ENHANCEMENT TO THE SPINNING RESERVE REQUIREMENTS FOR THE SINGAPORE POWER

SYSTEM

FINAL DETERMINATION PAPER

9 March 2017 ENERGY MARKET AUTHORITY 991G ALEXANDRA ROAD #01-29 SINGAPORE 119975 www.ema.gov.sg

 

Disclaimer: The information in this document is subject to change and shall not be treated as constituting any advice to any person. It does not in any way bind the Energy Market Authority to grant any approval or official permission for any matter, including but not limited to the grant of any exemption or to the terms of any exemption. The Energy Market Authority reserves the right to change its policies and/or to amend any information in this document without prior notice. Persons who may be in doubt about how the information in this document may affect them or their commercial activities are advised to seek independent legal advice or any other professional advice as they may deem appropriate. The Energy Market Authority shall not be responsible or liable for any consequences (financial or otherwise) or any damage or loss suffered, directly or indirectly, by any person resulting or arising from the use of or reliance on any information in this document.

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ENHANCEMENT TO THE SPINNING RESERVE REQUIREMENTS FOR THE SINGAPORE POWER SYSTEM

FINAL DETERMINATION PAPER

EXECUTIVE SUMMARY 1. The Energy Market Authority (EMA) conducted a public consultation exercise on

27 March 2015 – 23 April 2015, to seek feedback on proposed enhancement to the Spinning Reserve requirements for Singapore Power System.

2. After careful consideration of the feedback received from the consultation exercise,

the EMA is implementing the following enhancements set out in this determination paper:

For Generation Facility: The current Primary Reserve and Secondary Reserve

classes will be combined into a new single Primary Reserve class to enhance power system security with faster system frequency recovery following loss of generation facility contingencies. During the consultation, the industry expressed concerns over the ability of the existing generation facilities to meet the proposed Primary Reserve capability requirements from 10 seconds to 10 minutes, especially as a generation facility’s performance would degrade over time. Taking into account the feedback, EMA has decided that the new Primary Reserve required shall be the minimum change in MW output of the generation facility automatically by governor action in response to the frequency response profile measured between 9 seconds and 10 minutes, and each generation facility must be capable of providing minimum Primary Reserve as tabled below. The current Secondary Reserve class will be removed, while the current Contingency Reserve requirements remain unchanged.

Table 1: Minimum Primary Reserve Capability Requirements

Generation Facility Output (Based on Plant’s Rated Capacity)

Minimum Primary Reserve Capability Requirements

(from 9 seconds to 10 minutes)

Minimum Stable Load (MSL) to 75% 9%

90% 5%

For Interruptible Load: The interruptible load shall trip instantaneously when

frequency drops to 49.7Hz. 3. Existing generation facility shall re-register its new Primary Reserve capabilities in

accordance with the revised requirements based on results from its last Spinning Reserve capability tests conducted.

4. Interruptible loads registered to provide Primary Reserve will need to modify their

activation setting to trigger at 49.7Hz instantaneously. Re-tests are required to demonstrate the capability to meet the revised requirements.

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5. EMA will direct Energy Market Company (EMC) to make corresponding changes to the Market Rules, which together with modifications to the Transmission Code set out in Annex 1, will come into effect on 1 October 2017.

 

TABLE OF CONTENTS 1. BACKGROUND ................................................................................................... - 1 - 2. FEEDBACK FROM THE CONSULTATION PAPER ........................................ - 1 - 3. SUMMARY OF ENHANCEMENTS .................................................................... - 7 - 4. ANNEX 1: PROPOSED MODIFICATIONS TO THE TRANSMISSION CODE .. viii 5. APPENDIX 1: RESPONSE TO FEEDBACK .......................................................... x

 

LIST OF TABLES Table 1: Minimum Primary Reserve Capability Requirements .................................... a Table 2: List of parties who have responded to the EMA’s Consultation Paper ..... - 3 - Table 3: Summary of Enhancements ...................................................................... - 7 -

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1. BACKGROUND 1.1. Overview of Current Spinning Reserve Requirements 1.1.1 In the event of the loss of generation, Spinning Reserves are called upon

automatically and/or manually to restore the system frequency to normalcy and are provided in the form of three reserve classes, namely Primary, Secondary and Contingency Reserves.

1.1.2 Primary Reserve arrests the initial fall in system frequency resulting from the

loss of generation. In order to restore system frequency back to acceptable levels, Secondary Reserve is released. Contingency Reserve is activated manually by the Power System Operator (PSO) to replenish Primary and Secondary Reserves in preparation for the next contingency.

1.1.3 All generation facilities are to adhere to requirements stipulated in the

Transmission Code, Market Rules and System Operation Manual (SOM). 1.1.4 To complement generation facilities in providing Spinning Reserves,

interruptible loads are activated in two different stages as set out in the SOM for the provision of Primary and Secondary Reserves at predefined system frequency excursions. Separately, Contingency Reserve is to be released within 10 minutes upon receipt of instruction from the PSO.

2. FEEDBACK FROM THE CONSULTATION PAPER 2.1. Recap of the Consultation Paper 2.1.1 In the consultation paper, the EMA sought feedback from the industry and

public on the technical proposal to combine the current Primary Reserve and Secondary Reserve classes into a new single Primary Reserve class. This new Primary Reserve was proposed to be the minimum change in MW output of the generation facility automatically by governor action in response to the frequency response profile measured between 10 seconds and 10 minutes. The EMA highlighted that the new Primary Reserve capability will enhance power system security with faster system frequency recovery following loss of generation facility contingencies. Furthermore, it will simplify both offer submission and market clearing for the National Electricity Market of Singapore (NEMS). The current Secondary Reserve class will be removed and with only two classes of Reserves (i.e. Primary and Contingency) remaining, the constraints in Market Clearing Engine (MCE) will be reduced. As for Contingency Reserve, the study concluded that the current requirements remain relevant. The current Frequency Response Profiles for testing the capability for generation facilities and interruptible loads and the methodologies for Reserve Provider Group assessment shall remain the same.

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Figure 1: Frequency Response Profile for Generation Facility

 

Figure 2: Frequency Response Profile for Interruptible Load

2.1.2 The EMA had reviewed that it is not necessary for existing generation facilities to perform any modifications or Spinning Reserve re-tests to verify their capabilities against the new Primary Reserve requirement as results from their last Spinning Reserve capability tests conducted already shown compliance with the revised requirements.

2.1.3 The EMA had also informed the industry that the proposed modifications shall

apply to new or modified generation facilities undergoing the Spinning Reserve test, while all existing generation facilities shall have their new Primary Reserve capability re-registered by adopting their current Secondary Reserve capability, which is based on their Spinning Reserve test results that were previously used for registration.

2.1.4 On the interruptible load activation setting, the EMA had highlighted that it will

be revised to instantaneous tripping when frequency drops to 49.7Hz. The proposed modification will be applied to all new interruptible loads. For existing interruptible loads, there is a need to modify their activation setting to trigger at 49.7Hz instantaneously, thus the relevant interruptible load providers is required to arrange with the PSO for a re-test to demonstrate their capability to meet the revised requirements.

2.2. Summary of Feedback Received and EMA’s Responses 2.2.1 The EMA’s consultation closed on 23 April 2015 and comments from 9

stakeholders were received as shown in Table 2. The industry’s feedback and the EMA’s corresponding responses are detailed in Appendix 1. Notable feedback are summarised in the ensuing paragraphs together with the EMA’s responses.

0s

50Hz 

5s49.4Hz

30s 60s

49.7Hz

10mins 

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Table 2: List of parties who have responded to the EMA’s Consultation Paper Licensee Party that has responded

Market Company Energy Market Company Pte Ltd

Generation Company

Keppel Merlimau Cogen Pte Ltd PacificLight Power Pte Ltd Sembcorp Cogen Pte Ltd Senoko Energy Pte Ltd TP Utilities Pte Ltd Tuas Power Generation Pte Ltd YTL PowerSeraya Pte Ltd

Wholesaler (Interruptible Load) Diamond Energy Pte Ltd Cost-Benefit Analysis on the New Primary Reserve  

2.2.2 A common feedback was that the consultation paper only covered the technical proposal, and there was a need to also cover the associated NEMS changes required. In addition, a cost-benefit analysis regarding power system security and costs to be incurred on NEMS changes should be performed, including studying the NEMS benefits of new Primary Reserve framework.

2.2.3 EMA has assessed that with the new Primary Reserve framework, the MCE

will no longer be required to schedule Secondary Reserve, thereby achieving simpler offer submission and MCE scheduling. While the Primary Reserve requirement to be scheduled by MCE remains unchanged, the increase in Primary Reserve capability of generation facilities (from the current 8% to 9%) will increase the supply cushion1 as shown in Figure 3, which will lead to increased competition and potentially lower market clearing prices. In other words, there are clear benefits in adopting the new Primary Reserve framework.

                                                            1 Supply Cushion = (reserve capacity – reserve requirement) / reserve requirement

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Figure 3: Comparison of Supply Cushion between the New Primary Reserve Requirement, and the Current Primary and Secondary Reserves Requirements

2.2.4 To implement the new Primary Reserve framework, EMA will direct EMC to

modify the Market Rules, and EMC will first set Secondary Reserve requirement to 0MW in the MCE. EMC estimates that the implementation cost is S$62,000.

Why the Need for Change? 2.2.5 Some industry players questioned the need to implement the new Primary

Reserve requirement now, when larger H-class combined-cycle gas turbines (CCGTs) are not currently in the system. It was suggested to revise the Reserve requirements only when H-class CCGT is installed.

2.2.6 As mentioned in the EMA’s consultation paper, the Singapore power system

has grown in size and electricity is produced almost entirely by gas-fired combined cycle plants today. Considering that the current Spinning Reserve requirements and corresponding interruptible load settings were established in Year 2001 and 2004 respectively, it was timely to review the Spinning Reserve requirements. The new Primary Reserve requirement ensures that our power system is future ready, paving the way for future connection of larger sized power plants (e.g. H-Class CCGT) and large-scale deployment of intermittent generating facilities (Solar PV). This will enhance security of our power system with faster system frequency recovery following loss of generation facility contingencies seen in Figure 4.

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

2.00

2.20

2.40

2.60

2.80

3.00

3.20

3.40

3.60

3.80

4.00

4.20

4.40

0 10 20 30 40 50 60 70 80 90 100

Supply Cushion ‐Assume loss of 400MW contingency

Time (s)

ExistingPrimary Reserve

ExistingSecondary Reserve

NewPrimary Reserve

600s

8s

4.28

3.12

3.69

9s

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Figure 4: Comparison on System Frequency between New Primary Reserve Requirement and Current Primary Reserve and Secondary Reserve Requirements

Capability of Existing Generation facilities 2.2.7 During the initial review and prior to the publication of the consultation paper,

EMA also held an industry briefing session to gather feedback. One common comment was that existing generation facilities were unlikely to meet the increased ramp rate. EMA has clarified in the consultation paper that the new Primary Reserve would not require an increase in the ramp rate of generation facilities to meet the new Primary Reserve requirement.

2.2.8 Concerns were also raised on existing generation facilities’ ability to meet the

new Primary Reserve capability requirements, and that a generation facility’s performance would degrade over time. To address the industry’s concern, instead of re-registering the new Primary Reserve capability by adopting the current Secondary Reserve capability, the PSO would work with the Gencos to establish all existing generation facilities’ new Primary Reserve capabilities based on results of their last Spinning Reserve capability test conducted. This is on consideration that the result of such test should already indicate compliance with the revised requirements. Furthermore, based on the recent Spinning Reserve re-tests carried out by some Gencos, existing generation facilities have been able to meet the new Primary Reserve requirement through appropriate tuning of their generation facility.

2.2.9 In addition, EMA has further refined the new Primary Reserve capability

requirement to be the minimum change in MW output of the generation facility, automatically by governor action in response to the frequency response profile,

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measured between 9 seconds and 10 minutes, the duration of which is comparable to the current Primary and Secondary Reserves combined. As such, the ramp rate need not be increased even though more reserves will be provided from 8% to 9% as shown in Figure 5.

Figure 5: Generation facility’s Reserve Capability providing more reserves at 9 seconds and sustain till 10 minutes, based on existing ramp rate

Revised Interruptible Load Activation Setting 2.2.10 In terms of the revised interruptible load activation setting, there was a

comment that the proposal focused on Spinning Reserves from generation facilities and cannot be directly applied to interruptible loads. It was suggested that should new Primary Reserve requirement be implemented, the current Secondary Reserve setting of 49.7Hz for 30 seconds should be retained.

2.2.11 EMA assessed that the revised interruptible load activation setting serves to

improve the ability of the power system to arrest the initial frequency drop and to recover system frequency. This takes into consideration that interruptible loads are activated only when system frequency reaches the trigger setting. As interruptible loads complement the generation facilities in providing reserves, to minimise free-riding, it is necessary to ensure interruptible loads are activated instantaneously when required.

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

0 10 20 30 40 50 60 70 80 90 100

Reserve (% of rating)

Current Requirement Revised Requirement9s

8s

600s

Minimum Stable Load (MSL) to 75% loading level

90% loading level

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3. SUMMARY OF ENHANCEMENTS 3.1. Taking into consideration all the feedback received from the various

stakeholders, the EMA has reviewed and enhanced the Spinning Reserve requirements for the Singapore Power System. The enhancements, as summarised in Table 3, serve towards faster system frequency recovery following loss of generation facility contingencies. To be forward-looking and future ready, this enhancement to power system security shall also pave the way for future connection of larger sized power plants such as H-Class CCGTs, and large-scale deployment of intermittent generating facilities.

Table 3: Summary of Enhancements

Feature Current Requirement Enhancement Implementation

Generation facility

Primary Reserve

MSL to 75 % of rated capacity

Existing generation facilities shall re-register the minimum change in MW output measured between 9 seconds and 10 minutes, based on results from their last Spinning Reserve capability test conducted.

8% measured from 8 seconds to 30 seconds

9% measured from 9 seconds to 10 minutes

90% of rated capacity

5% measured from 8 seconds to 30 seconds

5% measured from 9 seconds to 10 minutes

Secondary Reserve

MSL to 75 % of rated capacity

Removed

10% measured from 30 seconds to 10 minutes

90% of rated capacity

6% measured from 30 seconds to 10 minutes

Interruptible load

Primary Reserve

49.4Hz 49.7Hz Re-test is required to demonstrate existing interruptible load is able to disconnect instantaneously at 49.7Hz.

Instantaneous Instantaneous

Secondary Reserve

49.7Hz Removed

Timer: ≤30 seconds

 

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4. ANNEX 1: PROPOSED MODIFICATIONS TO THE TRANSMISSION CODE Modification

Ref. No. Clause Original Text Modified Text Reasons

TC/2015/1 F7 F7 Primary and Secondary Reserve Requirement F7 Primary and Secondary Reserve Requirement

Combine primary and secondary reserve requirements into single Primary Reserve requirement.

TC/2015/2 F7.1 This section states the minimum spinning reserve requirement in terms of primary and secondary reserve for each generating unit which has a Completion Date after 1 January 2000.

This section states the minimum spinning reserve requirement in terms of primary and secondary reserve for each generating unit which has a Completion Date after 1 January 2000.

TC/2015/3 F7.4.1 The ability of a generating unit to release primary and secondary reserves is measured by artificially subjecting the generating unit to a test whereby “measured” frequency is of the form as illustrated in the following figure:

The ability of a generating unit to release primary and secondary reserves is measured by artificially subjecting the generating unit to a test whereby “measured” frequency is of the form as illustrated in the following figure:

TC/2015/4 F.7.4.2 Primary reserve is defined as the change in MW output of the generating unit automatically by governor action in response to this change in frequency, measured at 8 seconds and sustainable for an additional 22 seconds. If the change in MW output measured at 8 seconds is not sustained for the period of 22 seconds, the primary reserve is the minimum change in MW output reached during that period.

Primary reserve is defined as the change in MW output of the generating unit automatically by governor action in response to this change in frequency, measured at 8 9 seconds and sustainable for an additional 9 minutes and 51 22 seconds. If the change in MW output measured at 8 9 seconds is not sustained for a period of 9 minutes and 51 22 seconds, the primary reserve is the minimum change in MW output reached during that period.

Revised definition for Primary Reserve.

TC/2015/5 F.7.4.3 Secondary reserve is defined as the change in MW output of the generating unit automatically by governor action in response to this change in frequency, measured at 30 seconds and sustainable for an additional 9 minutes and 30 seconds. If the change in MW output measured at 30 seconds is not sustained for the period 9 minutes and 30 seconds, the secondary reserve is the minimum change in MW output reached during that period.

Secondary reserve is defined as the change in MW output of the generating unit automatically by governor action in response to this change in frequency, measured at 30 seconds and sustainable for an additional 9 minutes and 30 seconds. If the change in MW output measured at 30 seconds is not sustained for the period 9 minutes and 30 seconds, the secondary reserve is the minimum change in MW output reached during that period.

Combine primary and secondary reserve requirements into single Primary Reserve requirement.

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Modification Ref. No.

Clause Original Text Modified Text Reasons

TC/2015/6 F.7.4.4 The primary and secondary reserve release capability shall be verified via test procedure stipulated in the System Operation Manual.

The primary and secondary reserve release capability shall be verified via test procedure stipulated in the System Operation Manual.

Combine primary and secondary reserve requirements into single Primary Reserve requirement

TC/2015/7 F8.1 Each generating unit must be capable of providing minimum primary and secondary reserves as follows:

Generating unit MW

output as % of rated MW capacity

Primary reserve as % of Rated

MW capacity

Secondary reserve as % of Rated MW

capacity

i 90 5 6 ii 75 to Minimum

Stable Load 8 10

Each generating unit must be capable of providing minimum primary and secondary reserves as follows:

Generating unit MW

output as % of rated MW

capacity

Primary reserve as % of Rated

MW capacity

Secondary reserve as % of Rated MW

capacity

i 90 5 6 ii 75 to Minimum

Stable Load 8 9 10

New Primary Reserve requirement for generation facilities.

TC/2015/8 F8.2 The primary and secondary reserve requirements for each generating unit MW output between 75% and 90% of its rated MW capacity shall be linearly extrapolated from the requirements for the generating unit MW output at 75% and 90% of its rated MW Capacity. Additional details are provided in the System Operation Manual.

The primary and secondary reserve requirements for each generating unit MW output between Minimum Stable Load and 75%, 75% and 90%, and 90% and 100% of its rated MW capacity shall be linearly extrapolated interpolated from the requirements for the generating unit MW output at between Minimum Stable Load and 75%, 75% and 90%, and 90% and 100% of its rated MW Capacity respectively. Additional details are provided in the System Operation Manual.

Combine primary and secondary reserve requirements into single Primary Reserve requirement. For clarity, the derivations on the requirements for each respective loading level are re-defined.

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5. APPENDIX 1: RESPONSE TO FEEDBACK

S/N Comments/Feedback EMA’s Response

Energy Market Company’s Comments

1 General comments In principle, should there be a difference between the reserve responding during the 0-30s and 30s-10min periods, in terms of the factors below?

Type Nature Quantity Possible sources

Section 1.2.2 suggests different treatment, though in Figure 4 of the paper, the disruption was shown to be addressed within 30s. Perhaps simulations of more drastic disruptions which are not addressed within 30s could be done.

When a supply imbalance occurs through, for example, a contingency event, there are two distinct phases: containment (or arresting) of the initial frequency excursion restoration of the frequency Under the existing arrangements, the primary response was largely devoted to containment while the secondary response was for frequency restoration. The existing arrangements for procuring reserves (including the calculation of the quantum) address the loss of the largest online scheduled unit (and its dispatched reserve). The purpose of the proposed ‘combined service’ is to accomplish both containment and restoration. The proposal now enables faster response and recovery because additional support is and can be provided by the existing generators in 9 seconds rather than 30 seconds as shown above in Figure 4 of Section 2.2. To be forward-looking and future ready, this pave the way for future connection of larger size power plants such as H-Class combined-cycle gas turbines (CCGTs), typically 550MW in capacity, the proposed arrangement showed that in the event of such unit tripping (a single contingency event), the time taken for system frequency to recover from its minimum to the targeted frequency of 49.7Hz could be shortened from 106 seconds to 18 seconds as shown above in Figure 4 of Section 2.2.

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S/N Comments/Feedback EMA’s Response Hence, the proposed arrangements for the frequency responsive generators and interruptible loads will see a faster response in a shorter timeframe to any generator tripping incident and enhance system security.

2 General comments on cost-benefit analysis Would the proposal to combine the existing Primary and Secondary Reserve classes into a new single Primary Reserve class reduce the supply cushion for reserve (i.e. [(reserve capacity – reserve requirement)/reserve requirement])? A comparison between the new system-wide reserve capability (proxy for reserve capacity) and the new reserve requirement should be done. For each reserve class, the total reserve capability in the system would be the sum of each reserve provider’s reserve capability. For example, if the percentage decrease in reserve capability is more than the percentage decrease in reserve requirement, or if the reserve capability decreases but there is either no change or there is an increase in reserve requirement, then the supply cushion would be reduced. A reduction in reserve supply cushion would increase the cost of reserve, which would ultimately be priced into energy offers and be borne by consumers.

The proposed arrangements would effectively do away with the need for the Market Clearing Engine (MCE) to schedule Secondary Reserve. In addition, the Primary Reserve capability of existing generation facilities is increased from the current 8% to 9% while maintaining the same Primary Reserve requirement to be scheduled by the MCE, the supply cushion for Primary Reserve should improve (Refer to Figure 3 of Section 2.2 above), which will lead to increased competition and hence, potentially lower market clearing prices, i.e. there is clear benefits in adopting the new Primary Reserve framework. The lower reserve prices could also lead to lower energy prices given the effect of co-optimisation in the MCE.

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S/N Comments/Feedback EMA’s Response If the total cost is determined to be higher than the expected benefit, we should not be introducing this proposal.

3 Page 1, Section 1.1.1 of consultation paper Is faster system frequency recovery necessary (for example, are we trying to solve an existing problem with power system security)? The benefit of faster system frequency comes with associated costs (see point 2) to the market. Does the current classification of primary and secondary reserve prohibit the introduction of H-Class generators? We understand that H-Class generators are more efficient and would reduce the cost of producing electricity. However as H-class generators are larger in size, the risk size would be increased, resulting in a need for more reserve when these generators are scheduled. Specifically, there would be additional investment cost in the long run because the system would require more generation capacity to meet the increased need for reserve. The benefit

Please refer to our response in Point 2 above. In addition, our assessment showed that the existing generators already have the reserve capability to meet the proposed arrangement. The current reserve arrangements with Primary and Secondary Reserves are not adequate to ensure secure operation of power system should H-Class CCGTs are introduced as time taken for frequency to recover from its minimum to the targeted frequency of 49.7Hz takes more than 30 seconds following a loss of H-Class CCGT at 550MW as shown above in Figure 4 of Section 2.2. The proposed arrangement would enhance system security with faster recovery (within 18 seconds to 49.7Hz) following a contingency making use of the slightly higher reserve capability from each generation facility. Investment decision on H-Class CCGT is not a subject of this consultation paper. However, to reiterate our response in point 2 above, all else being equal, the proposed arrangements would effectively do away with the need for the MCE to schedule Secondary Reserve. In addition, the Primary Reserve capability of existing generation facility is increased from the current 8% to 9% while maintaining the same Primary Reserve requirement to be scheduled by the MCE, the supply cushion for Primary Reserve should improve (see Figure 3 of Section 2.2 above), which will lead to increased competition and potentially lower market clearing prices, i.e. there is clear benefits in adopting the new Primary Reserve framework.

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S/N Comments/Feedback EMA’s Response of improvement to power system security and better efficiency should be compared with this additional investment cost.

4 Page 6, Section 2.2.4 of consultation paper Clarification from the PSO indicated that the new Primary Reserve capability will be based on the existing Spinning Reserve site test results, measured at 10 seconds (i.e. neither the current Primary Reserve capability measured at 8 seconds, nor the current Secondary Reserve capability measured at 30 seconds). This is inconsistent with Section 2.2.4 which states that “all other existing generating units will have their new Primary Reserve capability re-registered by adopting their current Secondary Reserve capability, which is based on their Spinning Reserve site test results that were previously used for registration”. We appreciate if EMA/PSO can clarify what the new Primary Reserve capability for existing generators will be.

To clarify, the current Primary Reserve (capability) as defined in the Transmission Code stated: “Primary Reserve is defined as the change in MW output of the generating unit … measured at 8 seconds and sustainable for an additional 22 seconds. If the change in MW output measured at 8 seconds is not sustained for the period of 22 seconds, the primary reserve is the minimum change in MW output reached during that period.” The revised Primary Reserve capability of generation facility will be based on minimum change in MW output measured from 9 seconds to 600 seconds. The EMA will revise the wordings for clarity. The EMA will work with the Gencos to update their generation facilities’ reserve capability based on results from their last Spinning Reserve capability tests conducted and update their standing capability data and for re-registration with EMC.

5 Annex 1 Page ii Clause F8.1 Modified text of consultation paper

The correct statement is:

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S/N Comments/Feedback EMA’s Response Missing the word “minimum” as shown in bold below: “Each generating unit must be capable of providing minimum primary and secondary reserves as follows:”

“Each generating unit must be capable of providing minimum primary and secondary reserves as follows:”

TP Utilities’ Response

6 TC/2015/2 Section F7.1 of Transmission Code As stated in section 3 – this enhancement is to pave the way for future connection of larger sized power plants such as H-class generators, and potentially large-scale deployment of intermittent generating facilities. We proposed the following: This section states the minimum spinning reserve requirement in terms of primary and secondary reserves for each generating unit which has a Completion Date after 1 January 2000 the effective implementation date of this amendment.

The EMA has worked with TP Utilities to establish its generation facility reserve capability and the results from its last Spinning Reserve capability tests conducted shown that the facility was able to meet the new Primary Reserve requirement. While there could be degradation of generating facility over time, Gencos should perform regular maintenance of their plants to ensure performance of their facilities meet the prevailing code requirements.

YTL PowerSeraya’s Comments

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S/N Comments/Feedback EMA’s Response 7 TC/2015/1 F7, TC/2015/2 F7.1, TC/2015/3

F7.4.1 of Transmission Code Currently, we’ve to provide 2 reserve requirements, i.e. Primary and Secondary Reserve portions. Does it mean that the new requirement only provide one lump sum reserve requirement? How does PSO determine the new total system reserve requirement for the new Primary Reserve as compared to current two reserves? General Comments: The implementation of the changes to the Transmission Code would need to be together with implementation of changes to the Singapore Electricity Market Rules (“Market Rules”). The Market rules govern the formulation of the Market Clearing Engine (“MCE”) which produces the dispatch schedules including for reserve. Therefore to implement the Transmission Code changes, Market Rules changes would be required and further details would also need to be worked out with respect to Market Rules changes such as changes to price parameters in the MCE which are not covered in EMA’s consultation paper.

This is correct. Existing Primary and Secondary Reserves classes will be combined into a new single Primary Reserve class. There is no change on the methodology to determine the system new Primary Reserve requirement. Please refer to Section 12.2 of SOM Rev 10. The current Secondary Reserve requirement will be removed. To implement the proposed arrangement, preliminary discussion with EMC is to set the Secondary Reserve requirement to 0MW in the MCE. Market Rules will be updated subsequently to reflect the new Primary Reserve requirement and remove the current Secondary Reserve requirement accordingly.

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S/N Comments/Feedback EMA’s Response 8 TC/2015/4 F.7.4.2 of Transmission Code

Please share with us what would the frequency drop before and after 10 second. What would be the frequency trend recovery be (can provide consultancy study graph trend)?

Through further clarification, YTL PowerSeraya elaborated on its comments as follows: “Is the frequency drop from 50.0Hz to 49.4Hz of Figure 4 consultation

paper based on the trip of the largest single unit running in the system grid and what this MW is. If not, what is the frequency drop based on and how many MW is assumed to have tripped?

The curve only shows the frequency drop. What simulated system demand was used and what was the generation mix simulated in the system - CCGT, Open Cycle GT, etc.)”

The frequency drop in Figure 4 of the consultation paper was assuming the loss of a generation facility based on Year 2014 typical unit commitment. It was simulated based on system demand of ~7000MW and the generation mix is dominated by CCPs, as observed in Year 2014. Simulation results also showed that Figure 4 remains relevance in today’s context.

9 TC/2015/6 F.7.4.4 of Transmission Code Will the test graph for the frequency decay of 0.6Hz and 0.3Hz against the timing of 30 seconds, 60 seconds and 10 minutes be revised?

The Frequency Response Profile to test the capability of generation facilities remain unchanged.

10 TC/2015/7 F8.1 of Transmission Code Please share with us whether this is still based on the tripping of the largest running set in the system grid and what this value would be in the current system grid.

The Primary Reserve requirement is in response to the Frequency Response Profile (Figure 1 of the consultation paper). The largest online generation facility set in the power system is dependent on market dispatch. However, our records shown that the largest generation facility is CCGT of slightly more than 400MW.

Keppel Merlimau Cogen’s Comments

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S/N Comments/Feedback EMA’s Response 11 We seek to understand the implications of

this proposed enhancement to spinning reserve requirements in respect to the Market rules, System Operations Manual, and EMC Market Manual.

Changes to these documents to reflect the new Primary Reserve requirement will be in accordance to the respective procedures.

12 Additionally, we would like to clarify if this proposal can affect the process from the offering to the dispatch and settlement, as it could potentially impact the MCE and EMC-Genco interface.

Preliminary discussion with EMC is to set the Secondary Reserve requirement to 0MW in the MCE. Changes to the rules/code/manuals/processes will be required to, for example, remove the Secondary Reserve scheduling requirement from the MCE, proposed changes will be communicated to the stakeholders when ready. Please also refer to Section 2.2.4 on the expected NEMS changes.

13 What is the proposed methodology for calculation of the new reserve requirement?

The methodology for calculation of the new Primary Reserve requirement will be identical to the methodology for calculation of the current Primary Reserve. Please refer to Section 12.2 of SOM Rev 10. The current Secondary Reserve requirement will be removed.

14 How will the Reserve Provider Groups be assigned at the point of changeover to the new reserve requirement? Will they be based on current provider groups, or will there be new groups?

While the reserve capability shall be minimum measured at 9s and sustained for 9 minutes and 51 seconds, there is no change to the RPGs that are described in Section 12.3 of the SOM Rev 10 except Secondary Reserve RPG will no longer be required. The RPG assignments for the current Primary Reserve will be retained for the new Primary Reserve.

15 What is the impact on the calculation of system reserve shortfall, particularly in relation to the step-wise CVP method used by the MCE?

Based on our preliminary discussion with EMC, with the new Primary Reserve requirement and removal of Secondary Reserve, the CVP price of current Secondary Reserve will be re-allocated to the CVP price of new Primary Reserve and current Contingency Reserve. Simulation results showed that it is likely to result in lesser occurrences of Contingency Reserve shortfall.

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S/N Comments/Feedback EMA’s Response 16 What will be the effect on the new reserve

requirement upon disconnection of SPPG-TNB interconnector and the grid on island mode?

The methodology for calculation of the new Primary Reserve requirement is the same as the current methodology for calculation of the Primary Reserve as in Section 12.2 of SOM Rev 10 and thus the effect of SPPG-TNB interconnector status change will remain the same.

17 When is the target timeline to implement the new reserve requirement?

The proposed modifications to the Transmission Code set out in Annex 1 will come into effect on 1 October 2017.

Tuas Power Generation’s Comments

18 TC/2015/4 General We note the spinning reserve site test results that were previously used for registration for our existing units are able to meet the new single Primary Reserve requirement. In the recent spinning reserve tests for some of our existing units which have been in service for 10 years or longer, the test results showed that the current Primary and Secondary requirements can be met after optimum tuning of operation parameters of the gas turbine. However, the latest test results could not meet the new Primary Reserve requirement, mostly at the 75% and 90% load level. Degradation of gas turbine performance is expected over its life cycle. As the gas turbine of a combined cycle plant (CCP) is the prime contributor to the spinning

We noted Gencos’ concerns on the capability of their existing generation facilities in meeting new Primary Reserve requirement which was also highlighted to our Consultant during stakeholders’ discussion. The common position established was that the key limitation of frequency response in a CCP is the ramp rate at which plants can respond. This was taken into consideration and the new single Primary Reserve framework does not require a higher rate of change in output than what the existing generation facilities are capable of. In addition, as RE is based on generation facility’s ability to meet its registered standing capability data confirmed during commissioning tests, if there is degradation for older facilities, it is pertinent for Gencos to conduct re-tests, submit revised plant models and update the standing capability data.

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S/N Comments/Feedback EMA’s Response reserve, we are concern that the existing CCPs that have been in service for 10 years or longer would not be able to meet the new Primary Reserve requirement. Further tuning of the gas turbine to meet the new requirement could endanger the hot parts of the gas turbine operating at very high temperature. If the enhancement to the spinning reserve requirement were to go ahead, we propose that the monitoring of Reserve Effectiveness (RE) of a Generation Registered Facility and the criteria for conducting spinning reserve test as defined in the System Operation Manual should be reviewed by taking into consideration the technical limitations faced by existing CCPs with 10 year or longer service. The classification of Reserve Provider Group for a Generation Registered Facility should also be reviewed so as to give existing facilities the avenue to participate in the reserve market that they are capable to provide, instead of applying one new requirement to both “New or Modified units” and “existing units”. F.7.4.2 of Transmission Code

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S/N Comments/Feedback EMA’s Response Our recent test results have shown that some of the existing units with 10 years or longer service are not able to meet the new Primary Reserve requirements after optimum tuning of the gas turbine. Due to expected degradation of gas turbine performance, further tuning to meet the new requirements are constrained by the technical limitations in the material of the hot gas parts of the gas turbine.

19 F 8.2 of Transmission Code The new requirement has added the primary reserve requirement for load range between 90% and 100% shall be linearly interpolated. We would like to comment that at load level near to 100% the primary reserve is not likely to be linear. There are a few factors that could affect the response such as the extent of system disturbances, turbine blade path temperature, ambient temperature etc. The control system of the gas turbines is tracking in real time a few key parameters simultaneously and may automatically limit the output of the gas turbine should the change in power output hit the temperature control limits.

Transmission Code stipulates the minimum Spinning Reserve requirements that of generation facility at selective operating points. The EMA noted that more test points will increase cost and time to conduct Spinning Reserve tests and to strike a balance, a minimum of 7 tests have been stipulated in the SOM and linear interpolation is used to derive expected reserve capability in-between.

Senoko Energy’s Comments

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S/N Comments/Feedback EMA’s Response 20 The proposed change is intended to create

an enhancement to power system security that shall pave the way for future connection of larger sized power plants and potentially large-scale deployment of intermittent generating facilities. It is unclear from the analysis whether the current system has a weakness that would result in an inadequate response to the loss of a large unit load. At the time of the current reserve market design the largest unit was 600MW which is larger than a typical H-class CCGT.

As mentioned in the consultation paper, the Singapore Power System has grown in size and electricity is produced almost entirely by gas-fired combined cycle plants today. Considering that the current Spinning Reserve requirements and corresponding interruptible load settings were established in Year 2001 and 2004 respectively, it was timely to review the Spinning Reserve requirements. When a generation-load imbalance occurs, for example, resulting from a contingency event, there are two distinct phases: containment (or arresting) of the initial frequency excursion restoration of the frequency Under the existing arrangements, the Primary Reserve was largely devoted to containment while the Secondary Reserve was for frequency restoration. The existing arrangements for procuring reserves (including the calculation of the quantum) address the loss of the largest online scheduled generation facility (and its dispatched reserve). The purpose of the proposed change is to accomplish both containment and restoration. The proposal now enables faster response and recovery because additional support is and can be provided by the existing generation facilities in 9 seconds rather than in 30 seconds as shown above in Figure 4 of Section 2.2. To be forward-looking and future ready, this pave the way for future connection of larger size power plants such as H-Class combined-cycle gas turbines, typically 550MW in capacity, the proposed arrangement showed that in the event of such unit tripping (a single contingency event), the time taken for frequency to recover from its minimum to the targeted frequency of 49.7Hz could be shortened from 106 seconds to 18 seconds as shown above in Figure 4 of Section 2.2.

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S/N Comments/Feedback EMA’s Response Hence, the proposed arrangements for the frequency responsive generators and interruptible loads will see a larger response in a shorter timeframe to any generator tripping incident and enhance system security. The review showed that the proposed framework has the advantage of both simplifying reserve scheduling by the MCE thereby improving market efficiency, and improved performance in the form of the system frequency recovery time following a contingency.

21 As such, we request a more formal illustration of how the costs of the change in market design (e.g. rule changes and modifications to the market-clearing engine and settlement systems etc.) exceed the system security benefits associated with the amalgamation of primary and secondary reserve classes. Furthermore, the paper is silent on whether the proposal would affect, if at all, the reserve requirement (in MW) to be procured.

The methodology for calculation of the new single Primary Reserve requirement to be procured will be the same as the current methodology for calculation of the current Primary Reserve. Please refer to Section 12.2 of SOM Rev 10. The current Secondary Reserve requirement will not be required. The Consultant’s study was purely technical in nature and did not include a formal cost-benefit analysis considering the costs of the change in market design. However, benefits are apparent arising from simplifications in the removal of Secondary Reserve from scheduling and settlements. The proposed arrangements would effectively do away with the need for the MCE to schedule Secondary Reserve. In addition, the Primary Reserve capability of existing generation facilities is increased from the current 8% to 9% while maintaining the same Primary Reserve requirement to be scheduled by the MCE, the supply cushion for Primary Reserve should improve (see Figure 3 of Section 2.2 above), which will lead to increased competition and potentially lower market clearing prices, i.e. there is clear benefits in adopting the new Primary Reserve framework.

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S/N Comments/Feedback EMA’s Response

Diamond Energy’s Comments

22 Slide 3 Limitation of our Feedback Unlike other consultations conducted by

the EMA, the consultant’s report in this instance has not been made available for comment

Based on the limited information made available, our ability to submit meaningful comments is significantly hampered

As a result, we are unable to comprehend the rationale and justification of the proposed arrangements for Interruptible Load

Notwithstanding the limited information that has been made available, this presentation will demonstrate the unsuitability of the proposed changes to Interruptible Load

If PSO insists on combining primary and secondary reserve classes into a single class of reserve, retaining the present Interruptible Load settings for secondary reserve (i.e. 49.7 Hz for 30 seconds) is more appropriate

The Consultant’s report contains Licensee-specific sensitive information and was thus, not released. In any case, the presentation slides used during the briefing to all stakeholders already captured key points of the report. Moreover, the set of slides was extended to all stakeholders after the briefing. The proposed reserve requirements are considered prudent in preparing for future needs. The counterfactual of not reviewing such service would expose the power system to a reactionary development of sub-optimal methods of accommodating future changes. To recap, the objective of reserves is to arrest a frequency decline and then restore the frequency to an acceptable post-event level following a contingency event to ensure secure operation of the power system. Delay in respond would have impact on security of the power system. The proposed reserve requirements meet this objective with a single service, as opposed to the current two.

23 Slide 5 Background

The comment that EMA and its Consultant did not engage IL providers of the proposed arrangement is not true and unfair.

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S/N Comments/Feedback EMA’s Response EMA engaged IES to conduct a review

of the Spinning Reserve Requirements for the Singapore Power System which included engagement with industry stakeholders

IES conducted a briefing to the Gencos on 15th August 2014, however, there was no engagement with Diamond Energy by the consultant

PSO is proposing major changes to the reserve market structure, including Interruptible Loads, even though the consultant did not engage Interruptible Load Providers and Interruptible Loads were not specified in the consultant’s scope as stated in the published tender

Diamond Energy, the market participant managing 100% of Primary and Secondary Interruptible Loads, was not engaged by IES and would be a significantly impaired party based on the proposed changes

The earlier presentation to Gencos on 15th Aug 2014 was for discussion pertaining to power plant performance, etc. The PSO had on 26th Nov 14 separately briefed all Interruptible Load (IL) providers on the revised requirements on IL Facilities. During the presentation, PSO explained the merit, rationale as well as implications of proposed reserve requirements. Queries raised by IL providers were also clarified by the PSO. Further to this presentation, the PSO took in another discussion with Diamond Energy on 5th Dec 2014 at its request, to address its outstanding concerns on the revised requirements. Although ILs were not explicitly stated in the published tender, the Consultant included ILs in their study as the objective of the consultancy study was to review the Spinning Reserve regime for the Singapore Power System and ILs are also providers of Spinning Reserve. To reiterate, PSO did engage all existing as well as other potential IL providers.

24 Slide 7 Introduction Diamond Energy has reviewed the

consultation paper published by PSO titled “Enhancement of Spinning Reserve Requirements for the Singapore Power System”

The rationale had been clearly explained in the consultation paper. Furthermore, the current system Spinning Reserve requirements and corresponding IL settings were established in Year 2001 and 2004 respectively where there was a mix of older conventional steam turbine generators and newer gas-fired CCGTs. With the current predominately gas-fired and larger capacity CCGTs and the trend is likely to continue going forward, it is therefore timely to review the system Spinning Reserve requirements. Our power system has to be future readied, changes to power

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S/N Comments/Feedback EMA’s Response The rationale for overhauling the

current reserve scheme has not been adequately justified

A technical study on spinning reserves, without a comprehensive cost benefit assessment, is insufficient to justify an entire revamp of the current reserve structure, and does not reflect well on the EMA

This presentation is intended to communicate our concerns with regards to the spinning reserve assessment carried out by IES, and also explain why the proposed changes to Interruptible Load are not appropriate

The study carried out is unbalanced, with no analysis performed for Interruptible Load and the implications of the proposed scheme

Our comments are based on the limited information provided

Slide 9 Are the changes warranted? The “Current Scenario” demonstrated

frequency recovery well within the requirement specified by the consultant

No justification for a “faster recovery” has been made

infrastructures/facilities take time; hence, EMA must be forward looking and be future ready. With regard to cost-benefit, the proposed arrangements would effectively do away with the need for the MCE to schedule Secondary Reserve. In addition, the Primary Reserve capability of existing generation facility is increased from the current 8% to 9% while maintaining the same Primary Reserve requirement to be scheduled by the MCE, the supply cushion for Primary Reserve should improve (see Figure 3 of Section 2.2 above), which will lead to increased competition and potentially lower market clearing prices, i.e. there is clear benefits in adopting the new Primary Reserve framework. Hence, it is clear that there are net benefits to the Market with practically no additional cost imposing on the Market (Participants) and Consumers. To engage in a detailed cost-benefit analysis would be just a costly, time consuming and unproductive exercise. As explained in the consultation paper, the assessment clearly demonstrated that the new single Primary Reserve class will enhance power system security with faster system frequency recovery following loss of generation facility contingencies (please refer to Figure 4 in the consultation paper). The proposal will also simplify both Offer Submissions to the NEMS and Market Clearing Engine runs. To reiterate, the EMA remains technology neutrality and the new single Primary Reserve class serves to enhance security of the power system and to meet future development and needs. Diamond Energy’s accusation of the EMA being discriminatory is uncalled for. H-Class combined-cycle gas turbines (CCGTs) is just an example cited; the proposed arrangement can also cater for any new generation facilities which are likely to be larger in size than the existing CCGTs of ~400MW.

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S/N Comments/Feedback EMA’s Response If the proposed changes are intended

to address possible future scenarios caused by connection of larger “H Class” CCGT facilities and/or the deployment of intermittent generation (as suggested in the consultation paper) then changes to the reserve requirements, if any, should only be made when the need arises

The EMA has always maintained a “technology neutral” regulatory policy, and any changes to the market structure should be non-discriminatory

Slide 18 Where is the Cost-Benefit Analysis?

25 Slide 10 Timeframe for entry of H-Class CCGTs The graph below is a conservative

projection of reserve margin (intermittent generation and other embedded generation projects are ignored)

The entry of H Class CCGT facilities is not expected over the medium term, hence this is not appropriate justification for overhauling the reserve market

An appropriate trigger point to revisit this should be established in advance of the 30% reserve margin cited in the

Part of this review is to assess that the Singapore Power System can cope with future connection of such larger size power plants, H-Class CCGT. Moreover, its assertion that the entry of H-Class CCGTs is not expected over the medium term as well as the intermittent generation cap is not expected to be reached for 40 years are purely speculative or is IL provider dictating Energy Policy for Singapore? To reiterate, the EMA must ensure our power system is future readied, and the review enhances security of the power system and is necessary to meet future development and needs of the power system including large scale deployment of intermittent generation in the near future. To be forward looking and future ready, this pave the way for future connection of larger size power plants such as H-Class CCGTs, typically

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S/N Comments/Feedback EMA’s Response Capacity Assurance Scheme such as 40%

Slide 11 Deployment of intermittent generation The current cap for intermittent

generation has been set at 600 MW Such a cap would not have been

established if it could not be supported by the existing market structure

We therefore deduce that the power system can support 600 MW of intermittent generation as it is currently structured

There was only 25.5 MW of installed intermittent generation capacity in 2014 (less than 5% of the cap)

2014 saw an increase of 13.7 MW of intermittent generation

At this build rate, the cap is not expected to be reached for 40 years

It is therefore appropriate to establish an appropriate trigger to revisit this when intermittent generation reaches 80% of the cap

550MW in capacity, the proposed arrangement showed that the time taken for frequency to recover from its minimum to the targeted frequency of 49.7Hz has shortened from 106 seconds to 18 seconds as shown above in Figure 4 of Section 2.2.

26 Slides 12 to 17 Comments on consultant’s assessment

Assessment of the new Primary Reserve requirement considered both current power system conditions (peak and light load) as well as future conditions for Year 2023 (peak and light load). A model was developed to assess the responses of the existing framework and alternatives. The following criteria were adopted for Interruptible Load:

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S/N Comments/Feedback EMA’s Response Framework should consider a single service to be consistent with the

single service offered by generation facility under the new Primary Reserve requirement;

Similar method of assessing Reserve Effectiveness and Reserve Provider Groups as applied to generation facility, should also apply to ILs providing reserve services;

Time of delivery of the Interruptible Load service should be consistent with new Primary Reserve to enhance arrest of frequency decline.

Responses of generation facilities and ILs are different in nature. When responding to system frequency excursion, generation facility will automatically respond according to their governor action whereas ILs are activated based on the under frequency relay setting. Based on the two existing settings of IL, the Consultant studied options such as combination of both settings and adopting the existing trigger setting for Primary Reserve only. In view that the activation of ILs is to complement the Spinning Reserves provided by generation facilities, the revised setting of 49.7Hz instantaneously had been assessed to enhance arresting the frequency decline, and hence improved security of power system.

27 Slide 20 Proposed Changes to Interruptible Load It is not clear how the proposed

changes to spinning reserve requirements translate to instantaneous activation of Interruptible Load at 49.7 Hz

Nature of interruptible load is different from spinning reserve

ILs are to offer an equivalent service similar to generation facilities. For a given contingency, generation facilities and ILs will provide different responses depending on how much generation facilities and ILs reserves are available. The approach is to complement the services provided by a generation facilities and ILs to ensure power system security. Thus, generation facilities provide the immediate respond to arrest the initial frequency dip following a contingency event, thereafter ILs together with generation facilities are to recover the system frequency to 49.7Hz as soon as possible to ensure secure operation of the power system. As such, the revised reserve regime only requires ILs to be activated at 49.7Hz

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S/N Comments/Feedback EMA’s Response Spinning reserve is always in operation

so the proposed changes do not have a major operational impact

Premature activation of Interruptible Load when system stability is not under major threat is a waste of reserve, and this should be assessed

The proposed change in spinning reserve would mean that the generator is providing at a faster rate what it would have provided anyway

However, the proposed change in Interruptible Load would result in a disproportionate increase in activations and is of a much greater operational impact

instantaneously instead of what the generation facilities do i.e. whenever system frequency dips. Note that scheduled reserves by the MCE are to address the loss of single largest online generation facility, not when system stability is under major threat such as tripping of multiple generation facilities. To reiterate, currently, all frequency responsive generation facilities would automatically provide Primary and Secondary Reserves whenever there is tripping of any generation facility; while ILs activation have been disproportionately low with the current IL setting for Primary and Secondary Reserves. The revised setting would at least minimise the free-ridings.

28 Slides 36 to 37 Summary of Observations If the proposed changes were in place,

there would have been 4 frequency-related activation events for IL in Jan-Feb 2015

It was observed in the last 3 events, that the system frequency only touched 49.7 Hz briefly, and recovered very quickly

There were no abnormal condition advisories issued during these 4 events and the consultant should explain what was the cause of these frequency drops

The cited incidents were due to non-market participant’s generator tripping; PSO cannot issue advisory notice on non-market participants’ major equipment outage. In any case, providing abnormal condition advisory serve little purpose as system frequency typically recovered within a dispatch period after the non-market participants increased output of its generation facilities, and there is no further action required from the Market Participants. The Consultant’s study considered both interconnected and isolated conditions. Prior to the inception of IL scheme in Year 2004, Singapore and Malaysia power systems are already interconnected since mid-1980s and this has been clearly published in IL FAQ (https://www.emcsg.com/aboutthemarket/loadfacilityregistration). ILs are required to respond in accordance to the state of the system frequency

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S/N Comments/Feedback EMA’s Response Interruptible Load should not be

required to respond to contingencies in Malaysia that result in frequency drop in Singapore due to synchronization without adequate compensation

The fact that frequency has dropped to 49.7 Hz so many times without a corresponding forced outage of generation facility is concerning and highlights that the proposed set-point is not appropriate

In such incidents, activation of Interruptible Load would have been a premature use of a valuable resource, as the event was not serious

With the system recovering quickly anyway, instantaneous IL activation at 49.7 Hz poses a potential risk of over-frequency (as happened in New Zealand in 2004) and IL resources should complement spinning reserves, not work against them

49.7 Hz is too close to the normal operating frequency range (50±0.2 Hz) to be considered for instantaneous IL activation

However, a time-delayed response (30 seconds) at 49.7 Hz (as given by the current secondary reserve scheme for IL) would be more appropriate

(regardless of whether our power system is interconnected or isolated at the point in time of a contingency event) to complement the Spinning Reserves provided by generation facilities so as to ensure secure operation of the power system following a contingency event. The revised reserve regime requires generation facilities to provide the immediate respond to arrest the initial frequency dip following a contingency event, thereafter ILs together with generation facilities are to recover the system frequency to 49.7Hz as soon as possible to ensure secure operation of the power system. Hence, the revised reserve regime requires IL only respond at 49.7Hz instantaneously to complement generation facilities response. Any delay in respond to quickly recover the system frequency would compromise the power system security. Diamond Energy citing of the NZ 2004 over frequency incident is irrelevant as for the NEMS, there are system level limits on ILs reserves that can be scheduled by the MCE to prevent excessive disconnection of loads.

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S/N Comments/Feedback EMA’s Response 29 Slide 39

Further Considerations The frequency profile for testing

generating units (Figure 1 in the consultation paper) is based on the simulated loss of the largest generating unit online

This profile further served as the basis for deciding the frequency set-points for Interruptible Load

The consultant has concluded that this profile remains relevant, there is no need to change the frequency set-points

Capability of ILs is measured by artificially subject the load to a Frequency Response Profile as shown in Figure 3 of consultation paper reproduced:

The setting of ILs is revised to 49.7Hz instantaneous.

30 Slide 40 Comparison with Other Electricity Markets If spinning reserve requirements have

been compared with other electricity markets, it is only fair that similar comparisons for Interruptible Load should also be carried out

Some examples are listed below Ireland: Interruptible Load is activated

at 49.3 Hz New Zealand: Interruptible Load is

activated at 49.25 Hz (Reference: PSO comments to Paper

EMC/RCP/33/2007/CP15)

Please refer to our response above on point 28 on the rationale on the revised IL setting based on new reserve regime. Each power system is unique, IL setting adopted in other utilities depends on many factors such as composition and types of generation facilities, contingency event to cater for etc. for a given power system. Singapore’s power system is predominantly gas-fired CCGTs where output is known to reduce due to speed effect of Gas Turbines when there is large system frequency dips. In New Zealand, for example, hydro generators dominates, which have a greater tolerance for frequency deviations. In Ireland, there is a HVDC interconnection with the UK that allows frequency excursions to be arrested quickly. Hence, it is only logical that Singapore’s IL activation should be at a different setting than theirs, a result of rigorous engineering studies, Diamond Energy’s demand that IL frequency setting should be set that of similar electricity markets is not feasible.

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S/N Comments/Feedback EMA’s Response Justification should be provided why the

frequency settings proposed are considerably higher than what is implemented in similar electricity markets which the Singapore market has been designed against

31 Slide 41

Previous Re-evaluation of IL Frequency Settings In 2007, a proposal was submitted to

the Rules Change Panel to consider increasing the frequency set-points for Interruptible Load

Many factors were highlighted by major players and the conclusion was reached that it was not wise to make changes

The following comment was made by PSO in this regard: “Supply and demand fluctuations can occasionally cause the system frequency to drop below 49.8 Hz. If IL frequency setting was set slightly lower than 49.8 Hz as proposed by EMC, it could result in increased occurrences of unnecessary activations of IL due to causes other than forced outages. This will deprive the power system of the required reserves should a contingency happen before ILFs can be re-connected to the

The quoted comment was valid in Year 2007. However, our power system has since grown in size and there have been significant changes in generation facilities composition with the current predominately gas-fired and larger capacity CCGTs and the trend is likely to continue, including large scale deployment of intermittent generation in the near future, hence the revised reserve regime been proposed to ensure secure operation of the power system going forward.

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S/N Comments/Feedback EMA’s Response system. Therefore, it is important to set the activation frequency of ILFs at the current level, where it is most needed and should be activated during a significant forced outage rather than the minor fluctuations or forced outage events(Reference: PSO comments to Paper EMC/RCP/33/2007/CP15)”

These concerns still remain valid

32 Slides 43 to 44 Conclusion The current reserve arrangements are

acceptable according to the consultant, therefore, we do not see a need for the proposed change until such time as the triggers suggested earlier have been satisfied

The detailed report provided by the consultant should be shared in its entirety in a transparent manner to the industry, this is consistent with standard EMA’s established practice when major policy changes are proposed

Next review should be triggered by the following factors Reserve margin reaching 40% (not

likely to happen for at least 10 years) Intermittent generation reaching 80%

of cap (not likely to happen for at least 10 years)

Diamond Energy’s comment that “the consultant’s assessment was that the current scheme is acceptable” was taken out of context. The Consultant had concluded that the current scheme was acceptable in the case where there is no larger size power plant such as H-Class CCGT in Singapore. However, with larger size power plants in the foreseeable future, the Consultant’s results indicate that the system frequency recovery based on the current scheme is no longer acceptable in terms of system security. As explained above, the activation of ILs is to complement the spinning reserves provided by generation facilities. The setting is revised to 49.7Hz instantaneous so as to enhance security of power system. However, considering that it is an existing IL provider, PSO is prepared to grant a grace period of 6-12 months to comply with the revised requirements so as to ease the transition. Failing which it shall not be allowed to participate in the new Primary Reserve market. Changing the current setting of 49.4Hz for Primary Reserve and 49.7Hz at 30 seconds for Secondary Reserve to 49.7Hz to the new Primary Reserve setting of 49.7Hz instantaneous can be easily implemented by changing of under frequency relay setting. As such there shall not be compensation to any

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S/N Comments/Feedback EMA’s Response If PSO is insistent on carrying out a

revamp of the reserve structure now, even though it is not required, A comprehensive technical study

also incorporating Interruptible Load should be conducted along with a cost-benefit assessment

If the study results in the same recommendation for combining the primary and secondary reserve classes, Diamond Energy proposes the following For the new reserve class, set-point

for IL should be 49.7 Hz for duration of 30 seconds

If the assessment results in a different set-point requirement, existing IL facilities should be allowed to maintain legacy settings for the duration of their existing contracts

Compensation should be provided to impaired parties

IL cap for each reserve class should be set equal in MW terms to the cap for Contingency reserve

parties. IL providers are at liberty to not participate in the new primary reserve market if it so decides. The PSO noted its proposal on the IL cap for each reserve class. The PSO will consider it in our ongoing review and update in SOM accordingly. Please refer to our earlier responses to the other similar comments.

Sembcorp Cogen’s Comments

33 We would like to point out that such a change would be at significant cost to the

The benefits include simpler market processes, fewer constraint equations and simpler settlement processes, all of which would generate ongoing benefits on a market-wide basis over time.

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S/N Comments/Feedback EMA’s Response industry, including (but not limited to) the following: (i) Reconfiguration of EMC’s load

scheduler to remove the existing Secondary Reserve and modify the requirements for Primary Reserve.

(ii) Gencos will also have to reconfigure their internal systems (e.g., Plant Historian Databases as well as trading templates and bid tracking systems, etc) at some cost.

Preliminary discussion with EMC is to set the Secondary Reserve requirement to 0MW in the MCE. Please also refer to Section 2.2.4 on the expected changes in NEMS and MCE and the estimated cost.

34 Given that the industry is currently experiencing a period of significant downward pressure to profit levels, we would suggest that you consider the need for such a change at this time versus the potential benefits. With installed capacity being approximately twice peak system load, Singapore’s power system is one of the most resilient in the world. Hence the incremental benefits arising from this proposed enhancement to the power systems may not be particularly meaningful when viewed through the lens of today’s context and the costs of implementing this change.

The EMA must ensure our power system is future readied, this review enhances security of the power system and is necessary to meet future development and needs of the power system including large scale deployment of intermittent generation in the near future. To be forward-looking and future ready, this pave the way for future connection of larger size power plants such as H-Class combined-cycle gas turbine, typically 550MW in capacity, the proposed arrangement showed that the time taken for frequency to recover from its minimum to the targeted frequency of 49.7Hz has shortened from 106 seconds to 18 seconds as shown above in Figure 4 of Section 2.2. The proposed arrangements would effectively do away with the need for the MCE to schedule Secondary Reserve. In addition, the Primary Reserve capability of existing generation facility is increased from the current 8% to 9% while maintaining the same Primary Reserve requirement to be scheduled by the MCE, the supply cushion for Primary Reserve should improve (see Figure 3 of Section 2.2 above), which will lead to increased competition and

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S/N Comments/Feedback EMA’s Response potentially lower market clearing prices, i.e. there is clear benefits in adopting the new Primary Reserve framework.