_2007_21
1 December 2007	IMO amended clauses 5.2.1 and 5.2.2.	RC_2007_22
18 December 2007	IMO amended clause 4.16.5.	RC_2007_24
21 December 2007	IMO amended clause 6.20.3.	RC_2007_26
1 February 2008	IMO amended clauses 6.5.1A, 6.5.1C (new), 6.5.4, 6.17.1, 6.17.5, 6.21.2, 7.10.1, 9.8.1 and the Glossary.	RC_2007_10
	IMO amended clauses 6.17.6 and 7.13.1.	RC_2007_18
	IMO amended clause 4.28.8.	RC_2007_19
1 March 2008	IMO amended clause 10.5.1.	RC_2007_13
20 March 2008	IMO amended clauses 6.14.2, 6.14.3 and 6.14.4.	RC_2008_05
10 April 2008	IMO amended clause 4.5.9.	RC_2007_28
20 April 2008	IMO amended clauses 2.23.12, 3.11.8, 3.11.8A (new), 3.11.8B (new), 3.11.8C (new), 3.11.8D (new) and 3.13.1.	RC_2008_12
1 May 2008	IMO amended clause 4.28.9, Appendix 5 and Appendix 5A (new).	RC_2008_09
2 May 2008	IMO amended clauses 3.4.1 and 3.5.1.	RC_2007_31
15 May 2008	IMO amended clauses 2.24.5 and 2.24.5A (new).	RC_2008_13
26 May 2008	IMO amended clause 4.25.9.	RC_2008_01
	IMO amended clause 3.17.9.	RC_2008_02
	IMO amended clauses 3.16.4 and 3.17.5.	RC_2008_03
1 June 2008	IMO amended clauses 4.26.1, 4.26.1A (new), 4.26.1B (new), 4.26.2, 4.26.3, and the Glossary.	RC_2007_36
24 June 2008	IMO amended clauses 2.13.9 and 2.34.12.	RC_2008_04
1 July 2008	IMO amended clauses 2.30.1A (new), 2.30.4, 2.30.5 and 4.23A.4 (new).	RC_2008_10
10 July 2008	IMO amended clauses 4.25.4A (new), 4.25.4B (new), 4.25.4C (new) and 4.25.4D(new).	RC_2008_06
10 July 2008	IMO amended clauses 6.4.7 (new), 6.14.1, 6.14.1A (new), 6.14.7 (new) and 7.13.1B (new).	RC_2008_08
1 August 2008	IMO amended clauses 2.34.14, 6.18.1, 6.18.2, 6.18.3, 6.20.1, 6.20.5, 6.20.7, 6.20.8, 10.5.1 and Appendix 1.	RC_2008_07
1 August 2008	IMO amended clauses 2.13.8 (b), 4.16.4 (e), 4.26.2, 6.14.4 (b), 7.7.5A (b), 9.10.1 and Appendix 5.	RC_2008_19
6 August 2008	IMO amended clauses 2.26.1, 2.26.3, 2.26.4, 4.1.19, 4.16.3, 4.16.4, 4.16.5, 4.16.7, 4.16.8, 4.16.9 (new), 4.22.3 and Appendix 4.	RC_2008_11
20 August 2008	IMO amended clauses 6.5.1 and 6.5A.1.	RC_2008_15
2 September 2008	IMO amended clauses 3.21A.7, 3.21A.7A (new), 4.1.26, 4.10.1, 4.27.10, 4.27.10A (new), 4.27.11, 4.27.11A (new), 4.27.11B (new) , 4.27.11C (new), 4.27.11D (new), 4.27.12, 6.5.1A and 6.5.1C.	RC_2008_17
1 November 2008	IMO amended clauses 4.11.5 and 10.2.2.	RC_2008_14
	IMO amended clauses 3.7.3(new), 3.7.4 (new), 3.7.5 (new) and 3.7.6 (new).	RC_2008_21
	IMO amended the Glossary.	RC_2008_23
18 November 2008	IMO amended clauses 2.1.3 and 2.2.3.	RC_2008_18
1 January 2009	IMO amended clause 4.12.1.	RC_2008_26
1 January 2009	IMO amended clauses 4.28.3 and 4.28.4.	RC_2008_27
1 February 2009	IMO amended clauses 4.26.1 and 4.26.1A.	RC_2008_24
	IMO amended clause 4.28A.1.	RC_2008_25
	IMO amended clauses 4.24.3 and 4.24.15.	RC_2008_28
	IMO amended clause 2.33.4.	RC_2008_29
	IMO amended clauses 7.9.1, 7.9.1A (new) and 7.9.5.	RC_2008_40
16 February 2009	IMO amended clauses 4.13.1, 4.13.10, 4.13.10A (new), 4.13.11 , 4.13.11A (new) and 4.13.11B (new).	RC_2008_30
16 February 2009	IMO amended clauses 2.12, 2.14.5A (new), 2.14.6A (new), 2.14.6B (new), 2.14.7, 2.14.8(new) and 2.14.9 (new).	RC_2008_33
1 March 2009	IMO amended clauses 2.29.5, 2.29.8A (new), 2.29.9A (new), 2.29.9B (new), 2.29.9C (new), 4.8.3, 4.10.1, 4.11.1, 4.11.4, 4.11.4A (new), 4.12.8 (new), 4.14.1, 4.25.4E (new), 4.25.4F (new), 4.26.2C (new), 7.7.10 (new), 7.13.1 and the Glossary.	RC_2008_20
18 March 2009	IMO amended clause 7.10.5 and 7.10.5A (new).	RC_2009_09
17 April 2009	IMO amended the Glossary.	RC_2009_12
27 April 2009	IMO amended clauses 1.4.1, 2.5.7 and 4.11.5.	RC_2009_01
	IMO amended clause 2.8.13.	RC_2009_02
	IMO amended clauses 2.10.6, 2.10.13, 2.10.14, 2.10.15, 2.10.16 and the Glossary.	RC_2009_04
1 May 2009	IMO amended clause 8.6.1 and Appendix 5.	RC_2008_32
1 June 2009	IMO amended clauses 3.11.8E (new) and 6.17.6.	RC_2008_38
1 July 2009	IMO amended clause 7.2.5.	RC_2009_03
6 July 2009	IMO amended clauses 2.7.4, 2.7.5, 2.7.8, 2.28.4, 2.31.1, 2.31.5, 2.31.6, 2.31.12, 2.31.13, 2.31.21, 2.34.8, 2.37.8, 2.41.2, 2.41.3, 4.27.10, 5.2.1, 5.2.7, 5.4.2, 5.4.14, 5.5.3, 9.23.1, 9.23.1, 9.23.5, 9.23.6, 10.5.1 and the Glossary.	RC_2009_16
10 July 2009	IMO made minor corrections.
1 August 2009	IMO amended clauses 7.2.3C and 7.3.6.	RC_2009_13
17 August 2009	IMO amended clauses 3.18.4 and 3.18.5D (new).	RC_2009_05
24 August 2009	IMO amended clauses 3.11.15 (new), 4.14.11 (new), 7.13.3 (new) and 10.2.7 (new).	RC_2009_26
1 October 2009	IMO amended clauses 4.26.1, 4.26.1C (new), 4.26.2, 4.26.2D (new), 4.26.2E (new), 4.26.3 and 4.26.3A (new).	RC_2008_20
	IMO amended clause 4.26.1.	RC_2009_18
	IMO amended clauses 2.10.4 and 2.10.11.	RC_2009_24
	IMO amended clause 4.26.2D.	RC_2009_29
1 November 2009	IMO amended clauses 4.2.7, 4.14.6 and Appendix 3.	RC_2009_07
	IMO amended clause 4.27.2.	RC_2009_19
	IMO amended clause 3.19.2.	RC_2009_20
30 November 2009	IMO amended clauses 2.23.1, 2.23.2, 2.23.3, 2.23.5, 2.23.7, 2.23.12, 3.11.11, 3.11.14, 3.13.1, 3.13.3, 3.13.3A (new), 3.13.3B (new), 3.13.3C (new) and 3.22.1.	RC_2009_23
1 December 2009	IMO amended clauses 4.1.26 and 4.11.1.	RC_2009_11
18 December 2009	IMO amended clauses 1.4.1, 1.5.1, 2.1.2, 2.5.7, 2.5.14, 2.5.15, 2.7.6, 2.7.8, 2.8.9, 2.13.10, 2.14.1, 2.14.3, 2.16.2, 2.28.16B, 2.29.9, 2.30.5, 2.30B.3, 2.30B.5, 2.30B.9, 2.30B.11, 2.30C.1, 2.31.3, 2.32.4, 2.34.7, 3.10.2, 3.18.11, 3.18.11A, 3.19.6, 4.10.1, 4.11.1, 4.12.6, 6.3A.2, 6.5.1, 8.4.1, 8.4.2, 8.4.3, 8.4.4, 8.4.5, 8.5.2, 8.6.1, 8.6.2, 9.3.4, 9.9.1, 9.16.2, 9.23.4, 9.24.1, 9.24.2, 10.5.1, the Glossary, Appendix 4A and Appendix 5.	RC_2009_30
15 January 2010	IMO amended clauses 2.3.1, 2.3.1A (new), 2.3.2, 2.3.5, 2.3.10, 2.3.14, 2.3.15, 2.3.17, 2.7.4, 2.7.5, 2.7.7, 2.10.8, 2.10.9, 2.10.13 and the Glossary.	RC_2009_28
20 January 2010	IMO amended clauses 1.8.2, 1.9.7, 1.9.8, 1.9.9, 1.9.10 and Appendix 8.	RC_2009_41
1 February 2010	IMO amended clauses 4.1.1, 4.1.1A, 4.5.2, 4.9.3, 4.11.1, 4.12.6, 4.15.1, 4.15.2, 4.28C (new) the Glossary and Appendix 3.	RC_2009_10
1 February 2010	IMO amended clause 9.9.2.	RC_2009_21
1 March 2010	IMO amended clause 10.5.1.	RC_2009_17
1 April 2010	IMO amended clauses 4.26.2, 4.26.2E, 4.26.2F (new), 4.26.3. and 4.26.3A.	RC_2010_03
1 May 2010	IMO amended clause 3.9.1.	RC_2009_40
1 June 2010	IMO amended clauses 3.21A.2, 3.21A.3, 3.21A.4, 3.21A.7, 4.1.26, 4.12.6, 4.26.1A, 7.9.4. and the Glossary.	RC_2009_08
1 June 2010	IMO amended clauses 6.20.2, 6.20.7, 6.20.9, 6.20.9A (new) and 6.20.10.	RC_2009_35
1 July 2010	IMO amended clause 3.13.3A.	RC_2010_01
1 July 2010	IMO amended clauses 4.1.2, 4.1.27, 4.13.5, 4.13.8, 4.13.10, 4.13.11, 4.23A.3, 4.24.1, 4.25.3A, 4.25.4, 4.25.4B, 4.25.4F, 4.25.8, 4.25.9, 4.25.12, 4.26.2C, 4.27.5, 4.27.6, 4.27.7, 4.27.8, 4.27.9, 4.27.10A, 4.27.11, 4.27.11A, 4.27.11D, 4.28C.2, 4.28C.4, 4.28C.7, 4.28C.8, 4.28C.9 and 4.28C.12.	RC_2010_02
1 September 2010	IMO amended clauses 3.21A.7A, 4.1.26 and 4.26.1A.	RC_2010_16
1 September 2010	IMO amended clauses 2.8.1, 2.8.2, 2.11.1, 2.11.2, 2.13.17, 2.13.18, 2.13.22, 2.13.23, 2.13.24, 2.13.26, 2.13.28, 2.15.3, 2.16.9G, 2.16.9H, 2.17.3, 2.31.13, 2.32.1, 2.32.5, 2.32.6, 2.32.7, 10.2.2 and 10.5.1 and the Glossary.	RC_2010_18
1 October 2010	IMO amended clauses 2.29.8B (new), 4.25.1, 4.25.2, 4.25.3B (new), 4.25.4, 4.25.9 and 4.25A (new).	RC_2008_20
	IMO amended clauses 6.16.1, 9.3.3, 9.18.3, 9.24.1, 9.24.3, 9.24.3A (new), 9.24.4, 9.24.5, 9.24.8, 9.24.8A (new), 9.24.9 and the Glossary.	RC_2010_04
	IMO amended clause 6.4.6.	RC_2010_10
1 November 2010	IMO amended clauses 2.3.5, 2.3.5A (new) and 2.3.13.	RC_2010_15
1 December 2010	IMO amended clauses 2.13.6, 2.13.6A (new), 2.13.6B (new), 2.13.6C (new), 2.13.6D (new), 2.13.6E (new), 2.13.6F (new), 2.13.6G (new), 2.13.6H (new),2.13.6I (new), 2.13.6J (new), 2.13.6K (new), 2.13.7, 2.13.8,, 7.10.5, 7.10.5B (new), 7.10.7, 10.5.1 and the Glossary.	RC_2009_22
1 December 2010	IMO amended clauses 2.10.7, 2.34.2A, 2.34.10, 2.37.5, 3.4.5, 3.5.6, 3.17.1, 3.17.6, 3.21.4, 3.21.7, 4.8.3, 6.2.2, 6.2.2A, 6.2A.2, 6.3A.2, 6.3A.3, 6.3B.1B, 6.3B.3, 6.3C.3, 6.3C.9, 6.4.1, 6.4.3, 6.5.1A, 6.5.2, 6.5A.2, 6.5C.2, 6.5.4, 6.5C.6, 6.6.2A, 6.6.5, 6.7.2, 6.14.1, 6.16.1, 6.18.2, 6.19.3, 6.19.4, 6.19.9, 6.20.1, 6.20.9A, 6.21.1, 6.21.2, 7.10.5, 7.11.3, 7.11.4, 7.11.6A, 7.11.9, 8.7.1, 9.4.5, 9.4.7, 9.17.3, 9.18.3, 9.19.5, 9.20.5, 9.20.7, 9.24.10, 10.5.1, 10.7.1, 10.8.2 and the Glossary.	RC_2010_26
1 January 2011	IMO amended clauses 3.21A.16 (new) and 10.6.1.	RC_2009_08
1 January 2011	IMO amended clause 3.21A.16	RC_2010_34
1 February 2011	IMO amended clauses 3.21AA (new), 4.11.1, 7.10.2, 7.10.5A, 7.12.1, 7.13.1 and the Glossary.	RC_2009_37
1 February 2011	IMO amended clauses 4.24.1 and the Glossary.	RC_2010_35
1 April 2011	IMO amended clauses 2.30.6, 2.30.7, 2.30.7A (new) and Appendix 2.	RC_2010_06
1 April 2011	IMO amended clauses 2.38.7 (new), 2.38.8 (new), 2.38.9 (new) and 4.13.7.	RC_2010_36
1 May 2011	IMO amended clauses 9.16.3 and 9.16.3A(new) and the Glossary.	RC_2010_19
	IMO amended clauses 2.23.9, 2.23.11, 2.24.2, 2.24.2A (new), 2.24.2B (new) and 9.16.3.	RC_2010_20
	IMO amended clauses 2.34.1, 2.34.12 and 7.7.4A.	RC_2010_21
	IMO amended clauses 3.21.2, 3.21.6, 3.21.8 (new), 3.21.9 (new), 3.21.10 (new), 3.21.11 (new), 3.21.12 (new), 6.15.1, 6.15.2 and the Glossary.	RC_2010_23
1 July 2011	IMO amended clauses 2.1.2, 2.8.13, 2.17.1, 2.22.1, 2.37.6, 2.37.7, 2.37.8, 2.38.1, 2.38.2, 2.38.3, 2.38.4, 2.38.5, 5.1.1, 5.1.2, 5.1.3, 5.1.4, 5.2.1, 5.2.2, 5.2.3, 5.2.4, 5.2.5, 5.2.6, 5.2.7, 5.2A (new), 5.3.1, 5.3.2, 5.3.3, 5.3.4, 5.3.5, 5.3.6, 5.3.7, 5.3.8, 5.3.9, 5.3A (new), 5.4.1, 5.4.2, 5.4.3, 5.4.4, 5.4.5, 5.4.6, 5.4.7, 5.4.8, 5.4.9, 5.4.10, 5.4.11, 5.4.12, 5.4.13, 5.4.14, 5.5.1, 5.5.2, 5.5.3, 5.5.4, 5.6.1, 5.6.2, 5.6.3, 5.7.1, 5.7.2, 5.8.1, 5.8.2, 5.8.3, 5.8.4, 5.8.5, 5.8.6, 5.8.7, 5.8.8, 5.9.1, 5.9.2 (new), 5.9.3 (new), 6.17.6, 7.1.1, 7.6.1A (new) 7.6.6, 7.13.1, 9.12.1, 9.12.2, 9.14.1, 9.14.2, 9.18.3, 9.24.3A, 10.5.1, the Glossary and Appendix 1.	RC_2010_11
	IMO amended clauses 4.11.3A, 7.13.1C (new), 7.7.5B and 7.7.5E (new).	RC_2010_24
	IMO amended clauses 2.29.5N (new), 2.29.5O(new), 2.31.23A (new) and Appendix 1.	RC_2010_29
8 July 2011	IMO amended clauses 2.24.1, 2.24.2, 4.1.8, 4.1.9, 4.1.10, 4.1.12, 4.1.13, 4.1.14, 4.1.15A (new), 4.1.16, 4.1.17, 4.1.18, 4.1.20, 4.1.21, 4.1.21A (new), 4.1.26, 4.2.7, 4.4.1, 4.7.1, 4.9.5, 4.9.9, 4.9.9A (new), 4.10.1, 4.10.2, 4.10.3. 4.10.4 (new), 4.11.1, 4.11.2, 4.11.3A, 4.11.5, 4.11.10 (new), 4.11.11 (new), 4.15.1, 4.20.1, 4.20.5A (new), 4.27.10, 4.27.10A, 4.27.11, 4.27.11A, 4.27.11B, 4.27.11C, 4.27.11D, 4.28C.1, 4.28C.2, 4.29.1, 10.5.1 and the Glossary.	RC_2010_14
1 October 2011	IMO amended clauses 6.17.6 and 7.7.5D.	RC_2008_20
	IMO amended clauses 2.8.13, 4.1.21, 4.1.27, 4.9.9, 4.10.3, 4.11.2A (new), 4.11.3B (new), 4.13.1, 4.13.1A (new), 4.13.1B (new), 4.13.1C (new), 4.13.2, 4.13.2A (new), 4.13.2B (new), 4.13.2C (new), 4.13.3, 4.13.5, 4.13.8, 4.13.10, 4.13.10A, 4.13.10B (new), 4.13.10C (new), 4.13.11, 4.13.11A, 4.13.11B, 4.13.12, 4.13.13 (new), 4.13.14 (new), 4.20.1, 4.25.1, 4.25.2, 4.25.3B, 4.25.4B, 4.26.1, 4.26.1A, 4.28.4, 4.28C.8, 4.28C.8A (new), 4.28C.12, 4.28C.12A (new) and the Glossary.	RC_2010_12
	IMO amended clause 4.26.1 and 4.26.1A.	RC_2010_22
	IMO amended clauses 2.27.1, 2.27.2, 2.27.4, 2.29.1, 2.29.1A (new), 2.29.5, 2.29.5A (new), 2.29.5B (new), 2.29.5C (new), 2.29.5D (new), 2.29.5E (new), 2.29.5F (new), 2.29.5G (new), 2.29.5H (new), 2.29.5I (new), 2.29.5J (new), 2.29.5K (new), 2.29.5L (new), 2.29.5M (new), 2.29.8A, 2.29.8B, 2.29.9A, 2.29.9B, 2.29.9C, 2.30.3, 2.30.5, 2.30B.2, 2.30B.5, 2.33.1, 2.33.4, 2.35.1, 3.14.1, 3.17.5, 4.8.3, 4.10.1, 4.11.1, 4.11.4, 4.11.4A, 4.12.1, 4.12.4, 4.12.8, 4.14.1, 4.18.1, 4.18.2, 4.25.1, 4.25.2, 4.25.3B, 4.25.4, 4.25.4E, 4.25.4F, 4.25.9, 4.25.10, 4.25A, 4.25A.1, 4.25A.2, 4.25A.3, 4.25A.4, 4.25A.5, 4.26.1, 4.26.1A, 4.26.1B, 4.26.1C, 4.26.2, 4.26.2C, 4.26.2CA (new), 4.26.2D, 4.26.2E, 4.26.2F, 4.26.3, 4.26.3A, 4.26.4, 6.3A.2, 6.5A.1, 6.11.1, 6.11.2, 6.11A.1, 6.12.1, 6.15.2, 6.16.1, 6.16.2 (new), 6.17.6, 7.1.1, 7.2.2, 7.6.10, 7.7.3, 7.7.4, 7.7.4A, 7.7.10, 7.10.4, 7.13.1, 9.3.3, 9.3.4, 9.3.7, 9.13.1, 10.5.1, the Glossary, Appendix 1 and Appendix 3.	RC_2010_29
1 November 2011	IMO amended clauses 3.22.2, 3.22.3, 9.9.1, 9.9.1A, 9.9.2, 9.9.3, 9.9.3A (new), 9.9.3B (new), 9.9.4, 9.10A.1, 9.11.1 and the Glossary.	RC_2010_33
	IMO amended clauses 2.8.11, 2.24.1, 2.24.2A, 2.34.12, 3.19.12, 3.21.9, 4.1.13, 4.1.18, 4.5.9, 4.10.1, 4.25.4F, 5.1.1, 6.3B.1B, 6.6.3A, 6.14.4, 7.6A.5, 9.20.5, 9.24.5, the Glossary, Appendix 1 and Appendix 3.	RC_2011_06
	IMO amended clause 2.38.7.	RC_2011_04
	IMO amended clause 7.6.3.	RC_2011_05
1 December 2011	IMO amended clause 2.31.23A.	RC_2010_29
	IMO amended clauses 4.26.2, 4.26.2B and 4.26.5.	RC_2011_07
	IMO amended clauses 4.12.4, 4.12.8, 4.26.2D and 7.6.10.	RC_2011_08
1 January 2012	IMO amended clause 4.1.11.	RC_2010_14
	IMO amended clauses 4.10.1, 4.10.3, 4.10.3A (new), 4.11.2, 4.11.2A, 4.11.3A, 4.11.3B, 4.11.3C (new), 4.11.3D (new), 4.11.3E (new), 6.17.6, 7.7.5A, 7.7.5B, 7.7.5C, 7.7.5D, 7.7.5E, 7.7.9, 7.13.1, 7.13.1C, 10.5.1 ,the Glossary and Appendix 9 (new).	RC_2010_25
	IMO amended clauses 2.10.17 (new), 2.10.18 (new) and 2.10.19 (new).	RC_2011_12
	IMO amended clause 4.16.3.	RC_2011_13
1 March 2012	IMO amended clauses 2.17.1, 2.31.13, 2.32.7A (new), 2.32.7B (new), 2.32.7C (new), 2.32.7D (new), 2.32.7E (new), 2.32.7F (new) and the Glossary.	RC_2010_31
1 March 2012	IMO amended clauses 2.33.1, 2.33.2, 2.33.3, 2.33.4, 3.2.1, 3.11.8A, 3.11.8B, 3.13.1, 3.13.3B, 3.13.3C, 3.14.3, 3.21B.7, 4.25.2, 4.28.5, 6.5C.6, 6.18.2, 7.2.3B, 7.6.2, 7.6A.5, 10.5.1, Appendix 1 and the Glossary.	RC_2011_11
1 June 2012	IMO amended clauses 1.10, 2.37.4, 7A.1.2 and 7A.1.16.	RC_2011_10
6 June 2012	IMO amended clause 4.5.12 and Appendix 3.	RC_2011_14
1 July 2012	IMO amended clauses 2.17.1, 4.1.21B (new), 4.12.6, 4.13.1B, 4.20.8 (new), 4.20.9 (new), 4.20.10 (new), 4.20.11 (new), 4.20.12 (new), 4.20.13 (new), 4.20.14 (new), 10.5.1 and the Glossary.	RC_2010_28
	IMO amended clauses 1.10 (new), 2.1.2, 2.2.1, 2.2.2, 2.3.5, 2.10.2A (new), 2.13.6B, 2.13.6E, 2.13.6F, 2.13.6K, 2.13.9, 2.13.13A (new), 2.13.14, 2.16.2, 2.16.4, 2.16.7, 2.16.9, 2.16.9A, 2.16.9B, 2.16.9C, 2.16.9E, 2.16.9F, 2.16.9FB, 2.16.9G, 2.16.10, 2.16.12, 2.16.13, 2.17.1, 2.23.10, 2.34.1, 2.34.7, 2.34.7A (new), 2.34.7B (new), 2.34.7C (new), 2.34.12, 2.34.14, 2.36.1, 2.36.6, 2.36.7 (new), 2.36.8 (new), 2.36.9 (new), 2.36.10 (new), 2.37.4, 3.2.5, 3.4.4, 3.5.7, 3.9.1, 3.11.7, 3.11.7A, 3.11.8, 3.13.1, 3.13.3, 3.13.3A, 3.13.3AB (new), 3.14.1, 3.14.2, 3.21.6, 3.21A.13, 3.21A.14, 3.21AA, 3.22.1, 3.22.2, 3.22.3, 4.10.1, 4.11.1, 4.11.2, 4.11.3B, 4.11.4, 4.11.7, 4.11.10, 4.11.11, 4.11.12, 4.12.1, 4.12.4, 4.12.8, 4.14.4, 4.14.5, 4.23A.1, 4.23A.2, 4.25.3, 4.25.3A, 4.25.3B, 4.25.4, 4.25.7, 4.25.8, 4.25.9, 4.25.10, 4.25.11, 4.25.12, 4.25.14, 4.26.2, 4.26.2D, 5.7.4, 5.9.3, 6.2.4C, 6.3A.1, 6.3A.2, 6.4.6, 6.5.1, 6.5.1A, 6.5.1C, 6.5.4, 6.5A, 6.5C.1 (new), 6.5C.1A, 6.5C.2, 6.5C.7, 6.9.4, 6.11.1, 6.11.2, 6.11.3 (new), 6.11A, 6.12, 6.14, 6.15, 6.16.1A, 6.16.2, 6.16A (new), 6.16B (new), 6.17, 6.18, 6.19.1, 6.20.4, 6.20.6, 6.21.2, 7.1.1, 7.2.1, 7.2.3, 7.2.3A, 7.2.3B, 7.2.3C, 7.2.3D, 7.3.1, 7.3.2, 7.3.4, 7.5.1, 7.5.2, 7.5.3, 7.5.4, 7.5.7, 7.6.1, 7.6.1A, 7.6.1B (new), 7.6.1C (new), 7.6.1D (new), 7.6.2, 7.6.2A, 7.6.2B (new), 7.6.3, 7.6.4, 7.6.5, 7.6.5A, 7.6.6, 7.6.7, 7.6.8, 7.6.9, 7.6.10, 7.6.11, 7.6.12, 7.6.13, 7.6A.1, 7.6A.2, 7.6A.3, 7.6A.4, 7.6A.5, 7.6A.6, 7.6A.7, 7.6A.8, 7.7.1, 7.7.2, 7.7.3, 7.7.3A, 7.7.4, 7.7.4A, 7.7.5, 7.7.5A, 7.7.5B, 7.7.5C (new), 7.7.5D (new), 7.7.6, 7.7.6A (new), 7.7.6B (new), 7.7.7, 7.7.7A, 7.7.8, 7.7.9, 7.7.10, 7.8.1, 7.8.2, 7.9.1, 7.9.1A, 7.9.2, 7.9.4, 7.9.5, 7.9.6, 7.9.6A, 7.9.8, 7.10.1, 7.10.2, 7.10.3, 7.10.3A, 7.10.5, 7.10.5A, 7.10.5B, 7.10.6A, 7.10.7, 7.11.1, 7.11.5, 7.11.6, 7.11.6A (new), 7.11.6B, 7.11.7, 7.12.1, 7.13.1, 7.13.1A, 7.13.1B, 7.13.1C, 7.13.4 (new), 7A (new), 7B (new), 9.3.3, 9.3.4A, 9.7.1, 9.8.1, 9.9.1, 9.9.2, 9.9.3, 9.9.3A, 9.9.3B, 9.9.4, 9.10.1, 9.10A.1, 9.10A.2, 9.11.1, 9.18.3, 9.19.2, 9.22.6, 9.22.8, 10.2.2, 10.2.3, 10.2.5, 10.2.6, 10.5.1, 10.5.2 (new), 10.6.1, 10.7.1, 10.8.1, 10.8.2, Appendices and the Glossary.	RC_2011_10
	IMO amended clause 9.9.2.	RC_2012_05
	IMO amended clauses 6.17.3A and 6.17.4A.	RC_2012_08
1 August 2012	IMO amended clauses 2.30B.1, 2.30B.2, 2.30B.5, 2.30B.6, 2.30B.6A, 2.30B.7, 2.30B.8 and 2.30B.11.	RC_2012_01
1 September 2012	IMO amended clauses 3.18.6, 3.21.1 and 3.21.2.	RC_2012_04
1 November 2012	IMO amended clauses 2.22.3; 2.22.4; 2.22.6; 2.22.12; 2.23.3; 2.23.4; 2.23.5; 2.23.9; 2.23.12 and the Glossary.	RC_2011_02
1 February 2013	IMO amended clauses 6.16A.2 and 6.17.3A.	RC_2012_19
1 March 2013	IMO amended clause 3.21A.7.	RC_2012_15
1 April 2013	IMO amended clauses 3.21A.1, 3.21A.2, 3.21A.3, 3.21A.4, 3.21A.5, 3.21A.7, 3.21A.7A, 3.21A.8, 3.21A.9, 3.21A.10, 3.21A.11, 3.21A.12, 3.21A.13, 3.21A.14, 3.21A.15, 3.21A.16, 3.21A.17, 4.12.6, 4.26.1A, 7.9.4 and the Glossary.	RC_2012_12
1 May 2013	IMO amended clauses 4.5.9, 9.16.3, 9.16.3A and 9.19.1.	RC_2012_21 RC_2012_25
15 May 2013	IMO amended clause 7.2.3A.	RC_2013_06
20 May 2013	IMO amended clauses 2.27.1, 2.27.1A, 2.27.2, 2.27.2A, 2.27.3, 2.27.3A, 2.27.3B, 2.27.4, 2.27.5, 2.27.6, 2.27.7(new), 2.27.8(new), 2.27.9(new), 2.27.10(new), 2.27.11(new), 2.27.12(new), 2.27.13(new), 2.27.14(new), 2.27.15(new), 2.27.16(new), 2.27.17(new), 9.3.4A and the Glossary.	RC_2012_07
1 June 2013	IMO amended clauses 2.1.1, 2.1.3, 2.2.1, 2.5.6, 2.6.3A (new), 2.6.4, 2.7.7A (new), 2.7.8, 2.8.1, 2.8.3, 2.8.11, 2.10.2A, 2.11.1, 2.17.1, 2.17.2, 6.6.3A, 7A.2.19, 7B.2.17 and the Glossary.	RC_2012_06
	IMO amended clauses 9.23.4.	RC_2012_24
	IMO amended clauses 7B.1.6, 7B.2.10 and the Glossary.	RC_2013_03
1 July 2013	IMO amended clauses 2.22.8, 2.22.8A (new), 2.22.8B (new), 2.22.13, 2.22.14, 2.22.15 (new), 2.23.8, 2.23.8A (new), 2.23.8B (new), 2.23.13 (new) and 2.23.14 (new).	RC_2011_02
	IMO amended clauses 4.11.1, 4.11.2 and the Glossary.	RC_2012_20
	IMO amended clauses 2.13.9, 7.10.6, 7.10.6A and 7.10.7.	RC_2013_01
1 August 2013	IMO amended clause 6.15.2.	RC_2013_02
12 August 2013	IMO amended clauses 4.1.13, 4.13.9, 4.14.3, 4.14.10, 4.15.2, 4.20.5A, 4.20.5B, 4.20.5C and 4.20.5D.	RC_2012_03
1 September 2013	IMO amended clauses 7.9.1, 7.9.1A, 7.9.5, 7.9.13 (new), 7.9.14 (new), 7.9.15 (new), 7.9.16 (new), 7.9.17 (new), 7.9.18 (new) and 7.9.19 (new).	RC_2012_22
2 September 2013	IMO amended clauses 3.23 (new), 7A.3.7, 7A.3.7A (new) and the Glossary.	RC_2013_05
23 September 2013	IMO amended the Appendices and the Glossary.	RC_2013_11
1 October 2013	IMO amended clauses 3.18.6, 7.13.1D (new), 7.13.1E (new), 7.13.1F (new), 7.13.1G (new), 10.5.1 and 10.5.3 (new).	RC_2012_11
1 November 2013	IMO amended clauses 2.16.9F, 2.16.9FA and 2.16.9FB.	RC_2009_15
	IMO amended clause 4.5.10.	RC_2012_09
	IMO amended clauses 2.13.6L(new) and 6.17.9.	RC_2012_16
25 November 2013	IMO amended clauses 1.10.3, 2.2.2, 2.13.6B, 2.22.4, 2.22.8A, 2.22.12, 2.22.13, 2.22.14, 2.23.4, 2.23.8A, 2.23.12, 2.23.13, 2.29.4, 2.30A.2, 2.30B.3, 2.31.6, 2.31.8, 2.31.15, 2.31.16, 2.33.5, 2.34.2A, 3.3.2, 3.11.9, 3.13.3C, 3.16.9, 3.17.9, 3.18.2, 3.18.2A, 3.18.3, 3.18.11, 3.18.11A, 3.19.6, 4.1.4, 4.1.5, 4.1.6, 4.1.7, 4.1.8, 4.1.10, 4.1.11, 4.1.12, 4.1.13, 4.1.14, 4.1.15, 4.1.15A, 4.1.16, 4.1.17, 4.1.18, 4.1.20, 4.1.21, 4.1.21A, 4.1.21B, 4.1.23, 4.1.24, 4.5.10, 4.9.4, 4.9.5, 4.13.11, 4.13.11A, 4.14.1, 4.14.7, 4.14.11, 4.19.3, 4.20.1, 4.21.1, 4.23A.2, 4.23A.3, 4.23A.4, 4.24.2, 4.25.4E, 4.25.5, 4.25A.1, 4.25A.2, 4.25A.3, 4.25A.4, 4.25A.5, 4.27.10, 4.28.1, 4.28C.2, 6.3A.4, 6.6.10, 7.10.2, 7A.3.10, 7B.1.5, 9.5.2, 9.10, 9.10A, 9.16.1, 9.16.2, 9.16.4, 9.19.3, 9.20.5, 9.23.3, 9.23.6, 9.23.7, 10.5.1 and the Glossary.	RC_2013_07
30 December 2013	IMO amended clauses 1.11 (new) and 6.12.1.	RC_2013_18
1 January 2014	IMO amended clauses 2.25.1A (new), 2.25.1B (new), 2.25.4, 9.1.2, 9.16.3, 9.16.3A, 9.19.1 and the Glossary.	RC_2013_08
	IMO amended clauses 1.10.2, 1.10.3, 2.2.2, 2.3.5, 2.16.7, 3.11.7A, 3.11.8, 3.13.3A, 3.13.3AB, 4.12.1, 4.14.4, 4.14.5, 4.23A.2, 4.26.2, 6.5.1, 6.5.1A, 6.5.4, 6.5C.1, 6.11.1, 6.11.3, 6.15.1, 6.15.2, 6.16B.1, 6.16B.2, 6.17.1, 6.17.5, 6.17.5A, 6.17.5B, 6.17.9, 6.17.10, 6.21.2, 7.5.4, 7.6.2, 7.6.2A, 7.6.12, 7.6A.1, 7.6A.2, 7.6A.3, 7.6A.4, 7.6A.5, 7.6A.6, 7.6A.7, 7.6A.8, 7.7.1, 7.10.7, 7.11.5, 7.12.1, 7.13.1, 7.13.1A, 7.13.1C, 7A.1.14, 7A.2.1, 7A.2.2, 7A.2.3, 7A.2.9, 7A.2.10, 7A.2.12, 7A.3.1, 7A.3.5, 7A.4.1, 7A.4.2, 7A.4.4, 7A.4.5, 7A.4.6, 7A.4.8, 7A.4.9, 7B.2.1, 7B.2.2, 7B.2.3, 7B.2.4, 7B.2.5, 7B.2.6, 7B.3.7, 7B.4.1, 7B.4.2, 9.8.1, 9.9.1, 9.9.2, 9.18.3, 10.5.1 and 10.8.2, the Glossary and Appendices 1, 2 and 9.	RC_2013_18
1 May 2014	IMO amended clauses 2.37.1, 2.37.2, 2.37.3, 2.37.4, 2.37.5, 2.37.6, 2.37.7, 2.37.8, 2.37.9, 2.38.1, 2.38.2, 2.38.3, 2.38.4, 2.38.7, 2.40.1, 2.41.2, 2.41.3, 2.41.5 (new), 2.42.1, 2.42.2, 2.42.3, 2.42.4, 2.42.7, 2.43.1, 4.13.1, 4.13.2C, 4.13.3, 4.13.4, 4.13.5 and the Glossary.	RC_2012_23
	IMO amended clauses 6.15.2, 7.7.5A, 7.7.5B and Appendix 9.	RC_2013_17
1 November 2014	IMO amended clauses 1.12.1 (new) and 1.12.2 (new).	RC_2014_04
1 May 2015	IMO amended clause 1.12.1.	RC_2015_04
1 September 2015	IMO amended clauses 1.13.1 (new) and 1.13.2 (new).	RC_2015_05
30 November 2015	Minister amended clauses 1.4.1, 1.4.2, 1.5.1, 1.5.2, 1.6.2 (new), 1.7.1, 1.7.2 (new), 1.9.5, 1.9.6, section 1.14 (new), clause 2.1.2, section 2.1A (new), clauses 2.2.2, 2.3.1, 2.3.5, 2.3.17, 2.5.1, 2.9.2A (new), 2.9.4, 2.9.5, 2.9.7A (new), 2.10.1, 2.10.2, 2.10.2A, 2.10.3, 2.10.4, 2.10.5A (new), 2.10.7, 2.10.8, 2.10.9, 2.10.10, 2.10.11, 2.10.12A (new), 2.10.13, 2.10.14, 2.10.15, 2.10.16, 2.10.17, 2.10.18, 2.11.1, 2.11.2, 2.11.4, 2.13.2, 2.13.3A, 2.13.4, 2.13.6A, 2.13.6D, 2.13.6E, 2.13.6H, 2.13.6I, 2.13.6J, 2.13.6L, 2.13.9, 2.13.9A (new), 2.13.9B (new), 2.13.9C (new), 2.13.9D (new), 2.14.1, 2.14.1A (new), 2.14.2, 2.14.3, 2.14.4, 2.14.5, 2.14.5A, 2.14.5B (new), 2.14.5C (new), 2.14.5D (new), 2.15.5, 2.15.6, 2.15.6A (new), 2.15.6B (new), 2.15.6C (new), 2.15.7, 2.15.9 (new), 2.16.1, 2.16.2, 2.16.2A (new), 2.16.3, 2.16.4, 2.16.5, 2.16.6, 2.16.8, 2.16.8A (new), 2.16.9, 2.16.12, 2.16.14, 2.17.1, 2.17.2, 2.18.1, 2.18.2, 2.19.5, 2.21.5 (new), 2.21.6 (new), 2.22.1, 2.22.13, 2.22.14, section 2.22A (new), clauses 2.23.9, 2.23.11, 2.24.1, 2.24.2, 2.24.2A, 2.24.3, 2.24.4, 2.24.6, 2.25.1, 2.25.1A, 2.25.1B, 2.25.3, 2.25.4, 2.26.1, 2.26.2, 2.27.1, 2.27.2, 2.27.4, 2.27.5, 2.27.6, 2.27.7, 2.27.8, 2.27.9, 2.27.10, 2.27.11, 2.27.12, 2.27.13, 2.27.14, 2.27.15, 2.27.16, 2.27.17, 2.27.18, 2.27.19, 2.28.1, 2.28.3, 2.28.13, 2.28.15A (new), 2.28.16, 2.28.16A, 2.28.16B, 2.29.5B, 2.29.5C, 2.29.5D, 2.29.5E, 2.29.5F, 2.29.5G, 2.29.5H, 2.29.5I, 2.29.5J, 2.29.5K, 2.29.5L, 2.29.5M, 2.29.9, 2.29.9A, 2.29.10, 2.30.1, 2.30.1A, 2.30.4, 2.30.5, 2.30.7, 2.30.7A, 2.30.8, 2.30.9, 2.30.10, 2.30.11, 2.30A.1, 2.30A.2, 2.30A.3, 2.30A.4, 2.30A.5, 2.30A.6, 2.30B.2, 2.30B.3, 2.30B.4, 2.30B.6, 2.30B.7, 2.30B.8, 2.30B.11, 2.30C.1, 2.30C.3, 2.30C.4, 2.31.1, 2.31.2, 2.31.3, 2.31.4, 2.31.5, 2.31.6, 2.31.7, 2.31.10, 2.31.11, 2.31.12, 2.31.13, 2.31.15, 2.31.16, 2.31.17, 2.31.18, 2.31.19, 2.31.20, 2.31.21, 2.31.22, 2.31.23, 2.32.1, 2.32.2, 2.32.3, 2.32.4, 2.32.5, 2.32.6, 2.32.7, 2.32.7A, 2.32.7B, 2.32.7C, 2.32.7D, 2.32.7E, 2.32.7F, 2.32.9, 2.33.1, 2.33.2, 2.33.3, 2.33.4, 2.33.5, 2.34.1, 2.34.2, 2.34.3, 2.34.4, 2.34.5, 2.34.6, 2.34.7, 2.34.7A, 2.34.7B, 2.34.7C, 2.34.8, 2.34.9, 2.34.10, 2.34.11, 2.34.12, 2.34.13, 2.34.14, 2.34.15, 2.36.1, 2.36.3, 2.36.5, 2.36.6, 2.36.7, 2.36.8, 2.36.9, 2.36.10, 2.37.1, 2.37.2, 2.37.3, 2.37.4, 2.37.5, 2.37.6, 2.37.7, 2.37.8, 2.38.1, 2.38.2, 2.38.3, 2.38.4, 2.38.5, 2.38.7, 2.38.8, 2.38.9, 2.40.1, 2.40.2, 2.41.2, 2.41.3, 2.41.4, 2.41.5, 2.42.1, 2.42.4, 2.42.5, 2.42.7, 2.43.1, 2.44.1, 2.44.2, 2.44.3, 2.44.4, 3.2.1, 3.6.3, 3.6.5, 3.8.1, 3.8.2, 3.8.2A (new), 3.8.3, 3.8.4, 3.8.5, 3.8.5A (new), 3.11.6, 3.11.10, 3.11.11, 3.11.12, 3.11.13, 3.13.1, 3.13.1A, 3.13.2, 3.13.3A, 3.13.3AB, 3.15.1, 3.16.9, 3.17.1, 3.17.2, 3.17.9, 3.18.2, 3.18.3, 3.18.15, 3.18.16, 3.18.17, 3.18.21, 3.19.12, 3.19.13, 3.21.6, 3.21.10, 3.21.11, 3.21A.16, 3.22.1, 3.22.2, 3.22.3, 3.23.1, 3.23.2, 3.23.3, 4.1.4, 4.1.5, 4.1.6, 4.1.7, 4.1.8, 4.1.10, 4.1.11, 4.1.12, 4.1.13, 4.1.14, 4.1.15, 4.1.15A, 4.1.16, 4.1.17, 4.1.18, 4.1.19, 4.1.20, 4.1.21, 4.1.21A, 4.1.21B, 4.1.23, 4.1.24, 4.1.28, 4.1.32, 4.2.1, 4.2.2, 4.2.3, 4.2.4, 4.2.5, 4.2.6, 4.2.7, 4.3.1, 4.5.1, 4.5.2A, 4.5.3, 4.5.3A, 4.5.4, 4.5.5, 4.5.6, 4.5.7, 4.5.8, 4.5.9, 4.5.10, 4.5.11, 4.5.12, 4.5.13, 4.5.14, 4.5.15, 4.5.16, 4.5.19, 4.7.2, 4.9.1, 4.9.3, 4.9.4, 4.9.5, 4.9.6, 4.9.7, 4.9.8, 4.9.9, 4.9.9A, 4.9.10, 4.10.1, 4.10.3, 4.10.4, 4.11.1, 4.11.2, 4.11.2A, 4.11.3B, 4.11.4, 4.11.5, 4.11.6, 4.11.8, 4.11.9, 4.11.10, 4.11.11, 4.11.12, 4.12.1, 4.12.2, 4.12.3, 4.12.4, 4.12.6, 4.13.1, 4.13.1B, 4.13.2A, 4.13.2B, 4.13.2C, 4.13.3, 4.13.4, 4.13.5, 4.13.6, 4.13.8, 4.13.10, 4.13.10A, 4.13.10B, 4.13.10C, 4.13.11, 4.13.11A, 4.14.1, 4.14.6, 4.14.7, 4.14.8, 4.14.9, 4.14.10, 4.14.11, 4.15.1, 4.15.2, 4.16.1, 4.16.3, 4.16.5, 4.16.6, 4.16.7, 4.16.8, 4.17.1, 4.17.2, 4.17.3, 4.17.4, 4.17.5, 4.17.6, 4.17.7, 4.17.8, 4.17.9, 4.18.2, 4.19.1, 4.19.3, 4.19.5, 4.20.1, 4.20.2, 4.20.3, 4.20.4, 4.20.5, 4.20.5A, 4.20.5B, 4.20.5C, 4.20.5D, 4.20.8, 4.20.9, 4.20.10, 4.20.11, 4.20.12, 4.20.13, 4.20.14, 4.20.15, 4.21.1, 4.22.1, 4.22.2, 4.23A.3, 4.23A.4, 4.24.1, 4.24.2, 4.24.3, 4.24.4, 4.24.5, 4.24.6, 4.24.7, 4.24.8, 4.24.9, 4.24.10, 4.24.11, 4.24.12, 4.24.13, 4.24.14, 4.24.15, 4.24.16, 4.24.17, 4.24.18, 4.24.19, 4.25.1, 4.25.2, 4.25.3, 4.25.3A, 4.25.4, 4.25.4A, 4.25.4B, 4.25.4C, 4.25.4D, 4.25.4E, 4.25.5, 4.25.6, 4.25.7, 4.25.8, 4.25.9, 4.25.11, 4.25.12, 4.25.13, 4.25.14, 4.25A.1, 4.25A.2, 4.25A.3, 4.25A.4, 4.26.1, 4.26.1A, 4.26.1B, 4.26.2, 4.26.2A, 4.26.2B, 4.26.2C, 4.26.2CA, 4.26.2D, 4.26.2E, 4.26.4, 4.26.5, 4.27.1, 4.27.2, 4.27.3, 4.27.5, 4.27.6, 4.27.7, 4.27.8, 4.27.9, 4.27.10, 4.27.11A, 4.27.11B, 4.27.11C, 4.27.11D, 4.27.12, 4.28.1, 4.28.2, 4.28.3, 4.28.4, 4.28.7, 4.28.7A, 4.28.8, 4.28.8A, 4.28.8B, 4.28.9, 4.28.10, 4.28.11, 4.28.11A, 4.28.12, 4.28A.1, 4.28A.2, 4.28A.3, 4.28B.2, 4.28B.4, 4.28B.5, 4.28B.6, 4.28B.7, 4.28B.8, 4.28B.9, 4.28C.1, 4.28C.2, 4.28C.3, 4.28C.6, 4.28C.7, 4.28C.8, 4.28C.10, 4.28C.11, 4.28C.12, 4.28C.13, 4.28C.14, 4.28C.15, 4.29.1, 4.29.3, 4.29.4, 5.2A.2, 5.3A.1, 5.3A.2, 5.9.1, 5.9.2, 5.9.3, 6.2.1, 6.2.2, 6.2.2A, 6.2.3, 6.2.4B, 6.2.8, 6.2A.1, 6.2A.2, 6.2A.4, 6.2A.5, 6.3A.1, 6.3A.2, 6.3A.3, 6.3A.4, 6.3B.1, 6.3B.1A, 6.3B.1B, 6.3B.3, 6.3B.7A, 6.3B.7B, 6.3B.8, 6.3C.1, 6.3C.3, 6.3C.6B, 6.3C.6C, 6.3C.9, 6.4.1, 6.4.2, 6.4.3, 6.4.5, 6.4.6, 6.5.1, 6.5.1A, 6.5.1B, 6.5.2, 6.5.3, 6.5.4, 6.5C.1A, 6.5C.2, 6.5C.4, 6.5C.5, 6.5C.6, 6.6.2A, 6.6.9, 6.6.10, 6.6.11, 6.6.12, 6.9.1, 6.9.3, 6.9.4, 6.9.5, 6.9.6, 6.9.7, 6.9.8, 6.9.9, 6.9.10, 6.9.11, 6.9.12, 6.9.13, 6.10.1, 6.10.2, 6.11.1, 6.11.2, 6.12.1, 6.13.1, 6.15.3, 6.15.4, 6.16.1, 6.16.1A, 6.16.2, 6.16A.1, 6.16A.2, 6.16B.1, 6.16B.2, 6.17.1, 6.17.3, 6.17.3A, 6.17.4, 6.17.4A, 6.17.5, 6.17.5A, 6.17.5C, 6.17.6, 6.17.6A, 6.17.9, 6.19.1, 6.19.2, 6.19.3, 6.19.4, 6.19.6, 6.19.7, 6.19.9, 6.19.10, 6.20.3, 6.20.6, 6.20.7, 6.20.9, 6.20.9A, 6.20.10, 6.20.11, 6.21.1, 6.21.2, 7.1.1, 7.2.3B, 7.3.4, 7.3.6, 7.3.7, 7.4.1, 7.4.2, 7.4.3, 7.4.4, 7.5.1, 7.5.2, 7.5.3, 7.6.2B, 7.6.10, 7.6.11, 7.6A.2, 7.6A.5, 7.6A.9, 7.6A.10, 7.10.7, 7.10.8 (new), 7.11.1, 7.11.4, 7.11.6A, 7.11.9, 7.12.1, 7.12.2, 7.13.1, 7.13.1A, 7.13.1B, 7.13.1C, 7.13.1D, 7.13.1E, 7.13.1F, 7.13.1G, 7.13.3, 7.13.4, 7A.1.1, 7A.1.6, 7A.1.7, 7A.1.9, 7A.1.10, 7A.1.11, 7A.1.12, 7A.1.13, 7A.1.15, 7A.1.16, 7A.1.17, 7A.2.4, 7A.2.5, 7A.2.8, 7A.2.9, 7A.2.11, 7A.2.12, 7A.2.18, 7A.3.1, 7A.3.2, 7A.3.3, 7A.3.6, 7A.3.7, 7A.3.7A, 7A.3.8, 7A.3.9, 7A.3.10, 7A.3.11, 7A.3.12, 7A.3.13, 7A.3.14, 7A.3.15, 7A.3.16, 7A.3.17, 7A.3.18, 7A.3.19, 7A.3.20, 7A.3.21, 7A.4.1, 7A.4.2, 7A.4.4, 7A.4.5, 7A.4.6, 7A.4.7, 7A.4.8, 7A.4.9, 7B.1.1, 7B.1.4, 7B.2.3, 7B.2.4, 7B.2.7, 7B.2.8, 7B.2.16, 7B.2.18, 7B.2.19, 7B.3.1, 7B.3.2, 7B.3.3, 7B.3.4, 7B.3.5, 7B.3.7, 7B.3.9, 7B.3.10, 7B.3.11, 7B.3.12, 7B.3.13, 7B.3.14, 7B.3.15, 7B.3.16, 7B.4.2, 8.2.1, 8.3.2, 8.3.3, 8.3.4, 8.3.5, 8.3.6, 8.3.7, 8.4.1, 8.4.4, 8.4.5, 8.5.1, 8.5.2, 8.6.2, 8.8.1, 9.1.1, 9.1.2, 9.1.4, 9.2.1, 9.3.1, 9.3.3, 9.3.4, 9.3.4A, 9.3.6, 9.3.7, 9.4.1, 9.4.2, 9.4.3, 9.4.4, 9.4.5, 9.4.6, 9.4.7, 9.4.8, 9.4.9, 9.4.10, 9.4.12, 9.4.13, 9.5.3, 9.6.1, 9.7.1, 9.7.2, 9.9.1, 9.9.2, 9.9.3A, 9.9.3B, 9.10.1, 9.11.1, 9.13.1, 9.14.1, 9.15.1, 9.16.1, 9.16.2, 9.16.3, 9.16.3A, 9.16.4, 9.17.1, 9.18.1, 9.18.2, 9.18.3, 9.18.4, 9.19.1, 9.19.2, 9.19.4, 9.20.1, 9.20.2, 9.20.3, 9.20.5, 9.20.6, 9.20.7, 9.20.8, 9.21.1, 9.22.1, 9.22.2, 9.22.3, 9.22.4, 9.22.5, 9.22.6, 9.22.8, 9.22.9, 9.22.10, 9.22.11, 9.23.1, 9.23.2, 9.23.3, 9.23.4, 9.23.5, 9.23.6, 9.23.7, 9.24.1, 9.24.2, 9.24.3, 9.24.3A, 9.24.4, 9.24.5, 9.24.6, 9.24.7, 9.24.8, 9.24.8A, 9.24.9, 9.24.10, 10.1.1, 10.1.2, 10.2.1, 10.2.2, 10.2.3, 10.2.5, 10.2.6, 10.2.7, 10.3.1, 10.3.2, 10.3.3, 10.3.4, 10.3.5, 10.4.1, 10.4.2, 10.5.1, 10.5.2, 10.5.3, 10.7.1, 10.8.2, the Glossary and Appendices 1, 3, 4A, 5, 5A, 6 and 9.	Wholesale Electricity Market Rules Amending Rules 2015.
1 June 2016	Minister amended clause 1.4.1, section 1.15 (new), clauses 2.13.9, 2.26.1, 2.26.2, 2.26.3, 2.33.5, 4.1.13, 4.1.14, 4.1.15, 4.1.19, 4.1.20, 4.1.32, 4.1.33 (new), 4.2.7, 4.3.1, 4.5.12, 4.5.13, 4.5.14, 4.5.14A (new), 4.5.14B (new), 4.5.14C (new), 4.5.14D (new), 4.5.14E (new), 4.5.14F (new), 4.5.16, 4.5.17, 4.5.20, 4.6.4 (new), 4.6.5 (new), 4.7.3, 4.9.3, 4.9.9, 4.9.9A, 4.9.10, 4.10.1, 4.10.2, 4.11.1, 4.11.1A (new), 4.11.1B (new), 4.11.1C (new), 4.11.1D (new), 4.11.1E (new), 4.11.4, 4.12.2, 4.12.6, 4.12.7, 4.13.2, 4.13.9, 4.13.10C, 4.14.1, 4.14.1A (new), 4.14.6, 4.14.7, 4.14.9, 4.14.10, 4.14.11, 4.15.2, 4.16.1, 4.16.2, 4.16.3, 4.16.5, 4.16.6, 4.16.7, 4.16.8, 4.17.2, 4.17.4, 4.17.9, 4.17.10 (new), 4.18.1, 4.18.2, 4.20.1, 4.20.5A, 4.20.5B, 4.21.1, 4.22.1, 4.22.2, 4.22.3, 4.22.4, 4.22.5, 4.22.6, 4.24.18, 4.25.14, 4.25A.1, 4.25A.5, 4.27.12, 4.28.2, 4.28.12, 4.28A.3, 4.28B.8, 4.28B.9 4.28C.4, 4.28C.9, 4.28C.14, 4.28C.15, 4.29.1, 10.5.1, Glossary, Appendix 1, and Appendix 3.	Wholesale Electricity Market Rules Amending Rules 2016, Schedule B, Part 1.
1 July 2016	Minister amended clause 1.14.6, section 1.16 (new), clauses 2.2.1, 2.2.2, 2.2.3, 2.2.4 (new), 2.2.5 (new), 2.2.6 (new), 2.2.7 (new), 2.2.8 (new), 2.8.13, 2.10.4, 2.10.5A, 2.10.11, 2.10.12A, 2.10.13, 2.10.14, 2.10.15, 2.10.16, 2.10.17, 2.10.18, 2.11.1, 2.11.3, 2.13.6A, 2.13.6D, 2.13.6E, 2.13.6H, 2.13.6I, 2.13.6J, 2.13.6L, 2.13.8, 2.14.1A, 2.14.3, 2.14.6, 2.14.6A, 2.14.6B, 2.14.7, 2.14.8, 2.14.9, 2.15.3, 2.15.4, 2.15.5, 2.15.6, 2.15.6B, 2.15.6C, 2.15.7, 2.16.2, 2.16.7, 2.17.1, 2.17.2, 2.22A.1, 2.22A.2A (new), 2.22A.4, 2.22A.5, 2.22A.12, 2.23, 2.24.1, 2.24.2, 2.24.2A, 2.24.2B, 2.24.3, 2.24.4, 2.25.1, 2.25.1A, 2.25.1B, 2.25.2, 2.25.3, 2.25.4, 2.28.1, 2.28.3, 2.28.3A (new), 2.28.14A (new), 2.28.16B, 2.29.5F, 2.30.4, 2.30.5, 2.30.8, 2.30.11, 2.30A.3, 2.30A.5, 2.30A.6, 2.30B.3, 2.30B.8, 2.31.5, 2.31.22, 2.31.23, 2.34.1, 2.34.7A, 2.34.7B, 2.34.7C, 2.34.10, 2.34.12, 2.34.15, 2.36.7, 2.36.8, 2.36.9, 2.36.10, 2.36A (new), 3.2.1, 3.2.7, 3.2.8, 3.3.2, 3.4.1, 3.4.2, 3.4.4, 3.4.5, 3.4.6, 3.5.1, 3.5.3, 3.5.5, 3.5.6, 3.5.7, 3.5.8, 3.6.3, 3.6.5, 3.7.2, 3.8.1, 3.8.2, 3.10.5, 3.11.6, 3.11.10, 3.11.11, 3.11.12, 3.11.13, 3.12.1, 3.13.1, 3.13.1A, 3.13.2, 3.13.3A, 3.13.3AB, 3.15.1, 3.16.9, 3.17.1, 3.17.2, 3.17.9, 3.18.2, 3.18.11, 3.18.17, 3.18.21, 3.19.6, 3.19.13, 3.21.6, 3.21.11, 3.21A.16, 3.22.1, 3.22.2, 3.22.3, 3.23.1, 3.23.2, 3.23.3, 4.1.26, 4.10.1, 4.12.6, 4.18.1, 4.23A.3, 4.24.3, 4.24.13, 4.24.16, 4.24.17, 4.24.18, 4.25.2, 4.25.4, 4.25.5, 4.25.6, 4.25.7, 4.25.8, 4.25.9, 4.25.11, 4.25.14, 4.26.2, 4.26.2D, 4.26.5, 4.27.6, 4.27.11A, 4.27.11B, 4.27.11C, 4.27.12, 4.28A.2, 6.3A.1, 6.3A.2, 6.3A.3, 6.4.2, 6.4.6, 6.13.1, 6.15.3, 6.16A.2, 6.17.6, 6.17.6A, 6.17.9, 6.19.1, 6.19.4, 6.19.9, 6.19.10, 7.1.1, 7.2.3B, 7.3.4, 7.3.6, 7.3.7, 7.4.1, 7.4.2, 7.4.3, 7.4.4, 7.5.1, 7.5.2, 7.5.3, 7.6.1D, 7.6.2B, 7.6.11, 7.6A.2, 7.6A.5, 7.6A.9, 7.10.7, 7.10.8, 7.11.1, 7.11.4, 7.11.6A, 7.11.9, 7.12.1, 7.13.1, 7.13.1A, 7.13.1B, 7.13.1C, 7.13.1D, 7.13.1E, 7.13.1F, 7.13.1G, 7.13.3, 7.13.4, 7A.1.7, 7A.2.18, 7A.3.2, 7A.3.3, 7A.3.6, 7A.3.7, 7A.3.7A, 7A.3.8, 7A.3.9, 7A.3.11, 7A.3.12, 7A.3.13, 7A.3.15, 7A.3.17, 7A.3.21, 7A.4.2, 7A.4.6, 7A.4.7, 7B.1.4, 7B.1.5, 7B.2.7, 7B.2.18, 7B.2.19, 7B.3.4, 7B.3.5, 7B.3.7, 7B.3.8, 7B.3.15, 7B.3.16, 7B.4.2, 9.1.2, 9.3.4, 9.9.2, 9.9.4, 9.13.1, 9.15.1, 9.16.3, 9.19.1, 9.20.5, 9.20.7, 9.24.3A, 10.2.2, 10.2.3, 10.3.3, 10.3.4, 10.3.5, 10.5.1, the Glossary, Appendix 1 and Appendix 9.	Wholesale Electricity Market Rules Amending Rules 2016, Schedule A.
1 July 2016	Minister amended clauses 1.4.1, 1.4.2, 1.5.1, 1.5.2, 1.7.2, 1.7.3 (new), 1.9.12, 1.10.3, 1.14.3, 1.145.5, 1.16.1, 1.16.5, section 1.17 (new), clauses 2.1.2, 2.1.3, section 2.3A (new), clauses 2.3.1, 2.8.13, 2.9.2B (new), 2.9.5, 2.9.7B (new), 2.10.1, 2.10.2, 2.10.2A, 2.10.3, 2.10.5B (new), 2.10.7, 2.10.9, 2.10.10, 2.10.12B (new), 2.10.13, 2.10.17, 2.10.18, 2.11.1, 2.11.2, 2.11.4, 2.13.1, 2.13.2, 2.13.3, 2.13.3A, 2.13.4, 2.13.5, 2.13.6A, 2.13.6B, 2.13.6C, 2.13.6D, 2.13.6H, 2.13.6I, 2.13.8, 2.13.9A, 2.13.9B, 2.13.9C, 2.13.9D, 2.13.10, 2.13.11, 2.13.12, 2.13,13, 2.13.14, 2.13.15, 2.13.16, 2.13.17, 2.13.18, 2.13.19, 2.13.20, 2.13.21, 2.13.22, 2.13.24, 2.13.25, 2.13.26, 2.13.27, 2.13.28, 2.13.29, 2.13.31, 2.14.5A, 2.14.5B, 2.14.5C, 2.14.5D, 2.15.1, 2.15.2, 2.15.3, 2.15.6A, 2.15.6B, 2.15.6C, 2.15.7, 2.15.8, 2.15.9, 2.16.2A, 2.16.4, 2.16.5, 2.16.6, 2.16.8, 2.16.8A, 2.16.9, 2.16.9A, 2.16.9B, 2.16.9D, 2.16.9E, 2.16.9F, 2.16.9FA, 2.16.9G, 2.16.9H, 2.16.10, 2.16.12, 2.16.14, 2.17.1, 2.17.2, 2.18.1, 2.18.2, 2.19.5, 2.21.1, 2.21.2, 2.22.1, 2.22A.1, 2.24.2, 2.24.3, 2.25.1A, 2.29.5N, 2.29.5O, 2.30C.2, 2.32.1, 2.32.2, 2.32.6, 2.32.7, 2.32.7A, 2.32.7B, 2.44.1, 2.44.2, 2.44.3, 2.44.4, 3.8.2, 3.8.2A, 3.8.5A, 3.8.6, 3.11.6, 3.11.10, 3.11.11, 3.11.12, 3.15.1, 3.15.2, 3.15.3, 3.18.3, 3.18.15, 3.18.16, 3.18.18, 3.18.19, 3.18.20, 3.19.10, 4.1.22, 4.5.14, 4.5.15, 4.5.16, 4.5.17, 4.5.18, 4.5.19, 4.5.20, 4.11.3C, 4.11.3D, 4.11.3E, 4.14.5, 4.16.3, 4.16.9, 4.23A.1, 4.23A.2, 4.25.13, 4.28.6, 6.16A.1, 6.16A.2, 6.16B.1, 6.16B.2, 6.17.6, 7.6.10, 7.6A.5, 7.10.8, 7.11.1, 7.11.4, 7.11.6A, 7.11.9, 7.12.1, 7.12.2, 7A.1.2, 7A.2.18, 7B.2.16, 9.13.1, 9.22.11, 9.23.1, 10.2.3, 10.3.2, 10.5.1 and the Glossary.	Wholesale Electricity Market Rules Amending Rules 2016 (No. 2).
1 October 2016	Minister amended clauses 2.29.5B, 2.29.5E, 2.29.5G, 2.29.5LA (new), 2.29.5LB (new), 2.29.5LC (new), 2.29.9A (deleted), and Appendix 1.	Wholesale Electricity Market Rules Amending Rules 2016, Schedule B, Part 2.
26 November 2016	Minister amended clauses 1.4.1, 1.4.2, 1.5.1, 1.5.2, 1.6.1, 1.7.3, sections 1.18 (new), 1.19 (new), clauses 2.1.2, 2.1A.2, section 2.2B (new), heading to section 2.3A, clauses 2.3A.1, 2.3.1, 2.3.2, 2.3.4, 2.3.5, 2.3.5A, 2.3.8, 2.3.9, 2.3.10, 2.3.11, 2.3.12, 2.3.13, 2.3.14, 2.3.15, 2.3.16, 2.3.17, heading to section 2.4, clauses 2.4.1, 2.4.1A (new), 2.4.2, 2.4.3, 2.4.3A (new), 2.4.4, section 2.4A (new), clauses 2.5.1, 2.5.2, 2.5.3, 2.5.4, 2.5.5, 2.5.6, 2.5.7, 2.5.8, 2.5.9, 2.5.10, 2.5.11, 2.5.12, 2.5.14, 2.5.15, 2.6.1, 2.6.2, 2.6.3, 2.6.3A, 2.6.4, 2.7.1, 2.7.2, 2.7.3, 2.7.4, 2.7.5, 2.7.6, 2.7.7, 2.7.7A, 2.7.8, heading to section 2.8, clauses 2.8.1, 2.8.2, 2.8.3, 2.8.5, 2.8.6, 2.8.7, 2.8.9, 2.8.10, 2.8.11, 2.8.12, 2.8.13, 2.9.2C (new), 2.9.5, 2.9.7C (new), 2.10.1, 2.10.2, 2.10.2A, 2.10.3, 2.10.5C (new), 2.10.7, 2.10.9, 2.10.10, 2.10.12C (new), 2.10.13, 2.10.17, 2.10.18, 2.11.1, 2.11.2, 2.11.3, 2.11.4, 2.16.2, 2.16.6, 2.17.1, 2.17.2, 2.21.7 (new), 2.21.8 (new), 2.22.1, 2.24.3, 2.24.5, 2.24.5B (new), 2.24.6, 2.25.4, 2.25.4A (new), 2.29.5E, 3.8.4, 4.1.33, 9.13.1, 10.2.2, 10.2.3, 10.2.3A (new), 10.2.3B (new), 10.2.3C (new), 10.3.2, 10.5.1, the Glossary and Appendix 1.	Wholesale Electricity Market Rules Amending Rules 2016 (No. 3).
10 December 2016	Minister amended section 1.20 (new) and the Glossary.	Wholesale Electricity Market Rules Amending Rules 2016 (No. 4).
31 May 2017	Rule Change Panel amended clause 4.20.5B.	RC_2017_01
31 May 2017	Rule Change Panel amended Appendix 9.	RC_2017_03
24 June 2017	Minister amended clauses 3.21.2A (new), 4.1.34 (new), 4.1.35 (new), 4.1.36 (new), 4.1.37 (new), 4.1.38 (new), 4.10.1, 4.10.4, 4.10A.1 (new), 4.10A.2 (new), 4.10A.3 (new), 4.10A.4 (new), 4.10A.5 (new), 4.10A.6 (new), 4.11.1, 4.11.5, 4.11.10, 4.11.10A (new), 4.11.11, 5.2A.3 (new), 10.2.2, the Glossary and Appendix 11 (new).	Wholesale Electricity Market Rules Amending Rules 2017.
30 June 2017	Minister amended sections 1.21 (new), 1.22 (new), 1.23 (new) and the Glossary.	Wholesale Electricity Market Rules Amending Rules 2017 (No. 2).
1 July 2017	Minister amended clauses 2.4A.1, 2.28.3B(new), 2.28.3C(new), 3.21.1, 10.9 (new), 10.9.1 (new).	Wholesale Electricity Market Rules Amendng Rules 2017 (No. 3).
1 September 2017	Rule Change Panel amended section 1.24 (new) and the Glossary.	RC_2017_07
1 October 2017	Minister amended clauses 2.34.3, 2.34.7, 2.34.8, 2.34.14,3.2.5, 3.19.3A, 4.5.13, 4.5.14A, 4.5.14B, 4.12.4, 4.12.8, 4.25.1, 4.25.4B, 4.25.4E, 4.25.13, 4.25A.1, 4.26.1, 4.26.1A, 4.26.1C (new), 4.26.1D (new), 4.26.2, 4.26.2B, 4.26.2C, 4.26.2CA, 4.26.2D, 4.26.2E, 4.26.2F, 4.26.3, 4.26.3A, 4.26.4, 4.26.6 (new), 4.27.1, 4.27.2, 4.27.3, 4.27.3A (new), 4.27.4, 4.27.4A (new), 4.27.5, 4.27.6, 4.27.7, 4.27.8, 4.27.9, 4.28.1, 4.28.2, 4.28.4, 4.28.11A, 4.28A.1, 4.29.1, 4.29.3, section 6.11A (new), clauses 6.12.1, 6.17.6, 6.17.6B (new), 6.17.6C (new), 6.17.6D (new), 6.17.6E (new), 6.17.6F (new), 6.21.2, 7.6.1C, 7.6.1D, 7.6.1E (new), 7.6.1F (new), 7.6.1G (new), 7.6.1H (new), 7.6.10, 7.6.10A (new), 7.7.2, 7.7.3, 7.7.3B (new), 7.7.3C (new), 7.7.4A, 7.7.5, 7.7.6C (new), 7.7.10, 7.10.2, 7.10.4, 7.10.4A (new), 7.10.5, 7.11.1, 7.11.3, 7.11.5, 7.11.6, 7.11.6A, 7.13.1, 7.13.5 (new), 9.4.1, 9.4.1A (new), 9.4.4, 9.4.8, 9.5.1, 9.7.1, 9.7.1A (new), 9.7.1B (new), 9.8.1, 9.19.1, 9.19.1A (new), 10.5.1, the Glossary, Appendix 1, Appendix 5 and Appendix 10 (new)	Wholesale Electricity Market Rules Amending Rules 2016, Schedule B, Part 3.
1 October 2017	Rule Change Panel amended clauses 4.26.1, 4.26.1C and 4.26.6.	RC_2017_01
1 October 2017	Rule Change Panel amended clauses 4.5.14C, 4.26.3, 4.28.4, 6.11A.2, 6.17.6, 6.17.6C, 7.6.10, 7.13.5, 9.7.1, 9.7.1A, 9.7.1B and the Glossary.	RC_2017_04
13 October 2017	Rule Change Panel amended clauses 4.1.16, 4.1.16A (new), 4.1.21A, 4.1.26, 4.20.5A and 4.28C.13.	RC_2013_21
20 March 2018	Rule Change Panel amended clauses 2.11.1, 2.11.2, 2.13.6D, 2.24.2, 4.26.1, 4.26.1B, 4.26.5, 6.16B.1, 6.16B.2, 7.6.1D, 7.7.2, 7.10.8, 7.11.3, 10.2.2, 10.3.2, 10.5.1.	RC_2017_10
23 March 2018	Rule Change Panel amended clauses 2.1A.2, 2.3.1, 2.5.1A (new), 2.5.1B (new) and 2.22A.1.	RC_2017_05
27 March 2018	Rule Change Panel amended clause 1.17.5 and Appendix 9.	RC_2018_02
24 April 2018	Rule Change Panel amended clauses 1.4.2, 1.7.2, 1.7.3, 1.14.1, 1.14.2, 1.14.3, 1.14.4, 1.14.7, heading to 1.15, 1.15.1, 1.15.2, 1.15.3, 1.16.1, 1.16.2, 1.16.3, 1.16.4, 1.16.5, 1.16.6, 1.17.1, 1.17.2, 1.17.4, 1.17.5, 1.17.6, 1.18.1, 1.18.2, 1.18.3, heading to 1.19, 1.19.1, 1.19.3, 1.20.1, 1.20.2, 2.1A.2, 2.1A.3, 2.2.3, 2.2.4, 2.2B.2, 2.5.2, 2.7.8, 2.8.13, 2.10.8, 2.11.4, 2.13.18, 2.15.6C, 2.15.7, 2.16.5, 2.16.9B, 2.16.9E, 2.16.9FA, 2.16.12, 2.17.2, 2.21.6, 2.21.8, 2.22.1, 2.22A.1, 2.22A.2, 2.22A.11, 2.22A.12, 2.22A.14, 2.24.3, 2.24.6, 2.26.3, 2.28.3A, 2.28.3B, 2.29.5E, 2.29.5F, 2.29.5LA, heading to 2.30A, 2.30A.2, 2.30A.3, 2.30A.4, 2.30A.5, 2.30A.6, heading to 2.30B, 2.30B.1, 2.32.7B, 2.34.7A, 2.36A.1, 2.36A.2, 2.36A.3, 2.36A.4, 3.8.2A, 3.8.4, 3.11.15, 3.18.3, 3.18.15, 3.18.16, 3.18.19, 4.1.34, 4.1.37, 4.2.7, 4.3.1, 4.5.14, 4.5.14B, 4.5.14D, 4.5.14E, 4.10A.6, 4.11.1D, 4.11.10A, 4.13.5, 4.13.10, 4.13.10A, 4.13.10C, 4.16.3, 4.28B.8, 5.2A.3, 6.16B.1, 6.16B.2, 7.6A.5, 7A.3.7A, the Glossary and Appendix 11.	Notice of Corrigenda dated 24 April 2018
28 April 2018	Minister amended clauses 1.4.1, 1.4.2, 1.5.1, 1.5.2, 1.7.2, 1.9.1, 1.9.2, 1.9.3, 1.9.4, 1.9.5, 1.9.6, 1.9.7, 1.9.8, 1.9.9, 1.9.10, 1.9.11, 1.9.12, 1.10.1, 1.10.2, 1.10.3, 1.10.4, 1.11.1, 1.14.1, 1.14.2, 1.14.5, 1.14.6, 1.14.7, 1.17.2, 1.17.4, 1.17.6, section 1.25 (new), clauses 2.1.1, 2.1.2, 2.1.3, heading to section 2.2A, clauses 2.2A.1, 2.3.1, 2.3.1A, 2.3.17, 2.9.1, 2.9.5, 2.9.6, 2.9.8, 2.10.1, 2.10.2, 2.10.2A, 2.10.3, 2.10.5, 2.10.7, 2.10.9, 2.10.10, 2.10.12, 2.10.13, 2.10.17, 2.10.18, 2.11.1, 2.11.2, 2.11.3, 2.11.4, 2.16.2, 2.17.1, 2.17.2, 2.22.1, 2.22.2, 2.22.3, 2.22.4, 2.22.5, 2.22.6, 2.22.7, 2.22.8, 2.22.9, 2.22.10, 2.22.11, 2.22.12, 2.22.13, 2.22.14, 2.22.15, 2.24.2, 2.24.2A, 2.24.3, 2.25.1A, 2.25.1B, 2.25.3, 2.25.4, 2.26.5 (new), 2.28.1, 2.28.15, 4.1.33, 4.11.1E, 4.11.1F (new), 4.16.3, 4.16.10 (new), 4.26.1D, 4.26.1E (new), 4.29.1, 8.1.4, 9.13.1, 9.15.1, 10.2.2, 10.2.3, 10.2.3C, 10.3.2, 10.5.1 and the Glossary.	Wholesale Electricity Market Rules Amending Rules 2018.
29 June 2018 (8:00 AM)	Minister amended section 1.27 (new) and the Glossary.	Wholesale Electricity Market Rules Amending Rules 2018 (No. 2).
29 June 2018 (1:00 PM)	Minister amended section 1.20 (new) and the Glossary.	Wholesale Electricity Market Rules Amending Rules 2018 (No. 3).
1 August 2018	Rule Change Panel amended section 1.26 (new).	RC_2017_06
1 September 2018	Rule Change Panel amended Appendix 5.	RC_2018_01
18 October 2018	Rule Change Panel amended clause 1.27.1.	RC_2018_04
11 January 2019	Rule Change Panel amended clauses 2.12.1, 2.12.2, 2.12.3, 2.12.4, 2.12.5, 2.13.15, 2.13.16, 2.16.9FA, 2.30A.6, 2.31.23, 2.33.2, 2.33.5, 2.34.14, 2.38.4, 3.2.5, 3.5.1, 3.11.8A, 3.16.4, 3.16.9, 3.21B.8, 3.22.1, 4.5.1, 4.5.2, 4.7.1, 4.13.11B, 4.27.2, 4.27.10, 4.27.10A, heading to 5.1, 5.1.1, 5.1.2, 5.1.3, 5.1.4, 5.2.1, 5.2.2, 5.2.3, 5.2.4, 5.2.5, 5.2.6, 5.2.7, 5.3.1, 5.3.2, 5.3.3, 5.3.4, 5.3.5, 5.3.6, 5.3.7, 5.3.8, 5.3.9, 5.4.1, 5.4.2, 5.4.3, 5.4.4, 5.4.5, 5.4.6, 5.4.7, 5.4.8, 5.4.9, 5.4.10, 5.4.11, 5.4.12, 5.4.13, 5.4.14, 5.5.1, 5.5.2, 5.5.3, 5.5.4, 5.6.1, 5.6.2, 5.6.3, 5.8.1, 5.8.2, 5.8.3, 5.8.4, 5.8.5, 5.8.6, 5.8.7, 5.8.8, 6.2.4C, 8.4.5, 8.6.1, 9.3.2, 9.4.7, 9.9.3A, 9.12.1, 9.12.2, 9.14.2, 9.20.1, the Glossary and Appendix 1.	RC_2014_07
1 June 2019	Rule Change Panel amended clauses 2.31.13, 2.33.5, 4.1.23A(new), 4.1.23B(new), 4.1.23C(new), 4.1.24, 4.1.25, 4.1.28, 4.14.1, 4.14.1A, 4.14.5, 4.15.1, 4.20.5B, heading to 4.21, 4.21.1, 4.25.4C, 4.25.4CA(new), 4.26.2CA, 4.28.1, 4.28.2, 4.28.3, 4.28.6, 4.28.7, 4.28.7A, 4.28.8, 4.28.8A, 4.28.8B, 4.28.8C(new), 4.28.9, 4.28.10, 4.28.11, 4.28.11A, 4.28.12, 4.28A.1, 4.28B.8, 4.28C.14, 4.29.3, 9.3.6, 9.4.1, 9.4.1A, 9.4.2, 9.4.3, 9.4.4, 9.4.5, 9.4.6, 9.4.7, 9.4.8, 9.4.9, 9.4.10, 9.4.11, 9.4.12, 9.4.13, 9.4.14(new), 9.4.15(new), 9.4.16(new), 9.4.17(new), 9.4.18(new), 9.5.1, 9.5.3, 9.7.1A, 9.7.1B, 9.16.2, 9.18.3, 10.5.1, the Glossary, Appendix 1, Appendix 4A, Appendix 5 and Appendix 5A.	RC_2017_06
1 July 2019	Rule Change Panel amended clauses 2.13.9, 2.16.2, 2.16.4, 2.16.12, 2.22A.1, 2.26.3, 2.27.1, 2.27.5, 2.27.15, 2.29.1A, 2.29.5, 2.29.8, 2.29.8A, 2.30B.2, 2.30B.13, 2.34.3, 2.34.8, 2.34.14, 2.35.1, 2.36.1, 2.37.5, 3.9.2, 3.9.6, 3.13.2, 3.13.3A, 3.13.3AB, 4.1.26, 4.10.1, 4.11.4, 4.12.1, 4.12.4, 4.18.1, 4.18.2, 4.25.2, 4.25.4, 4.26.2, 4.26.2B, 4.26.5, 6.3A.2, 6.3A.4, 6.3B.1, 6.4.1, 6.4.2, 6.4.3, 6.4.4, 6.4.5, 6.4.6, 6.4.6A (new), 6.4.6B (new), heading to 6.5, 6.5.1, 6.5.1A, 6.5.1B, 6.5.2, 6.5.3, 6.5.3A, 6.5.4, heading to 6.5A, heading to 6.5B, heading to 6.5C, 6.5C.1, 6.5C.1A, 6.5C.2, 6.5C.3, 6.5C.4, 6.5C.5, 6.5C.6, 6.5C.7, 6.6.9, heading to 6.11, 6.11.1, 6.11.2, 6.11.3, 6.11A.1, 6.12.1, heading to 6.13, 6.15.1, 6.15.2, 6.16A.1, 6.16A.2, 6.16B.1, 6.16B.2, 6.17.1, 6.17.3, 6.17.4, 6.17.5, 6.17.5A, 6.17.6, 6.17.6A, 6.17.6C, 6.17.7, 6.17.9, 6.21.2, 7.1.1, 7.2.2, heading to 7.4, 7.4.1, 7.4.2, 7.4.3, 7.4.4, heading to 7.5, 7.5.1, 7.5.2, 7.5.3, 7.5.4, 7.5.5, 7.5.6, 7.6.1C, 7.6.2B, heading to 7.6A, 7.6A.1, 7.6A.2, 7.6A.3, 7.6A.5, 7.7.4A, 7.7.5, 7.9.4, 7.9.8, 7.11.5, 7.13.1, 7A.1.3, 7A.1.6, 7A.2.1, 7A.2.3, 7A.2.4, 7A.2.4A (new), 7A.2.4B (new), 7A.2.4C (new), 7A.2.8, 7A.2.9, 7A.2.10, 7A.2.10A (new), 7A.2.12, 7A.2.13, heading to 7A.3, 7A.3.1, 7A.3.2, 7A.3.3, 7A.3.4, 7A.3.5, 7A.3.6, 7A.3.8, 7A.3.9A (new), 7A.3.10, 7A.3.13, 7A.3.16, 7A.3.17, 7A.3.18, 7A.3.19, 7A.3.20, 7A.3.21, 7B.1.4, 7B.1.5, 7B.2.1, 7B.2.2, 7B.2.3, 7B.2.4, 7B.2.5, 7B.2.6, 7B.2.10, 7B.2.18, 7B.2.19, heading of 7B.3, 7B.3.1, 7B.3.2, 7B.3.3, 7B.3.4, 7B.3.5, 7B.3.6, 7B.3.7, 7B.3.8, 7B.3.9, 7B.3.10, 7B.3.11, 7B.3.12, 7B.3.14, 7B.3.15, 7B.3.16, heading to 7B.4, 7B.4.1, 9.3.3, 9.3.4, 9.3.7, 9.8.1, 9.9.2, 9.11.1, 9.13.1, 9.18.3, 9.24.2, 10.5.1, 10.7.1, the Glossary, Appendix 1, and Appendix 9.	RC_2014_06
1 July 2019	Rule Change Panel amended clauses 7.7.3A, 7.7.6, 7.7.7B (new), 7.7.11 (new), and the Glossary.	RC_2018_07
1 July 2019	Rule Change Panel amended clause 2.34.14.	RC_2014_07
1 August 2019	Rule Change Panel amended clauses 1.14.1, 1.16.1, 1.17.1, 1.18.2, 2.2.2, 2.9.2D (new), 2.9.2E (new), 2.9.5, 2.11.1, 2.11.2, 2.13.2, 2.13.3, 2.13.6A, 2.13.6K, 2.13.9C, heading to section 2.15, 2.15.1, 2.15.2, 2.15.3, 2.15.6A, 2.15.6B, 2.15.6C, 2.15.7, 2.27.6, 2.27.10, 2.27.15, 2.27.17, 2.30.11, 2.30A.6, 2.31.23, 2.35.4, 2.36.5, 2.36A.1, 2.36A.2, 2.36A.5, 2.37.8, heading to section 2.43, 2.43.1, 3.2.2, 3.2.4, 3.2.6, 3.2.8, 3.3.3, 3.4.9, 3.5.11, 3.11.14, 3.11.15, 3.16.4, 3.16.7, 3.16.8A, 3.16.10, 3.17.10, 3.18.3, 3.18.15, 3.18.21, 3.19.10, 3.19.14, 3.21.12, 3.21A.15, 3.21B.5, 3.21B.8, 4.5.14, 4.5.14B, 4.5.15, 4.5.16, 4.5.17, 4.9.10, 4.13.8, 4.14.11, 4.17.9, 4.24.18, 4.25.14, 4.25A.1, 4.27.12, 4.28A.3, 4.28B.9, 4.28C.15, 6.17.6F, 6.19.6, 6.19.10, 7.2.5, 7.6.13, 7.6A.7, 7.6A.8, 7.6A.10, 7.7.4A, 7.7.5A, 7.7.5B, 7.7.6, 7.9.19, 7.10.4, 7.13.1, 7.13.3, 7A.1.6, 7A.3.1, 7A.3.2, 7A.3.3, 7A.3.4, 7A.3.7, 7A.3.7A, 7A.3.15, 7B.1.2, 7B.1.4, 7B.3.2, 8.6.2, heading to section 9.2, 9.2.1, 9.4.18, 9.20.1, 10.2.7, the Glossary and Appendix 9.	RC_2015_01
1 September 2019	Rule Change Panel amended clause 2.30.7A and Appendix 2.	RC_2018_06
1 October 2019	Rule Change Panel amended clauses 2.24.1, 4.26.2CB (new), 4.26.2CC (new), 4.26.2CD (new), 4.26.2CE (new), 4.26.2CF(new), 4.26.2CG (new), 4.26.2CH (new), 4.28.8, 4.28.8C, 4.28.9A (new), 4.28.9B (new), 4.28.9C (new), 4.28.9D (new), 4.28.9E (new), 4.28.9F (new), the Glossary, Appendix 5A and Appendix 10.	RC_2015_03
1 November 2019	Minister amended section 1.28 (new) and the Glossary.	Wholesale Electricity Market Amendment (AEMO to provide information to the Minister) Rule 2019.
1 February 2020	Rule Change Panel amended clauses 2.34.4, 3.18.1, 3.18.1A (new), 3.18.1B (new), 3.18.2, 3.18.2A, 3.18.3, 3.18.4, 3.18.4A, 3.18.5, 3.18.5C, 3.18.5D, 3.18.5E (new), 3.18.6, 3.18.6A (new), 3.18.7, 3.18.8, 3.18.9, 3.18.9A (new), 3.18.9B (new), 3.18.10, 3.18.10A (new), 3.18.10B (new), 3.18.10C (new), 3.18.11, 3.18.14, 3.18.15, 3.18.16, 3.18.17, 3.18.20, 3.19.1, 3.19.2, 3.19.2A (new), 3.19.2B (new), 3.19.2C (new), 3.19.2D (new), 3.19.2E (new), 3.19.2F (new), 3.19.2G (new), 3.19.2H (new), 3.19.3, 3.19.3A, 3.19.3B (new), 3.19.3C (new), 3.19.4, 3.19.4A (new), 3.19.6, 3.19.11, 3.19.12, 3.19.13, 3.20.1, 3.21A.14, 7.1.1, 7A.2.4C, 7A.2.6, 7A.2.8A (new), 7A.2.9, 7A.2.9A (new), 7A.2.9B (new), 7A.2.9C (new), heading to section 7A.2A (new), 7A.2A.1 (new), 7A.2A.2 (new), 7A.2A.3 (new), 7A.2A.4 (new) and the Glossary.	RC_2013_15
22 February 2020	Minister amended heading to section 1.28, sections 1.29 (new), 1.30 (new), 1.31 (new), 1.32 (new), clauses 2.4A.1, 2.4A.2, 2.8.13, 2.17.1, 2.26.3, 2.26.3A (new), 2.26.4, 2.29.5E, 2.30.1, 2.30.5, 2.38.3, 2.38.4, 2.43.1, 3.16.4, 4.1.1, 4.1.1A, 4.1.1B (new), 4.1.1C (new), 4.1.13, 4.1.15, 4.1.16A, 4.1.18A (new), 4.1.21, 4.1.21A, 4.1.26, 4.1.29, 4.1.31, 4.1.32, 4.2.7, 4.3.1, section 4.4A (new), clauses 4.6.4, 4.6.5, 4.7.3, 4.9.5, 4.9.9, heading before section 4.13, heading to section 4.13, 4.13.1, 4.13.2, 4.13.4, 4.13.5, 4.13.7, 4.13.8, 4.13.9, 4.13.12, 4.13.14, section 4.13A (new), heading before section 4.14 (new), clauses 4.14.1, 4.14.1A, 4.14.1B (new), 4.14.1C (new), 4.14.2, 4.14.6, 4.14.9, 4.14.10, 4.14.11, 4.15.2, 4.17.10, 4.18.1, 4.18.2, 4.20.1, 4.20.5A, 4.20.5AA (new), 4.20.5B, 4.25.1, 4.25.4B, 4.25.4E, 4.26.1, 4.28.2, 4.28.3, 4.28.4, 4.28A.1, 4.28B.8, 4.28C.13, 4.28C.14, 4.29.1, 4.29.1A (new), 4.29.1B (new), 4.29.1C (new), 4.29.1D (new), 4.29.2, 4.29.2A (new), 4.29.2B (new), 4.29.3, heading to section 6.11A, clauses 6.11A.2, 6.17.6D, 7.6.1C, 7.6.1H, 7.7.4A, 9.4.9, 9.4.10, 9.5.1, 9.7.1A, 9.9.2, 10.5.1, the Glossary, Appendix 1 and Appendix 3.	Wholesale Electricity Market Amendment (Reserve Capacity Pricing Reforms) Rules 2019 (Part 1).
30 March 2020	Rule Change Panel amended clause 9.13.1.	RC_2020_01
24 June 2020	Rule Change Panel amended clause 7.7.5A and Appendix 9.	RC_2020_03
1 July 2020	Minister amended clauses 1.4.1, 1.5.1, 1.7.4 (new), sections 1.33 (new), 1.34 (new), heading to section 2.1A, clause 2.1A.2, section 2.2C (new), clauses 2.3.1, 2.9.2CA (new), 2.10.1, 2.10.2, 2.10.2A, 2.10.3, 2.10.5D (new), 2.10.7, 2.10.9, 2.10.12D (new), 2.10.13, 2.10.17, 2.10.18, 2.11.1, 2.11.2, 2.11.3, 2.11.4, 2.17.1, 2.17.2, 2.21.9 (new), 2.21.10 (new), 2.22A.1, heading before sections 2.27A (new), 2.27A (new), 2.27B (new), 2.27C (new), clauses 10.3.2, 10.5.2 and the Glossary.	Wholesale Electricity Market Amendment (Constraints Framework and Governance) Rules 2020.
1 July 2020	Minister amended section 1.20A (new), clause 2.1A.2, heading before section 3.24 (new), section 3.24 (new) and the Glossary.	Wholesale Electricity Market Amendment (Distributed Energy Resources Register and Roadmap Implementation – Costs) Rules 2020.
2 July 2020	Rule Change Panel amended clauses 6.15.4, 9.2.1, 9.16.2, 9.16.3, 9.16.3A, 9.16.4, 9.17.3, 9.18.1, 9.18.2, 9.18.3, 9.18.4, 9.19.1, 9.19.1A, 9.19.1B (new), 9.19.3, 9.19.5, 9.19.6, 9.19.7, 9.20.3, 9.20.4, 9.20.4A (new), 9.20.5, 9.20.6, 9.20.7, 9.20.7A (new), 9.20.7B (new), 9.20.8, 9.21.1, 9.22.2, 9.22.4, 9.22.6, 9.22.7, 9.22.8, 9.23.1, 9.23.4, 9.23.5, 9.23.6, 9.23.7, 9.24.1, 9.24.2, 9.24.4, 9.24.5, 9.24.6, 9.24.7, 9.24.8, 9.24.8A, 9.24.9, 9.24.10 and the Glossary.	RC_2019_04
21 July 2020	Rule Change Panel amended clauses 2.13.3A, 2.13.3B, 2.13.9A, 2.13.9B, 2.15.4, 2.16.9G and 2.16.14.	RC_2018_05
7 August 2020	Rule Change Panel amended section 1.35 (new), clauses 2.26.1, 6.20.9, 6.20.9A, 6.20.10, 6.20.11, 6.20.12 (new), 6.20.13 (new), 6.20.14 (new), 6.20.15 (new), 6.20.16 (new), 6.20.17 (new), 6.20.18 (new), 6.20.19 (new), 6.20.20 (new), 6.20.21 (new), 6.20.22 (new), 6.20.23 (new), 6.20.24 (new), 6.20.25 (new), 6.20.26 (new), 6.20.27 (new), 6.20.28 (new), 6.20.29 (new), 6.20.30 (new), 10.5.1,10.7.2 (new) and the Glossary.	RC_2019_05
25 November 2020	Minister amended section 1.36 (new) and the Glossary.	Wholesale Electricity Market Amendment (Tranche 1 Amendments) Rules 2020, Schedule A.
1 December 2020	Rule Change Panel amended clauses 7A.1.16, 7A.1.17, 7A.2.6, 7A.2.9, 7A.2.12, 7A.2A.4, 7A.3.5, 7B.2.4 and the Glossary.	RC_2017_02
1 January 2021	Minister amended clauses 2.1A.2, 2.22A.1 and the Glossary.	Wholesale Electricity Market Amendment (Technical Rules Change Management) Rules 2020.
1 January 2021	Minister amended clause 2.1A.2.	Wholesale Electricity Market Amendment (Tranche 1 Amendments) Rules 2020, Schedule B, Part 1.
1 January 2021	Minister amended sections 1.36A (new), 1.36B (new) and 1.36C (new).	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule A.
1 February 2021	Minister amended heading above section 1.1, heading to section 1.1, clauses 1.1.2, 1.3.1, 1.4.1, 1.4.2, 1.4.3, 1.5.1, 1.5.2, 1.6.1, 1.6.2, 1.7.1, 1.7.3, 1.7.4, 1.7.5 (new), heading to section 1.8, clauses 1.8.1, 1.8.2, 1.8.3, 1.8.5, 1.8.6, heading to section 1.12, 1.12.1, 1.12.2, heading to section 1.13, clauses 1.13.1, 1.13.2, heading to section 1.14, clauses 1.14.1, 1.14.2, 1.14.3, 1.14.4, heading to section 1.15, clauses 1.15.1, 1.15.2, 1.15.3, heading to section 1.16, clauses 1.16.1, 1.16.2, 1.16.3, 1.16.4, 1.16.5, 1.16.6, heading to section 1.17, clauses 1.17.1, 1.17.2, 1.17.3, 1.17.4, 1.17.5, heading to section 1.18, clauses 1.18.1, 1.18.2, 1.18.3, 1.18.4, heading to section 1.19, clauses 1.19.1, 1.19.2, 1.19.3, 1.20.1, 1.20.2, 1.20.5, section 1.21, section 1.22, clauses 1.24.1, heading to section 1.25, clauses 1.25.1, 1.25.2, 1.25.3, 1.25.4, 1.26.1, 1.27.1, 1.28.1, 1.28.3, 1.29.2, 1.30.1, 1.33.2, 1.34.1, 1.36.1, 1.36.7, section 1.37 (new), 1.38 (new), 1.39 (new), 1.40 (new), 1.41 (new), 1.42(new), clauses 2.1A.1A (new), 2.1A.2, 2.1A.3, 2.1A.4 (new), 2.1A.5 (new), 2.1A.6 (new), 2.1A.7 (new), 2.1A.8 (new), heading to section 2.2, clauses 2.2.1, 2.2.2, 2.2.3, 2.2.4, 2.2.5, 2.2.6, 2.2.7, 2.2.8, 2.2A.1, 2.2B.2, 2.2B.3, 2.2C.1, section 2.2D (new), clauses 2.3.1, 2.3.3, 2.3.5, 2.3.15, 2.3.17, heading to section 2.4, clauses 2.4.1, 2.4.1A, 2.4.2, 2.4.4, heading to section 2.4A, clauses 2.4A.2, 2.5.4, 2.5.7, 2.8.4, 2.8.5, 2.8.7, 2.8.13, heading to section 2.9, clauses 2.9.2, 2.9.2A, 2.9.2B, 2.9.2C, 2.9.2CA, 2.9.2CB (new), 2.9.2D, 2.9.3, 2.9.4, 2.9.5, 2.9.7, 2.9.7A, 2.9.7B, 2.9.7C, 2.9.8, 2.10.1, 2.10.2, 2.10.2A, 2.10.3, 2.10.5A, 2.10.5E (new), 2.10.6, 2.10.7, 2.10.9, 2.10.10, 2.10.12A, 2.10.12E (new), 2.10.13, 2.10.17, 2.10.18, 2.11.1, 2.11.2, 2.11.3, 2.11.4, heading to section 2.13, clauses 2.13.2, 2.13.3, 2.13.3A, 2.13.4, 2.13.6, 2.13.6A, 2.13.6B, 2.13.6C, 2.13.6D, 2.13.6E, 2.13.6F, 2.13.6G, 2.13.6H, 2.13.6K, 2.13.7, 2.13.8, 2.13.9, 2.13.9A, 2.13.9C, 2.13.9D, 2.13.10, 2.13.11, 2.13.12, 2.13.13, 2.13.15, 2.13.16, 2.13.18, 2.13.23, 2.14.3, 2.14.5A, 2.14.5B, 2.14.5C, 2.15.1, 2.15.2, 2.15.3, 2.15.4, 2.15.6A, 2.15.6B, 2.15.6C, 2.16.2, 2.16.7, 2.16.9, 2.16.9D, 2.16.9FA, 2.16.10, 2.16.12, 2.16.14, 2.17.1, 2.17.2, 2.18.1, 2.18.2, 2.18.4, 2.21.1, 2.21.3, 2.21.4, 2.21.5, 2.21.7, 2.21.9, 2.21.11 (new), 2.21.12 (new), heading to section 2.22A, clauses 2.22A.1, 2.22A.2, 2.22A.2A, 2.22A.4, 2.22A.5, 2.22A.7, 2.22A.11, 2.22A.12, 2.22A.14, 2.24.1, 2.24.2, 2.24.2A, 2.24.2B, 2.24.3, 2.24.4, 2.24.5, 2.24.5B, 2.24.6, 2.25.1, 2.25.2, 2.25.4, 2.26.3, 2.27.6, 2.27.10, 2.27.14, 2.27.15, 2.27.17, 2.27A.2, 2.27A.3, 2.27A.4, 2.27A.6, 2.27A.7, 2.27A.10, 2.27A.11, 2.27B.2, 2.27B.3, 2.27B.4, 2.27B.6, 2.27B.8, 2.27C.2, 2.28.1, 2.28.3, 2.28.3A, 2.28.3B, 2.28.3C, 2.28.11A, 2.28.11B, 2.28.13, 2.28.14, 2.28.14A, 2.28.16A, 2.28.16B, 2.28.17, 2.28.19, 2.29.1, 2.29.6, 2.29.7, 2.29.10, 2.30.5, 2.30.7, 2.30.10, 2.30.11, 2.30A.6, 2.30B.3, 2.30B.10, 2.30C.1, 2.30C.2, 2.30C.3, 2.30C.4, 2.31.1, 2.31.6, 2.31.7, 2.31.8, 2.31.9, 2.31.13, 2.31.17, 2.31.22, 2.31.23, 2.32.8, 2.33.1, 2.34.2, 2.34.2A, 2.34.7, 2.35.1, 2.35.2, 2.35.4, 2.36.1, 2.36.5, 2.36A.1, 2.36A.2, 2.36A.3, 2.36A.4, 2.37.4, 2.37.7, 2.37.8, 2.38.3, 2.38.4, 2.38.7, 2.40.1, 2.41.5, 2.42.4, 2.43.1, 2.44.1, 3.2.2, 3.2.4, 3.2.5, 3.2.6, 3.2.7, 3.2.8, 3.3.1, 3.3.2, 3.3.3, 3.4.1, 3.4.2, 3.4.3, 3.4.4, 3.4.5, 3.4.6, 3.4.7, 3.4.8, 3.4.9, 3.5.1, 3.5.2, 3.5.3, 3.5.4, 3.5.5, 3.5.6, 3.5.7, 3.5.8, 3.5.9, 3.5.10, 3.5.11, 3.6.1, 3.6.2, 3.6.4, 3.6.5, 3.6.6, 3.6.6A, 3.6.6B, 3.7.1, 3.7.2, 3.7.3, 3.7.5, 3.7.6, 3.8.3, 3.8.4, 3.8.5, 3.8.5A, section 3.8A (new), clauses 3.10.2, 3.10.4, 3.10.5, 3.10.6, 3.11.1, 3.11.2, 3.11.3, 3.11.4, 3.11.6, 3.11.7, 3.11.7A, 3.11.8, 3.11.8A, 3.11.8B, 3.11.8E, 3.11.9, 3.11.10, 3.11.11, 3.11.12, 3.11.13, 3.11.14, 3.11.15, 3.12.1, 3.13.3, 3.13.3A, 3.13.3C, 3.16.1, 3.16.3, 3.16.4, 3.16.5, 3.16.6, 3.16.7, 3.16.8, 3.16.8A, 3.16.9, 3.16.10, 3.17.1, 3.17.4, 3.17.5, 3.17.6, 3.17.7, 3.17.8, 3.17.9, 3.17.10, 3.18.1B, 3.18.2, 3.18.2A, 3.18.3, 3.18.4, 3.18.4A, 3.18.5, 3.18.5A, 3.18.5B, 3.18.5C, 3.18.5D, 3.18.5E, 3.18.7A, 3.18.8, 3.18.9, 3.18.9A, 3.18.9B, 3.18.10, 3.18.10A, 3.18.10B, 3.18.10C, 3.18.11, 3.18.11A, 3.18.12, 3.18.13, 3.18.14, 3.18.15, 3.18.16, 3.18.17, 3.18.18, 3.18.19, 3.18.21, 3.19.1, 3.19.2, 3.19.2A, 3.19.2B, 3.19.2C, 3.19.2D, 3.19.2F, 3.19.2G, 3.19.2H, 3.19.3, 3.19.3A, 3.19.3B, 3.19.3C, 3.19.4, 3.19.4A, 3.19.5, 3.19.6, 3.19.7, 3.19.8, 3.19.9, 3.19.10, 3.19.11, 3.19.12, 3.19.13, 3.19.14, 3.20.1, 3.20.2, 3.20.3, 3.21.1, 3.21.2, 3.21.2A, 3.21.3, 3.21.4, 3.21.5, 3.21.6, 3.21.7, 3.21.8, 3.21.9, 3.21.10, 3.21.11, 3.21.12, 3.21A.2, 3.21A.3, 3.21A.4, 3.21A.6, 3.21A.7, 3.21A.8, 3.21A.9, 3.21A.10, 3.21A.11, 3.21A.12, 3.21A.13, 3.21A.15, 3.21A.17, 3.21B.1, 3.21B.2, 3.21B.3, 3.21B.4, 3.21B.5, 3.21B.6, 3.21B.7, 3.21B.8, 3.23.1, 3.24.1, 3.24.2, 3.24.3, 3.24.5, 3.24.6, 3.24.7, 3.24.8, 3.24.9, 3.24.10, 3.24.11, 3.24.12, 3.24.14, 3.24.15, 3.24.16, Chapter 3A (new), Chapter 3B (new), 4.1.1C, 4.1.10, 4.1.34, 4.1.36, 4.1.37, 4.3.1, 4.4A.2, 4.4A.4, 4.4A.7, 4.5.7, 4.5.14, 4.5.14B, 4.5.14C, 4.5.14D, 4.5.14E, 4.5.14F, 4.5.15, 4.5.16, 4.5.17, 4.5.20, 4.7.2, 4.7.3, 4.9.3, 4.9.10, 4.10.1, 4.10A.6, 4.11.1, 4.11.1A, 4.11.1B, 4.11.6, 4.12.1, 4.12.6, 4.13.4, 4.13.5, 4.13.8, 4.13.9, 4.13.10A, 4.13.10C, 4.13A.6, 4.13A.12, 4.13A.14, 4.13A.23, 4.13A.25, 4.14.2, 4.14.8, 4.14.11, 4.16.3, 4.16.5, 4.16.6, 4.16.7, 4.16.8, 4.16.9, 4.17.1, 4.17.4, 4.17.9, 4.20.3, 4.20.7, 4.20.13, 4.24.6, 4.24.13, 4.24.18, 4.24.19, 4.25.2, 4.25.3A, 4.25.3B, 4.25.4, 4.25.4CA, 4.25.5, 4.25.6, 4.25.9, 4.25.14, 4.25A.1, 4.26.1C, 4.26.2, 4.26.2CB, 4.26.2CD, 4.26.2CE, 4.26.2D, 4.27.3A, 4.27.5, 4.27.12, 4.28.9A, 4.28.9C, 4.28.9D, 4.28.9E, 4.28.12, 4.28A.3, 4.28B.9, 4.28C.15, 5.2A.3, 5.3A.3, 5.3A.4, 5.7.2, 5.7.4, 5.9.3, 6.3A.2, 6.3A.3, 6.12.1, 6.13.1, 6.15.2, 6.16A.1, 6.16A.2, 6.16B.1, 6.16B.2, 6.17.3, 6.17.4, 6.17.5, 6.17.5A, 6.17.6B, 6.17.6D, 6.17.6E, 6.17.6F, 6.17.9, 6.19.5, 6.19.6, 6.19.10, 6.20.2, 6.20.9, 6.20.9A, 6.20.11, 6.20.24, 7.1.1, 7.1.2, 7.1.3, 7.2.1, 7.2.3A, 7.2.4, 7.2.5, 7.2.6, 7.3.4, 7.6.1, 7.6.1A, 7.6.1B, 7.6.1C, 7.6.1D, 7.6.1E, 7.6.1F, 7.6.1H, 7.6.2A, 7.6.10, 7.6.10A, 7.6.11, 7.6.12, 7.6.13, 7.6A.1, 7.6A.2, 7.6A.3, 7.6A.4, 7.6A.5, 7.6A.6, 7.6A.7, 7.6A.8, 7.6A.10, 7.7.1, 7.7.2, 7.7.4A, 7.7.5, 7.7.5A, 7.7.5B, 7.7.5C, 7.7.5D, 7.7.6, 7.7.6A, 7.7.6B, 7.7.6C, 7.7.7, 7.7.7A, 7.7.7B, 7.7.8, 7.7.9, 7.7.10, 7.7.11, heading to section 7.8, clauses 7.8.1, 7.8.2, 7.8.3, 7.9.1, 7.9.1A, 7.9.2, 7.9.3, 7.9.4, 7.9.5, 7.9.6, 7.9.6A, 7.9.7, 7.9.8, 7.9.9, 7.9.10, 7.9.12, 7.9.13, 7.9.14, 7.9.15, 7.9.16, 7.9.17, 7.9.18, 7.9.19, 7.10.2, 7.10.3, 7.10.3A, 7.10.4, 7.10.4A, 7.10.5, 7.10.6A, 7.10.7, 7.10.8, 7.11.2, 7.11.3, 7.11.3A, 7.11.4, 7.11.5, 7.11.6, 7.11.6A, 7.11.6B, 7.11.7, 7.11.9, 7.12.1, 7.12.2, 7.13.1, 7.13.1A, 7.13.1B, 7.13.1C, 7.13.1D, 7.13.1E, 7.13.1F, 7.13.1G, 7.13.2, 7.13.3, 7.13.4, 7.13.5, 7A.1.6, 7A.1.11, 7A.1.12, 7A.1.15, 7A.1.16, 7A.2.9, 7A.2.9B, 7A.2.9C, 7A.2.18, 7A.2A.1, 7A.2A.2, 7A.2A.3, 7A.2A.4, 7A.3.1, 7A.3.2, 7A.3.3, 7A.3.4, 7A.3.7, 7A.3.7A, 7A.3.8, 7A.3.9, 7A.3.15, 7A.4.2, 7A.4.7, 7B.1.2, 7B.1.4, 7B.1.5, 7B.2.18, 7B.2.19, 7B.3.1, 7B.3.2, 7B.3.6, 7B.3.7, 7B.3.8, 7B.4.1, 7B.4.2, 8.6.2, 8.7.1, 8.8.1, 9.1.1, 9.1.2, 9.1.3, 9.2.1, 9.3.4, 9.4.5, 9.4.10, 9.4.15, 9.4.17, 9.4.18, 9.7.2, 9.9.2, 9.13.1, 9.15.1, 9.16.2, 9.16.3, 9.16.3A, 9.19.1, 9.20.1, 9.20.4, 9.20.5, 9.20.6, 9.22.4, 9.22.5, 9.22.9, 9.22.11, 9.23.1, 9.23.4, 9.24.1, 9.24.2, 9.24.3, 9.24.3A, 10.2.1, 10.2.2, 10.2.3, 10.2.3A, 10.2.3B, 10.2.7, heading to section 10.3, clauses 10.3.1, 10.3.2, 10.4.2, heading above section 10.5, clauses 10.5.1, 10.5.3, 10.7.1, heading to section 10.9, clause 10.9.1, the Glossary, Appendix 1, Appendix 5A, Appendix 9, Appendix 11, Appendix 12 (new) and Appendix 13 (new).	Wholesale Electricity Market Amendment (Tranche 1 Amendments) Rules 2020, Schedule B, Part 2.
1 February 2021	Minister amended clauses 1.4.1, 1.36A.2, 1.36A.3, 1.36A.6, 1.36A.7, 1.36B.2, 1.36B.3, 1.36B.6, 1.36B.7, 2.9.2D, 2.10.10, 2.10.13, 2.36A.2, 2.36A.5, 3.13.3B, 4.16.3 and 7.6A.5.	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule B.
1 February 2021	Minister amended Appendix 12.	Wholesale Electricity Market Amendment (Governance) Rules 2021, Schedule A.
1 February 2021	Minister amended section 1.45 (new), section 4.2 (replaced), section 4.3 (replaced), heading to section 4.4, clauses 4.4.1, 4.8.2, 4.8.3, heading above section 4.8A (new), section 4.8A (new), clauses 4.9.1, 4.9.3, 4.9.5, 4.9.7A (new), 4.9.8, 4.9.9, 4.10.1, 4.10.2, 4.10.3, 4.10.3A and the Glossary.	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule C (in accordance with notice in Gazette 2021/20).
29 June 2021	Rule Change Panel amended clauses 3.18.1A, 3.18.2A, 3.18.4A, 3.18.9A, 3.19.2E, 3.21.1, 3.21.2, 3.21.2B (new), 3.21.3, 3.21.4, 3.21.4A (new), 3.21.4B (new), 3.21.5, 3.21.5A (new), 3.21.6, 3.21.6A (new), 3.21.6B (new), 3.21.7, 3.21.8, 3.21.9, 3.21.10, 3.21.11, 3.21.12, 3.21.13 (new), 3.21.14 (new), 3.21.15 (new), 3.21.16 (new), 3.21.17 (new), 4.11.1, 4.12.6, 4.25.3A, 4.25.9, 4.26.1, 4.26.1A, 4.26.1C, 4.26.2, 4.26.6, 6.3A.2, 6.3A.3, 6.15.2, 6.15.3, 6.17.5A, 6.17.9, 6.17.10, 7.3.4, 7.3.5, 7.10.2, 7.13.1A, 7.13.1D, 7.13.1E, 7.13.1F, 7.13.1G, 7A.2.4A, 7A.2.8A, 7A.2.8B (new), 7A.2.10, 7A.2A.1, 7A.2A.2, the Glossary and Appendix 9.	RC_2014_03
1 July 2021	Minister amended clauses 1.4.1, 1.4.2, 1.5.1, 1.5.2, 1.6.1, 1.7.3, 1.7.3A (new), 1.7.5, sections 1.17A (new), 1.18A (new), 1.19A (new), clauses 2.1A.2, 2.2A.1, heading to section 2.2B, clauses 2.2B.1, 2.2B.2, 2.2D.1, 2.3.1, 2.3.1B (new), 2.3.1C (new), 2.3.2, 2.3.4, 2.3.5, 2.3.5A, 2.3.5B (new), 2.3.5C (new), 2.3.7A (new), 2.3.8, 2.3.8A (new), 2.3.8B (new), 2.3.8C (new), 2.3.8D (new), 2.3.8E (new), 2.3.9, 2.3.10, 2.3.11, 2.3.12, 2.3.13, 2.3.15, 2.3.16, 2.3.17, heading to section 2.4, clauses 2.4.1, 2.4.2, 2.4.3, 2.4.3A, 2.5.1, 2.5.1C (new), 2.5.2, 2.5.3, 2.5.3A (new), 2.5.3B (new), 2.5.4, 2.5.5, 2.5.6, 2.5.7, 2.5.8, 2.5.8A (new), 2.5.9, 2.5.10, 2.5.11, 2.5.12, 2.5.14, 2.5.15, 2.6.1, 2.6.2, 2.6.3, 2.6.3A, 2.6.4, 2.7.1, 2.7.2, 2.7.3, 2.7.4, 2.7.5, 2.7.6, 2.7.7, 2.7.7A, 2.7.8, heading to section 2.8, clauses 2.8.1, 2.8.2, 2.8.3, 2.8.5, 2.8.6, 2.8.7, 2.8.9, 2.8.10, 2.8.11, 2.8.12, 2.8.13, 2.9.2C, 2.9.5, 2.9.7C, 2.10.1, 2.10.2, 2.10.2A, 2.10.3, 2.10.5C, 2.10.7, 2.10.9, 2.10.10, 2.10.12C, 2.10.13, 2.10.17, 2.10.18, 2.11.1, 2.11.2, 2.11.4, 2.16.1, 2.16.2, 2.16.4, 2.16.5, 2.16.6, 2.16.7, 2.16.9, 2.16.9A, 2.16.10, 2.16.11, 2.16.12, 2.16.13, 2.16.13A (new), 2.16.13B (new), 2.16.13C (new), 2.16.13D (new), 2.16.13E (new), 2.16.13F (new), 2.16.14, 2.16.15A (new), 2.16.16, 2.17.1, 2.17.2, 2.21.7, 2.21.8, 2.22A.1, 2.24.2, 2.24.2A, 2.24.2B, 2.24.3, 2.24.4, 2.24.5B, 2.24.5C (new), 2.24.5D (new), 2.24.5E (new), 2.24.6, 2.24.6A (new), 2.25.1, 2.25.1A, 2.25.1C (new), 2.25.2, 2.25.3, 2.25.4, 2.25.4A, heading to section 2.26, clauses 2.26.1, 2.26.2, 2.26.3, 2.32.7A, 4.5.14, 4.5.15, 4.5.16, 4.5.17, 4.5.18, 4.5.19, 4.5.20, 4.11.1E, 4.11.1F, 4.16.1, 4.16.3, 4.16.5, 4.16.6, 4.16.7, 4.16.8, 4.24.19, 4.26.1D, 4.26.1E, 6.20.6, 6.20.7, 6.20.9, 6.20.9A, 6.20.10, 6.20.11, 9.1.2, 9.13.1, 10.2.2, 10.2.3, 10.2.3B, 10.2.3BA (new), 10.3.2, 10.5.1 and the Glossary.	Wholesale Electricity Market Amendment (Governance) Rules 2021, Schedule B.
1 July 2021	Minister amended clauses 2.29.5B, 2.29.12 (new), 2.29.13 (new), 2.29.14 (new), 2.29.15 (new), section 4.5A (new), clauses 4.8A.7 (new), 4.11.1, 4.11.1C, 4.11.1D, 4.11.2, 4.11.3, 4.11.3A, 4.11.3B, 4.11.3BA (new), 4.11.4, 4.11.5, 4.11.6, 4.11.7, 4.11.8, 4.11.9, 4.11.10A, the Glossary and Appendix 9 (replaced).	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule C (in accordance with notice in Gazette 2021/20).
1 July 2021	Minister amended section 1.43 (new), clause 1.45.6 (new), section 2.34A (new), section 2.36A (replaced), clauses 4.4A.1, 4.4A.2, 4.16.2, 4.28C.7 and 4.28C.11.	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule C (in accordance with notice in Gazette 2021/96).
1 July 2021	Minister amended section 1.36D (new), clauses 1.43.1, 1.45.1, 1.45.4, 1.45.5, 1.45.6, 1.45.6A (new), 1.45.8, 1.45.9, 1.45.10, 1.45.11 (new), sections 1.49 (new), 1.50 (new), clauses 2.9.4, 2.11.3, 2.29.5B, 2.29.12, 2.29.13, 2.29.14, 2.29.15, heading before clause 2.34A.1 (new), clauses 2.34A.2, 2.34A.4, 2.34A.4C (new), 2.34A.6, 2.34A.9, 2.34A.12, 2.34A.12A (new), 2.34A.12B (new), 2.34A.12C (new), 2.34A.12D (new), 2.34A.12E (new), 2.34A.12F (new), 2.34A.12G (new), 2.34A.12H (new), 2.34A.14 (new), 2.36A.1, section 3.1A (new), clauses 3.8.5A, 4.2.1, 4.2.7, 4.8A.1, 4.8A.3, 4.8A.5, 4.8A.6, 4.8A.7, 4.10.1, 4.11.1, 4.13.10B, 6.20.7, 9.15.1, 9.24.3A, the Glossary and Appendix 9 (replaced).	Wholesale Electricity Market Amendment (Miscellaneous Amendments No. 1) Rules 2021, Schedule A.
1 August 2021	Minister amended clause 4.8A.7 (new).	Wholesale Electricity Market Amendment (Miscellaneous Amendments No. 1) Rules 2021, Schedule B.
1 October 2021	Minister amended clauses 2.31.13, 2.34.7, 2.34.14, 4.5.13, 4.5.14A, 4.5.14B, 4.5.14C, 4.5.14D, 4.5.14E, 4.5.14F, 4.25.1, 4.25.2, 4.25.3B, 4.25.4, 4.25.4B, 4.25.4CA, 4.25.4E, 4.25.4G (new), 4.25.4H (new), 4.25.4I (new), 4.25.9, 4.25A.5, 4.26.1, 4.28.1, 4.28.2, 4.28.4, 4.29.3, heading to section 6.11A, clauses 6.11A.1, 6.11A.2, 6.11A.4, 6.12.1, 6.17.6, 6.17.6B, 6.17.6C, 6.17.6D, 6.17.6E, 6.17.6F, 6.17.7, 6.21.2, 7.6.1C, 7.6.1E, 7.6.1H, 7.6.10, 7.7.4A, 9.4.1, 9.4.2, 9.4.4, 9.4.5, 9.4.9, 9.4.10, 9.4.12, 9.4.13, 9.4.14, 9.4.15, 9.4.16, 9.4.17, 9.5.1, 9.5.2, 9.7.1A, 9.7.1B, 9.8.1, 10.5.1, the Glossary, Appendix 1 and Appendix 5.	Wholesale Electricity Market Amendment (Reserve Capacity Pricing Reforms) Rules 2019 (Part 2).
1 October 2021	Minister amended clauses 2.31.13, 4.25.2, 4.25.4CA, 9.4.10, 9.4.15 and 9.4.17.	Wholesale Electricity Market Amendment (Tranche 1 Amendments) Rules 2020, Schedule C.
1 October 2021	Minister amended clauses 2.35.4 and 2.36A.5.	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule C (in accordance with notice in Gazette 2021/96).
1 October 2021	Minister amended heading before clause 2.34A.12I (new), clauses 2.34A.12I (new), 2.34A.12J (new), heading before clause 2.34A.13 (new), clause 2.34A.13 (new), heading before section 7.13A (new), section 7.13A (new) and the Glossary.	Wholesale Electricity Market Amendment (Miscellaneous Amendments No. 1) Rules 2021, Schedule C.
1 October 2021	Minister amended clauses 2.36.7, 2.36A.6 (new), section 4.1 (replaced) and clause 4.4A.2.	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule C (in accordance with notice in Gazette 2021/166).
1 October 2021	Minister amended clause 1.7.3A, heading to section 1.17A, clauses 1.17A.1, 1.19A.2, 1.36B.2A (new), 1.36B.6, sections 1.51 (new), 1.52 (new), clauses 2.3.2, 2.4.3, 2.4.3B (new), 2.4.3C (new), 2.4.3D (new), 2.4.3E (new), 2.4.4, 2.5.1D (new), 2.5.7, 2.5.11, 2.6.1, 2.7.2, 2.7.7, 2.7.8, 2.8.14 (new), 2.9.2D, 2.10.2A, 2.10.9, 2.10.10, 2.10.13, 2.11.2, 2.16.5, 2.16.9D, 2.16.9FA, 2.16.14, 2.24.1, 2.25.1A, 2.25.4, 2.32.7A, 2.34A.6, 2.34A.8, 2.34A.11, 3.13.3A, 3.13.3B, 3.13.3C, 4.4.1, 4.4A.1, 4.8.3, 4.9.3, 4.9.5, 4.9.9, 4.10.2, 4.11.1, 4.11.3, 4.11.3BA, 4.11.6, 4.16.6, 4.16.7, 4.16.8, 6.20.9, 6.20.9A, 10.2.2, 10.2.3, the Glossary, Appendix 9 and Appendix 12.	Wholesale Electricity Market Amendment (Miscellaneous Amendments No. 2) Rules 2021, Schedule A.
30 October 2021	Minister amended clause 2.22A.2B (new).	Wholesale Electricity Market Amendment (Transitional Provisions) Rules 2021.
1 November 2021	Minister amended clause 4.9.10 and section 4.13B (new).	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule C (in accordance with notice in Gazette 2021/96).
1 November 2021	Minister amended clauses 4.3.1, 4.4.1, section 4.4B (new), clauses 4.5.2, 4.5.3A, 4.5.9, 4.5.10, 4.5.13, 4.6.1, 4.6.2, 4.6.3, 4.27.2, 4.27.3, 4.27.4, 4.27.4A, 4.27.10, 4.27.11C, section 4.28C (replaced),	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule C (in accordance with notice in Gazette 2021/166).
1 November 2021	Minister amended section 1.53 (new), clauses 4.5.2, 4.9.10 and 4.28C.8.	Wholesale Electricity Market Amendment (Miscellaneous Amendments No. 2) Rules 2021, Schedule B.
1 December 2021	Minister amended clauses 2.29.12 and 4.8A.3.	Wholesale Electricity Market Amendment (Miscellaneous Amendments No. 2) Rules 2021, Schedule C.
18 December 2021	Minister amended clause 2.1A.2 and the Glossary.	Wholesale Electricity Market Amendment (Tranches 2 and 3 Amendments) Rules 2020, Schedule C (in accordance with notice in Gazette published on 17 December 2021.
18 December 2021	Minister amended section 1.20 (deleted), 1.20A (deleted), clauses 1.33.1, 1.36.6, 1.36.7 (new), 1.43.6, 1.43.7 (new), section 1.43A (new), 1.48A (new), clauses 2.1A.2, 2.2A.1, 2.9.2F (new), 2.22A.1, 2.22A.2, 2.22A.2A, 2.22A.2B, 2.22A.3, 2.22A.4, 2.22A.5, 2.22A.6, 2.22A.7, 2.22A.8, 2.22A.9, 2.22A.10, 2.22A.11, 2.22A.12, 2.22A.13, 2,22A,13A (new), 2.22A.14, 2.22A.15 (new), 2.22A.16 (new), 2.22A.17 (new), 2.24.2, 2.24.3, 2.33.1, 3A.13.2A (new), 4.1.23A, 4.1.23B, 4.1.24, 4.2.7, 4.10.3, 4.10.3A, 4.11.3B, 4.11.3BA and the Glossary.	Wholesale Electricity Market Amendment (Tranche 5 Amendments) Rules 2021, Schedule A.

[1] A Facility may satisfy its fuel obligations using a combination of primary and alternative fuels.

[2] See clause 4.26.1 in relation to the refund payable where a Market Participant holding Capacity Credits associated with a Facility fails to comply with the Reserve Capacity Obligations for the Facility.

[3] See section 4.13A in relation to Reserve Capacity Security for Demand Side Programmes.

[4] On this occasion, the MWh number does not get divided by 2, because measurement is across a full hour, ie. 2 Trading Intervals.

[5] For both proportional and integral control actions. Note that one per unit excitation voltage is that field voltage required to produce nominal voltage on the air gap line of the Generating Unit open circuit characteristic (refer IEEE Standard 115-1983 - Test Procedures for Synchronous Machines).