RCP PAPER NO. : EMC/RCP/120/2021/CP86

SUBJECT : RESERVE PROVISION BY NON-SPINNING GENERATION

FACILITIES

FOR : DECISION

PREPARED BY : JOASH SENG

ECONOMIST

REVIEWED BY : POA TIONG SIAW

SVP, MARKET ADMINISTRATION

DATE OF MEETING : 27 JANUARY 2021

_________________________________________________________________________

Executive Summary

This paper proposes to enhance the modelling of primary and contingency reserve

capabilities of generation registered facilities (GRF). The enhancements will better

represent the reserve capabilities of facilities such as open cycle gas turbine (OCGT) and

battery energy storage systems (BESS) that can meet the reserve performance standards

from a non-spinning start-state. Such facilities can then be scheduled to provide reserve

while being scheduled for energy levels below LowLoad.

The proposal would allow more resources to participate and compete in the reserve

markets, thereby enhancing system security and market efficiency. To mitigate potential

risks to the system security, safeguards are suggested by the PSO to limit the quantity of

contingency reserve that can be scheduled from non-spinning generation facilities.

The EMC recommends for the RCP to:

1. Support the proposal to allow primary and contingency reserves to be provided

from generation facilities with loading below LowLoad point;

2. Support the proposal to subject reserve scheduling of non-spinning generators to

the allowable limit, with an initial value of 100MW for contingency reserve; and

3. Task the EMC to work with the PSO to assess the impacts and costs of

implementation options, and draft relevant modifications to the Market Rules in

order for reserve-capable non-spinning generation facilities to provide primary and

contingency reserves in the SWEM.

The RCP discussed the proposal at its 120th meeting. Upon deliberation, the RCP considered that deeper technical investigation is needed to: (i) ascertain the usefulness of the proposal, as there is uncertainty on whether generators/storage facilities can operate below minimum stable load in a viable manner; and (ii) determine the most appropriate

approach to modify the reserve envelop, given the impact and costs of different implementation options.

The RCP by majority vote supported, in-principle, 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.

EMC/RCP/120/2021/CP86 3

1. Introduction

This paper discusses a proposal raised by Senoko Energy at the 2019/20 mid-year workplan

review exercise. Senoko Energy proposed to allow generation assets that can meet reserve

performance standard from an offline start-state (e.g., open cycle gas turbines), to provide

ancillary services without being scheduled for energy.

2. Background

2.1. Ancillary Services in the SWEM

In the Singapore Wholesale Electricity Market (SWEM), reserves and regulation products are

real-time ancillary services required for the stable functioning of the power system when

contingency events and disturbances occur. These products are largely provided by

Generation Registered Facilities (GRF) that are synchronised to the grid and able to respond

to system frequency changes. In the SWEM, reserves are classified into ‘primary’ and

‘contingency’ reserves. Reserve providers scheduled for these two classes will have to

respond within 9 seconds and 10 minutes respectively.

To ensure that dispatch schedules are feasible, the Market Clearing Engine (MCE) models

reserves and regulation constraints faced by GRFs that provide energy and ancillary services

in the SWEM. Doing so reflects the physical capabilities of the GRFs and enables the MCE to

produce security-constrained economic dispatch schedules for the power system.

2.2. Modelling of Reserve in the SWEM

Reserves can be provided by GRFs, and Load Registered Facilities (LRF) under the

interruptible load scheme.

Every LRF providing reserve is subject to a facility-specific maximum reserve capacity

constraint, which limits the amount of reserve it can be scheduled for. The LRF’s maximum

reserve capacity is verified at the facility registration stage through site tests and reports to

ascertain that LRF has met the performance standards as stipulated in the System Operating

Manual and Transmission Code.

GRFs registered to provide reserves are subject to the following main constraints:

(a) Maximum Reserve Capacity to limit the scheduled reserve to the maximum amount of

reserve that a GRF has offered;

(b) Reserve Generation Max Constraint to limit a GRF’s aggregate scheduled energy,

reserve and regulation to its maximum generation capacity;

(c) Reserve Generation Segments, where reserve provision capability differs depending

on the generation loading level of the GRF. This capability is depicted as 3 reserve

generation line segments spanning from the LowLoad 1 point to

ReserveGenerationMax2 point; and

1 LowLoad is the minimum loading level at which a GRF can provide reserve – this is usually set at the Minimum Stable Load (MSL) registered for the generation facility. 2 ReserveGenerationMax is the maximum combined generation and reserve that can be provided by a GRF.

EMC/RCP/120/2021/CP86 4

(d) Reserve Proportion Constraint such that the amount of scheduled reserve cannot

exceed a proportion of the scheduled energy3.

These constraints are depicted in Figure 1 below, where (a) is represented by the black

horizontal line segment, (b) is represented by the blue line segment, (c) is represented by the

red line segments, and (d) is represented by an orange line segment that starts from the graph

origin. These line segments ‘envelop’ the reserve solution space for a GRF, forming a reserve

(capability) envelope for the GRF.

Figure 1: Existing Modelling of Contingency Reserve Envelope

In addition, considering that typically GRFs operating below LowLoad will be unable to

respond within 9 seconds to provide primary reserve, an additional constraint4 is applied to

disallow a GRF, whose energy scheduled is below LowLoad, from being scheduled for primary

reserve. As a result, the part of the solution space where energy scheduled is below LowLoad

is considered infeasible and removed, as depicted in Figure 2.

3 In addition to Reserve Proportion Constraint, a less restricting constraint (Reserve Proportion Ramp Constraint) would also limit the provision of contingency reserve to a proportion of the ExpectedStartGeneration and/or energy scheduled. This effectively restrict any contingency reserve provision from units which do not provide energy (i.e. ExpectedStartGeneation is 0) during normal times. 4 Mixed Integer Program based reserve constraint.

EMC/RCP/120/2021/CP86 5

Figure 2: Existing Modelling of Primary Reserve Envelope

3. Analysis

3.1. Reserve Capability Differ for Non-spinning Generation Facilities

The proposal centres around the reserve capability of generation facilities that can provide

reserve from an offline start-state. Specifically, generation facilities like OCGTs and BESSs

have relatively higher/more flexible ramp rates. Some OCGTs claim to be able to ramp up

from zero to a significant proportion of its load within a time norm of 8-12 minutes5, while some

BESSs were reported to be able to ramp up to full power within 0.2 seconds6.

OCGTs, due to its low fuel efficiency and therefore higher variable cost, are usually positioned

as peaking capacity that supply energy for a few peak periods during the year. In other words,

OCGTs are not expected to provide energy in normal times. BESSs, being duration-limited

rapid response resources, are also not best utilised when primarily scheduled for providing

energy continuously. Instead, they are better suited to provide load-following/frequency

regulation and fast reserve services. While OCGTs and BESSs are unlikely to be scheduled

5 Some OCGT models were reported to be able to ramp up to full load (260 MW) within 12 minutes. Some GT models from Wartsila (50SG, 34SG) and GE (LMS 100) were noted to have such capabilities. 6 Source: Batteries: Beyond The Spin; Everoze, et. al., (2017) - Queen’s University Belfast (QUB) research at Kilroot Power Station, Northern Ireland demonstrated that with the right controls in place, BESS can ramp to fully power in less than 200ms. Source: Hornsdale Power Reserve: Year 1 Technical and Market Impact Case Study; Aurecon (2018) - Hornsdale Power Reserve (HPR), the world’s largest lithium-ion battery ESS was recorded to be able to discharge up to 100MW in less than 150ms. Under the System Integrity Protection Scheme (SIPS), the HPR is intended to provide a premium service in Fast Frequency Response (FFR) with fast response time of approx. 100ms. During FFR modelling, the HPR’s modelled response based on lab tested characteristics is up to 100 MW with a response time of 100ms.

EMC/RCP/120/2021/CP86 6

for energy in most periods, they are still able to provide reserves from an offline start-state due

to their ‘fast ramping’ capability.

Offline vs. Non-Spinning Start State

Discussions with the PSO suggest that calling on offline(/non-synchronised) generators to

provide reserves pose considerable risk to the power system, in part due to the need for plant

start-up. Generators should be minimally synchronised to the grid and generating to be eligible

for reserves provision. While BESSs may be connected/synchronised to the grid at 0MW

output, this is unlikely the case for OCGTs that need to be generating above 0MW in order to

be synchronised and ready to provide contingency reserve.

For avoidance of doubt, the PSO refers to instances where generators are synchronised to

the grid at loading levels below LowLoad(/MSL) as “non-spinning”.7 The PSO is of the view

that it is valuable to extend reserve provision eligibility to reserve capable non-spinning

generators. Performance testing can be conducted to ascertain the lowest output level (0MW

inclusive) that non-spinning generators are able to provide reserves reliably. Eligibility of offline

generators to provide reserve can be revisited when there is adequate track record to assure

the system operator that they can meet reserve performance standards.

Restrictive Parameters for Reserve Capable Non-Spinning Assets

Currently, all GRFs are subject to the same set of parameters determining their reserve

envelopes. As illustrated in Figure 1, GRFs are subject to a Reserve Proportion Constraint,

where the amount of scheduled reserve cannot exceed a proportion of the scheduled energy.

This Reserve Proportion Constraint implies that GRFs must be scheduled for energy (and

consequently be synchronised and generating during the dispatch period) in order to be

scheduled for contingency reserve. While the current formulation ensures that conventional

GRFs, e.g., combined cycle gas turbines (CCGT), can provide scheduled reserves in a stable

and sustained manner, it is not reflective of the ability of certain generation facilities to ramp

up steadily from a non-spinning state (i.e., not scheduled for energy) when called upon. The

current model, when applied to such facilities, places an unnecessary constraint on the

feasible solution space. As a result, in meeting the reserve requirements, the MCE may have

to: (a) schedule less efficient units to generate; and (b) restrain the generation level of more

efficient units. This can result in less than optimal dispatch schedules.

The proposal seeks to distinguish reserve-capable non-spinning generation facilities

from conventional GRF reserve providers, so that the former can be scheduled for

contingency reserves without being concurrently scheduled for energy levels at/above

LowLoad. Doing so can potentially improve the utilisation of spinning GRFs, since a

proportion of the reserve requirement can be met by non-spinning generation facilities.

7 This is opposed to ‘spinning’ generators that are generators synchronised to the grid at load levels at or above MSL.

EMC/RCP/120/2021/CP86 7

3.2. Modifications to Reserve Envelope for Reserve-capable Non-spinning Generation Facilities

In order for non-spinning generation facilities to provide contingency reserve, the following

modifications to the reserve envelope are required to represent such generation facilities:

(a) Introduce additional parameter to represent generation facilities’ reserve

capability below LowLoad level. This parameter (i.e., non-spin reserve point)

should indicate the maximum MW quantity a unit can ramp up to from its lowest reserve

capable “non-spinning” loading level within 10 minutes. It should be determined based

on actual testing results approved by the PSO. For BESS, the non-spin reserve point

could potentially be set at 0MW (as represented by the y-intercept point highlighted in

green in Figure 3), subject to future testing results from ongoing BESS testbeds.

By connecting the non-spin reserve point and LowLoad reserve point, a new reserve

generation segment (represented by ‘line segment 4’) is created to limit the solution

space for reserve-capable non-spinning GRFs whose energy schedule are below

LowLoad. For GRFs that are not capable of fast ramping from a non-spinning start

state, its non-spin reserve point should be set at 0 or invalidated.

(b) Remove Reserve Proportion Constraint and Reserve Proportion Ramp

Constraint. The next step is to remove these two constraints for GRFs that are

approved to provide non-spinning reserves. This would allow reserve-capable non-

spinning GRFs to be scheduled for contingency reserve from an energy level below

the conventional LowLoad point for conventional generators (i.e., Minimum Stable

Load).

(c) Convexity Test for Reserve Envelope. Tests to validate the convexity of the reserve

envelope will still apply as part of the pre-processing of the GRF’s standing capability

data, to ensure the MCE receives inputs that will produce valid results. With the

introduction of the new parameter: “non-spin reserve point”, the convexity test should

be conducted based on the new solution space which consists of four segments (as

illustrated in Figure 3).

The proposed modifications produce a better representation of the reserve capability of non-

spinning generation facilities that are capable of meeting reserve performance standards and

provide more assurance from a security standpoint.

EMC/RCP/120/2021/CP86 8

Figure 3: Sample Modified Contingency Reserve Envelope

3.3. Other Considerations

EMC also assessed the proposal against ongoing developments in the SWEM and the

associated risks and benefits of enabling fast start units to provide non-spinning reserves.

(a) Risks of Non-spinning Resources Providing Reserves. As LRFs are not ‘steel in

the ground’ and not on Automatic Governor Control, the PSO has instituted maximum

allowable limits to safeguard power system reliability. As the performance of non-

spinning reserve providers have not been proven over time, the PSO has thus

suggested an initial limit of 100 MW for contingency reserve scheduled from reserve-

capable non-spinning GRFs. The allowable limit for non-spinning reserves can be

subject to review. (Please refer to Annex A for a comparison with non-spinning reserve

treatment in the PJM).

(b) Applicability to Provision of Primary Reserve. The EMC notes that the proposal

elaborated through sections 3.1 and 3.2 was to allow for contingency reserve to be

scheduled without energy. However, we assessed that the proposed remodelling could

also apply to primary reserve provision by BESSs, which are able to respond within 9

seconds with their rapid response capability.

With Singapore’s national deployment target of 200 MW of BESS beyond 2025,

several BESS projects are slated for commissioning by 2021, with the intention of

providing ancillary services in the SWEM. The current reserve constraints modelled for

GRFs are not applicable to BESS units and could hinder their provision of valuable

services to the SWEM.

EMC proposes for the modified reserve envelope in section 3.2 apply to primary

reserve for primary reserve-capable non-spinning generation facilities (e.g., BESS).

Like in the case of contingency reserve, such generation facilities that wish to provide

primary reserve from a non-spinning start-state would need to undergo capability

EMC/RCP/120/2021/CP86 9

testing with the PSO to ascertain the non-spin reserve point. For such resources, the

solution space for primary reserve should be the similar to the one illustrated in Figure

3 instead of that in Figure 2.

4. Consultation

The concept paper was published for consultation on 15 October 2020. Comments were

received from 5 stakeholders, namely Senoko, Sembcorp, PacificLight, Keppel, and the Power

System Operator.

Comments

from Comments EMC’s Response

Senoko

We are fully supportive of this proposal as it not only

better utilizes OCGTs and BESSs, it also frees up

‘spinning capacity’ which could flow into the energy

market. Inclusion of non-spinning GRFs in the reserve

market might not only result in units generating at a

higher efficiency level (less instances of running at part

load) but it also enhances system security in the

SWEM.

While we understand PSO’s concerns on LRFs

providing reserves beyond 30% of the total system

requirement, non-spinning GRFs (I.E., OCGTs) have

consistently proven over time of its ability to ramp

up to levels above 100MW in under 10 minutes.

Hence, we disagree with the proposed 100MW

aggregate cap on non-spinning GRFs.

As a suggestion to alleviate reliability concerns, PSO

could conduct periodic ‘reserve tests’ on these

non-spinning GRFs and place unit specific caps or

ratings based on actual test results.

EMC notes Senoko’s comments.

Concerning Senoko’s suggestions,

unannounced periodic reserve tests

could be helpful to review and update

the reserve provider group and

specific cap that a non-spinning GRF

is subject to.

For avoidance of doubt, the PSO

clarified that non-spinning GRFs are

synchronised (see sect 3.1), and

hence not synonymous with GRFs

that are offline.

Sembcorp

Sembcorp is supportive of the proposal to allow

primary and contingency reserves to be provided from

reserve-capable non-spinning generation facilities as

OCGTs and BESSs.

The rapid injection of power by BESSs in the system

would help provide initial stabilisation of the grid as

other technologies such as OCGTs and CCGTs ramp

up and dispatch power to recover grid frequency back

to stable levels prevent sector or system-wide

blackouts. To ensure system security, EMC may

consider modelling the aggregate primary and

contingency reserve capacity required by each

form of technology on a time scale. The intent is to

determine the required amount of reserve from BESSs

and OCGT needed to maintain the system while the

larger capacity of reserves providers can ramp up to

restabilise the system in a sustainable manner.

Modelling primary/contingency

reserve capabilities and setting the

requirements for each reserve class

falls out of the EMC’s purview. We

understand that the current

primary/contingency reserve classes

and requirements are designed

based on the current reserve

operation strategy of the PSO; and

that the power system’s reserve

capability is technology neutral. EMA

will share more insights on modelling

implications from the EMA-ESS

testbeds and Industry Working Group

2 workstream.

EMC/RCP/120/2021/CP86 10

By establishing the aggregate capacity required from

each technology, EMC could set limitations on the

amount of reserve provided by different

technologies by creating new tiers (e.g. fast

response reserve) to ensure that the system has a

balanced supply of different reserve products to amply

support reserve events and prevent oversupply and

dependence from one particular technology.

On top of the participation in the reserves market,

additional incentive payments to BESSs for the

provision for fast response and flexible reserve

options would encourage higher participation from

existing distributed energy storage as well as the

attraction of new investments on ESS.

The prospect of Fast Frequency

Response product(s) is currently

being studied under EMA’s

“Consultancy Studies to Develop

Technical and Market Based

Solutions to Address Intermittency at

Higher Solar PV Penetrations”. EMC

will work with PSO following the

conclusion of the study to effect the

recommended changes in the

market.

Notwithstanding the above, EMC’s

view is that reserve classes,

requirements and performance

standards, should be designed based

on system need rather than targeting

certain technology.

All BESS systems should not be allowed to charge

back immediately after each event of reserve

provision. This would ensure that grid stability would

be not be affected. Battery energy storage systems at

lower SOC states have a very low impedance

compared to an LRF or a GRF asset. High

concentration of BESS systems drawing power from the

grid at >3C rate might create a nodal voltage sag effect.

The PSO could explore imposing limits on the charge curve of the reserve providing BESSs. This would have to be studied further.

Unlike OCGTs and CCGTs, BESSs cannot offer both

reserve and regulation simultaneously as the

activation for discharge may conflict with an AGC

signal to lower frequency.

In order to have BESSs as a reliable source of

reserve, BESSs have to be on 100% standby and

readily available to be activated and hence will not

be able to offer other grid ancillary services. In

addition, the provision of multiple services will hinder

the storage of renewable energy into batteries. More

accurate stand by times and scheduling are necessary

for using BESS for multiple gird disturbances.

EMC’s view is that BESS can offer

and be scheduled for reserve and

regulation simultaneously. During

actual operations, the BESS

scheduled for reserve and/or

regulation will respond to the AGC

depending on system needs.

How BESS should be apportioned

and timed for different services is the

prerogative of the BESS owner and

his operating strategy. A BESS MP

should offer into the market according

to the unit’s practical capabilities.

Gate closure exemptions could be

considered so that BESS MPs can

submit timely offer variations to

reflect a unit’s actual capability.

PacificLight

Consistent with the principles the NEMS operates

under, all reserve providers should stand an equal

chance of being activated, up to the volume of their

scheduled quantity.

When OCGTs are called upon to provide

contingency reserve, they will be dispatched at

energy prices that they are not willing to offer in the

first place (otherwise they would have been dispatched

This proposal’s intent is to open

opportunities for non-spinning GRFs

to offer and compete in the reserves

market. MPs have full autonomy over

their reserve offer and would have to

assess for themselves, the reserve

offer price needed to recover start-up

cost, energy cost, and other possible

expenses to be on reserve stand-by.

EMC/RCP/120/2021/CP86 11

and are “spinning”) and it is at odd with how the energy

prices are cleared. Factor in the potential losses in

margin (if activated) and the high heat rate of OCGT

and the high amount of carbon emissions, it is not

justifiable to assume that their entrance in the reserve

market improves market efficiency. Increased cost

effectiveness of OCGT’s reserve provisions is therefore

implausible. As such, it would be more cost effective for

the online units to continue providing reserves.

The MCE in-turn decides whether to

schedule reserve from such units

based on its reserve offer price.

Furthermore, we would seek clarification on factors

the PSO will consider in choosing which GRF to

activate, given that now there are two groups of

providers, the online and offline units. Considering the

lead time required to start up the unit, it might not be

efficient to dispatch the offline OCGT for

contingency, especially if the scheduled reserve

volume is small and can be easily met by the online

units. If the chances of being activated is not equal

across providers, this creates an imbalanced playing

field.

We also would like to highlight that BESS should

undergo the frequency injection test, like the one

that Gencos underwent, to determine the primary

reserve envelope.

Lastly, please also advise how OCGT and BESS will

be classified and assessed for the Reserve Provider

Group.

Priority ranking of all generation

registered facilities (computed using

offer prices for energy, regulation and

reserve of all Generation Licensees)

shall be used by the PSO to call on

contingency reserve. As offline units

may require a longer “warm-up” time,

the PSO discussed possibilities to

activate offline units ahead of online

units if scheduled for contingency

reserve.

EMC agrees that BESS should be

subject to the same testing

requirements as current reserve

providers to determine the reserve

envelope. Non-spinning generation

facilities can adhere to the current

standing procedures for defining

reserve provider group for GRFs and

LRFs. For initial verification testing,

non-spinning GRFs could be subject

to unannounced reserve test(s)

across a specified period to mimic

real-life activation scenarios.

Keppel

Keppel is of the view that the providers of spinning

reserves are more reliable than non-spinning reserves

as the former does not suffer from start-up issues.

Replacing a portion of spinning reserves with non-

spinning reserves without considering the unique risks

from different types of providers will reduce the

reliability of the reserve class leading to reduced system

security. Furthermore, there can be additional

concentration risk, where a single non-spinning reserve

provider dispatched a relatively large reserve fails to

deliver, leading to a large shortfall. Keppel does not

support allowing contingency reserves to be provided

by non-spinning generation facilities.

Non-spinning reserves are currently procured as a

distinct market reserve product in other jurisdictions (i.e.

CAISO, PJM). Can EMC perform a study if such a

reserve product could be beneficial in SWEM?

The reliability of non-spinning GRFs

for providing contingency reserves

should be assessed using the same

performance test procedures PSO

administers for other GRFs.

Performance risks of non-spinning

GRFs should have been accounted

for by the PSO, before determining

each GRF’s eligibility, reserve

capacity and reserve effectiveness.

We agree with Keppel that there are

additional risks involved with non-

spinning reserves compared with

online spinning reserves. An

allowable limit on reserves scheduled

from non-spinning units, subject to

regular review, can further safeguard

the system.

EMC/RCP/120/2021/CP86 12

Keppel has no objection for Primary Reserves to be

provided by BESS should they meet the reserve

capability standards.

A recent study on real-time reserves

was concluded in 2017 and

recommended that 2 classes of

reserves, instead of 3, was sufficient

to meet the risk requirements of the

SWEM. The recency of the study and

limited non-spinning GRFs in the

market may not justify a detailed

assessment of a separate non-

spinning reserve class. We can revisit

this possibility as part of future wider

ancillary services studies.

PSO

Currently, the proposal of non-spinning reserve

(offline unit) is already cater for under AS Contract

which covers Fast Start, Black Start, Reliability Must-

Run services. The current NEMS market is designed

for all online units to provide spinning reserve.

Thus, this proposal is basically to allow registered

facility with very low load point (online and non-zero

energy output) to register and participate in the ancillary

services market under NEMS. The registered facility

can carry out testing to validate their characteristics and

registered in NEMS accordingly as well as complying

with MR/SOM/Transmission Code requirements.

It would also be good for EMC to share how other

jurisdictions treat offline OCGTs that provide

contingency reserve and ESS that provide both

contingency and primary reserve. Our understanding is

other jurisdictions classified it as non-spinning reserve

which in our NEMS designed is under AS contract.

While it is true offline units can be

signed under AS Contracts, this does

not necessarily mean that offline units

should be limited to AS Contracts.

EMC did an initial survey and found

that markets like PJM and CAISO

schedule non-spinning reserves as

part of real-time ancillary services. In

the PJM, both spinning and non-

spinning units that can respond within

10 mins and maintain for the duration

of the event or 30 mins from the start

of the event, can participate in the

primary reserve market as part of the

economic dispatch process.

This is broadly similar to the SWEM’s

contingency reserve product.

In addition, EMC to provide reference on ‘BESSs were

reported to be able to ramp up to full power within 0.1

seconds. On the modelling of the contingency reserve

envelope, EMC should consider shifting the low-load to

zero-load in the reserve envelope (Figure 3), in effect,

reverting back to the original reserve envelope (Figure

1) as the gradient seems identical. The existing facility

registration form can still be used and may not require

any additional testing requirement since it is not

necessary to introduce a new ‘zero-load reserve’

parameter in the model.

EMC agrees that modelling the zero-load reserve point using the current low-load reserve mould could be the more expedient approach. We would study this further during the rule change paper drafting stage.

The limit is necessary as a substantial amount of

contingency reserve could be provided by offline

resources. Suggest a jurisdictions scanning be

conducted.

There is no specific limit placed on

offline units that offer into PJM’s 10-

minute response Primary Reserve

product. We can consider adapting

PJM’s operating reserve

methodology for the treatment of

contingency reserve offers by non-

spinning OCGTs in the SWEM

(Annex A).

EMC/RCP/120/2021/CP86 13

5. Conclusion and Recommendations

The proposed modifications to the primary and contingency reserve modelling would allow for

better representation of non-spinning generation facilities that can meet the reserve

performance standards. Safeguards are also proposed to mitigate potential risk to the system

security that could arise from non-performance of these facilities.

With Singapore on track to meeting its 2 GWp solar target by 2030, solar intermittency during

peak periods and consequently the risk of contingency events is expected to increase.

Enabling reserve-capable non-spinning generation facilities to provide primary and

contingency reserves increases the available sources of reserve to address the increasing

risk. In periods where reserve requirement is moderate, scheduling non-spinning units for

reserve frees up stand-by capacity of conventional generators to supply energy at better heat

rates.

EMC concludes that the proposal to remodel the reserve envelope for GRFs is timely and

should be considered to promote added system security and market efficiency.

EMC recommends for the RCP to:

1. Support the proposal to allow primary and contingency reserves to be provided

from generation facilities with loading below LowLoad point;

2. Support the proposal to subject reserve scheduling of non-spinning generators to

the allowable limit, with an initial value of 100MW for contingency reserve; and

3. Task the EMC to work with PSO to assess the impacts and costs of implementation

options, and draft relevant modifications to the Market Rules in order for reserve-

capable non-spinning generation facilities to provide primary and contingency

reserves in the SWEM.

6. Decision at the 120th RCP Meeting

The concept paper was discussed at the 120th RCP meeting.

Upon deliberation, the RCP considered that deeper technical investigation is needed to: (i) ascertain the usefulness of the proposal, as there is uncertainty on whether generators/storage facilities can operate below minimum stable load in a viable manner; and (ii) determine the most appropriate approach to modify the reserve envelop, given the impact and costs of different implementation options.

The RCP by majority vote supported, in-principle, 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.

The following RCP members supported the proposal:

1. Mr. Soh Yap Choon (Representative of the PSO) 2. Mr. Henry Gan (Representative of EMC) 3. Mr. Calvin Quek (Representative of Generation Licensee) 4. Mr. Cheong Zhen Siong (Representative of Wholesale Electricity Trader) 5. Mr. Sean Chan (Representative of Retail Electricity Licensee) 6. Mr. Terence Ang (Representative of the Retail Electricity Licensee)

EMC/RCP/120/2021/CP86 14

7. Mr. Song Jian En (Representative of the Retail Electricity Licensee) 8. Dr. Toh Mun Heng (Representative of Consumers of Electricity in Singapore) 9. Mr. Fong Yeng Keong (Representative of Consumers of Electricity in Singapore) 10. Ms. Ho Yin Shan (Representative of the Market Support Services Licensee) 11. Mr. Tan Chian Khong (Person experienced in Financial Matters in Singapore)

The following RCP member abstained from voting:

1. Mr. Tony Tan (Representative of Generation Licensee)

EMC/RCP/120/2021/CP86 15

Annex A: Allowable Limits for Non-Spinning Reserve in PJM

Industry consultations suggest that performance risks can be minimised through proper

reserve verification testing. To address concerns over perceived risks from offline and/or non-

spinning reserves, EMC studied a possible adaptation of non-spinning reserve treatment

from the PJM.

In the PJM, spinning and non-spinning units that can respond within 10 minutes can offer into

the real-time Primary Reserve product. PJM’s latest proposal8 is for Primary Reserve demand

to be modelled using an Operating Reserve Demand Curve (ORDC) made of two line

segments: (i) minimum reserve requirement (MRR) quantified as 150% of “N-1” contingency

(~2,100MW) priced at a reserve shortage penalty factor of $2000/MWh; and (ii) a downward

sloping segment modelled using LOLP multiplied by the penalty factor across reserve quantity

procured.

In determining the PJM’s Primary Reserves schedule, spinning units scheduled for the higher

quality Synchronised Reserve9 product (10-minute response) is prioritised for clearing. The

balance can be met by the most economic combination of additional online and offline

reserves. As the Synchronised Reserve’s MRR of 100% of “N-1” contingency (~1,400MW) is

nested within Primary Reserve MRR, spinning reserves will be sufficiently scheduled against

the PJM’s single largest contingency in the Primary Reserve market (provided no reserve

shortage). Hence, there is no numerical allowable limit (e.g., XMW) that non-spinning reserves

can only be scheduled within.

There are similarities in the operating reserve structure between the PJM and the SWEM. The

SWEM’s Primary Reserve requirement is similar to the PJM’s Synchronised Reserve in that

the scheduled Primary Reserve and presence of power system response is set to cover the

loss of the largest on-line generation unit. Correspondingly, the SWEM’s Contingency Reserve

requirement is akin to the PJM’s Primary Reserve where the risk requirement is scaled to

150% of the largest contingency.

Reserve Type Reserve Requirement Response Time

SWEM

Primary Reserve

(Online/BESS)

(100% “N-1” Contingency)

x (Power System

Response),

Up to 9 seconds

Contingency Reserve

(Online/Offline) 150% “N-1” Contingency10 Up to 10 minutes

8 As of July 2020. https://www.aepenergy.com/2020/07/01/ferc-approves-pjm-reserve-pricing-reforms/ 9 Synchronised Reserves (SR) is a 10-minute response time real-time product that can only be met by online spinning units. SR has a separate ORDC with MRR set at 100% of “N-1” contingency. As SR is a higher quality product, the scheduled SR MW quantity will also be used to meet the Primary Reserve requirement. 10 In the SWEM, a Risk Adjustment Factor (RAF) is used to scale the risk requirement for Contingency Reserve since the termination of fast start ancillary service contract in 2004. Barring extraneous events, the RAF for Contingency Reserves is 1.5 times the “N-1” contingency.

EMC/RCP/120/2021/CP86 16

PJM

Synchronised Reserve

(Online) 100% “N-1” Contingency Up to 10 minutes

Primary Reserve

(Online/Offline) 150% “N-1” Contingency Up to 10 minutes

Referencing the PJM, a possible option is for eligible non-spinning units to compete with LRFs

within the allowable limit of 30% (~one-third) Contingency Reserve requirement. Doing so

ensures that there will be enough spinning reserves to at least cater for the loss of the single

largest online generation unit.