Wholesale Electricity Market Rules - Amending Rules (No. 1 of 2005) (WA)
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WESTERN 4193 AUSTRALIAN GOVERNMENT
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PERTH, FRIDAY, 9 SEPTEMBER 2005 No. 171 SPECIAL PUBLISHED BY AUTHORITY JOHN A. STRIJK, GOVERNMENT PRINTER AT 3.45 PM
© STATE OF WESTERN AUSTRALIA
ELECTRICITY INDUSTRY ACT 2004
_________
ELECTRICITY INDUSTRY
(WHOLESALE ELECTRICITY
MARKET) REGULATIONS 2004
———————————
WHOLESALE ELECTRICITY MARKET RULES
_________
AMENDING RULES
4194 GOVERNMENT GAZETTE, WA 9 September 2005
9 September 2005 GOVERNMENT GAZETTE, WA 4195 ELECTRICITY INDUSTRY ACT 2004
ELECTRICITY INDUSTRY (WHOLESALE ELECTRICITY MARKET) REGULATIONS 2004
WHOLESALE ELECTRICITY MARKET RULES
AMENDING RULES
I, Alan Carpenter, Minister for Energy for the State of Western Australia, under regulation 6(2) of the Electricity Industry (Wholesale Electricity Market) Regulations 2004 hereby make the amending rules contained in this document.
These amending rules are to come into force on the date on which they are published in the
Government Gazette.Dated at Perth this day 26th of August 2005.
ALAN CARPENTER MLA, Minister for Energy.
————
(1) To replace the table following the comment box after clause 1.8.6 with the following table
(noting format changes).
Chapter Date Clause 1—Introduction 5 Oct 2004 Entire Chapter 2—Administration
4 Jan 2005
2.1, 2.2, 2.12 2.17 to 2.23 2.28 to 2.34
1 Jul 2006 Entire Chapter
3—Power System Security and Reliability 1 Jul 2006 Entire Chapter 4—Reserve Capacity Rules 5 Oct 2004 Entire Chapter 5—Network Control Service Procurement 1 Jul 2006 Entire Chapter 6—The Energy Market 1 Jul 2006 Entire Chapter 7—Dispatch 1 Jul 2006 Entire Chapter 8—Wholesale Market Metering 1 Jul 2006 Entire Chapter 9—Settlement 1 Jul 2006 Entire Chapter 10—Release of Market Information 4 Jan 2005 Parts of Chapter 1 Jul 2006 Entire Chapter 11—Glossary 5 Oct 2004 Entire Chapter 2. Market Rule 2.8 amended
(1) Delete the existing clause 2.18.13(g) and replace it with the following—
(g) clauses 10.1.1, 10.1.2, 10.2.1, 10.3 and 10.4.
3. Market Rule 2.13 amended
(1) Delete the comment box after clause 2.13.9 (but before 2.13.9(a)).
(2) Delete clause 2.13.9(d) and replace it with the following—
(d) clauses 3.6.5 and 3.6.6B;
(3) Delete clause 2.13.9(e) and replace it with the following— (e) clauses 3.16.4, 3.16.7 and 3.16.8A;
(4) Insert new clause 2.13.9(gA) and associated comment box after clause 2.13.9(g)— (gA) clauses 3.21A.2, 3.21A.12, and 3.21A.13;
Rule Participants must seek approval of Commissioning Tests and comply with their approved test plans.
(5) Insert a new clause 2.13.9(hA) and comment box after the comment box following clause
2.13.9(h)—(hA) clause 7.5.5;
Market Participants can only declare a change of fuel in specified situations.
(6) Delete clause 2.13.9(i) and replace it with the following— (i) clause 7.7.6(b);
(7) Delete clause 2.13.9(j) and replace it with the following— (j) clauses 7.10.1, 7.10.3, 7.10.6 and 7.10.6A; and
4. Market Rule 2.16 amended
(1) To amend a clause and to correct a typographical error, delete two existing clauses both
referred to as 2.16.2(d) and replace them with the following—
(d) Balancing Data prices and other Standing Data prices used in Balancing;
4196 GOVERNMENT GAZETTE, WA 9 September 2005 (dA) all Reserve Capacity Auction offers;
(2) Delete the existing clause 2.16.2(g) and insert “2.16.2(g) [Blank]” instead. (3) Insert new clauses for 2.16.2 as follows— (gA) all Fuel Declarations;
(gB) all Availability Declarations;
(gC) all Ancillary Service Declarations;
(4) Delete the text in clause 2.16.2(n) and insert “2.16.2(n) [Blank]” instead. (5) Insert the following new clause 2.16.4(cA)— (cA) any consistent or significant variations between the Fuel Declarations, Availability Declarations, and Ancillary Service Declarations for, and the actual operation of, a Market Participant facility in real-time;
(6) Delete the existing comment box for clause 2.16.7 and replace it with the following comment
box instead—
Note that under clauses 2.16.6 and 2.16.14, the ERA can only collect and use this data in
carrying out its functions under this clause 2.16—i.e. in the case of the above data, primarily
for market power assessment. Western Power is not commercially accountable to the ERA.(7) Delete the existing clause 2.16.8 and insert the following instead— 2.16.8. Rule Participants may notify the IMO or the Economic Regulation Authority of behaviour that they consider reduces the effectiveness of the market, including behaviour related to market power, and the Economic Regulation Authority, with the assistance of the IMO, must investigate the behaviour identified in each relevant notification. (8) Delete the existing clause 2.16.9(b)(i) replace it with the following— i. prices in STEM Submissions, including Standing STEM Submissions, used in forming STEM Bids and STEM Offers that do not reflect the reasonable expectation of the short run marginal cost of generating the relevant electricity (including a reasonable allowance for profit after allowing for revenue provided by payments for Reserve Capacity);
(9) Delete the existing clause 2.16.9(b)(ii) and insert “2.16.9(b)(ii) [Blank]” instead. (10) Insert new clauses for 2.16.9(b) as follows— iii. Balancing Data price changes, and changes in other Standing Data prices used in Balancing, that cannot be justified by an underlying change in cost;
iv. Availability Declarations that may not reflect the reasonable expectation of a facility’s availability, beyond outages of which System Management has been notified;
v. Ancillary Service Declarations that may not reflect the reasonable expectation of the ancillary services to be provided by a facility; and
vi. Fuel Declarations that may not reflect the reasonable expectation of the fuel that a facility will be run on in real-time.
(11) Insert new clauses, 2.16.9A to 2.16.9J, as follows— 2.16.9A. The IMO must assist the monitoring activities identified in clause 2.16.9(b)(i) by examining prices in STEM Submissions, including Standing STEM Submissions, used in forming STEM Bids and STEM Offers against information collected from Rule Participants in accordance with clauses 2.16.6 and 2.16.7.
2.16.9B. Where the IMO concludes that prices in STEM Submissions may not reflect the reasonable expectation of the short run marginal cost of generating the relevant electricity (including a reasonable allowance for profit after allowing for revenue provided by payments for Reserve Capacity) and the IMO considers that the behaviour relates to market power the IMO must—
(a)
as soon as practicable, request an explanation from the Market Participant which has made the relevant STEM Submission; and
(b)
by 4:00 PM on the Scheduling Day to which the Submission relates, advise the Economic Regulation Authority of its conclusions. The IMO advice must outline the reasons for the IMO’s conclusions.
2.16.9C. The Market Participant must submit the explanation requested under clause 2.16.9B
within 2 Business Days from receiving the request.
2.16.9D. The IMO must publish the explanation submitted under clause 2.16.9C on the Market
Web Site as soon as practicable.
2.16.9E. Where the Economic Regulation Authority receives an advice from the IMO under clause 2.16.9B(b) or receives a notification from a Rule Participant under clause 2.16.8, the Economic Regulation Authority must investigate the identified behaviour. Without limitation, for this purpose the Economic Regulation Authority must examine the IMO advice, any explanation received under clause 2.16.9C, any data already in the possession of the Economic Regulation Authority or additional data it requests from the relevant Market Participant under clause 2.16.6 to assist in the investigations.
9 September 2005 GOVERNMENT GAZETTE, WA 4197 2.16.9F. The Economic Regulation Authority must publish the results of its investigations within 20 Business Days from receiving the IMO advice under clause 2.16.9B(b) or from receiving a notification from a Rule Participant under clause 2.16.8.
2.16.9G. Where the Economic Regulation Authority determines that prices in the STEM Submission, subject to the investigation, did not reflect the reasonable expectation of the short run marginal cost of generating the relevant electricity (including a reasonable allowance for profit after allowing for revenue provided by payments for Reserve Capacity), the Economic Regulation Authority must request that the IMO refers the matter to the Energy Review Board.
2.16.9H. Where the IMO receives a request under clause 2.16.9G the IMO must refer the relevant matter to the Energy Review Board requesting that a civil penalty be imposed on the relevant Market Participant.
2.16.9I. Civil penalties imposed as a result of clause 2.16.9H must apply to each single occasion where a Market Participant was determined to have submitted prices that do not reflect the reasonable expectation of the short run marginal cost of generating the relevant electricity (including a reasonable allowance for profit after allowing for revenue provided by payments for Reserve Capacity). For the avoidance of doubt, “each single occasion” in this clause relates to each Trading Interval.
This will be a category C civil penalty provision.
2.16.9J. Where a civil penalty is imposed in accordance with clause 2.16.9I, the civil penalty amount should be distributed amongst all Market Customers in proportion to their Market Fees calculated over the previous full 12 months, or part thereof if Market Commencement was less than 12 months prior to the date the civil penalty is received.
5. Market Rule 2.17 amended
(1) Delete the comment box after clause 2.17.1 (but before 2.17.1(a)).
(2) Amend clause 2.17.1(b) by adding a semi-colon to the end of the clause.
(3) Insert a new clause 2.17.1(dA) and comment box after the comment box following clause
2.17.1(d) as follows—(dA) clauses 2.30A.2 and 2.30A.5;
Market Participant applies to the IMO for exemption from funding Spinning Reserve, or IMO decides to change the facilities status in this regard.
(4) Insert a new clause 2.17.1(dB) and comment box after the comment box following clause
2.17.1(dA) as follows—(dB) clauses 2.30B.4. 2.30B.6 and 2.30B.7;
Market Participant applies to the IMO to be treated as an Intermittent Load, or the IMO decides to cease treating a load as an Intermittent Load.
(5) Amend clause 2.17.1(f) by adding a semi-colon to the end of the clause. (6) Amend clause 2.17.1(g) by adding a semi-colon to the end of the clause. (7) Amend clause 2.17.1(j) by adding a semi-colon to the end of the clause. (8) Delete 2.17.1(k) and replace it with the following clause. (k) clause 4.16.1;
(9) Amend clause 2.17.1(l) by replacing “clauses” with “clause” and adding a semi-colon to the end
of the clause.—(10) Delete clause 2.17.1(m) and replace it with the following clause. (m) clauses 4.28.7 and 4.28.11;
(11) Amend clause 2.17.1(o) by adding “and” to the end of the clause after the semi-colon. (12) Amend clause 2.17.1(p) by adding full-stop to the end of the clause. 6. Market Rule 2.26 amended (1) Delete the existing clause 2.26.3(e) and replace it with the following—
(e) historical STEM Bids and STEM Offers and the proportion of STEM Bids and Offers with prices equal to the Energy Price Limits; 7. Market Rule 2.28 amended
(1) Delete the existing clauses 2.28.6, 2.28.7, 2.28.8 and replace them with the following—
2.28.6. Subject to clause 2.28.16, a person who owns, controls or operates a generation system which has a rated capacity that equals or exceeds 10 MW and is electrically connected to a transmission system or distribution system which forms part of the South West Interconnected System, or is electrically connected to that system, must register as a Rule Participant in the Market Generator class.
2.28.7. A person that owns, controls or operates a generation system which has a rated capacity of less than 10 MW, but which equals or exceeds 0.005 MW, and is electrically connected to a transmission system or distribution system which forms part of the South West Interconnected System, or is electrically connected to that system, may register as a Rule Participant in the Market Generator class.
4198 GOVERNMENT GAZETTE, WA 9 September 2005 2.28.8. A person who intends to own, control or operate a generation system which has a rated capacity that equals or exceeds 0.005 MW and is or will be electrically connected to a transmission system or distribution system which forms part of the South West Interconnected System, or is electrically connected to that system, may register as a Rule Participant in the Market Generator class.
(2) Delete the existing clauses 2.28.16 and replace it with the following— 2.28.16. The IMO may determine that a person is exempted from the requirement to register in accordance with clauses 2.28.2, 2.28.6, 2.28.10 or 2.28.13. An exemption may be given subject to any conditions the IMO considers appropriate.
8. Market Rule 2.29 amended
(1) Amend clause 2.29.4(a) by deleting “0.2 MW” and replacing it with “0.005 MW”.
(2) Amend clause 2.29.4(b) by deleting “registered as a Non Scheduled Generator” and replacing it
with “an Intermittent Generator”.(3) Delete the existing clauses 2.29.4(c) and 2.29.4(d) and replace them with the following—
(c)
subject to clause 2.29.6, may register that generation system as a Scheduled Generator where the generation system is not an Intermittent Generator and has a rated capacity that equals or exceeds 0.2 MW but which is less than 10 MW; and
(d)
must register that generation system as a Non-Scheduled Generator where the generation system has a rated capacity that equals or exceeds 0.005 MW and where the generation system is not otherwise required to be registered in accordance with (a) or (b) and where the option to register in accordance with (c), if applicable, is not exercised.
(4) Insert new clauses 2.29.10 and 2.29.11 as follows— 2.29.10. On request, the IMO must exempt a person from the requirement to register a generating system in accordance with this clause 2.29 if that generating system is identified by that person as supplying an Intermittent Load in accordance with clause 2.30B.2 and that generating system satisfies all the requirements of these Market Rules to serve Intermittent Load.
This exemption is an option that can be taken up by the person responsible for the generating system. However, if the option is taken up, the generating system will not be able to hold Capacity Credits and will not be able to participate in the energy market other than via its impact on the metered load. Thus there are reasons for such persons not to take up the option for this exemption.
2.29.11. With respect to the registration of a generation system to serve Intermittent Load, not
more than one generation system may be registered for each Intermittent Load.
The aim of this clause is to avoid having two or more separate Scheduled Generators without their own meters being recorded by an Intermittent Load meter as it would be impossible to distinguish their output for settlement purposes. However this clause does not restrict several distinct generating units being aggregated as a single “generation system” for the purpose of registration.
9. Market Rule 2.30 amended
(1) Insert a new clause 2.30A as follows—
2.30A Exemption from Funding Spinning Reserve
2.30A.1. When registering an Intermittent Generator as a Non-Scheduled Generator, a Rule Participant, or an applicant for rule participation, may apply to the IMO for that Intermittent Generator to be exempted from funding Spinning Reserve cost.
2.30A.2. Where an application is received in accordance with clause 2.30A.1, the IMO must exempt the Intermittent Generator from funding Spinning Reserve costs where the applicant demonstrates to the satisfaction of the IMO that the shut down of the facility is a gradual process not exceeding a maximum ramp down rate equal to the installed capacity divided by 15MW/minute.
2.30A.3. The IMO must consult with System Management when assessing an application forexemption from funding Spinning Reserve costs.
2.30A.4. If the IMO approves the application for exempting an Intermittent Generator from funding Spinning Reserve costs then that facility must be excluded from the set of applicable facilities described in Appendix 2.
2.30A.5. Where the IMO considers, after consultation with System Management, that a change in the nature of an Intermittent Generator means that it should no longer be exempted from funding Spinning Reserve costs, it must—
(a)
inform the relevant Market Participant of the first Trading Month from which the facility will cease to be exempted; and
(b)
include that facility in the list of applicable facilities described in Appendix 2 from the commencement of that Trading Month.
2.30A.6. The IMO must document the Spinning Reserve costs exemption process in the
Registration Procedure, and—
(a)
applicants for exemption from Spinning Reserve costs must follow that documented Market Procedure; and
9 September 2005 GOVERNMENT GAZETTE, WA 4199
(b)
the IMO and System Management must follow that documented Market Procedure when processing applications for exemption from Spinning Reserve cost funding.
(2) Insert a new clause 2.30B as follows— 2.30B Intermittent Load 2.30B.1. An Intermittent Load is a Load that satisfies the requirements of clause 2.30B.2 and is
recorded in Standing Data as being an Intermittent Load.
2.30B.2. For a Load to be eligible to be an Intermittent Load the following conditions must be
satisfied—
(a) a generation system must exist—
i. which can typically supply the maximum amount of that Load to be treated as Intermittent Load without requiring energy to be withdrawn from a Network;
A “Network” is a registered network. Connection assets etc that are not registered networks do not count.
ii. the output of which is netted off consumption of the Load by the meter registered to that Load; and
iii. which would in the view of the IMO, if it were not serving an Intermittent Load, be eligible to hold an amount of Certified Reserve Capacity, in accordance with clause 2.30B.4, at least sufficient to supply the amount of energy that the generation system is required by (a)(i) to be able to supply while simultaneously being able to satisfy obligations on any Capacity Credits associated with that generation system;
This previous clause, in combination with clause 2.30B.4 means that if a generating system holds Capacity Credits (which requires it to be a registered generator) then the capacity available to serve that Intermittent Load is reduced by the amount of Capacity Credits held.
(b)
the Load shall reasonably be expected to have no net consumption of energy for at least 4320 Trading Intervals in any Capacity Year;
4320 Trading Intervals corresponds to 90 days.
(c) the Market Customer for that Load must have an agreement in place with a Network Operator to allow energy to be supplied to the Load from a Network; and (d) the Load must be an Interruptible Load, Curtailable Load, or a Non-Dispatchable Load.
2.30B.3. The IMO must require that a Market Customer, or applicant to become a Market Customer, applying to register an Intermittent Load provide in regard to the generation system referred to in clause 2.30B.2(a)—
(a)
the maximum capacity in MW, excluding capacity for which Capacity Credits are held, that generating system can be guaranteed to have available to supply Intermittent Load, when it is operated normally at an ambient temperature of 41°C; and
(b) at the option of the applicant,
i. the anticipated reduction, measured in MW, in the maximum capacity described in (a) when the ambient temperature is 45°C;
ii. the method to be used to measure the ambient temperature at the site of the generating system for the purpose of determining Intermittent Load Refunds, where the method specified may be either—
1.
a publicly available daily maximum temperature at a location representative of the conditions at the site of the generating system as reported daily by a meteorological service; or
2.
a daily maximum temperature measured at the site of the generator by the SCADA system operated by System Management.
(Where no method is specified, a temperature of 41°C will be assumed); and
Assuming 41°C will be an attractive approach for generators with capacity that have no significant temperature dependency.
(c) details of primary and any alternative fuels, including details and evidence of both firm and non-firm fuel supplies and the factors that determine restrictions on fuel availability that could prevent the Facility operating at its full capacity;
2.30B.4. The IMO must use the information provided by a Market Customer in accordance with clause 2.30B.3 to assess the additional Certified Reserve Capacity beyond the capacity required to meet Reserve Capacity Obligations on Capacity Credits actually held by the generation system referred to in clause 2.30B.2(a) that the IMO would normally assign to that generation system in accordance with Chapter 4 if—
(a) the Intermittent Load did not exist; and
(b)
the generation system otherwise satisfied all requirements necessary to be treated as a Scheduled Generator entitled to hold Certified Reserve Capacity.
4200 GOVERNMENT GAZETTE, WA 9 September 2005 2.30B.5. A Market Customer, or applicant to become a Market Customer, may apply for a Load to be treated as an Intermittent Load as part of Market Customer registration (for a Non-Dispatchable Load) or Facility Registration (for an Interruptible Load or Curtailable Load).
2.30B.6. The IMO must accept an application for a Load to be an Intermittent Load if the
requirements of clause 2.30B.2 are satisfied.
The process itself by which the IMO does this is via processing registration and standing data changes.
2.30B.7. The IMO may cease to treat a Load as an Intermittent Load and require a Market Participant to modify its Standing Data in accordance with clause 2.34.11 from the commencement of a Trading Month if the IMO considers that the requirements of clause 2.30B.2 are no longer satisfied.
If a Load ceases to be an Intermittent Load then its requirement to fund Reserve Capacity will increase from the next Trading Month (as implied by the equations of Appendix 5).
2.30B.8. The IMO may consult with System Management in determining whether or not to
accept, or continue to accept, a Load as satisfying the requirements of clause 2.30B.2.
2.30B.9. Where an Intermittent Load is transferred from one Market Customer to another all obligations to pay Intermittent Load Refunds calculated after the date of transfer in regard to that Intermittent Load, including those Intermittent Load Refunds arising from consumption that occurred prior to the date of transfer are to be automatically transferred.
2.30B.10. For the purpose of defining Metered Schedules associated with the meter measuring an
Intermittent Load, the following methodology is to apply—
(a) Define for each Trading Interval—
i. NMQ to be the net metered energy measured by the meter where a positive amount indicates supply and a negative amount indicates consumption;
ii. NS to be the net supply (supply less consumption) measured by the Intermittent Load meter which corresponds to supply and consumption, excluding consumption by Intermittent Loads, by Market Customers and Market Generators which are separately metered for the purpose of settlement under these Market Rules. This may have a positive or negative value;
iii. NL to be the maximum possible consumption behind that meter due to consumption which is not Intermittent Load but which is measured only by the meter which also measures the Intermittent Load. This has a negative value;
iv. MIL to be the maximum allowed Intermittent Load at the meter. This has a negative value;
v. MSG to be the maximum energy output from a registered generating system measured only by the Intermittent Load meter where MSG equals the greater of zero and the maximum energy output of the facility based on Standing Data less the sum of MIL and NL. This has a positive value;
vi. AMQ to be the adjusted meter quantity which equals the sum of NMQ and NS;
(b) if there is no registered generating system the output of which is measured only by the meter which also measures the Intermittent Load then— i. if AMQ is less than or equal to MIL then—
1. for the purpose of defining its Metered Schedule the metered quantity associated with the Intermittent Load is MIL; 2. for the purpose of defining its Metered Schedule the metered quantity associated with non-Intermittent Loads only measured by the Intermittent Load meter is AMQ –MIL; ii. if AMQ is greater than MIL then—
1.
for the purpose of defining its Metered Schedule the metered quantity associated with the Intermittent Load is AMQ;
2.
for the purpose of defining its Metered Schedule the metered quantity associated with non-Intermittent Loads only measured by the Intermittent Load meter is zero;
(c) if there is a registered generating system measured only by the meter that also measures the Intermittent Load then: i. if AMQ is less than or equal to MIL then—
1.
for the purpose of defining its Metered Schedule the metered quantity associated with the Intermittent Load is MIL;
2.
for the purpose of defining its Metered Schedule the metered quantity associated with non-Intermittent Loads measured only by the meter that also measures the Intermittent Load is AMQ –MIL;
9 September 2005 GOVERNMENT GAZETTE, WA 4201 3. for the purpose of defining its Metered Schedule the metered quantity associated with the Scheduled Generator measured only by the meter that also measures the Intermittent Load is zero;
ii. if AMQ is greater than MIL but less than or equal to zero then—
1. for the purpose of defining its Metered Schedule the metered quantity associated with the Intermittent Load is AMQ; 2. for the purpose of defining its Metered Schedule the metered quantity associated with non-Intermittent Loads measured only by the meter that also measures the Intermittent Load is zero; 3. for the purpose of defining its Metered Schedule the metered quantity associated with the Scheduled Generator measured only by the meter that also measures the Intermittent Load is zero; iii. if AMQ is greater than zero but less than or equal to MSG then—
1. for the purpose of defining its Metered Schedule the metered quantity associated with the Intermittent Load is zero; 2. for the purpose of defining its Metered Schedule the metered quantity associated with non-Intermittent Loads measured only by the meter that also measures the Intermittent Load is zero; 3. for the purpose of defining its Metered Schedule the metered quantity associated with the Scheduled Generator measured only by the meter that also measures the Intermittent Load is AMQ; iv. if AMQ is greater than MSG then—
1.
for the purpose of defining its Metered Schedule the metered quantity associated with the Intermittent Load is AMQ—MSG;
2.
for the purpose of defining its Metered Schedule the metered quantity associated with non-Intermittent Loads measured only by the meter that also measures the Intermittent Load is zero;
3.
for the purpose of defining its Metered Schedule the metered quantity associated with the Scheduled Generator measured only by the meter that also measures the Intermittent Load is MSG.
Suppose the separately metered supply behind the Intermittent Load meter is 5 MWh and the purposes the Intermittent Load is +7, non-Intermittent Load is 0, the Scheduled Generator has an output of 5. Note that if there were no Scheduled Generator (only unregistered generators) then Intermittent Load would be 12 in this case. This would be settled at MCAP rather than at the prices applicable to a Scheduled Generator.
separately metered consumption is -2 MWh. This means NS=5– ( -2) = +7 MWh.
If the Intermittent Load has a maximum consumption of 15 MWh, normal load beyond the
Intermittent Load has a maximum consumption of 20 MWh and there is a scheduled generator
with the ability to generate 40 MWh then we have MIL=-15, NL=–20 and MSG = Max(0, 40 -
15—20) = +5.
If the meter reading is NMQ =—27 then AMQ = -20 and (c)(i) implies that for settlement
purposes the Intermittent Load is -15, the non-Intermittent Load is -5 and the Scheduled
Generator has an output of 0. Because there are penalties on exceeding Intermittent Load it is
necessary to assume that meter load is Intermittent Load before allocating it to normal load.
If the meter reading is NMQ =—17 then AMQ = -10 and (c)(ii) implies that for settlement
purposes the Intermittent Load is -10, the non-Intermittent Load is 0 and the Scheduled
Generator has an output of 0.
If the meter reading is NMQ = -3 then AMQ = +4 and (c)(iii) implies that for settlement
purposes the Intermittent Load is 0, the non-Intermittent Load is 0 , and the Scheduled
Generator has an output of 4.
(3) Insert a new clause 2.30C as follows— 2.30C. Rule Commencement and Registration Data
The purpose of this section is to provide some over-arching principles for the registration
process to describe how changes in registration requirements, or changes in how participants
want to be registered, are handled.2.30C.1. The IMO must not require that an applicant for Rule Participant registration or Facility Registration provide information on any application form, or evidence to support that application form, pertaining to registration if the applicable Market Rules requiring that information to be provided have not commenced.
2.30C.2. Prior to the Appointed Day, the IMO may delay the requirement for a person to pay fees related to Rule Participant registration or Facility Registration until the Appointed Day.
The Appointed Day is a date to be announced by the Minister on which the regulation requirements to be registered take effect.
4202 GOVERNMENT GAZETTE, WA 9 September 2005
2.30C.3. Where a rule is to commence after the Appointed Day which requires additional or
revised Standing Data to be maintained, the IMO must notify Rule Participants of—
(a) the additional or changed Standing Data required, and
(b) the time and date by which the additional or changed Standing Data must be provided and accepted; where the IMO must set the time and date in (b) to allow Market Participants sufficient time to provide the requested data and for it to be accepted prior to the rule commencing.
2.30C.4. Where the IMO issues a notice in accordance with clause 2.30C.3, Rule Participants must provide the additional Standing Data requested by the time and date specified in that notice.
Note that any participant that fails to satisfy this clause will be in breach of the market rules and could be fined or, in the extreme case, could be suspended by the Energy Review Board.
10. Market Rule 2.31 amended
(1) Delete the existing clause 2.31.4 and replace with the following clause and comment box—
2.31.4. Subject to clause 2.30C.1, the IMO may, at its discretion, require that an applicant provide information that is missing from the relevant application form, or is inadequately specified. The date at which the requested information is submitted to the IMO in full is to become the date of receipt of the application for the purpose of clause 2.31.3.
Clause 2.30C.1 states that the IMO must ignore information required by clauses that are not yet active because the IMO may not have a process in place for dealing with that information and may not have defined precisely the form of data to be provided.
(2) Delete the existing clause 2.31.10(b) and replace it with the following clause—
(b)
within 20 Business Days after the date of notification of receipt in the case of an application for Rule Participant registration in the Market Generator or Market Customer class; and
(3) Delete the existing clause 2.31.13(a) and 2.31.13(b) insert the following instead—
(a) subject to clause 2.30C.1, the application form, when read together with any information received after a request under clause 2.31.4, is incomplete or provides insufficient detail; (b) subject to clause 2.30C.1, required supporting evidence is insufficient or not provided; 11. Market Rule 2.33 amended
(1) Delete the existing clause 2.33.1(g) and insert “2.33.1(g) [Blank]” instead.
12. Market Rule 2.34 amended
(1) Insert new clauses for 2.34 in their appropriate order as follows—
2.34.2A. A Rule Participant must, as soon as practical, seek to have its Standing Data revised, other than Standing Data described in clause 2.34.2B, if it becomes aware that its Standing Data is currently inaccurate or not in compliance with the requirements of these Market Rules, or will become inaccurate or will cease to be in compliance with the requirements of these Market Rules within the next 5 Business Days.
2.34.2B. A Rule Participant may seek to have the following Standing Data changed at anytime—
(a) price or payment related data;
(b)
whether a Load not currently treated as an Intermittent Load is treated as an Intermittent Load, provided that the Rule Participant is confident that the Load satisfies the requirements of clause 2.30B.2 and provided that the Rule Participant complies with clause 4.28.8A; and
(c)
whether a Load currently treated as an Intermittent Load is to cease to be treated as an Intermittent Load.
(2) Delete the existing opening sentence for clause 2.34.3 and insert instead the following— 2.34.3. A Rule Participant that seeks to change its Standing Data, other than Standing Data changed in accordance with the processes set out in clauses 6.3C or 6.5B, must notify the IMO of— (3) Amend clause 2.34.4 by inserting “resulting from a Planned Outage, Forced Outage or
Consequential Outage.” after “a Registered Facility”.(4) Delete the comment box for clause 2.34.4. (5) Amend clause 2.34.6 by inserting “described in clause 2.34.3.” after “Standing Data”. (6) Amend clause 2.34.8 by deleting the existing opening sentence and replacing it with the
following—2.34.8. Other than Standing Data changed in accordance with the processes set out in clauses 6.3C or 6.5B, the IMO must notify the Rule Participant of its acceptance or rejection of the change in Standing Data as soon as practical, and no later than three Business Days after the later of:
9 September 2005 GOVERNMENT GAZETTE, WA 4203
(7) Delete the existing clause 2.34.14(a) and comment box and replace them with the following—
(a)
8:00 AM on the Scheduling Day following the IMO’s acceptance of the revised Standing Data in the case of—
i. Standing STEM Submissions;
ii. commitment and decommitment cost data and Standing Balancing Data; and
iii. Standing Data changes stemming from acceptance of an application under clause 6.6.9;
with the exception that the previous Standing Data remains current for the purpose of settling the Trading Day that commences at the same time as that Scheduling Day; and
Clause 6.6.9 refers to applications to have a non-dual fuelled generator deemed dual-fuelled for the energy market. The condition about settlement of the Trading Day that commences at the same time as that Scheduling Day is required because the old Standing Data will still apply for the settlement of that Trading Day as that old data was used in scheduling that day.
13. Market Rule 2.39 amended
(1) Amend clause 2.39.2 by deleting “[0.84]”and replacing it with “0.87”.
(2) Delete the existing comment box after clause 2.39.2 and replace it with the following—
This initial prudential factor has been determined as one minus the ratio of the maximum
number of days required for a participant to be suspended following a margin call which leads
to a “suspension even” (as described in clause 9.23) divided by the maximum number of days
between the start of a Trading Month and the non-STEM settlement statement being issued
for that month. A margin call requires a response in 1 business day, a market participant can
be given up to 5 business days (7 days assumed) to respond to a suspension event, and 1 day
might elapse in actually suspending the participant. Hence the numerator is about 9 days. The
period from the first day of a Trading Month until that month is settled is about 69 days.
Hence the prudential factor is 1- (9 /69) = 0.87. This result has been tested under more detailed
models and is quite robust.(3) Insert a new clause 2.39.3 as follows— 2.39.3. Any change to the prudential factor described in clause 2.39.2 must be set on the basis that the product of the prudential factor and a Market Participant’s Credit Limit will result in a Trading Limit which is sufficiently less than the Market Participant’s Credit Limit, such that if the Market Participant fails to comply with a Margin Call Notice it would be expected that default event and Suspension Event procedures could be applied to the Market Participant before the Outstanding Amounts of the Market Participant exceed the Credit Limit, on the basis of trading, price and volatility assumptions used in calculating the Credit Limit for that Market Participant.
14. Market Rule 2.44 amended (1) Between clause 2.43.1 and clause 2.44 add the heading—
“Emergency Powers”15. Market Rule 3.6 amended (1) Delete the existing clause 3.6.6 and replace it with the following clauses— 3.6.6. System Management must make plans for manual load shedding, and must inform Network Operators of these plans.
3.6.6A. System Management may issue manual disconnection directions to Network Operators, where such directions must be in accordance with System Management’s load shedding plans.
3.6.6B. Network Operators must comply with any manual disconnection directions received from System Management.
16. Market Rule 3.9 amended (1) In clause 3.9.5 replace the “three” with “two” after “measured over”. 17. Market Rule 3.10 amended (1) Amend clause 3.10.1(a)(ii) by deleting “; and” after “a thirty minute rolling average” and
inserting a full stop “.” instead.(2) Delete the existing clause 3.10.1(b) and its associated comment box and insert “3.10.1(b)
[Blank]” instead.(3) Delete the existing clause 3.10.2(a) and replace it with the following—
(a) the level must be sufficient to cover the greater of— i. 70% of the total output, including parasitic load, of the generation unit synchronised to the SWIS with the highest total output at that time; and
ii. the maximum load ramp expected over a period of 15 minutes;
(4) Delete the existing comment box after clause 3.10.2(b) and replace it with—
The Load Following and Load Ramp requirements will be met only by generators. The
remaining part of the Spinning Reserve requirement, if any, can be met by interruptible load
as well.
4204 GOVERNMENT GAZETTE, WA 9 September 2005 18. Market Rule 3.13 amended
(1) Delete the existing clause 3.13.1and insert the following instead—
3.13.1. The total payments by the IMO to the System Management business unit of Western Power for Ancillary Services in accordance with Chapter 9 comprise—
(a) [Blank]
(aA) for Load Following Service for each Trading Month—
i. a capacity payment Capacity_LF calculated as;
1. the Monthly Reserve Capacity Price in that Trading Month; 2. multiplied by LFR, the capacity necessary to meet the Ancillary Service Requirement for Load Following in that month; ii. an availability payment Availiability_Cost_LF(m) calculated in accordance with clause 9.9.2(d) for that Trading Month;
Clause 9.9.2(d) determines the share of the total Availability Cost for Ancillary Services associated with Load Following.
(b) an amount Availability_Cost_R(m) for Spinning Reserve and Fifteen Minute Reserve for each Trading Month, which is calculated in accordance with clause 9.9.2(c) for that Trading Month; and (c) Cost_LRD, the monthly amount for Load Rejection Reserve, System Restart, and Dispatch Support services, determined in accordance with System Management’s budget process described in clause 2.23.
19. Market Rule 3.14 amended
(1) Amend clause 3.14.1(b)(i) by inserting “and” after the semi colon.
(2) Amend clause 3.14.1(b)(ii) by deleting the semi colon after “Trading Month” and replacing it
with a full stop “.”.(3) Delete clause 3.14.1(b)(iii) and comment box following the clause and insert “3.14.1(b)(iii)
[Blank]” instead.(4) Delete the existing clause 3.14.2 and replace it with the following— 3.14.2. Market Participant p’s share of the Spinning Reserve and Fifteen Minute Reserve services payment costs in each Trading Interval t is Reserve_Share(p,t) which equals the amount determined in Appendix 2. 20. Market Rule 3.16 amended (1) Replace clause 3.16.8 with the following two clauses— 3.16.8. System Management must review the information provided by Rule Participants, and where necessary, seek additional information or clarifications. 3.16.8A. Rule Participants must provide any additional information or clarifications requested by System Management, within the time frame specified in the Power System Operating Procedure.
(2) Amend clause 3.16.9(h) by deleting “and” after the semi colon. (3) Amend clause 3.16.9(i) by deleting the full stop “.” at the end of the clause and replace it with “;
and”.(4) Insert a new clause 3.16.9(j) as follows—
(j) for each approved Commissioning Test the Facility to be tested and the dates and times during which the Commissioning Test will be conducted. 21. Market Rule 3.17 amended
(1) Amend clause 3.17.9(h) by deleting “and” after the semi colon.
(2) Amend clause 3.17.9(i) by deleting the full stop “.” at the end of the clause and replace it with “;
and”.(3) Insert a new clause 3.17.9(j) as follows—
(j) for each approved Commissioning Test the Facility to be tested and the dates and times during which the Commissioning Test will be conducted. 22. Market Rule 3.18 amended
(1) Insert a new clause 3.18.2(c)(iiA) as follows—
iiA. all generation systems to which clause 2.30B.2(a) relates;
(2) Amend clause 3.18.5(a) by inserting after “must” the following “, subject to clause 3.18.5A,” to
read as follows—3.18.5. Market Participants and Network Operators—
(a)
must, subject to clause 3.18.5A, submit to System Management details of a proposed outage plan (“Outage Plan”) at least one year in advance of the proposed outage, where:
9 September 2005 GOVERNMENT GAZETTE, WA 4205
(3) After 3.18.5(b) insert a following new clause 3.18.5A and comment box as follows— 3.18.5A. Market Participants and Network Operators may submit an Outage Plan to which clause 3.18.5(a) relates to System Management less than one year in advance of the proposed outage, but in such instances—
(a)
System Management must give priority to Outage Plans to which clause 3.18.5(a) relate and which were received more than one year in advance of the commencement of the proposed outage;
(b)
System Management must give priority to Outage Plans to which this clause 3.18.5A relates in the order they are received; and
(c)
System Management must give no special priority to Outage Plans to which this clause 3.18.5A relates relative to Outage Plans to which clause 3.18.5(a) does not relate.
The intent of this is that if an outage with duration of more than a week is scheduled more outage B will be accepted while outage A is rejected. The intent of the rules is that to the extent that both outages could be approved without having undue impact on other outages or long term system security, but outages A and B are mutually exclusive, then outage A will be accepted ahead of outage B.
than a year before the event then it will get priority over a similar outage scheduled less than
a year before the event. An outage with a duration of more than a week scheduled less than a
year before the event should be treated with the same priority as any other outage scheduled
less than a year before the event, except that outages lasting more than a week will, to the
extent possible, be approved in the order they are received.
(4) Delete the existing clause 3.18.12 and instead the following instead— 3.18.12. Except to the extent required by the criteria in clause 3.18.11 and to the extent allowed by clause 3.18.5A, in evaluating Outage Plans, System Management must not show bias towards a Market Participant or Network Operator in regard to its Outage Plans. 23. Market Rule 3.19 amended
(1) Replace clauses 3.19.2 and 3.19.3 with the following clauses and comment boxes—
3.19.2. Market Participants and Network Operators may request that System Management approve an outage of a Facility or item of equipment that is not a Scheduled Outage (“Opportunistic Maintenance”) to be carried out during a Trading Day at any time between 6:00 AM and 10:00 AM on the Scheduling Day for that Trading Day. The request must relate to the following Trading Day only and must include all of the information specified in clause 3.18.6, and must specify the Trading Intervals during which the Opportunistic Maintenance will occur.
3.19.3. Subject to clause 3.19.3A, System Management must assess the request for approval of a Scheduled Outage or Opportunistic Maintenance, based on the information available to System Management at the time of the assessment, and applying the criteria set out in clause 3.19.6.3.19.3A. In assessing whether to grant a request for Opportunistic Maintenance, System
Management—
(a)
must not grant permission for Opportunistic Maintenance to begin prior to the first Trading Interval for which Opportunistic Maintenance is requested;
This ensures that Opportunistic Maintenance cannot be requested retrospectively.
(b)
must not approve Opportunistic Maintenance for a facility on two consecutive Trading Days; and
This prevents participants using Opportunistic Maintenance to disguise Forced Outages.
(c) may decline to approve Opportunistic Maintenance for a facility where it considers that the request has been made principally to avoid exposure to Reserve Capacity refunds as described in clause 4.26 rather than to perform maintenance.
Clause (c) gives System Management the power to refuse Opportunistic Maintenance where it is being used to avoid the participant being declared as being in Forced Outage (or otherwise not complying with Reserve Capacity obligations) and where no maintenance is actually expected to be performed.
(2) Insert a new clause 3.19.12(aA) as follows— (aA) Compensation will only be paid where details of the relevant Outage Plan have been submitted to System Management at least one year in advance of the time when the outage would have commenced.
(3) Delete clause 3.19.12(b) and replace it with the following clause—
(b)
Compensation will only be paid for the additional maintenance costs directly incurred by a Market Participant or Network Operator in the deferment or cancellation of the relevant outage.
4206 GOVERNMENT GAZETTE, WA 9 September 2005 24. Market Rule 3.21 amended
(1) Insert a new clause 3.21A and heading as follows—
Commissioning Tests3.21A Commissioning Tests
3.21A.1. A Commissioning Test (“Commissioning Test”) is a test of the ability of a generating
system to operate at different levels of output reliably.
3.21A.2. A Market Participant seeking to conduct a Commissioning Test for a Scheduled Generator or a candidate facility to be registered as a Scheduled Generator must request permission for such trials from System Management in accordance with clause 3.21A.4.
3.21A.3. System Management may only approve a Commissioning Test for new generating systems that are expected to be registered as Scheduled Generators, or for existing Scheduled Generators which have undergone significant maintenance.
3.21A.4. A Market Participant requesting permission for Commissioning Tests must submit to System Management the following information at least 20 Business Days in advance of the start date of the proposed trial—
(a) the name and location of the facility to be tested; (b)
the date and commencement time of all Trading Intervals during which testing will be conducted; and
(c) details of the tests to be conducted, including an indicative test program.
3.21A.5. Commissioning Test plans submitted by a Market Participant must represent the good
faith intention of the Market Participant to conduct such Commissioning Test.
3.21A.6. Where a Market Participant no longer plans to conduct a Commissioning Test it must
inform System Management as soon as practicable.
3.21A.7. System Management must accept a request for a Commissioning Test unless—
(a) inadequate information is provided in the request; or
(b)
the conduct of the test at the proposed time would pose a threat to Power System Security or Power System Reliability.
3.21A.8. System Management must not show bias towards a Market Participant in regard to
scheduling of Commissioning Tests.
3.21A.9 System Management must notify a Market Participant as to whether System Management has approved a Commissioning Test within 10 Business Days of receiving the notification described in clause 3.21A.4.
3.21A.10. Where System Management notifies a Market Participant that—
(a)
a Commissioning Test has not been approved it must provide an explanation for its decision.
(b)
a Commissioning Test has been approved then, subject to clause 3.21A.11, the Market Participant may proceed with that Commissioning Test.
3.21A.11. If having approved a Commissioning Test, System Management becomes aware that—
(a)
the conduct of the test at the proposed time would pose a threat to Power System Security or Power System Reliability, or in the case of a Facility returning to service after extended maintenance the return to service has been delayed, then it may delay the commencement of the Commissioning Test; or
(b)
the Commissioning Test is no longer required then it may revoke its approval of the Commissioning Test,
and must notify the Market Participant conducting the Commissioning Test of such
delay or cancellation.
3.21A.12. In conducting a Commissioning Test a Market Participant must conform to the test
plan approved by System Management.
3.21A.13. If a Market Participant conducting a Commissioning Test cannot conform to the test plan approved by System Management then it must inform System Management as soon as practicable.
3.21A.14. Where a Facility is subject to a Commissioning Test the Dispatch Schedule for that Facility during the period of the Commissioning Test is to reflect the energy produced by the facility.
Note that the previous clause is relevant primarily to IPP generation as Western Power is effectively settled at MCAP on what it produces anyway.
3.21A.15. System Management must document the procedure it follows in scheduling Commissioning Tests in the Power System Operation Procedure and System Management and Market Participants must follow that documented Market Procedure when planning and conducting Commissioning Tests.
25. Market Rule 3.22 amended
(1) Delete the existing clause 3.22.1 and replace it with the following instead—
3.22.1. The IMO must provide the following information to the Settlement System for each
Trading Month—
(a) Capacity_LF as described in clause 3.13.1(aA);
(b) [Blank]
9 September 2005 GOVERNMENT GAZETTE, WA 4207 (c) Margin_Peak as described in clause 2.23.12(d)(i);
(d) Margin_Off-Peak as described in clause 2.23.12(d)(ii);
(e)
Capacity_R_Peak, the requirement for Spinning Reserve for Peak Trading Intervals assumed in forming Margin_Peak;
(f)
Capacity_R_Off-Peak, the requirement for Spinning Reserve for Off-Peak Trading Intervals assumed in forming Margin_Off-Peak;
(fA) LFR as described in clause 3.13.1(aA)(i)(2);
(g) Cost_LRD as described in clause 3.13.1(c); and
(h) the compensation due to changed outage plans to be paid to a Market Participant for that Trading Month as determined in accordance with clause 3.19.12(e).
26. Market Rule 4.1 amended
(1) Amend clause 4.1.28(a) by deleting “review” and replacing it with “update”.
(2) Delete the existing clause 4.1.28(b) and replace it with the following—
(b) the IMO must publish updated Individual Reserve Capacity Requirements no later than by 5:00 PM on the Business Day being five Business Days prior to the commencement of the Trading Month from which the updated Individual Reserve Capacity Requirements will apply. 27. Market Rule 4.4 amended
(1) Insert a new clause 4.4.1(b)(iA) as follows—
iA. a non-Intermittent Generator not serving Intermittent Load;
(2) Delete the existing clause 4.4.1(b)(ii) and insert instead the following— ii. a non-Intermittent Generator serving Intermittent Load; or
(3) Insert a new clause 4.4.1(cA) as follows— (cA) for non-Intermittent Generators serving Intermittent Load, the maximum capacity anticipated to be required to serve the Intermittent Load;
28. Market Rule 4.5 amended
(1) Amend clause 4.5.2(c) by deleting “and” after the semi colon.
(2) Amend clause 4.5.2(d) by deleting full stop “.” after “losses and constraints” and replacing it
with “; and”.(3) Insert a new clause 4.5.2(e) as follows— (e) the capacity described in clause 4.5.2A.
(4) Insert a new clause 4.5.2A and comment box as follows— 4.5.2A. The IMO must determine an estimate of the Reserve Capacity required to cover the forecast cumulative needs of Intermittent Loads such that—
(a) this Reserve Capacity estimate is in addition to the Reserve Capacity required to satisfy the Planning Criterion in the situation where there were no Intermittent Loads; and (b) this Reserve Capacity estimate must be set by the IMO to equal the sum over all expected Intermittent Loads of their forecast maximum possible Intermittent Load levels multiplied by—
i. the ratio of—
1.
the Reserve Capacity Target for the relevant Capacity Year as described in clause 4.5.10(b)(i); and
2.
the expected peak demand for the relevant Capacity Year as described in clause 4.5.10(b)(ii);
ii. minus one.
In the above clause, clause (a) means that capacity required to serve the Planning Criterion for regular loads cannot count as capacity to cover Intermittent Loads. The ratio in clause (b) is just the reserve margin for the year (e.g. 115%) and clause (b) ensures that the Reserve Capacity associated with any Intermittent Load will equal the capacity margin (e.g. 15%) required for a normal Load beyond the capacity required to cover the load itself. Note that clause (b) may force some iteration into the process, as the amount of Reserve Capacity required for Intermittent Loads will influence the values specified in clause 4.5.10(b).
(5) Insert a new clause 4.5.3A and comment box as follows— 4.5.3A. The information requested by the IMO under clause 4.5.3 must include a request for Market Customers to provide the following information pertaining to Intermittent Loads and Loads that are expected to be registered and operating as Intermittent Loads during the second Capacity Year commencing during the Long Term PASA Study Horizon—
The Long Term PASA Study Horizon begins on 1 October of the year following a Reserve
Capacity auction, so the Capacity Year applicable to that auction is the second Capacity Year
of the Long Term PASA Study Horizon.
The information requested is for forecasting purposes only and is not binding on Intermittent
Loads.
4208 GOVERNMENT GAZETTE, WA 9 September 2005
(a) the amount of capacity required to serve that Load in the event of a failure of on- site generation where this amount of capacity cannot exceed the greater of— i. either—
1. for an existing Intermittent Load, the maximum allowed level of Intermittent Load specified in Standing Data for that Intermittent Load at the time of providing the data; or 2. for an Intermittent Load that is yet to be registered with the IMO, zero; and ii. the Contractual Maximum Demand associated with that Intermittent Load to apply during the Capacity Year to which the nomination relates. The Market Customer must provide evidence to the IMO of this Contractual Maximum Demand level unless the IMO has previously been provided with that evidence; and
(b) for each Intermittent Load that is yet to be registered with the IMO— i. the location of the Load; and
ii. evidence that the Load can be expected to satisfy the requirements to be registered as an Intermittent Load during the second Capacity Year within the Long Term PASA Study Horizon.
(6) Delete the existing clause 4.5.9(a) and insert the following instead—
(a)
meet the forecast peak demand (including transmission losses and allowing for Intermittent Loads) supplied through the SWIS even after the outage of the largest generation unit and while maintaining the Minimum Frequency Keeping Capacity for normal frequency control. The forecast peak demand should be calculated to a probability level that the forecast would not be expected to be exceeded in more than one year out of ten; and
(7) Insert a new clause 4.5.13(a)(vA) as follows— vA. the amount of Reserve Capacity forecast to be required to serve the aggregate Intermittent Load;
29. Market Rule 4.8 amended
(1) Amend clause 4.8.2 by deleting “4.12.4” and inserting “4.12.5” instead.
30. Market Rule 4.10 amended
(1) Delete the existing clauses 4.10.1(e)(ii) and 4.10.1(e)(iii) and insert the following instead—
ii. the maximum sent out capacity, net of Intermittent Loads, embedded and parasitic loads, that can be guaranteed to be available for supply to the relevant Network from the Facility when it is operated normally at an ambient temperature of 41oC;
iii. the maximum sent out capacity, net of Intermittent Loads, embedded and parasitic loads, beyond the capacity described in (ii), that can be made available for supply to the relevant Network from the Facility at an ambient temperature of 41oC and any restrictions on the availability of that capacity, including limitations on duration;
equal to the number of full Trading Days that meter was registered to Market
Customer i in Trading Month n divided by the number of days in Trading Month n.
So, for a month with 30 days, if meter u was registered to Market Customer A for 10 days, for
Market Customer B for 20 days and Market Customer C for 0 days then d(v,A)=0.33,
d(v,B)=0.66 and d(v,C) = 0, unless this meter was an Intermittent Load meter in which case all
values would be zero. The value of d(w,i) is determined in the same way but the definition is
modified to account for the treatment of Intermittent Loads.
Note that meters that have been de-registered will have a d(v,i) or d(u,i) value of 0 for all
Market Customers. If Load ceases to be Intermittent Load then d(w,i) will be zero for allMarket Customers
STEP 9: For each Market Customer, i, calculate ILRCR(i), respectively, in STEP 5 recalculated using the identical equations and data as used in STEP 5 but using the d(u,i), d(v,i), d(w,i) and IILRCR(w) values applicable to Trading Month n and setting NTDL(u) and TDL(v) to be zero for any meters not registered at the time of the original STEP 5 calculation. Note that IILRCR(w) is updated monthly in accordance with clause 4.28.11 and Appendix 4A.
X(i) = Sum(i, ILRCR(i)* + NTDLRCR(i)* + TDLRCR(i)*) + Sum(u, NMNTCR(u) × d(u,i)) +Sum(v, NMTDCR(v) × d(v,i))
The first three terms in X(i) reflect the IRCR for Market Customer i associated with meters
and interruptible loads . The last two terms are the contribution of new meters.STEP 11: The Individual Reserve Capacity Requirement of Market Customer i for Trading
Month n of a Capacity Year equals (X(i) × RR/Y) where
• Y = Sum(i,X(i))
• RR is the Reserve Capacity Requirement
This equation should generally have the effect that as demand grows during a year, the monthly cost of reserve capacity associated with load that has existed all year will decline. Note also that if a load disappears then the reserve capacity it funded will be allocated amongst all Market Customers in proportion to their capacity requirements.
81. Appendix 6 amended
(1) Amend Appendix 6 by deleting the existing appendix and replacing it with the following—
Appendix 6: STEM Bid, STEM Offer and MCAP 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.
Clause 6.9.4 states that no STEM Bids or Offers or MCAP Price Curves are to be determined if
the IMO has recorded that the Market Participant has not made a STEM Submission.For each Market Participant and for each Trading Interval in the Trading Day except those for which the IMO has recorded that the Market Participant has not made a STEM Submission—
(a) Determine for every price between the Minimum STEM Price and the Alternative Maximum STEM Price— 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 (ii) less the value in (iii);
2. the maximum STEM Price Curve quantity for that price equals the value in (i) less the value in (iv); and
3. the STEM Price Curve for that price includes all quantities between those in (1) and (2).
Suppose we have a Portfolio Supply Curve comprising the following Price Quantity Pairs: 20
MWh @ $50/MWh and a Portfolio Demand Curve comprising the following Price Quantity
Pairs 5 MWh @ $50/MWh, 10 MWh @ $100/MWh.
At a price above $100 the values in (a) are (i) 20 (ii) 20 (iii) 0 (iv) 0 so (v)(1) = 20, v(2)=20.
Hence at any price above $100 up to the Alternative Maximum STEM Price the STEM Price
Curve quantity is +20 MWh, meaning that the participant is a net supplier of 20 MWh.
4242 GOVERNMENT GAZETTE, WA 9 September 2005 At a price of $100 the values in (a) are (i) 20 (ii) 20 (iii) 10 (iv) 0 so (v)(1) = 10, v(2)=20. Hence at quantity is -15 MWh, meaning that the Market Participant is a net consumer.
price of $100 the STEM Price Curve quantity is all values between +10 MWh and +20 MWh.
At a price of $100 the values in (a) are (i) 20 (ii) 20 (iii) 10 (iv) 0 so (v)(1) = 10, v(2)=20. Hence at
price of $100 the STEM Price Curve quantity is all values between +10 MWh and +20 MWh.
At a price of $51 the values in (a) are (i) 20 (ii) 20 (iii) 10 (iv) 10 so (v)(1) = 10, v(2)=10. Hence at
price of $51 the STEM Price Curve quantity is +$10 MWh.
At a price of $50 the values in (a) are (i) 20 (ii) 0 (iii) 15 (iv) 10 so (v)(1) = -15, v(2)=10. Hence at
price of $50 the STEM Price Curve quantity is all values between—15 MWh and +10 MWh.
That is, at a price of $50/MWh the supply could be 20 MWh and demand 10 MWh (STEM Price
Curve quantity +10 MWh) or supply could be 0 MWh and demand could be 15 MWh (STEM
Price Curve Quantity of—10 MWh).
At a price below $50 the values in (a) are (i) 0 (ii) 0 (iii) 15 (iv) 15 so (v)(1) = -15, v(2)=-15.
(b) If the minimum quantity in a STEM Price Curve is greater than the Net Bilateral Position of the Market Participant then extend the STEM Price Curve to include the range between the Net Bilateral Position and the minimum quantity in the STEM Price Curve where this range is priced at the Minimum STEM Price. If a Market Participants Net Bilateral Position is 15 MWh and their STEM Price Curve covers the range 20 MWh to 100 MWh the this will be interpreted as meaning that the participant is prepared to sell 5 MWh as a price taker. That is, the participant is prepared to supply 5 MWh at any price, so should be scheduled. Hence we extend the STEM Price Curve to start at 15
MWh where the first 5 MWh is priced at the Minimum STEM Price. Likewise if the Net the curve would be extended to start at -15 MWh.
(c) If the maximum quantity in a STEM Price Curve is less than the Net Bilateral Position of the Market Participant then extend the STEM Price Curve to include the range between the maximum quantity in the STEM Price Curve and the Net Bilateral Position where this range is priced at the Alternative Maximum STEM Price. If a Market Participants Net Bilateral Position is 15 MWh and their STEM Price Curve covers the range 0MWh to 10 MWh the this will be interpreted as meaning that the participant is prepared to buy 5 MWh as a price taker. Hence we extend the STEM Price Curve to end at 15 MWh where the last 5 MWh is priced at the Alternative Maximum STEM Price. That is, the participant is prepared to pay any price to buy out of this position. Likewise if the Net Bilateral Position were -15 MWh and the STEM Price Curve maximum was -20 MWh then a the curve would be extended to start at -15 MWh.
(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 (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 (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 (i) set a Price-Quantity Pair price equal to that price;
v. for each price identified in (i) set a Price-Quantity Pair quantity equal to the quantity defined in (iii) less the quantity defined in (ii);
vi. set the Market Participant’s STEM Bids to be the set of Price-Quantity Pairs defined in (iv) and (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;
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;
9 September 2005 GOVERNMENT GAZETTE, WA 4243 ii. for each price identified in (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 (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 (i) set a Price-Quantity Pair price equal to that price;
v. for each price identified in (i) set a Price-Quantity Pair quantity equal to the quantity defined in (iii) less the quantity defined in (ii);
vi. set the Market Participant’s STEM Offers to be the set of Price-Quantity Pairs defined in (iv) and (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;
3. an amount between 0 MWh and the Price-Quantity Pair quantity if the STEM Clearing Price equals the Price-Quantity Pair price;
Suppose the STEM Price Curve is—
-10 MWh for a price less than $10/MWh
-10 MWh to +5 MWh for $10/MWh
+5 MWh for a price between $10/MWh and $20/MWh
+5 MWh to +20 MWh for $20/MWh
+20 MWh for a price between $20/MWh and $40/MWh
+20 MWh tp + 100 MWh for a price of $40/MWh
+100 MWh for a price more than $40/MWhIf the Net Bilateral Position is -5 MWh then for STEM Bids we have more than one STEM Price Curve quantity defined for a price of $10/MWh, while for STEM Offers we have more than one STEM Price Curve quantity defined for prices of $10/MWh , $20/MWh and $40/MWh.
STEM Bids: (-5)—(-10) = 5 MWh @ $10/MWh
STEM Offers: (+5)—(-5) = 10 MWh @ $10/MWh,
STEM Offers: (+20)—(+5) =15 MWh @ $20/MWh,
STEM Offers: (+40)—(+20) = 20 MWh @ $40/MWh,Note that if a Market Participant submits a Demand Portfolio Curve with no quantities in it, such that the STEM Price Curve only reflects a Supply Portfolio Curve with a range of 0 to 100 MWh and the Net Bilateral Position is 40 MWh, then the Market Participant will have 40 MWh of STEM Bids and 60 MWh of STEM Offers. Thus STEM Bids can be generated even if no demand is bid into the STEM. In this situation the STEM will be performing economic trading between generators, clearing STEM Offers with prices below the STEM Clearing Price and STEM Bids with prices above the STEM Clearing Price.
The second part of this appendix describes a process for converting all Market Participant
Portfolio Supply Curves into a single MCAP Price Curve.For each Trading Interval in the Trading Day—
(f) Determine for every price between the Minimum STEM Price and the Alternative Maximum STEM Price— i. the sum over all Market Participants except those recorded as not making a STEM Submission for the Trading Interval of 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 sum over all Market Participants except those recorded as not making a STEM Submission for the Trading Interval of 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 MCAP Price Curve quantity for that price where
1. the minimum MCAP Price Curve quantity for that price equals the value in (ii);
2. the maximum MCAP Price Curve quantity for that price equals the value in (i); and
3. the MCAP Price Curve for that price includes all quantities between those in (1) and (2).
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