RCP PAPER NO. : EMC/RCP/121/2021/06

RCP PAPER NO. : EMC/RCP/121/2021/06 SUBJECT : RULES CHANGE PANEL WORK PLAN 2021 FOR : DISCUSSION AND DECISION PREPARED BY : QIN WEIXIAO SENIOR ECONOMIST REVIEWED BY : POA TIONG SIAW SVP, MARKET ADMINISTRATION DATE OF MEETING : 10 MARCH 2021 ____________________________________________________________________________

Executive Summary

This paper presents a proposed update of the Rules Change Panel (RCP) work plan, incorporating feedback from joint briefing sessions held with stakeholders from 4th to 5th February 2021. EMC recommends that the RCP discuss and agree on an updated work plan, and task EMC to monitor the progress of the approved work plan.

EMC/RCP/121/2021/06 Page 2 of 36

1. Introduction This paper takes stock of the progress made in the previous work plan approved in March 2020. It then presents the list of existing and new issues raised during the work plan consultation exercise, together with the corresponding rankings and comments made by various stakeholders. The proposed issues to be tackled over the next 1 year are then tabled for the Rules Change Panel (RCP)’s discussion and approval. 2. RCP’s Achievements: April 2020 – March 2021 2.1 Overview At its 114th meeting in March 2020, the RCP agreed on the 2020 work plan (see Annex 1) and tasked EMC to monitor its progress. This work plan comprises 29 issues, with 11 to be addressed within 12 months (i.e. by March 2021). Of the 11 issues, the RCP has completed work on 2 of them, including: (1) Review of Automatic Financial Penalty Scheme (AFPS) & related issues raised in the 2017

Work Plan Prioritisation Exercise (2) Compensation guidelines for interruptible load facilities interrupted for prolonged duration At the same time, significant progress has been made on 7 of these issues: (1) Imposition of Minimum Net Tangible Asset as a Condition of Participation for Retailers

The concept paper was tabled at the 106th RCP meeting, where the Panel agreed that a minimum net tangible asset level should be introduced as a condition of participation for retailers, and tasked EMC to study this issue further.

(2) Holistic review of the current prudential requirement obligations and its enforcement process under the market rules As part of the holistic review, EMC first examined the credit risks associated with the current bilateral contract arrangements and the RCP has supported the proposed enhancements in the concept paper (CP83) at its 119th meeting.

(3) Deterrence of settlement payment default by market participants EMC has started consultation with relevant stakeholders.

(4) Review allowable remedies for default events The concept paper (CP82) was tabled at the 117th RCP meeting and the Panel unaminously supported the conceptual modifications to the EMC actions stated in Chapter 3 Section 7.3.3 that were proposed to ensure that these remedies and actions are appropriate for each type of default.

(5) Proposed review of constraint violation penalty structure EMC has started consulting relevant stakeholders and studying the issue.

(6) Provision of Real-time Estimates of the Reserve Responsibility Share (RRS) for Each GRF The concept paper (CP84) was tabled at the 118th RCP meeting and the Panel supported the conceptual proposal of providing forecasted RRS in RTS, STS and PDS using the existing RRS calculation methodology to the relevant owner-MPs only.

(7) Provision/clearing of ancillary services without active power generation The concept paper (CP86) was tabled at the 120th RCP meeting and the Panel in-principle supported the proposal to allow primary and contingency reserves to be provided from generation facilities with loading below LowLoad point, and tasked the Technical Working

EMC/RCP/121/2021/06 Page 3 of 36

Group (TWG) to conduct the said technical investigation and make its recommendations to the RCP.

3. RCP Work Plan Prioritisation Exercise 2021 3.1 List of Issues for Prioritisation During the joint briefing sessions, EMC presented to stakeholders a list of 35 issues comprising 27 that were carried over from the previous work plan and 8 that were newly raised by stakeholders. The new issues are briefly described below: (1) Review the treatment of import in the market

This proposal suggests reviewing the treatment of import in the market, i.e. whether it continues to be out-of-market or it needs to be offered and cleared in the market clearing engine when the magnitude of import into the Singapore electricity market increases. (Proposed by: Tuas Power Generation)

(2) Review of reserve allocation and AFPS for import This proposal suggests that import to be included in the reserve allocation using the current modified runway method. (Proposed by: Tuas Power Generation)

(3) Review the scope for compensation under market rules 5.4.3 of Chapter 5 This proposal suggests that the scope of GRF compensation be extended to include abnormal event in the PSO controlled system that can affect the output of any GRF. (Proposed by: Tuas Power Generation)

(4) Registration of facilities and settlement of auxiliary load of Contracted Ancillary Service Providers For generation facilities that provide fast start services, it is proposed that the cost of the auxiliary load be borne by consumers and settled directly in market. (Proposed by: YTL PowerSeraya / Seraya Energy)

(5) Load forecasting and MCE dispatch and price determination when contracted Fast Start unit(s) is performing monthly test or when actual activation In the event where fast start units are operated, depending on how the demand forecast, MCE dispatch and price determination will be impacted, it is proposed that the MCE conducts re-runs as if generation from the fast start units was not available to offset the artificial market disturbance. (Proposed by: YTL PowerSeraya / Seraya Energy)

(6) Introduction of Solar Forecast in existing EMC's MCE To better account for the solar PV generation in electricity market dispatch as solar PV penetration increases, it is proposed that the MCE be integrated with solar forecast. (Proposed by: PSO)

(7) Review of Automatic Financial Penalty Scheme (AFPS) This proposal suggests that the partial forced outage of a multi-unit GRF be exempted from AFPS and be considered as a full outage. (Proposed by: NEA)

(8) Export rebate for Solar PV system installed at Premise under Master-sub metering scheme This proposal suggests adopting a simpler alternative “software/IT” solution to determine the exported energy from IGS systems installed on premises that are under master-sub metering scheme. (Proposed by: LYS Genco Beta)

The comprehensive list of 35 issues is attached in Annex 2.

EMC/RCP/121/2021/06 Page 4 of 36

3.2 Consultation Process From 04 February 2021 to 05 February 2021, EMC conducted joint briefing sessions for the market participants (MPs) and the service providers to refine the scope of the issues, and rate each issue according to its importance and urgency1. Stakeholders could also vote to remove issues from the list and provide their qualitative comments. Section 4 below summarises stakeholders’ ranking, with their comments supplemented in Annex 2. The following message emerged from the consultation process: EMC should continue to work on issues where work has already commenced, with an aim to

complete them as soon as possible before embarking on new issues. Issue 35 (Export rebate for Solar PV system installed at Premise under Master-sub metering

scheme) is not within the purview of the RCP, and hence proposed to be removed. However, it reflects concerns and issues faced by the industry. EMC proposes that the RCP refer Issue 35 to the EMA and remove it from the RCP’s work plan.

Issues that could potentially overlap with ongoing EMA workstreams should be referred to the EMA and removed from the RCP’s work plan to avoid duplication of effort. (1) Issue 28 (Review the treatment of import in the market) and Issue 29 (Review of reserve

allocation and AFPS for import) on imports2, and (2) Issue 22 (Treatment of consecutive trading periods for demand response events) and

Issue 25 (Minimum Stable Load for Load Registered Facilities) on demand response3. 4. Ranking Methodology Adopted Two methods to determine the overall ranking of each issue are presented for the RCP’s consideration: Simple Average Methodology: Averages scores for ‘importance’ and ‘urgency’ of each issue

across all stakeholders. Group-Weighted Methodology: Averages scores for ‘importance’ and urgency’ of each

issue across each of the 4 groups of representatives/stakeholders (generation licensees, retail licensees, wholesale trader licensees and service providers). The average of these 4 scores is then calculated.

Table 1 overleaf summarises the ranking results under each of these methodologies, together with an indication of whether work has commenced and the number of stakeholders who proposed to remove the issue, with a detailed breakdown of the ranking results shown in Annex 3.

1 Response received from 20 market participants and 3 service providers, namely Air Liquide Singapore, Best Electricity Supply, Energy Market Company (Market Operations), Exxon Mobil, Flo Energy, National Environmental Agency, Ohm Energy, PacificLight Energy, PacificLight Power, PSO, Sembcorp Cogen, Sembcorp Power, Sembcorp Solar, Senoko Energy Supply, Senoko Energy, Seraya Energy, Shell Eastern Petroleum, Singapore District Cooling, SP Power Grid, Tuas Power Generation, Tuas Power Supply, TP Utility and YTL PowerSeraya. 2 EMA’s media release on “EMA To Trial Electricity Imports”, dated 26 October 2020. Refer to: https://www.ema.gov.sg/media_release.aspx?news_sid=20201025mSZFbaqw5Sj7 3 EMA’s Consultation Paper on “Review of the Demand Response Programme in the National Electricity Market of Singapore”, dated 30 November 2020. Refer to: https://www.ema.gov.sg/cmsmedia/PPD/Review%20of%20the%20Demand%20Response%20Programme%20in%20the%20National%20Electricity%20Market%20of%20Singapore.pdf

https://www.ema.gov.sg/media_release.aspx?news_sid=20201025mSZFbaqw5Sj7

https://www.ema.gov.sg/cmsmedia/PPD/Review%20of%20the%20Demand%20Response%20Programme%20in%20the%20National%20Electricity%20Market%20of%20Singapore.pdf

https://www.ema.gov.sg/cmsmedia/PPD/Review%20of%20the%20Demand%20Response%20Programme%20in%20the%20National%20Electricity%20Market%20of%20Singapore.pdf

EMC/RCP/121/2021/06 Page 5 of 36

Table 1: Work Plan Issue by Rank4

Issue No.

Issue Title Rank (Simple

Average)

Rank (Group-

Weighted)

Work Started

?

Propose to

Remove

Summary of Reasons for Removal

On-going Issues

1 Imposition of Minimum Net Tangible Asset as a Condition of Participation for Retailers N.A. N.A. Y N.A. N.A.

2 Holistic review of the current prudential requirement obligations and its enforcement process under the market rules

N.A. N.A. Y N.A. N.A.

3 Deterrence of settlement payment default by market participants N.A. N.A. Y N.A. N.A.

4 Review allowable remedies for default events N.A. N.A. Y N.A. N.A.

5 Proposed review of constraint violation penalty structure N.A. N.A. Y N.A. N.A.

8 Provision of Real-time Estimates of the Reserve Responsibility Share (RRS) for Each GRF

N.A. N.A. Y N.A. N.A.

9 Provision/clearing of ancillary services without active power generation N.A. N.A. Y N.A. N.A.

4 Arising from the RCP’s decision at its 78th meeting, ongoing issues need not be ranked.

EMC/RCP/121/2021/06 Page 6 of 36

Issue No.


Average)

Rank (Group-

Weighted)

Work Started

?

Propose to

Remove


Other Issues

28 Review the treatment of import in the market 1 3 N 3

One of the requirements for energy imports is that it must be ‘retailed’ to end-users and ‘offered’ into the NEMS.

Part of existing EMA’s electricity import workstreams and proposed to be removed

6 Framework for determining compensation claims amount for MPs in compliance of PSO directions

2 4 N

33 Introduction of Solar Forecast in existing EMC's MCE 3 1 N

32

Load forecasting and MCE dispatch and price determination when contracted Fast Start unit(s) is performing monthly test or when actual activation

4 8 N 2

If such tests can be proceeded by securing the dispatch from the market, it doesn’t warrant a rule change on this.

The running of fast start units is to address system security issue such as reserve shortfall or quick restoration of supply during major system disturbances. It will not affect the load forecast.

11

Price revision (re-run) to market price cap for periods with real-time load shedding and periods whereby PSO issues overriding dispatch instructions

5 2 N 3

Ex-ante pricing design shall minimize the price revision so as to preserve the price certainty.

1. Any potential issue from an ‘energy-only’ market will be addressed by the Forward Capacity Market currently in consultation with EMA. 2. Since the proposed changes and additional income for Generators only applies to unplanned outages it would unlikely provide a direct incentive to invest (uncertain value).

EMC/RCP/121/2021/06 Page 7 of 36

Issue No.


Average)

Rank (Group-

Weighted)

Work Started

?

Propose to

Remove


The existing market rule stipulated clearly the condition for a price re-run and EMC has reviewed the incident on 18 Sep 2018 and determined that it did not warrant a price re-run. Hence, this proposal is not necessary. This is a self commitment market so Genco should bid out immediately when their generators trip. EMC should surfaced this incident to MSCP for further investigation if there is a breach in market rule by the Gencos.

29 Review of reserve allocation and AFPS for import 5 7 N 1 Part of existing EMA’s electricity import workstreams

and proposed to be removed

13

Amendments to the StartGeneration used in the real-time schedule (RTS), and the first dispatch period of the short-term schedule (STS) and pre-dispatch schedule (PDS)

7 5 N

15 Redeeming the full amount of an MP’s Banker’s Guarantees (BGs) upon default 8 11 N 1

This is way too broad. The BG should not be claimed for amounts that are not (yet) due. It might be the case that there will be subsequent defaults, but at the mentioned point in time there is no ‘legal’ claim yet.

19 Adjustment for regulation charges and price neutralisation after final settlement 9 9 N

20 Proposed change in frequency of Pre-dispatch Schedule 9 6 N 3

There is no real urgency to run the PDS every hour as those data are used only for 6 hours look ahead. Instead maybe EMC can consider increasing the STS to 8 hours?

RCP has agreed to publish additional scenarios for the STS. There is no need to create additional PDS which will result in more system changes and costs incurred.

EMC/RCP/121/2021/06 Page 8 of 36

Issue No.


Average)

Rank (Group-

Weighted)

Work Started

?

Propose to

Remove


14 Improvement of real-time information flow regarding unplanned outages and return to service

9 10 N 1 Generation availability is already published in the AGOP on EMC website. Hence, this proposal is not necessary.

30 Review the scope for compensation under market rules 5.4.3 of Chapter 5 12 13 N 1

There was no basis under the Market Rules for Tuas to claim compensation due to price deviation on the market network node after network reconfiguration.

24

To require an MP submitting a request for cancellation of facility registration to also state the intended effective date of cancellation

12 14 N

12 Review of Expected Net Exposure formula and application 14 12 N

7 Request for EMC to Publish Filtered Reserve and Regulation Supply Curves 15 16 N

10 Calculation of the market energy price for a multi-unit facility when one of the constituent generating unit is islanded

16 18 N

16 Provisions regarding settlement bank and settlement account 16 15 N 2 Little to no benefit to the industry. MPs should be able

to setup its banking process from the get-go.

34 Review of Automatic Financial Penalty Scheme (AFPS) 16 20 N 1 This issue was already discussed in Review of

Automatic Financial Penalty Scheme.

18 To review the requirement for registration as commissioning generation facility for generation settlement facilities, except for

19 19 N

EMC/RCP/121/2021/06 Page 9 of 36

Issue No.


Average)

Rank (Group-

Weighted)

Work Started

?

Propose to

Remove


intermittent generation facilities of aggregate name-plate rating 10MW or more

23 Review CVP associated with violation of Type 2 Artificial Lines 20 17 N

27 Compensation in the event of load shedding for Embedded Generators 21 21 N 1

There is no compensation for automatic under-frequency load shedding. Under MR Chapter 6 Sect 7.2.4, Notwithstanding section 13 of Chapter 1, no market participant shall be entitled to compensation from the EMC or the PSO for any financial loss sustained by the market participant due to the market participant having been dispatched on the basis of load as forecasted pursuant to this section 7 rather than on the basis of actual load.

17 Review of Rules Change Panel composition to increase number of independent representatives

22 27 N

22 Treatment of consecutive trading periods for demand response events 23 22 N 2

EMA was conducting consultation on reviewing the DR scheme which may completely revamp the current approach.

EMA is reviewing DR as part of the service journey.

21 Broaden Exemptions of AFPS to Include De-loading due to Refuse Characteristics 24 26 N 3

All gencos including incineration plants should be treated equally.

The AFPS review is completed.

31 Registration of facilities and settlement of auxiliary load of Contracted Ancillary Service Providers

25 23 N 5

This should be part of procurement contract rather than in the NEMS market rules.

All settlement related issues would have been discussed in the Bilateral Agreement between PSO and the Ancillary Service Provider.

EMC/RCP/121/2021/06 Page 10 of 36

Issue No.


Average)

Rank (Group-

Weighted)

Work Started

?

Propose to

Remove


It should be part of the ancillary service contract negotiation between PSO, EMC and the ancillary service provider to acocunt for the auxiliary loads.

26 Removal of RCP’s review of EMC Budget 26 28 N 1 The budget review will ensure that resources are properly allocated to the key projects.

25 Minimum Stable Load (MSL) for Load Registered Facilities 27 24 N 3

The load reduction characteristics can be factored into the LRF’s market bids. Similar to GRFs, OCGTs could partially clear in the market and potentially offer at a price lower than itss marginal cost (due to efficiency losses running at lower loads), which is a known risk when bidding into the market.

LRF can aggregrate loads and choose to vary their offer according to the number of loads to be connected, unlike the GRF which is a real technical constraint in order to keep the plant stable.

35 Export rebate for Solar PV system installed at Premise under Master-sub metering scheme

28 25 N 9

It seems meter issues rather than the wholesale market settlement.

It should be a commercial decision whether to use the software/IT solution.

Not the right forum to discuss this issue.

This is not a Market Rules issue. Defer to MSSL to follow up.

As this issue pertains to the metering requirement from SP Services, it is not under the purview of the RCP.

EMC/RCP/121/2021/06 Page 11 of 36

5. Approach to Prioritisation EMC recommends that the RCP consider the following in its prioritisation process: Ranking by stakeholders – The rankings by stakeholders indicate which issues are likely to

provide the most impact in enhancing the performance of the market. On-going issues – As considerable effort would have been expended on-going issues, it would

be sensible to continue with these work streams. Issues to be removed and referred to the EMA –

a. Issue 35 is not under the purview of the RCP, b. Issue 28 and 29 overlap with ongoing EMA workstreams to assess and refine the technical

and regulatory frameworks for importing electricity into Singapore, and c. Issue 22 and 25 overlap with ongoing EMA workstreams on review of the demand

response programme. Stakeholders had proposed that certain issues be removed from the work plan, along with

their reasons. It would be useful for the RCP to deliberate if these issues should be removed from the work plan.

EMC proposes that 12 issues (as set out in Table 2) be addressed in the next 12 months (i.e. from April 2021 to March 2022).

Table 2: Work Plan Issues to be Addressed in the Next 12 Months

Serial No. Issue Title Issue No.

1 Imposition of Minimum Net Tangible Asset as a Condition of Participation for Retailers 1

2 Holistic review of the current prudential requirement obligations and its enforcement process under the market rules 2

3 Deterrence of settlement payment default by market participants 3

4 Review allowable remedies for default events 4

5 Proposed review of constraint violation penalty structure 5

6 Provision of Real-time Estimates of the Reserve Responsibility Share (RRS) for Each GRF 8

7 Provision/clearing of ancillary services without active power generation 9

8 Framework for determining compensation claims amount for MPs in compliance of PSO directions 6

9 Introduction of Solar Forecast in existing EMC's MCE 33

10 Load forecasting and MCE dispatch and price determination when contracted Fast Start unit(s) is performing monthly test or when actual activation

32

11 Price revision (re-run) to market price cap for periods with real-time load shedding and periods whereby PSO issues overriding dispatch instructions 11

12 Amendments to the StartGeneration used in the real-time schedule (RTS), and the first dispatch period of the short-term schedule (STS) and pre-dispatch schedule (PDS)

13

EMC/RCP/121/2021/06 Page 12 of 36

6. Conclusions and Decisions at the 121st RCP Meeting The Panel, having considered the list of 35 issues and EMC’s recommendations, made the following decisions: a. The Rules Change Work Plan 2021

The RCP unanimously agreed on the Rules Change Work Plan 2021 (as set out in Table 2) and tasked EMC to monitor its progress.

b. Issues to be Removed and Referred to the EMA The RCP by majority vote supported the proposal to refer the following 5 issues to the EMA and remove them from the work plan.

Table 3: Work Plan Issues to be Removed and Referred to the EMA

Issue No. Issue Title


28 Review the treatment of import in the market

29 Review of reserve allocation and AFPS for import

22 Treatment of consecutive trading periods for demand response events

25 Minimum Stable Load (MSL) for Load Registered Facilities

The following RCP members supported: Mr Henry Gan (Representative of EMC) Mr Soh Yap Choon (Representative of the PSO) Mr Teo Chin Hau (Representative of Generation Licensee) Mr Tony Tan (Representative of Generation Licensee) Mr Calvin Quek (Representative of Generation Licensee) Mr Sean Chan (Representative of Retail Electricity Licensee) Mr Terence Ang (Representative of Retail Electricity Licensee) Mr Song Jian En (Representative of Retail Electricity Licensee) Ms Ho Yin Shan (Representative of the market support services licensee) Dr Toh Mun Heng (Representative of Consumers of Electricity in Singapore) Mr YK Fong (Representative of Consumers of Electricity in Singapore) Ms Carol Tan (Representative of the transmission licensee) The following RCP member abstained: Mr Cheong Zhen Siong (Representative of Wholesale Electricity Trader)

EMC/RCP/121/2021/06 Page 13 of 36

Annex 1: RCP Work Plan finalised at the 114th RCP Meeting on 10 March 2020

No. Issue Title Status (After the 119th RCP Meeting in November 2020)

1 Review of Automatic Financial Penalty Scheme (AFPS) & related issues raised in the 2017 Work Plan Prioritisation Exercise

Completed This paper examines whether the (i) exceptions currently allowed under the AFPS should be expanded to include other cases, (ii) to review the minimum penalty value and (iii) the treatment of EG’s must-run quantity.

At the 112th RCP meeting, the Rules Change Panel discussed this paper and made the following decisions:

(i) The Panel unanimously supported the case for exemption of GRF’s on local control responding positively to system disturbance, and the case for exemption relating to partial forced outage, de-loading and fail-to synchronise deferred.

(ii) The Panel requested EMC the Panel requested EMC to seek clarification from the EMA on the intent of the current minimum penalty value before EMC starts to develop any new penalty model.

(iii) The Panel by majority vote supported EMC’s recommendation that no change is required.

2 Imposition of Minimum Net Tangible Asset as a Condition of Participation for Retailers

In-Progress One of the issues examined in RC341 (Review of Mechanisms to Mitigate Credit Default) pertains to whether minimum capitalisation requirements should be imposed on new MPs. At its 92nd meeting, the Panel noted that the EMA does not require licensees to satisfy any capitalisation requirements. The RCP agreed that a minimum net tangible asset level should be introduced as a condition of participation for retailers, and tasked EMC to study this issue further.

EMC is studying the issue and will report back to the RCP when the study is completed.

3 Compensation guidelines for interruptible load facilities interrupted for prolonged duration

Completed This paper seeks to design a calculation methodology to determine the compensation amount for LRFs that have been interrupted for reserve provision for a duration beyond 2 hours. EMC considered the prevailing USEP would correctly reflect the value of the curtailment to the system and proposed a compensation guideline to use the prevailing USEP as the reference price to compute compensation amounts for LRFs across affected periods.

At its 118th meeting, the RCP unanimously supported the proposed compensation guidelines and endorsed its publication for MPs’ reference.

4 Holistic review of the current prudential requirement obligations and its enforcement process under the market rules

In-Progress A growing number of payment default events implies a higher credit risk faced by non-defaulting MPs. This issue suggests adopting a more stringent prudential requirement, and a more efficient enforcement process in order to ensure adequacy of credit support provided, mitigate the risk and reduce the financial impact to non-defaulting MPs in the event of default.

EMC/RCP/121/2021/06 Page 14 of 36


As part of the holistic review, EMC first examined the credit risks associated with the current bilateral contract arrangements and proposed the following enhancements:

(1) for the buyer to be notified by the EMC of the seller-submitted bilateral contract data;

(2) for the EMC to validate the seller’s actual generation or credit support level, or both, against the bilateral contract submission and settlement; specifically,

a. for the seller’s bilateral contract submission to be validated and accepted only if its contract position can be sufficiently covered by its actual generation or credit support level, or both; and

b. for the seller to be required to make prepayment of its negative preliminary settlement statement amount within 2 business days if such exposure is not covered by its credit support held with the EMC.

(3) to introduce Wholesale Electricity Price settlement and strike price settlement as new settlement mechanisms for bilateral contracts;

(4) to allow bilateral contracts to be used for ex-post trade reallocation in the event of a buyer’s margin call;

(5) to allow the expected bilateral settlement amount to be subtracted from the initial credit support requirement calculation for new MPs that have entered into bilateral contracts as buyers; and

(6) for the timeline for submission of bilateral contract data to be updated to T-15 calendar days to accommodate the Retail of Last Resort timeline.

The RCP supported the proposed enhancements at its 119th meeting.

5 Deterrence of settlement payment default by market participants

Not Started

6 Review allowable remedies for default events

In-Progress This proposal arises as EMC has encountered certain types of default that were impractical for the MP to remedy within 1 BD, and/or inappropriate for EMC to take the actions specified in Chapter 3 Section 7.3.10 of the market rules. Therefore, for each type of event of default, EMC has reviewed the allowable remedies by MPs and the appropriate actions to be taken by EMC. Modifications to the EMC actions stated in Chapter 3 Section 7.3.3 are proposed to ensure that these remedies and actions are appropriate for each type of default.

At the 117th RCP meeting, the RCP unanimously supported the proposed conceptual modifications.

7 Proposed review of constraint violation penalty structure

In-Progress The proposal seeks to review the stepwise CVP structure of reserves and finetune the structure to reduce occurrences of

EMC/RCP/121/2021/06 Page 15 of 36


contingency reserve shortfalls and to improve system security and market efficiency.

EMC is studying the issue and has explored a few plausible solutions to modify CVP settings to reduce reserve shortfalls. Simulation has been conducted to assess the impact of the solutions. EMC will report back to the RCP when the study is completed.


Not Started

9 Request for EMC to Publish Filtered Reserve and Regulation Supply Curves

Not Started

10 Provision of Real-time Estimates of the Reserve Responsibility Share (RRS) for Each GRF

In-Progress This paper discusses a proposal for the EMC to establish a methodology to calculate an estimated Reserve Responsibility Share (RRS) for each Generation Registered Facility in real time and to publish the estimated RRS for each dispatch period of the market outlook scenario (MOS), pre-dispatch schedule (PDS), short-term schedule (STS) and real-time schedule (RTS).

The following proposals are recommended by the EMC:

a. use the existing RRS calculation methodology to calculate forecasted RRS

b. calculate forecasted RRS for RTS, STS and PDS

c. provide forecasted RRS to the relevant owner-MPs only and are supported by the RCP at its 118th meeting.

11 Provision/clearing of ancillary services without active power generation

In-Progress This paper discusses a proposal raised by Senoko Energy to allow generation assets that can meet reserve performance standard from a non-spinning start-state (e.g., open cycle gas turbines), to provide ancillary services without being scheduled for energy.

The concept paper has been published for consultation on 15 Oct 2020.


Not Started

13 Price revision (re-run) to market price cap for periods with real-time load shedding and periods whereby PSO

Not Started

EMC/RCP/121/2021/06 Page 16 of 36


issues overriding dispatch instructions

14 Review of Expected Net Exposure formula and application

Not Started


Not Started


Not Started

17 Redeeming the full amount of an MP’s Banker’s Guarantees (BGs) upon default

Not Started

18 Provisions regarding settlement bank and settlement account

Not Started


Not Started

20 To review the requirement for registration as commissioning generation facility for generation settlement facilities, except for intermittent generation facilities of aggregate name-plate rating 10MW or more

Not Started

21 Adjustment for regulation charges and price neutralisation after final settlement

Not Started

22 Proposed change in frequency of Pre-dispatch Schedule

Not Started

EMC/RCP/121/2021/06 Page 17 of 36


23 Broaden Exemptions of AFPS to Include De-loading due to Refuse Characteristics

Not Started

24 Treatment of consecutive trading periods for demand response events

Not Started

25 Review CVP associated with violation of Type 2 Artificial Lines

Not Started

26 To require an MP submitting a request for cancellation of facility registration to also state the intended effective date of cancellation

Not Started

27 Minimum Stable Load (MSL) for Load Registered Facilities

Not Started

28 Removal of RCP’s review of EMC Budget

Not Started

29 Compensation in the event of load shedding for Embedded Generators

Not Started

EMC/RCP/121/2021/06 Page 18 of 36

Annex 2: Issues for Consultation and Stakeholders’ Comments

Existing Issues

1. Imposition of Minimum Net Tangible Asset as a Condition of Participation for Retailers Issue description

The RCP reviewed the mechanisms to mitigate credit default in 2017. At its 94th meeting, the RCP supported amendments in RC341 (Review of Mechanisms to Mitigate Credit Default) intended to strengthen the prudential framework in Singapore Wholesale Electricity Market (SWEM).

In that review, EMC also assessed that since an MP’s default risk is his day-to-day trading exposure, there is no strong rationale to impose minimum capitalisation requirements on MPs. However, the RCP noted that the EMA currently do not require retail electricity licence applicants to meet any minimum capitalisation requirements. The RCP therefore tasked EMC to conduct further study on the imposition of minimum net tangible asset levels as a condition of participation for retailers.

Status

In-progress. EMC is studying the issue and will report back to the RCP when the study is completed.

Comments on Issue Description, Scope, etc

(1) The objective is to achieve the financial integrity of the market, hence the study can go beyond exploring imposing minimum net tangible asset. Besides the entry requirements, the termination/suspension needs to be reviewed as well.

(2) This would defy the whole idea of a free market. Imposing minimum capitalization requirement would increase the threshold for new participants to enter. Also this would limit parties ability to grow as the majority of their value is in intangible assets (consumer contracts). I would advise strongly against this.

(3) This proposal will deter new entrants. Such a proposed mechanism will likely result in requests to increase this minimum capitalisation number annually. Also, the current annual MP fees to EMC and PSO of over $10000 is already enough to filter out retailers who do not have sufficient funding to participate in the market.

2. Holistic review of the current prudential requirement obligations and its enforcement process under the market rules Issue description

A growing number of payment default events implies a higher credit risk faced by non-defaulting MPs. This issue suggests adopting a more stringent prudential requirement, and a more efficient enforcement process in order to ensure adequacy of credit support provided and mitigate the risk and reduce the financial impact to non-defaulting MPs in the event of default.

a) Top up credit support in the event of default in payment

Require a MP that has defaulted in payment to provide additional credit support such that its ENE determined at the time of default, over the sum of additional credit support and unutilised credit support is less than 50% of the total value of credit support, similar to the current margin call requirements.

b) Assess credit support requirement based on MP’s payment history

For new entrants with no payment history, propose to set a minimum credit support requirement (e.g. Daily Gross Energy Withdrawal - Daily Gross Energy Injection = 15MWh).

For existing MPs with default in payment in the past 2 years, propose to charge a multiplier on the existing credit support requirement.

c) Review the current enforcement process and timeline in the event of payment default to shorten lead time

Propose to review the actions to be taken by EMC where an event of default has occurred.

EMC/RCP/121/2021/06 Page 19 of 36

Propose to review the current enforcement process and timeline in relation to the issuance of suspension order.

d) The current credit support requirements are set based on an MP’s average trading exposure in the past 90 days. However, doing so fails to account for (i) price volatility which characterises the electricity spot market and (ii) potential changes in recent trading volumes. It is therefore proposed that the methodology for setting credit support requirements be reviewed to take into account, among other factors, price volatility and trading volume changes.

Status

In-progress. As part of the holistic review, EMC first examined the credit risks associated with the current bilateral contract arrangements and RCP has supported the proposed enhancements conceptually.


(1) Propose to review the credit support on market creditors to cover the participant annual fee, for example.

(2) Credit risk is part of normal market operations. This proposal will only force the defaulting retailer into a squeeze. Also the term of 2 years seems unnecessary long. This again would increase the threshold for new entrants.

3. Deterrence of settlement payment default by market participants Issue description

Section 7.3 in Chapter 3 details down different types of events of default and how the defaulting market participant may remedy the payment default within the timeline EMC stipulates, i.e. no more than 1 business day after EMC having issued a default notice.

With the retail market opening up, the occurrence of payment default has become more frequent. It suggests that market rules need to be tightened further for sufficient deterrence in order to preserve the financial integrity of the wholesale market.

Proposed changes can be:

1. Introducing a threshold to trigger the retailer of last resort without a need for market participant suspension hearing, for example, 3 events of default in 12 months;

2. Imposing an administration charge for each event of default, i.e. $5,000. The collected amount can be re-distributed back to the market through MEUC;

3. Publishing the defaulting market participant on a watchlist.


(1) Is there any real indication that currently the wholesale markets financial integrity is at risk? Any example? Again, this increases the threshold for market entrants. Something the EMC has no role in, but must be assessed by the EMA in our opinion.

(2) We have seen many retailer defaults over the last few months, a significant increase compared to past years.

(3) There is increasing urgency in order to preserve the financial integrity of the wholesale market.

4. Review allowable remedies for default events Issue description

Section 7.3.6 of Chapter 3 states that default events described in Sections 7.3.1.7 to 7.3.1.14 of Chapter 3 may be remedied by topping up credit support and/or paying up outstanding debts. However, the nature of these defaults relates to the operational risk of the entities and not to any outstanding margin call or debt. This presents an issue for EMC when EMC is required to issue a default notice for one of those types of default as the remedies prescribed in Section 7.3.6 do not address the default.

It is thus proposed that the allowable remedies for events of default be reviewed.

Status

EMC/RCP/121/2021/06 Page 20 of 36

In-progress. At the 117th RCP meeting, the RCP unanimously supported the proposed conceptual modifications.

5. Proposed review of constraint violation penalty (CVP) structure Issue description

A review of the stepwise CVP structure for reserves is proposed.

The stepwise CVP structure for reserve and regulation deficits was introduced in 2014 (under RC317: Review of Constraint Violation Penalties) to address the phenomenon where during a tight supply situation, capacity was channelled to meet reserve requirements instead of energy demand. The cheapest block for contingency reserve deficit was set at $90/MWh (and subsequently increased to $185/MWh in Oct 2017 when secondary reserve was removed).

However, contingency reserve shortfalls have been occurring relatively frequently recently even though there were sufficient capacity offered to meet both energy and reserve requirements. This could be caused by the CVP for contingency reserve being set relatively too low, and thus the MCE decides not to procure reserve from offers which are priced above the CVP level.

The following proposals seek to finetune the current CVP structure to reduce such occurrences and to improve system security and market efficiency. Additionally, the issue of prolonged interruption of IL (due to contingency reserve shortfalls) may be alleviated as well.

a) Reduce quantity for CVP Block 1 for contingency reserve deficit Aligned with the current IL limits, the current quantity for CVP Block 1 is set at 30% of the total system contingency reserve requirement. According to the system study conducted by the PSO (SOM Chapter 12.5.3), the IL limits for reserves is capped at 30% of the total system contingency reserve requirement because if LRFs fail to deliver, GRFs will be able to meet this shortfall.

Considering that 30% of the total system contingency reserve requirement is the maximum threshold that the system can tolerate, it is proposed that the sum of the reserves provided by ILs and the CVP Block 1 quantity ought to be less than 30% of the total system contingency reserve requirement.

Hence, the quantity of CVP Block 1 (Contingency Reserve Deficit) ought to be revised down to take into account the amount of contingency reserve scheduled from ILs in that period. This will indirectly lower the potential reserve shortfall, and therefore lower the risk to the system.

b) Re-allocate the proportion of Block 1 violation penalty price for contingency reserve deficit The high incidence of contingency reserve shortfalls in 2018 ought to be addressed. In 2018, there were 240 periods of contingency reserve shortfalls, compared to only three periods for primary reserve. These shortfalls reflect a market failure for suppliers to provide adequate capacity to insure the system against large shocks.

Currently, the sum of Block 1 CVP prices for both classes of reserve is set at 0.099 of VoLL (i.e. $495/MWh), with 0.062×VoLL ($310/MWh) for primary reserve and 0.037×VoLL ($185/MWh) for contingency reserve. This imposes a large gap between the Block 1 CVP prices of primary and contingency reserve deficits ($185 vs $310), possibly contributing to the frequent contingency reserve shortfalls.

It is proposed that a higher weightage for contingency reserves ought to be considered (i.e. to increase the Block 1 CVP price for contingency reserve deficit, relative to that for primary reserve deficit) to reduce the frequency of contingency reserve shortfalls as primary reserve shortfall hardly occurs except during periods when the intertie is not synchronised.

Similar action has been evaluated and adopted for regulation block 2’s penalty price in Option 5R in RC317. The simulated results indicated significant reduction in regulation deficits. c) General review of the CVP structure At the 105th RCP meeting, during discussions on instances of prolonged IL interruption due to contingency reserve shortfalls in periods following IL activations, the Panel raised the concern on whether the current CVP is set at an optimal level and proposed to enhance the CVP settings to address abnormal contingency reserve shortfall incidents.

Status

In-progress. EMC is studying the issue and will report back to the RCP when the study is completed.

EMC/RCP/121/2021/06 Page 21 of 36


(1) Suggest the scope of study extended to include the possibility of separating the scarcity pricing out from the CVP setting.

6. Framework for determining compensation claims amount for MPs in compliance of PSO directions Issue description

Chapter 5 section 5.6.2 of the market rules allow a MP which complies with a direction issued to it under section 5.6.1 to request for compensation from the PSO.

It is proposed that a framework be introduced to determine compensation claim amounts, as a pre-determined methodology for compensation will reduce uncertainty and administrative burden for MPs.


(1) Compensation guidelines are already in place.

(2) In addition to a framework, the scenarios that PSO is allowed to issue a direction should be clearly stipulated as well to reduce uncertainty.

(3) The framework should also comprise of a MCE rerun to be conducted ex-post to produce a revised market price given that when PSO overrides dispatch instructions in real-time, the dispatch run (DPR) market price does not reflect the actual market situation.

(4) The existing guideline is optional for the MPs to choose. There is a need to make a firm decision on which methodology to follow.

7. Request for EMC to Publish Filtered Reserve and Regulation Supply Curves Issue description

Currently, reserve and regulation supply curves are published without removing offers which are submitted by Market Participants who are unable to fulfil the submitted offer based on their unit status, for example, if they are on outage or running below their MSL or is desynchronised from the grid. Units which are unable to provide this offer due to their unit status, even if they are not scheduled, submit offers or do not revise their offers to reflect their units’ status to provide reserve and regulation.

It is proposed that EMC publish filtered reserve and regulation supply curves with similar data format dimensions as the current energy supply curve.


(1) The RCP proposal paper #105 in 2019 highlighted this limitation. One way to overcome this can come from MPs who need to revise their offers based on its availability.

(2) EMC should assess potential impact on market behaviour from such publication and ensure it does allow all MPs to benefit equally.

(3) Market rules require the MP to reflect its real time capability, including reserve and regulation, similar to that of energy, the supply curves should be updated with revised offers from MP.

8. Provision of Real-time Estimates of the Reserve Responsibility Share (RRS) for Each GRF Issue description

A proposal suggested establishing a methodology to calculate an estimated RRS for each GRF in real-time and to publish the estimated RRS for each dispatch period of the market outlook scenario, pre-dispatch schedule scenario, short-term schedule and real-time schedule.

The estimated RRS will not be used for settlement but serves as an indicative figure of the actual RRS. This would improve transparency on the reserve share (and associated reserve costs) arising from the scheduled generation level for each GRF.

Status

In-progress. The conceptual proposals have been supported by the RCP.


EMC/RCP/121/2021/06 Page 22 of 36

(1) EMC should assess cost/efforts vs. benefits to MPs and ensure it allows all MPs to benefit equally.

9. Provision/clearing of ancillary services without active power generation Issue description

With influx of renewables and aging thermal generation fleet, the market will be required to procure more ancillary services to ensure system reliability, the number of reserve shortfall is on the rise over the past few years. FCM pointed out that the utilisation rate of CCGT is low mainly due to the co-optimised energy and ancillary markets where generators must reserve certain volume of their capacity for ancillary services. Consequently, this volume that is used for ancillary services reduces the load factor of the market.

Therefore, if fast start capable assets such as OCGT could offer ancillary services without active power generation, it would increase the available dispatchable reserve capacity which also increases system reliability.

In addition, it frees up CCGT capacity which ultimately increases the plant load factor. A high plant load factors means higher efficiency/low fuel cost for the generators and lower carbon emission for market.

Status

In-progress. The RCP in-principle supported the proposal to allow primary and contingency reserves to be provided from generation facilities with loading below LowLoad point; and tasked the Technical Working Group (TWG) to conduct the said technical investigation and make its recommendations to the RCP.

10. Calculation of the market energy price for a multi-unit facility when one of the constituent generating unit is islanded Issue description

The current formula in D.24.1.2 of Appendix 6D for deriving the market energy price (MEP) for a multi-unit facility (MUF), if one of the constituent generating units (CGUs) is islanded, would lead to a greater proportion of weightage being given to the nodal price of the ST.

Assume a (2 GT + 1 ST) facility, where the GTs’ capacity is 80MW each and the ST’s capacity is 100MW. Each of the GTs are assumed to drive half the capacity of the ST.

Proportionu = (Capacity of the CGU)/(Capacity of ST), where CGU = GT1, GT2 or ST, i.e. Proportion of GT1, GT2, ST = 0.8, 0.8, 1.

When one of the GTs is disconnected, the MUF’s MEP will be calculated as: MEP = (0.8 × GT1’s Nodal Price + 1 × ST’s Nodal Price)/1.8

However, the ratio of the remaining connected GT vs the ST’s contribution to the MEP should be 80:50 instead of 80:100. The current formula also leads to inconsistency between the MEP calculated at the CCGT node and the MEP calculated based on section D.24.1.2.


(1) It is about correctness in the mathematical modelling. It should be rectified and should not depend on the voting results from prioritization exercise.

11. Price revision (re-run) to market price cap for periods with real-time load shedding and periods whereby PSO issues overriding dispatch instructions Issue description

The NEMS is an “energy-only” wholesale electricity market, where the only source of remuneration for generators is the revenue from the sale of electricity and provision of ancillary services. Price signals serve to encourage market participants to operate their assets and undertake new investment efficiently.

a) It is proposed that the wholesale market price be revised to the market price cap of $4,500/MWh ex-post to reflect the scarcity of capacity in real time power interruption event in order not to undermine the investment signals in an energy-only wholesale electricity market.

When PSO overrides dispatch instructions generated by the MCE, the market prices may remain artificially suppressed leading to distorted price signals and affecting the ability of a well-functioning

EMC/RCP/121/2021/06 Page 23 of 36

energy-only market to convey price signals to MPs that encourage them to operate their assets and undertake new investments efficiently.

b) It is proposed that when PSO overrides dispatch instructions in real-time, a MCE rerun be conducted ex-post to produce a market price which reflects the PSO’s dispatch instructions. For instance, if the PSO instructs a peaking plant to generate even though it was not scheduled by the MCE, the prices in that period should be revised to reflect that such a peaking plant was running.

12. Review of Expected Net Exposure formula and application Issue description

a) Review of risk assessment for MPs who are exiting the market

Current ENE calculation is indifferent for all MPs regardless of status and in this case, a MP who is exiting the market, its risk assessment would be magnified. This is due to the general application of “(20-X)*ADE” for the unknown trades component.

To more accurately reflect the above stated scenario for a MP who is exiting the market, it is proposed to apply a different risk assessment approach on this group of MPs, i.e. “Current Exposure + Y × (Estimated Average Daily Exposure) + Amount overdue – Prepayment Amount”, where Y is the number of remaining active days before its exit.

b) Make clear the EMC’s obligation to notify the MP of their risk exposure levels

According to the Market Rules Chapter 2, Section 7.2, the EMC is to determine a MP’s current exposure and ENE on each business day. However, it is unclear on the EMC’s obligation to notify the MP if its ENE is zero or negative.

By eliminating the need to notify the MPs in the following scenarios, it would align the processes and efficiency would be gained.

1) MPs with zero or negative ENE

2) MPs that are suspended. For the above MPs, the risk assessment is often misrepresented. For this group of MPs, it is often that its credit support would be used to offset its daily payment. Hence, the risk exposure levels would eventually hit 70% and a margin call would be issued. However, for a MP that is suspended the margin call would be redundant.


(1) Propose to be included in the holistic review in #2 for the better efficiency

(2) Should combine with similar issues and addressed together.

13. Amendments to the StartGeneration used in the real-time schedule (RTS), and the first dispatch period of the short-term schedule (STS) and pre-dispatch schedule (PDS) Issue description

Proposal 1: StartGeneration for RTS and the first dispatch period of STS

Appendix 6D section D.12.1 of the market rules currently stipulates that the StartGeneration value for each GRF to be used in the RTS or the first dispatch period of the STS shall be:

a) the value received from the PSO,

b) if a) is unavailable, the scheduled generation levels in the RTS for the dispatch period when the calculation commences, or

c) if the RTS in b) is unavailable, zero.

Using zero as StartGeneration will result in all regulation providers being ineligible for regulation provision and could therefore lead to a dispatch schedule with no regulation procurement in the market.

It is proposed that the StartGeneration value used in RTS (e.g. RTS P5) be:

a) the value received from the PSO,

b) if a) is unavailable, the scheduled generation levels in the RTS for the dispatch period when the calculation commences (e.g. RTS P4), or

EMC/RCP/121/2021/06 Page 24 of 36

c) if the RTS in b) is unavailable, the scheduled generation levels, in the most recently released STS normal load scenario, for the dispatch period immediately preceding the dispatch period that the RTS is for (e.g. STS containing P4).

It is proposed that the StartGeneration value used in the first period of the STS (e.g. STS P5) be:

a) the scheduled generation levels in the RTS for the dispatch period immediately after the dispatch period when the calculation commences (e.g. RTS P4), or

b) if the RTS in a) is unavailable, the scheduled generation levels, in the most recently released STS with a load scenario corresponding to the STS scenario being calculated, for the dispatch period immediately preceding the first dispatch period required in the calculation of the STS (e.g. STS containing P4).

This proposal is expected to provide a more feasible dispatch schedule in the case when the values from the PSO and RTS in the preceding period are not available as the StartGeneration.

Proposal 2: StartGeneration for the first dispatch period in PDS

Appendix 6D section D.12.2 of the market rules stipulates that the StartGeneration value for each GRF for the first dispatch period of the PDS shall be scheduled generation level in the RTS current at the time (or the RTS immediately preceding the current time) when calculation of the PDS commences.

This leads to two unwanted effects:

1. It creates a dependency of PDS on RTS. In the recent NEMS downtime on 2 October 2018 which lasted about one hour, two RTS (P27 and P28) were affected and failed to be produced. After the system was up and PDS P33 was triggered to run, PDS P33 failed due to the unavailability of RTS P27 and 28.

2. Calculation of additional 4 leading periods which are not published to the market. When calculation of the PDS commences, there is a 4-period gap between the most recent RTS and first dispatch period covered by the PDS. For example, PDS P33, which forecasts from P33 today to P48 tomorrow, requires the projected scheduled generation levels in P32 as its StartGeneration level. At 13:45 when calculation of PDS P33 starts, the available RTS is P28. In order to get the projected scheduled generation levels for P32, the MCE calculates 4 additional periods (P29-P32) which are not published to the market. Since there are projected scheduled generation levels for these 4 additional periods in the STS, recalculating the leading periods take up system resources with little benefit (other than to take into account offer changes for P32 which may be made between the time the STS is calculated and the time the PDS is calculated, usually 20 mins.).

The StartGeneration value for the first dispatch period of the PDS is proposed to be the scheduled generation levels in the most recently released STS normal load scenario, for the dispatch period immediately preceding the first dispatch period required in the calculation of the PDS.

This proposal removes the dependency of PDS on RTS and enhances the robustness of PDS for MPs and the PSO. It also eliminates the need to calculate additional periods in PDS and makes it more efficient. Although this is replaced with a dependency on STS, there are more STSs for a given dispatch period in question, which reduces the chance of PDS failing to be produced.


(1) It is about robustness in market clearing engine design so as to ensure the feasible dispatch as much as possible.

(2) If the described scenario in proposal 1 happens, it will result in generating un-usable dispatch instruction for the PSO. Proposal 1 should be rectified regardless of the voting results from prioritization exercise.

(3) Option 1 would contain a more up-to-date figure, and hence should lead to better market dispatch accuracy.

(4) What is the frequency of occurrence that there is no value received from PSO and the scheduled generation levels in the RTS is unavailable?

14. Improvement of real-time information flow regarding unplanned outages and return to service Issue description

This proposal suggests improvements in the reporting of real-time generator availability. This includes the reporting of planned and unplanned outages in each individual half-hour. If a unit trips, the market is

EMC/RCP/121/2021/06 Page 25 of 36

currently notified within a reasonable timeframe. However, the market is not notified immediately when that unit has returned in a similar time frame.

For example, a section on the EMC’s website could show all units that are unavailable in the current half-hour.

This would help all MPs with spot market exposure in managing their risks more accurately, as well as promote liquidity in the SGX electricity futures market. It would also enhance the forecasting and analytical capability for natural and non-natural players.


(1) Real-time information regarding generation availability would be more useful.

(2) In-line with the principles of FCM, outage planning and information flows should be more granular than it is in current practice.

15. Redeeming the full amount of an MP’s Banker’s Guarantees (BGs) upon default Issue description

The current BG template only allows EMC to make a claim to the issuing bank for an amount that covers the outstanding obligations due and payable by the MP. However, once an MP defaults on payment for a given day, the MP is unlikely to be able to pay for its invoices due on the subsequent payment dates.

Given daily settlement in the SWEM, if EMC is strictly only allowed to make claim on the BGs for invoices that are due, EMC would need to submit such claims to the issuing bank every day, which creates operational challenges for EMC.

It is proposed that EMC be allowed to claim an MP’s BG amount in full once the MP defaults on payment. This will reduce the operational costs and expenses incurred by EMC, and thereby reducing the default levy charged, but may incur additional costs to the MP if an MP provides a BG amount which is more than the amount required to cover its exposure.


(1) Drawing down the full amount of the BG will make the market securer and preserve the market financial integrity in the event of payment default.

(2) We do not support this. EMC should not be allowed to claim an MP’s BG amount in full, but rather only on the amounts that are outstanding at the time of the claim.

(3) This is way too broad. The BG should not be claimed for amounts that are not (yet) due. It might be the case that there will be subsequent defaults, but at the mentioned point in time there is no ‘legal’ claim yet.

(4) It may not be appropriate to redeem the full amount of an MP’s BG as it makes the assumption that the MP will continue defaulting on its payment. We propose for EMC to claim up to total outstanding amount incurred by the MP, instead of just the amount due for payment.

(5) Fundamentally agree with the proposal. Perhaps EMC could draw down on the BG up to the exposure amount instead of drawing down on the full BG amount.

(6) Study should consider the current situation which creates an administrative burden to EMC. It should also consider the costs incurred by the MP and how he should be compensate (eg daily interest) if the BG drawn exceeds the final default amount.

(7) Should combine with similar issues and addressed together.

16. Provisions regarding settlement bank and settlement account Issue description (a) Introduction of settlement account flexibility and settlement bank diversification MPs are currently restricted to one bank account for settlement purposes with the settlement bank (i.e. OCBC).

This proposal is intended to improve options available to MPs and also diversify settlements to flow through more than one financial institution. This can be performed by (a) introducing multiple settlement

EMC/RCP/121/2021/06 Page 26 of 36

banks, and (b) allowing a MP to nominate which account is to be used for the settlement of the designated service(s).

This will provide greater flexibility to MPs and also improve the ability of the market to sustain operations in the situation if the settlement bank were to become unstable.

(b) Allowing MPs without embedded generators to have multiple settlement accounts At the 82nd RCP Meeting, when the Panel was discussing RC333 (Rectification of Settlement Formula for Net Participant Settlement Credit), Mr. Dallon Kay noted that MPs without embedded generators (EGs) are allowed to have only 1 settlement account. He requested allowing MPs without EGs to also be able to have multiple settlement accounts, for greater flexibility.


(1) It is up to cost and benefit analysis.

(2) This is very useful. The current clearing bank is very slow and for entering retailers that have their primary business with other banks, there is no account manager available at all.

17. Review of Rules Change Panel composition to increase number of independent representatives Issue description

The Rules Change Panel composition was reviewed in 2017 with the conclusion that the current MP structure classification is aligned with the current regulatory framework and that the current representation model is working efficiently, and therefore concluded that there was no reason to deviate from the existing model.

This proposal suggests that further review be done in terms of considering the expertise and background of the Panel members. Specifically, a portion of Panel members (e.g. 50%) can be made up of independent expertise that collectively have relevant experience to provide independent advice.

Having independent members that do not necessarily represent any class of stakeholders caters to a more holistic approach in the rules change process. Such an approach is important to the future development of a market and ensuring that the market rules keep pace with changing conditions, particularly in one where new initiatives often take place.


(1) Agree

(2) The current Panel composition and voting process is not structured to allow for any changes to the composition itself. This inherent limitation impedes the ability for the Panel to evolve with changing market conditions.

18. To review the requirement for registration as commissioning generation facility for generation settlement facilities, except for intermittent generation facilities of aggregate name-plate rating 10MW or more Issue description

It is proposed that generating units with name plate rating less than 10MW not be required to be registered during the period they are undergoing commissioning tests. As the commissioning activities of smaller units would not compromise system security, the PSO do not need to monitor such units’ commissioning activities. Chapter 2 Section 5.3.1.2 is therefore proposed to be amended as follows:

5.3.1 A market participant shall apply to register a commissioning generation facility:

5.3.1.1 …

5.3.1.2 if the facility is required or intended to be registered as a generation settlement facility under section 5.1, and has an aggregate name-plate rating of 10 MW or moreis required to cause or permit any physical service to be conveyed into, through or out of the transmission system,

on a transitional basis…during the period in which the commissioning generation facility is undergoing the commissioning tests referred to in section 5.3.4.

This would streamline the registration process and requirements.

EMC/RCP/121/2021/06 Page 27 of 36


(1) To streamline the registration process and requirements. It will reduce time and effort for MPs.

19. Adjustment for regulation charges and price neutralisation after final settlement Issue description Currently, when there are any settlement adjustments for metering errors discovered after T+10BDs that is due to generation metering errors (i.e. IEQ), the adjustment is only applied to MEP and PSO/EMC fees, but not the allocated regulation price (AFP).

Similarly, the neutralisation of price differentials (USEPh + HEUCh – MEPh) is also not adjusted even if there is any corrected withdrawal price quantity (WPQ) data for an embedded generator.

However, under the central intermediary scheme (CIS) where the MSSL acts as an aggregator and payment intermediary for contestable consumers with intermittent generation source (IGS) capacity of less than 1MWac, the AFP and the neutralisation of price differentials (USEPh + HEUCh – MEPh) are adjusted when there is any corrected metering data occurring to the IEQ and WPQ.

The above misalignment between the current market rules and the current practice under CIS would result in an over/under-collection of revenue by the MSSL. Given the revenue neutrality of MSSL in the CIS, any over-collection or under-collection of revenue might have to be borne by the non-contestable consumers (NCCs), which would not be equitable.

Furthermore, given that the CIS has been extended to include embedded generators up to 10MW (in March 2018), there is a need to change the above market rules to align with the practice of CIS so as to avoid recovering the under-collection from, or returning the over-collection to the NCCs while maintaining the revenue neutrality of the MSSL when there is any meter data adjustment affecting the IEQ and WPQ.


(1) Propose to have a holistic review on the Settlement reruns including the need of the current 2nd rerun.

(2) We seek clarity of outcome with sufficient lead time before such adjustments take effect, due to potential changes to bill adjustment protocol and impacts to charges that will need to be assessed and implemented.

(3) MSSL should explore ways to improve their system to align with the current market rules.

20. Proposed change in frequency of Pre-dispatch Schedule Issue description

It is proposed that the frequency with which the Pre-dispatch Schedule (PDS, also known as the Day Ahead Run or DAR) is produced be increased from every 2-hour interval to 1-hour interval.

At present, the PDS includes the forecast for the next day after 10am each day and refreshes every 2 hours. Under this proposal, the higher frequency run for PDS will facilitate price discovery and allow MPs to react timely to the changes in the short-term market.


(1) Fully agree with this proposal. The increase in frequency will improve market transparency which should translate to better market efficiency and outcomes.

(2) To facilitate price discovery, suggest extending the duration of Look Ahead Run or LAR instead.

21. Broaden Exemptions of AFPS to Include De-loading due to Refuse Characteristics Issue description

In the context of WTE plant, the source of fuel is mainly the municipal waste with varying refuse characteristics and with varying NCV. Hence, the steam flow production will fluctuate and in turn affect the STG power generation. Due the combustion nature of the municipal waste, there is no way to ramp up and down the MW within a short period of 30 mins to within 10MW. WTE plants can provide EMC / PSO with the steam flow level for the affected periods to prove that generation fluctuation is solely due to varying NCV of waste that is out of the plants’ control.

EMC/RCP/121/2021/06 Page 28 of 36

The industry is also facing a lack of refuse situation and the WTE plants are often running with a lower than average bunker level. With the 6th WTE plant starting operations soon and the new Tuas Nexus coming into the masterplan, steam flow fluctuation (due to lack of refuse) situation may be more prevalent in the future as the WTE plants will need to share the limited refuse resources. Likelihood of refuse with lower NCV can become higher when operating at low bunker level.


(1) With respect to the SNK WTE plant owned by Keppel, it has a combined rating of 56 MW. Keeping output within the range of +/- 10MW is almost an allowance of 20%. Perhaps the WTE plants can bid lower in the energy market and ramp up bunker levels if energy output level is not met as compared to the schedule.

(2) Instead of broadening the exemptions of AFPS for WTEs, market rules should establish equitable treatment for all generation types which adhered to the dispatch schedule (EGs, CCGTs, solar and WTE). If WTE and solar due to the nature of the generation is unable to adhere to the dispatch schedule, perhaps those units that can adhere to schedule should receive an additional compensation for doing so, eg being on AGC to offset the deviation from schedule from the rest.

(3) This issue has been reviewed in EMC/RCP/114/2020/363.

22. Treatment of consecutive trading periods for demand response events Issue description Consecutive Demand Response (DR) periods should be considered as a single “event” when calculating the implied energy curtailment in order to determine the corresponding incentive payment.

Currently, for a period where a facility is scheduled for DR curtailment, if the preceding period was also a curtailment period, then the implied energy curtailment is calculated as the difference between the “as-if” ramp-up load and the ramp-down load (shown by the blue shaded area in Period 2 in the below figure).

It is proposed that the unshaded white area in Period 2 also be included in this calculation since it is a continuation of the same DR event. With the current rules, considering that ramp-up rates are usually much lower than ramp-down rates for curtailable load facilities, DR participants will only receive a fraction of the actual performance that is delivered for DR events which are multi-trading period in duration.

23. Review CVP associated with violation of Type 2 Artificial Lines Issue description Type 2 artificial lines are currently used to connect generating units that are not represented as synchronised in the dispatch network data, under section D.6.5 of Appendix 6D. This is so that the market clearing engine (MCE) will always model unsynchronised units as connected, allowing them to be scheduled in the next period.

Type 2 artificial lines have real line characteristics (i.e. losses) that are the same as the default lines designated by the PSO. However, they are currently considered facility constraints with their violation

EMC/RCP/121/2021/06 Page 29 of 36

incurring a CVP of 20×VoLL. Given that such artificial lines are meant to be considered as real lines, it is proposed that their CVP should be 2.2×VoLL instead.


(1) Type 2 Artificial Line limit won’t be violated without incurring violation in Facility constraint. Changing it to 2.2 VOLL will not have effect.

24. To require an MP submitting a request for cancellation of facility registration to also state the intended effective date of cancellation Issue description

This proposal suggests adding the requirement that when a MP wishes to cancel the registration of a registered facility, the MP should also state the date that it wishes for the cancellation to be effective at the same time as such request is filed with the EMC under Chapter 2 section 6.1.1.

This is so that all parties involved (including PSO) will have a common understanding on when an MP intends to cancel the registration of its facility.


(1) Even though the rules provided the timeline for PSO to determine whether technical assessment is required, it is unclear on the part of the Market Participant when it intends to cancel its registration. With the change, it will provide a common understanding for all parties involved.

25. Minimum Stable Load (MSL) for Load Registered Facilities Issue description

Currently, the modelling of MSL is only available for GRFs but not for LRFs. The current MSL modelling for GRFs was introduced in consideration of the technical constraints of generators that cannot function properly at very low loading.

This issue proposes that LRFs also be allowed to have their MSL modelled in the market clearing formulation when participating in the energy market (to provide load curtailment), as LRFs similarly have technical constraints that may not permit compliance with dispatch instructions at or below the equivalent MSL level.

For example, a certain participating load rated at 5 MW may only have on/off capability, rendering it incapable of partially reducing load to comply with a partial dispatch schedule (for example, of 2 MW). The only way it can comply with the dispatch instructions is by curtailing the full 5 MW, while only being remunerated for 2 MW. This is unfair from the perspective of the LRF and it is proposed that LRFs be given the choice to have their MSL modelled, such that the scheduled curtailed load for the facility will not be less than its MSL (i.e. 5 MW in the above example).

This change will give MPs with LRFs participating in the DR programme greater confidence that they will be remunerated at the equivalent MSL level.

26. Removal of RCP’s review of EMC Budget Issue description

Under Chapter 2 section 10.1, EMC is required to submit its proposed expenditure and revenue requirements and a schedule of the fees that it proposes to charge (collectively referred to herein as the “EMC Budget”) to the RCP for review. EMC is also required to publish notice of the EMC Budget inviting interested persons to make submissions to the RCP. The RCP will then review the EMC Budget and submit a written report to the EMC Board indicating the views of the RCP and a summary of material submissions filed by interested persons.

It is proposed that the aforementioned process and requirements be removed as under the EMC’s current regulatory framework for 1 April 2018 to 30 June 2023 (“revenue regime”), EMC’s projections were comprehensively reviewed by the EMA and there is little flexibility for EMC to deviate from its annual budget given the following reasons:

(i) Fixed Regulated Revenue – Under the revenue regime, the total allowed revenue collected by EMC is fixed and the only adjustments allowed are approved changes such as approved efficiency claims or recovery of costs under the Annual Exogenous Cost Budget. There is no room for EMC’s proposed revenue requirements to deviate from the allowed revenue approved under the revenue regime.

EMC/RCP/121/2021/06 Page 30 of 36

(ii) Controlled spending – the Capex variance scheme and Opex variance scheme means that EMC’s proposed expenditure is unlikely to deviate materially from that presented to EMA for the revenue regime.

(iii) EMC’s schedule of fees derived from regulated revenue and expenses – EMC’s schedule of fees is derived from the regulated revenue and expenses with little room for deviation, as highlighted above.

Further, EMC is the only regulated licensee subject to this process. The removal of this requirement will result in a consistent approach being adopted across the energy industry.

EMC will also continue to publish the EMC Budget for interested persons to make written submissions to EMC, which will continue to be considered (but does not bind) the EMC Board and EMA.


(1) The planned introduction of the FCM may likely require significant work for EMC to provide these new processes. We expect the additional capex/opex to be borne by MPs and, hence, like to keep the existing review process – at least until after implementation of the FCM.

27. Compensation in the event of load shedding for Embedded Generators Issue description

Currently compensation payment in the event of load shedding is allocated to Market Participants based on WEQ.

Embedded Generators typically generate power to offset their own power consumption, therefore they do not benefit from the lower USEP due to load shedding. Cost should be allocated based on net import (WEQ-IEQ) for Embedded Generators.


(1) The compensation for Embedded Generators should be reviewed in entirety with reviewing the price settlement calculations during load shedding event (Proposal 11)

New Issues

28. Review the treatment of import in the market Issue description

EMA has indicated in SEMO2020 that there will be 200MW of import in 2022 and potentially up to 1,000MW of import in 2030.

Currently, the interties between Singapore and Malaysia have a manual support function and the amount of power flowing through the interties are scheduled by PSO, out-of- market.

Given the magnitude of import into the Singapore electricity market starting from 2022, it is timely to review the treatment of import in the market, i.e. whether it continues to be out-of- market or it needs to be offered and cleared in the market clearing engine.


(1) Supportive that import power be transacted the same in the SWEM.

(2) Timely to perform a comprehensive review of the market rules that are applicable and relevant for offshore imports.

29. Review of reserve allocation and AFPS for import Issue description

EMA has indicated in SEMO2020 that there will be 200MW of import in 2022 and potentially up to 1,000MW of import in 2030. As the import capacity is set to increase, it will also pose similar burden on the system as a non-performing GRF (regardless of whether it is out-of-market or it has to be offered into the MCE) and its performance should have similar obligations as a GRF.

EMC/RCP/121/2021/06 Page 31 of 36

It is proposed that import to be included in the reserve allocation using the current modified runway method.


(1) Timely to perform a comprehensive review of the market rules that are applicable and relevant for offshore imports.

(2) Following the principles in the FCM consultation paper, energy from different sources will be deemed equal once calculated on a QCAP basis. Hence, reserve requirements should be applied to all different energy sources, including imports.

30. Review the scope for compensation under market rules 5.4.3 of Chapter 5 Issue description

The scope of compensation should be extended to include abnormal event in the PSO controlled system that can affect the output of any GRF.


(1) Suggest for this to be addressed together with issue 6

(2) Can be incorporated and assessed together with item 6.

31. Registration of facilities and settlement of auxiliary load of Contracted Ancillary Service Providers Issue description

The EMC plans to procure fast start services on behalf of the PSO to ensure system reliability with the increase in renewable generation. When contracted, these facilities will be in-effect under the operational control of the PSO and EMC. The settlement rules are not very clear which party will be paying for the auxiliary load from these facilities while they are not net injecting into the system. These costs should be borne directly by the market/consumers instead of the Ancillary Service Provider.

The consumers benefit from the enhanced system reliability and accordingly should be the ones paying for the auxiliary load from the fast start facilities. By settling these energy withdrawals directly in the market, this avoids unnecessary transactional costs in the process. It will also reduce unnecessary transactional costs and improve efficiency.


(1) To improve price transparency and accuracy for Fast Start (FS) contracts, stripping out the Auxiliary load component from the contract payment will be beneficial as we avoid over/under compensation in terms of the Auxiliary load forecasting component. Facilities on FS contracts will pay EMC for Auxiliary load consumption, and will then be passed through to consumers where payment will be collected via MEUC.

(2) We would like to clarify that the cost of procuring ancillary services, including fast start services, would be recovered from the load in the form of Monthly Energy Uplift Charge (MEUC).

32. Load forecasting and MCE dispatch and price determination when contracted Fast Start unit(s) is performing monthly test or when actual activation Issue description

When performing the monthly tests or during actual activations, the fast start units are expected to generate >100 MWh per hour of energy into the system.

The running of the fast start units are out of market activities; whose generation artificially displaces the system requirement from the other generation facilities. At the moment, it is not clear how the demand forecast, MCE dispatch and price determination will be impacted when the fast start units are dispatched.

We propose an efficient market re-run methodology whenever the fast start units are operated. Depending on how the demand forecast, MCE dispatch and price determination will be impacted, the MCE should re-run as-if generation from the fast start unit was not available to offset the artificial market disturbance.

EMC/RCP/121/2021/06 Page 32 of 36

This will ensure that market integrity and the price formulation process is not disturbed by artificial out-of-market activities. The price formulation process would not be impacted by artificial out-of-market activities.

33. Introduction of Solar Forecast in existing EMC's MCE Issue description

Solar energy is the most promising renewable energy source for Singapore when it comes to electricity generation. The number of grid-connected solar photovoltaic (PV) systems is expected to increase significantly in the near future. However, a major limitation to large scale deployment of solar energy for electricity generation is that the output of solar PV is variable and dependent on environmental and whether conditions such as cloud cover and rain.

Variation in solar power output can result in imbalances between electricity supply and demand. This requires the power system to either procure additional reserves or adjust the output of conventional generators to ensure balance in supply and demand. It is therefore important that solar irradiances and the corresponding solar power output are accurately forecasted so that the PSO can take appropriate actions to manage intermittency.

It is, thus, necessary for the solar forecasting model to be integrated without power system operation and for the solar PV forecast to be provided to EMC. The Market Clearing Engine (MCE) will the account for the solar PV Generation in electricity market dispatch.

Without integrating solar forecast in EMC's MCE, the electricity market dispatch will not be accurate when solar PV penetration increases. This will have direct impact on EMC's MCE and the power system due to insufficient reserves to balance supply and demand. This may also indirectly affect the Market Participants and consumers as reserves costs may potentially increase.


(1) Another option which can be explored is for PSO to provide the generation forecast after matching off the solar forecast. The Intermittent Pricing Mechanism as per EMA consultation discusses the solar impact on reserve.

(2) EMC should assess the actual impact of the missing solar forecast and potentially delay such activity until the impact reaches a significance that makes this worthwhile.

(3) According to EMA System Operation Manual (SOM) Chapter 4, the PSO produces half hourly system load forecasts and monthly forecasts of peak demand load for the use of the wholesale electricity market. Since PSO already has a load forecast tool, which takes into account time-sensitive base load, weather-sensitive load component, day type specific load component, there may be more synergy for PSO to also forecast on the solar PV output and provide the net NEM demand for input into the MCE.

34. Review of Automatic Financial Penalty Scheme (AFPS) Issue description

Waste-to-Energy Plants GRF comprises two steam turbo generators. Due to the plant design, the two steam turbo generators have to be registered as a single GRF. The tripping of a turbo generator is only considered as a partial forced outage, and thus do not exempt the GRF from the AFPS. Tuas South Incineration Plant thus suggests for the forced outage of one of its turbo generators to also be considered as a full outage of the GRF.

35. Export rebate for Solar PV system installed at Premise under Master-sub metering scheme Issue description

Under current metering/billing calculations by MSSL, any export of electricity would result in the lowering of the master readings, and therefore result in inaccurate computation of the common services load. Current alternative solution proposed by SP for installing PV systems on master-sub account premise with probable exports are physical workaround solutions that may be un-necessary cost and complexities.

A simpler alternative “software/IT” solution could be used to determine the exported energy from IGS systems. Simpler alternative “software/IT” solutions will allow deployment of more PV systems on such premises. This will enable the industry aid EMA achieve the 2.5GW target set for 2030.

EMC/RCP/121/2021/06 Page 33 of 36

Consumers will be able to fully utilise the premise roof for Solar PV deployment without being restricted by the Master load account’s consumption limit. For MPs and developers, simpler software/IT solution will make such project development more cost effective and deployment and operation efficiency.

EMC/RCP/121/2021/06 Page 34 of 36

Annex 3: Ranking Results by Key Stakeholders Each stakeholder was asked for his view on the importance and urgency of each of the issues where work has not started. A score of 3 corresponds to “High”, 2 corresponds to “Medium”, 1 corresponds to “Low”, and 0 scores are assigned if the stakeholder has not provided the corresponding ranking. In the Grand Total column, the number in front of the bracket shows the ranking score and the number in the bracket gives the number of stakeholders providing that ranking score. For example, 1(7) means 7 stakeholders have ranked this item as 1 or “Low”. The overall average score arising from each method is represented in the last 2 columns of Table 3A.

Table 3A: Scoring of issues by stakeholders

Issue No. Issue Title Grand Total

Overall Score

(Simple Average Method)

Overall Score

(Group-weighted Average Method)


Importance: 0 (2), 1 (4), 2 (8), 3 (9) Urgency: 0 (2), 1 (7), 2 (9), 3 (5) 1.89 1.92

7 Request for EMC to Publish Filtered Reserve and Regulation Supply Curves Importance: 0 (6), 1 (7), 2 (6), 3 (4) Urgency: 0 (6), 1 (8), 2 (5), 3 (4) 1.33 1.36



11 Price revision (re-run) to market price cap for periods with real-time load shedding and periods whereby PSO issues overriding dispatch instructions


12 Review of Expected Net Exposure formula and application Importance: 0 (2), 1 (10), 2 (10), 3 (1) Urgency: 0 (2), 1 (13), 2 (7), 3 (1) 1.37 1.41





EMC/RCP/121/2021/06 Page 35 of 36

15 Redeeming the full amount of an MP’s Banker’s Guarantees (BGs) upon default Importance: 0 (2), 1 (10), 2 (9), 3 (2) Urgency: 0 (2), 1 (10), 2 (9), 3 (2) 1.48 1.59

16 Provisions regarding settlement bank and settlement account Importance: 0 (1), 1 (14), 2 (6), 3 (2) Urgency: 0 (1), 1 (16), 2 (5), 3 (1) 1.33 1.28



18 To review the requirement for registration as commissioning generation facility for generation settlement facilities, except for intermittent generation facilities of aggregate name-plate rating 10MW or more


19 Adjustment for regulation charges and price neutralisation after final settlement Importance: 0 (4), 1 (6), 2 (10), 3 (3) Urgency: 0 (4), 1 (7), 2 (10), 3 (2) 1.48 1.64

20 Proposed change in frequency of Pre-dispatch Schedule Importance: 0 (4), 1 (10), 2 (3), 3 (6) Urgency: 0 (4), 1 (10), 2 (3), 3 (6) 1.48 1.54

21 Broaden Exemptions of AFPS to Include De-loading due to Refuse Characteristics Importance: 0 (8), 1 (7), 2 (6), 3 (2) Urgency: 0 (8), 1 (9), 2 (4), 3 (2) 1.04 1.13

22 Treatment of consecutive trading periods for demand response events Importance: 0 (5), 1 (12), 2 (5), 3 (1) Urgency: 0 (5), 1 (12), 2 (5), 3 (1) 1.09 1.06

23 Review CVP associated with violation of Type 2 Artificial Lines Importance: 0 (3), 1 (12), 2 (8), 3 (0) Urgency: 0 (3), 1 (15), 2 (5), 3 (0) 1.15 1.21

24 To require an MP submitting a request for cancellation of facility registration to also state the intended effective date of cancellation


25 Minimum Stable Load (MSL) for Load Registered Facilities Importance: 0 (6), 1 (12), 2 (3), 3 (2) Urgency: 0 (6), 1 (14), 2 (3), 3 (0) 0.96 1.08

26 Removal of RCP’s review of EMC Budget Importance: 0 (4), 1 (15), 2 (3), 3 (1) Urgency: 0 (4), 1 (16), 2 (3), 3 (0) 1.00 1.11

EMC/RCP/121/2021/06 Page 36 of 36

27 Compensation in the event of load shedding for Embedded Generators Importance: 0 (4), 1 (11), 2 (8), 3 (0) Urgency: 0 (4), 1 (13), 2 (6), 3 (0) 1.13 1.06

28 Review the treatment of import in the market Importance: 0 (5), 1 (0), 2 (3), 3 (15) Urgency: 0 (5), 1 (2), 2 (9), 3 (7) 2.00 1.94

29 Review of reserve allocation and AFPS for import Importance: 0 (3), 1 (5), 2 (7), 3 (8) Urgency: 0 (3), 1 (7), 2 (8), 3 (5) 1.76 1.66

30 Review the scope for compensation under market rules 5.4.3 of Chapter 5 Importance: 0 (4), 1 (5), 2 (11), 3 (3) Urgency: 0 (4), 1 (10), 2 (6), 3 (3) 1.46 1.44

31 Registration of facilities and settlement of auxiliary load of Contracted Ancillary Service Providers


32 Load forecasting and MCE dispatch and price determination when contracted Fast Start unit(s) is performing monthly test or when actual activation


33 Introduction of Solar Forecast in existing EMC's MCE Importance: 0 (5), 1 (0), 2 (9), 3 (9) Urgency: 0 (5), 1 (2), 2 (9), 3 (7) 1.87 2.10

34 Review of Automatic Financial Penalty Scheme (AFPS) Importance: 0 (3), 1 (12), 2 (5), 3 (3) Urgency: 0 (3), 1 (13), 2 (5), 3 (2) 1.30 1.28



Date post:	17-Nov-2021
Category:	Documents
Upload:	others
View:	10 times
Download:	0 times

RCP PAPER NO. : EMC/RCP/121/2021/06

Documents