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Rate of Change of Frequency (RoCoF) Modification to the

Grid Code

DOCUMENT

TYPE:

Decision Paper

REFERENCE:

CER/14/081

DATE

PUBLISHED:

4th April 2014

QUERIES TO: rorourke@cer.ie

The Commission for Energy Regulation,

The Exchange,

Belgard Square North,

Tallaght,

Dublin 24.

www.cer.ie

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CER – Information Page

Abstract:

The TSO has proposed a modification to the Grid Code relating to

Rate of Change of Frequency (RoCoF). This paper outlines the

CER’s decision on this modification.

Target Audience:

Conventional generators, renewable generators, TSO, DSO,

Generator Manufacturers and other interested parties.

Related Documents:

CER Consultation on RoCoF (CER/13/143)

EirGrid’s published documents relating to RoCoF

o MPID 229 & Recommendation Letter to the CER

o Northern Ireland Modification proposal

o DNV KEMA RoCoF Report

o DS3 Working Group minutes and meeting materials

PPA’s RoCoF Report

EirGrid Technical Studies for DS3

Delivering a Secure Sustainable Electricity System (DS3)

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Table of Contents

1 Introduction .............................................................................................................. 4

1.1 The Commission for Energy Regulation ............................................................ 4

1.2 Purpose of this paper ........................................................................................ 4

1.3 Background Information .................................................................................... 4

2 Overview .................................................................................................................. 6

2.1 DS3 & RoCoF ................................................................................................... 6

2.2 System Operation ............................................................................................. 7

2.3 Conventional Generators .................................................................................. 8

2.4 Wind Generators ............................................................................................... 9

2.5 Distribution System ........................................................................................... 9

3 CER Decision ......................................................................................................... 11

3.1 Summary......................................................................................................... 11

3.2 Approval of Modification .................................................................................. 11

3.3 Phased Implementation ................................................................................... 12

3.4 Generator Studies ........................................................................................... 13

3.5 TSO-DSO Implementation Project .................................................................. 14

3.6 Alternative Solutions Project ........................................................................... 15

3.7 Financial Arrangements .................................................................................. 16

3.8 Distribution Code Modification ......................................................................... 18

3.9 Northern Ireland Grid Code ............................................................................. 18

4 Responses to CER/13/143 ..................................................................................... 20

4.1 Summary......................................................................................................... 20

4.2 Approval of MPID 229 in Principle ................................................................... 21

4.3 Conditions for giving effect to MPID 229 ......................................................... 22

4.4 Implementation Project for Generator Studies ................................................. 22

4.5 Cost Recovery ................................................................................................ 23

4.6 Generator Performance Incentive ................................................................... 24

4.7 Alternative Solutions to RoCoF ....................................................................... 25

4.8 Other Issues .................................................................................................... 26

5 Next Steps ............................................................................................................. 29

Appendix: Project Governance ...................................................................................... 30

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1 Introduction

1.1 The Commission for Energy Regulation

The Commission for Energy Regulation (‘the CER’) is the independent body responsible

for overseeing the regulation of Ireland's electricity and gas sectors. The CER was

initially established and granted regulatory powers over the electricity market under the

Electricity Regulation Act 1999. The enactment of the Gas (Interim) (Regulation) Act

2002 expanded the CER’s jurisdiction to include regulation of the natural gas market,

while the Energy (Miscellaneous Provisions) Act 2006 granted the CER powers to

regulate electrical contractors with respect to safety, to regulate to natural gas

undertakings involved in the transmission, distribution, storage, supply and shipping of

gas and to regulate natural gas installers with respect to safety. The Electricity

Regulation Amendment (SEM) Act 2007 outlined the CER’s functions in relation to the

Single Electricity Market (SEM) for the island of Ireland. This market is regulated by the

CER and the Northern Ireland Authority for Utility Regulation (NIAUR). The CER is

working to ensure that consumers benefit from regulation and the introduction of

competition in the energy sector.

1.2 Purpose of this paper

The purpose of this paper is to outline the CER’s decision following from a review of

comments received to CER/13/143.

1.3 Background Information

The CER published a consultation paper in relation to a proposal submitted by EirGrid

requesting a modification to the Grid Code. The proposal was published alongside the

consultation paper. The modification was recommended by the Grid Code Review Panel

(the “Panel”) by a majority vote on 4th December, 2012.1

This followed an extensive period of industry engagement through a Working Group of

the Joint Grid Code Review Panel2 (the “Working Group”) as well as a number of

discussions at the Joint and Irish Grid Code Review Panels. The minutes and meeting

materials of the Working Group can be found here.

The CER issued an open invitation to generators to meet and discuss the technical

issues with the proposal and met with all generators who requested a meeting. The CER

1 Minutes are available here

2 The Joint Grid Code Review Panel is made up of the Grid Code Review Panels of Ireland and Northern

Ireland respectively.

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also commissioned technical advice on this issue from PPA – the report received by the

CER was published alongside the consultation paper.

The current RoCoF capability required of all units in Ireland is 0.5 Hz/s and is set out in

the Irish Grid Code clause CC7.3.1.1 (d). Detailed technical studies undertaken by

EirGrid have indicated that, during times of high wind generation following the loss of the

single largest credible contingency, RoCoF values of greater than 0.5Hz/s but no greater

than 1 Hz/s could be experienced on the island power system. In addition, TSO studies

have shown that instantaneous RoCoF values in excess of 2 Hz/s could be experienced

in Northern Ireland if system separation were to occur on the island. In addition there are

issues associated with voltage dip induced power imbalances in a system with significant

volumes of wind generation which will be addressed through other elements of the DS3

programme.

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2 Overview

2.1 DS3 & RoCoF

EirGrid has proposed the RoCoF modification in order to facilitate the delivery of the

2020 renewables targets, whilst maintaining operational security on the power system.

Specifically the higher RoCoF standard will allow EirGrid to operate the system at a

higher SNSP3 than the present operational limit of 50%. EirGrid has indicated that a

change to the RoCoF capability of the island power system may allow for an SNSP of up

to 60%, along with changes to other operational constraints. Due to system

interdependencies, the RoCoF change alongside other DS3 initiatives will be required to

reach the SNSP of 75%; the target at the completion of the DS3 programme. Therefore

without this higher RoCoF standard, the curtailment of wind will be higher (SNSP cannot

exceed 50%, a threshold which is being hit with increasing regularity as more wind

connects to the system) and the overall 40% target may not be achieved by 2020.

Therefore the realisation of the objectives of DS3, of which RoCoF is an integral work

stream, is important in terms of meeting the obligations under Directive 2009/28/EC to

take appropriate measures to minimise curtailment. EirGrid estimates the benefits of

increasing the SNSP to 75% to be approximately €300m per annum from 2020.4

However, there is considerable technical uncertainty as to whether conventional

generation units are capable of complying with the increased standard. Conventional

generators have argued that it will be both costly to determine the exact RoCoF

capability of their unit and to modify the unit if the current capability is below the

proposed Grid Code modification. In addition, they have argued that the increased

RoCoF requirement will lead to increased wear and tear on plant and a higher risk of

catastrophic failure and an increased risk of safety events.

In summary the TSOs are of the opinion that this modification is necessary to meet the

2020 targets and that there is no theoretical reason that generators cannot meet the

higher standard. The TSOs’ recommendation paper expands on this view. In addition,

the TSOs commissioned DNV KEMA to carry out a desktop study on generator

capability. This study has been published and discussed at various industry fora

including at the Working Group. This report shows that generally generators should be

able to withstand a 1Hz/s RoCoF, subject to several caveats. Conventional generators

have outlined some concerns with this study to the CER, and, through the Electricity

Association of Ireland (EAI), presented the findings of an ESB GWM commissioned

study. The conventional generators’ position is that they do not know what the impact of

a 1Hz/s RoCoF event will be and the modification would require extensive studies of

each unit to assess the impact to be undertaken. These studies are expensive and will

take between 12 and 18 months to complete. Generators argue this is an excessive cost

3 Simultaneous Non Synchronous Penetration

4 See the TSOs’ System Services Recommendations paper

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for them to incur particularly as the benefits of the RoCoF change will accrue to wind

plant only. In addition, generators have outlined concerns with the definition of the

modification particularly in relation to the timeframes for recording compliance, while

some generators have also challenged the interpretation of the results of the desktop

analysis carried out by DNV KEMA for EirGrid.

The vast majority of wind generators have no difficulty with the technical standard

proposed and have an obvious commercial benefit to its implementation. They argue

that the longer the delay (and the greater the impact on curtailment) the less likely it is

for developers to be able to make investments. There are also issues associated with

the distribution system which must be addressed during the implementation phase of

any change to RoCoF requirements.

2.2 System Operation

Changes to Grid Code RoCoF requirements are required in order to increase the SNSP

to the eventual 75%. Without RoCoF changes it is unclear what the final SNSP could be.

Significantly credible or detailed alternatives to increasing SNSP through RoCoF

changes have not been put forward to date by either the TSOs or members of the

Working Group although it is apparent that mechanisms which increase system inertia

without impacting on curtailment levels could play a role in increasing SNSP (e.g. lower

minimum generation levels of generators). However it is not clear that such mechanisms

are either more straightforward, less costly or would have as great an impact as a

change to the RoCoF standard in the Grid Code. Given the interdependencies in the

system improvements proposed by the DS3 programme there is a limit to what can be

delivered through System Services, other Grid Code modifications and TSO operational

improvements. For the new RoCoF standard to have any impact, the TSOs have stated

that all (or almost all) generators must be able to comply with the new standard. If the

system experiences a RoCoF of 1Hz/s and one generator tripped, the level of system

RoCoF would increase possibly resulting in another generator (who withstood the

original RoCoF event) tripping, increasing the RoCoF yet further, and so on. This

cascade effect would threaten system security.

Therefore it is essential that all generators are compliant with the standard if the system

is to operate at a higher SNSP (above the 50% current operational limit). At such an

SNSP, any generators that were not compliant would have to be taken off the system

during high wind events to mitigate the risk of such a system failure and/or wind would

have to be curtailed.

Proving compliance with a higher RoCoF standard than that currently required in the

Grid Code will be an issue for the TSO. There is no test that can reliably check that a

generator will withstand a high RoCoF event. Therefore the TSO is almost entirely

reliant on the generator’s assessment and “certification” of the unit’s capability. It is for

this reason that the generator studies (discussed below) must be robust and of sufficient

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quality to convince the TSO that it is safe to operate the system with a high SNSP when

that unit is on the system.

2.3 Conventional Generators

Conventional generators have two main concerns aside from the ability to remain

synchronised. These are that a high RoCoF event will cause a catastrophic failure of a

unit – which is primarily a safety concern for station staff – and that repeated high

RoCoF events will negatively impact the commercial life of the plant. The risk of

catastrophic failure is considered by the CER’s consultants to be “highly unlikely” on the

basis that units can be expected to undergo more severe network fault events without

such catastrophic failure. The impact on the commercial life of the plant is highly

dependent on the frequency of high RoCoF events. If they are infrequent, as is

expected, then there will be minimal impact on the life of the unit. The frequency of such

events cannot be forecasted with accuracy. That said, there is a greater likelihood of

increased wear and tear on conventional plant in the coming years as levels of wind on

the system increase, even in the absence of RoCoF events. This will be due to

increased cycling of plant to accommodate wind and other priority-dispatch units. While

on one hand it can be argued that increasing the grid code RoCoF requirement will drive

further wear and tear, it would not be possible to separate out RoCoF associated wear

and tear from normal, non-RoCoF wear and tear. In any event, conventional generators

must take note of the clear direction of European and National policy which favours

incremental movement towards a low carbon electricity system as well as the explicit

requirements of the Renewables Directive (2009/28/EC) to minimise curtailment of wind.

By implementing these policies through binding national targets, the policy makers have

made clear the importance of achieving these objectives regardless of the impact on pre-

existing investments. This policy will result in a system with a high penetration of wind

and a system which has different technical requirements to those currently prevailing.

Indeed failure to achieve the target will not only result in a higher carbon electricity

system, but also significant fines for Ireland from non-achievement of its binding targets.

It is estimated that these fines could be in the significant.5 The purpose of the Grid Code

is to establish the minimum standards required to maintain system security and the

electricity system in 2020, and the years leading up to it, will require a generation fleet

capable of withstanding higher RoCoF events than the current standard.

In order to ascertain generators’ ability to withstand a RoCoF event of 1Hz/s over 500ms

studies will need to be carried out on every unit on the system. The only alternative at

5 The Renewables Directive provides a formula for Member States to calculate their trajectory to meeting

their target in 2020. Ireland is currently on target with regard to its trajectory. Failure by Member States to meet their individual binding target by 2020 (in Ireland’s case 16% of total energy met by renewables) would result in the European Commission taking infringement proceedings. While the scale of such penalties cannot be known at this point, the Sustainable Energy Authority of Ireland (SEAI) estimates that non-compliance costs could amount to around €140 million to €210 million for each 1 percentage shortfall relative to Ireland’s EU target of 16% of energy from renewable sources by 2020.

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present is to wait for a RoCoF event(s) to take place, with the associated risk of system

outages or system failure. The main difficulty however with the study approach is that

such studies have not been carried out previously and it is therefore not possible to

utilise prior international experience. The costs which have been indicated to the CER

while high could be considered to be reasonable were a large scope of specialised work

required, albeit that it is accepted by CER that out of necessity, Ireland will be a “first-

mover” internationally in carrying out such studies, with the associated advantages and

disadvantages of first mover status.

It is noted that several generation units on the island have similar equipment and there

may be some scope for co-ordinating the studies of different units (i.e. plants with the

same type of turbine) and the required network modelling but it appears that there will be

a significant element of each study that will be unique to the unit in question. The studies

will only determine if a unit can withstand a 1Hz/s RoCoF event. Therefore it is possible

that the studies may conclude that it is not possible to increase the standard or that an

implementation phase is required (retrofitting of plant etc.). It is also noted that some of

the manufacturers active in Ireland have also built units for the Danish market. Denmark

has a standard of 2.5Hz/s for new units (and previously had a standard of 2.0Hz/s) –

manufacturers may be able to make some use of the studies undertaken in the design of

these units.

2.4 Wind Generators

Wind farms, with some exceptions, do not have any issue with the proposed standard

and the manufacturers have confirmed they could comply with the proposed RoCoF

standard.

The main issue for wind is that the longer the delay in resolving this issue the higher

wind’s curtailment levels are likely to be. Therefore there is considerable concern in the

industry that a delay to the implementation of the proposed RoCoF standard will have a

significant impact on the commercial viability of wind projects.

2.5 Distribution System

The DSO currently uses RoCoF protection to prevent islanding on the distribution

system. Islanding occurs when a section of the distribution system becomes separated

from the rest of the system but remains live. A RoCoF of 1Hz/s is not compatible with

current DSO practice. If no changes were made on the distribution system a high RoCoF

event could result in large parts of the distribution system tripping creating a cascade

effect across the entire transmission network. The DSO supported the TSO’s

modification and based on their analysis consider that the current protection settings can

be modified to allow for the 1Hz/s standard. There is a considerable amount of further

work to be undertaken in terms of implementation and engagement between TSO and

DSO to work out remaining technical details. While the amount of outstanding work

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should not be underestimated there does not appear to be any issues which would

prevent the implementation of the TSOs’ proposed RoCoF standard.

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3 CER Decision

3.1 Summary

The CER approves the modification in principle, but it will only come into effect following

confirmation from EirGrid that, from a system security perspective, it can be

implemented. To determine this there will be an industry implementation project made up

of three strands; TSO & DSO implementation; Alternative solutions; and generator

studies. The implementation of RoCoF will be phased over a period of 18 to 36 months,

with higher priority units being required to complete their studies first. The overall

industry project will be coordinated by an independent consultant and overseen by the

CER. Incentives will be implemented and will be progressed through the established

SEM process.

3.2 Approval of Modification

Having reviewed EirGrid’s recommendation, submissions from industry, the independent

report from PPA, the responses to CER/13/143, further submissions made by individual

generators and the EAI and the national and European policy background, the CER

considers that it is critically important to increase the RoCoF standard in the Grid Code

in order to facilitate the achievement of Ireland’s legally binding renewables targets.

Delivery of higher levels of wind penetration on the electricity system is a clear national

policy and it is important that the CER does not obstruct this policy. However the CER is

cognisant of the fact that delivery of policy should only take place without impacting on

the quality, reliability or safety of electricity supplies. Therefore it is important that in

approving the RoCoF modification in principle that the modification can be implemented

without a significant risk to the safety and reliability of the electricity system. As outlined

in the PPA report, published alongside the consultation paper, there is a level of

uncertainty regarding the technical capability of the Irish generation fleet and the

potential requirements to undertake work to comply with the higher RoCoF standard, the

CER therefore considers it prudent to propose to delay implementation of the RoCoF

modification (MPID 229) for a period of time to allow the required studies and works to

be carried out.

Therefore, the CER approves the modification, as proposed, in principle but the CER will

not give effect to the new standard in the Grid Code until it has received confirmation

from EirGrid that, in its professional judgement, a sufficient number of generators can

comply with the standard to allow EirGrid to safely operate the system in a manner

reliant on the new RoCoF standard. Generators shall be required to make a declaration

to EirGrid regarding their level of compliance within 18 to 36 months of the publication of

this paper.

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3.3 Phased Implementation

The deadline for the declaration of compliance (or submission of a derogation) will be

phased according to the importance, in terms of system operation, of each unit. The

CER directs EirGrid to categorise each unit into i) high-priority ii) mid-priority iii) low-

priority and iv) exempted units. The TSO will use its judgment in making these

categorisations but will have regard to the following criteria:

1. High-priority: relatively high run-hours; frequently constrained on; frequently run

at times of high wind

2. Mid-priority: those units not falling into the other categories

3. Low-priority: low run-hours; infrequently constrained on; rarely running at times of

wind generation

4. Exempted units: units which are soon to retire; very low run-hours; infrequently

constrained on; very rarely running at times of wind generation, units which

EirGrid’s operational experience shows would have historically experienced and

ridden through high RoCoF events.

5. New units: new units will be required to declare compliance during the

commissioning process

The formal commencement of the RoCoF implementation project will be notified to

industry through the CER’s website. High-priority units must make a declaration of

compliance (or submit a derogation) within 18 months of this commencement of the

RoCoF implementation project. Low-priority units must make a declaration of compliance

(or submit a derogation) within 36 months. Mid-priority units must make a declaration of

compliance (or submit a derogation) within 24 months. Exempted units will not have to

complete a study though they may choose to do so, if they wish. For the avoidance of

doubt any unit may apply for a derogation; however a necessary component of such an

application will be a study detailing the nature of the non-compliance and the remedial

actions taken to attempt to rectify the non-compliance. Exempted units that cannot

comply with the requirements will be required to formally make an application for a

derogation, though they will not be required to enclose a RoCoF study with their

application. It is not envisaged that any derogations will be assessed by the CER prior

to the 18 month deadline.

The TSO shall categorise each unit based on the criteria set out above and seek

comments from generators prior to submitting their recommendation to the CER for

approval. For the avoidance of doubt any unit categorised as “exempted” by the TSO,

and approved as such by the CER, is so categorised without prejudice to the CER’s

decision in relation to the derogation application the unit ultimately submits.

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The TSO will also assess the possibility of operating the system at a higher penetration

of non-synchronous generation where a portion of the generation fleet has demonstrated

compliance with the new standard and a portion has not. The TSO will assess the

viability of relying on the dispatch of compliant generators at these times although it is

acknowledged that there may be implementation issues to be overcome. Under such

circumstances non-compliant generators would be considered technically unavailable

when the SNSP (or equivalent metric) is over 50%.

3.4 Generator Studies

As discussed above generators have indicated that they must undertake technical

studies in order to determine their unit’s ability to meet the proposed RoCoF standard. In

discussions with generators, individually and as part of the Working Group it is

understood that such studies should take between 12 to 18 months to complete.

However, of the conventional generators who responded to the CER/13/143 the general

view was that the proposed 18 month deadline for completion of studies was

unreasonably short. Generators cite difficulties such as the technical complexity of the

studies themselves, the requirement to rely on OEM’s6 (multiple OEMs in some cases)

actively engaging with the generator and resource constraints within the OEMs even if

active engagement is achieved. The CER has considered generators’ responses and

while it is accepted that such studies are significant and complex pieces of work, delays

in the completion of the studies will directly impact on the level of curtailment faced by

wind generators, their financeability, the national renewable targets, and delay savings

to consumers associated with an increased SNSP. Therefore the CER wishes to

proceed as quickly as possible while acknowledging the difficulties faced by

conventional generators.

Process for carrying out generator studies

As set out above EirGrid will identify the relative priority of each unit. EirGrid will

engage with industry on these priority classifications and will submit them to the

CER for approval.

In order to ensure consistent delivery of studies and a fair and transparent

process, the overall industry project will be coordinated by an independent

consultant and overseen by the CER, possibly in co-ordination with UR. The

Independent consultant, in consultation with generators and the TSO, will set out

the requirements from EirGrid in terms of information provision to generators

(e.g. system scenarios) and the requirements from generators in terms of

carrying out the studies and the minimum level of information which the generator

will need to obtain from the OEM.

6 Original Equipment Manufacturer

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The generator studies will be project managed by the generator concerned with

an agreed report structure to the independent consultant to ensure consistency

across all studies. Specifically the TSO will input into the generator’s study at the

outset, at pre-agreed interim milestones and at the study’s conclusion.

It is envisaged that there would be a tripartite meeting at the outset of every

generator’s study with the TSO, generator and the independent consultant, but

the exact organisational structure will be determined by the Independent

consultant in discussions with the CER. The CER may attend these meetings as

it considers it appropriate. At this initial tripartite meeting the scope of the study

will be discussed based on what results the TSO considers necessary and on

what results the generator can reasonably deliver through the study. Interim

milestones will also be agreed at this initial meeting where progress will be

reviewed and any changes to the plan that may be required based on preliminary

results will be agreed.

Upon the conclusion of the generator’s study and submission to the Independent

consultant (who will review for consistency), the TSO will review it with a view to

determining the overall security of the system with the new RoCoF standard.

The independent consultant, in consultation with EirGrid and industry, will propose the

scope of the appropriate TSO network modelling at the outset of the project. EirGrid and

generators will assist by providing all reasonably required information. If required, the

CER, working with UR, will co-ordinate the sharing of information if required for reasons

of commercial confidentiality, ensuring that confidential information is protected at all

times. The objective of this modelling is to provide an agreed set of system scenarios

upon which the generator studies can be based and additionally to facilitate generators

appropriately scoping their projects.

Generators will be required to submit detailed project plans to the CER, the independent

consultant and give frequent updates to the independent consultant co-ordinating the

industry project. Generators will also be required to regularly publish public reports on

their progress – the publication of reports will be co-ordinated by the consultant. The

frequency of both the project updates and the public reports will be determined when the

project plans are being agreed.

3.5 TSO-DSO Implementation Project

As discussed above there is a significant programme of work required to implement the

new RoCoF standard on the distribution system. The DSO is directed to set out a project

plan and will provide regular updates to CER and the industry at appropriate DS3 fora,

the distribution code panel and the Grid Code review panel.

As part of the project governance of the overall RoCoF implementation project the TSO

and DSO will engage regularly to agree and monitor the delivery of the project. The SOs

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will provide public quarterly updates on this work stream through the existing DS3

communications process.

The potential impact of higher RoCoF events on demand customers was raised in

bilateral discussions, noted in the PPA report, and by one of the respondents to

CER/13/143. From subsequent discussions with the system operators the CER

understands that it is unlikely that demand customers should be negatively impacted by

the new Grid Code standard. However, the CER considers it prudent that this issue is

monitored to ensure that quality of supply is not negatively affected.

The CER directs the DSO and TSO to monitor the impact of the new RoCoF standard on

demand customers and the quality of supply as part of the TSO-DSO Implementation

Project, and report any concerns, if any, to the CER.

3.6 Alternative Solutions Project

In light comments received during the extensive consultation with industry on this topic

the CER is of the view that there is a risk that lead time for implementation of a new

RoCoF standard could take longer than the 18-36 month deadline set out by the CER in

this paper. The CER must also be cognisant of the possibility that a new RoCoF

standard will not be implementable in a timely enough manner to affect the 2020 targets.

Therefore it is considered prudent that the CER direct EirGrid to investigate, and where

relevant propose and implement, alternative solutions to the inertia problem that RoCoF

would resolve. If complementary and realistic alternatives to RoCoF consistent with the

objectives of the DS3 programme can be delivered, they may mitigate any potential

impact of a delay to the completion of the RoCoF implementation project and may

ensure a somewhat higher SNSP than otherwise possible. The TSO will provide regular

updates on its progress through the existing reporting arrangements for DS3. The TSO

should engage with industry in developing the scope for this project and throughout. The

report will be submitted to the CER within 18 months of the publication of this paper. It is

envisaged that where the TSO can make recommendations or implement measures

earlier than 18 months, this should be done.

The TSO should consider the following areas as part of this project:

Measures to increase inertia on the system through network investments, storage

and strategic generation investment

Synthetic inertia

Changes to operational policy

Any other matters the TSO considers relevant.

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3.7 Financial Arrangements

Generators have requested that the costs associated with the technical studies be

recoverable. In CER/13/143 the CER set out two options, no cost recovery or costs

socialised across all generators. The CER stated that its preferred option was for no cost

recovery. The CER remains of this view and accordingly will not be providing for cost

recovery of the studies.

Several generators have made representations to the CER, both before the publication

of, and in response to, CER/13/143, requesting that the costs associated with the

studies be recoverable. It is noted that this would be a departure from industry practice

as compliance with the Grid Code is the responsibility of the generator as are any costs

required to achieve or maintain compliance. Electricity systems across the world are

demanding greater flexibility from generators in response to initiatives to diversify

supplies and increase renewable (often intermittent) penetration. Ireland is no different,

indeed the requirement for flexibility is more acute, and against this background, the

CER is of the view that it is reasonable to expect improved flexibility from all generators

on the system. In some cases, it is appropriate to reward this flexibility and the DS3

System Services work stream is currently considering appropriate levels of payment in

this area. However in other areas it is appropriate that improved flexibility is mandatory

giving the changing nature of the generation portfolio.

That said there is also an argument to suggest that the RoCoF modification is slightly

different in nature from other Grid Code modifications in that the costs for delivering

compliance rest chiefly with conventional generators without any associated benefit from

making the required investment. In fact, delivering compliance is likely to result in a

negative commercial impact on many conventional generators as it actively facilitates a

displacement of conventional generation by wind generation. Notwithstanding the

national policy requirements, the commercial benefit of the successful implementation of

this modification will go to wind farms, whereas the successful implementation will

disadvantage the commercial position of conventional generators as they will be more

frequently displaced by wind generation. This coupled with the costs of the studies does

not incentivise timely implementation of the modification.

While the CER can appreciate the views of generators who feel they are required to pay

for expensive studies to prove compliance with a modification which will, upon

implementation, actively disadvantage their plant, the CER has nonetheless decided not

to allow cost recovery. On balance the CER does not consider that the arguments in

favour of cost recovery are sufficient to warrant a change in policy regarding Grid Code

modifications. It is current policy, and a condition of the generator licence, that all costs

associated with Grid Code compliance are the responsibility of the generator.

Furthermore, the RoCoF modification has arisen as a direct result of European and

national policy which favours renewable penetration. The purpose of the Grid Code is to

set the minimum standards necessary to ensure the safe operation of the system given

the nature of that system. As a result of European and national policy the nature of the

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Irish system will be different in 2020 to the historically traditional system with a portfolio

of predominately conventional generation. Generators must meet the minimum

standards required of a system with a high penetration of non-synchronous generation,

including a higher RoCoF standard than previously required. Generators in signing up to

the Grid Code carry the risk of the cost of implementing changes to the Grid Code; if the

generator decides not to comply with the Grid Code then there is a clear signal that that

generator should not be a connected party to the Irish electricity system. Accordingly the

CER will not provide for cost recovery and generators should pay in full for the costs of

their individual studies.

However, the CER acknowledges that in addition to the costs associated with the studies

there will be operational costs associated with higher RoCoF events. Such costs may not

be recoverable through energy bids. Accordingly the CER and the Utility Regulator in

Northern Ireland will recommend that the SEM Committee request the TSOs to consider

and propose the introduction of a remuneration mechanism which may include a new

Harmonised Ancillary Services (HAS) rate for RoCoF. It is envisaged that all generators

demonstrating compliance with the 1Hz/s standard would be eligible for a period of time.

While it is hoped that the introduction of a remuneration mechanism would incentivise

the timely completion of the generator studies it is considered that a Generator

Performance Incentive (GPI) should also be applied. The CER has revised the proposed

design of the GPI to lower the daily charge and to phase the introduction of the full

charge. Units will become eligible for the GPI according to the deadline associated with

their categorisation as discussed in Section 3.3. The CER and the Utility Regulator will

recommend to the SEM Committee that a harmonised GPI of the form set out below be

applied on an all-island basis.

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Formula:

(a – b) x (€5,500) x (d) x (e) = c

Where a=RoCoF standard; b=Unit’s RoCoF level; d=scalar associated with size of unit;

e=scalar associated with the period of time from the commencement of the

implementation project; and c=the daily charge.7

Reg. Cap d Annual charge

18 months 24 months 30 months 36 months e= 25% e= 50% e= 75% e= 100%

≥ 400MW 1 €1,003,750 €250,938 €501,875.0 €752,812.50 €1,003,750

≥ 300MW 0.75 €752,813 €188,203 €376,406.3 €564,609.38 €752,813

≥ 200MW 0.5 €501,875 €125,469 €250,937.5 €376,406.25 €501,875

≥ 100MW 0.25 €250,938 €62,734 €125,468.8 €188,203.13 €250,938

≥ 50MW 0.15 €150,563 €37,641 €75,281.3 €112,921.88 €150,563

< 50MW 0.05 €50,188 €12,547 €25,093.8 €37,640.63 €50,188

It should also be noted that it may be possible to operate the system at the new standard

with a set of generators who are compliant, and excluding those that are not, at times of

high non-synchronous generation. Under such circumstances non-compliant generators

would not be technically available which may have an impact on market payments. The

viability of operating at a higher SNSP with less than full compliance from the entire

generation fleet will be determined after the TSO has completed its analysis after the 18

month deadline.

3.8 Distribution Code Modification

The DSO has submitted a RoCoF modification8 to the CER. Similarly to MPID 229, the

CER approves this modification in principle and will assess whether to give effect to it in

the Distribution Code, when the TSO submits its recommendation on the Grid Code

modification.

3.9 Northern Ireland Grid Code

Modifications to the Grid Code are currently dealt with on a jurisdictional basis and so

are separately proposed to and decided upon, by the respective regulators. However, it

is noted that a similar modification has been proposed by SONI in Northern Ireland and

has since been consulted on by the Utility Regulator. Given the similarities of the two

modifications and the all-island implications (in particular the Regulatory Authorities’

7 For example a 450MW unit, categorised as high-priority, and that had not demonstrated

compliance after 18 months would face a daily charge of €687.5 and €1,375 after 24 months, etc. 8 Modification Proposal #26

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intention to recommend the SEM Committee introduce incentives) of RoCoF the CER

has been actively engaging with the Utility Regulator. The Regulatory Authorities have

agreed a common position which ensures the respective decisions of CER and UR are

not in conflict. The Regulatory Authorities will continue to work together to oversee the

implementation of the new standard on an all-island basis.

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4 Responses to CER/13/143

4.1 Summary

Respondents with generation portfolios including conventional units formed a majority of

respondents and were strongly opposed to many aspects of the CER’s proposed

approach. In essence these respondents are of the view that the 18 month timeframe is

unrealistic, that no decision should be taken on MPID 229 (even in principle) until the

technical studies have been completed and alternative solutions have been fully

explored. Furthermore they are of the view that the costs of studies should be

recoverable and that the application of a GPI is not an appropriate method of

incentivising the timely completion of the technical studies. This view is informed by the

complexity of the studies, the requirement of OEM involvement, the high costs involved

and that the successful implementation of RoCoF will potentially have an adverse

financial impact on conventional generators. Respondents representing renewable

generation were broadly in favour of the CER’s proposals although they emphasised the

need for a timely implementation of the new RoCoF standard.

Respondents were broadly supportive of the CER’s approach to the project governance

for the implementation of RoCoF with the caveat that several respondents were of the

opinion that the TSO should not take as central a role in the generator studies as

proposed.

Generally respondents expressed support for the DS3 project and its objectives. In this

context it should be noted that several of the respondents with conventional generation

also have significant interests in wind farms (both currently connected and in

development). These respondents expressed their support for the new RoCoF standard

insofar as it increases the SNSP but nonetheless disagreed with the CER’s proposed

approach.

Responses were received from the following parties and are published with this paper:

AES ESB GWM

Aughinish Alumina Ltd IWEA

Bord Gáis Energy RES

Bord na Mona SSE

EirGrid Tynagh Generation Ltd

Electricity Association of Ireland One confidential respondent

In addition several parties discussed the issues with the CER bilaterally. In January 2014

EAI presented analysis carried out by ESB GWM to the CER. A copy of the presentation

and letter is published with this paper.

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4.2 Approval of MPID 229 in Principle

There was limited support for the CER’s proposal to approve MPID 229 in principle

ahead of the completion of studies. There was near unanimity amongst conventional9

generators, a majority of respondents, that it was premature to approve MPID 229 in

principle. They argue that, given the degree of technical uncertainty regarding

generators ability to comply, a decision on the approval (or otherwise) of the modification

should only be taken after the studies have been completed and there is clarity

regarding the generation fleet’s capability. It was also argued by some respondents that

before a decision on the modification is taken alternative solutions to RoCoF should be

explored and compared to the cost and effectiveness of implementing RoCoF.

4.2.1 The CER’s View

The CER accepts that there is uncertainty as to whether conventional generators are

capable of meeting the new RoCoF standard. This will not be known until the completion

of the technical studies. This uncertainty is the underlying rationale for much of the

content and provisions of this Decision. The process under the Grid Code has reached

an impasse. The CER notes that there has been extensive consultation over a number

of years and engagement with industry through the Panel and bilateral engagements, in

addition to a dedicated industry working group which met regularly for a year.

It has not proved possible to progress this issue without a regulatory decision. By

approving the decision in principle the CER is providing certainty and a framework

through which a conclusion to this matter can be reached. The CER also wishes to

express its clear intention to industry that it will give effect to the higher RoCoF standard

should it be possible to do so in terms of system security. It is noted that the CER is not

giving effect to the modification until confirmation is received from the TSO that system

security will not be compromised. The CER considers that approving in principle strikes

the appropriate balance in order to prudently progress this issue.

It is noted that alternative solutions to RoCoF were considered and discussed by the

Working Group. At this point in time increasing the RoCoF standard remains the most

credible solution. The CER does not consider that there is any merit in the proposal to

complete the alternative solutions project before the generator studies are commenced.

Such an approach would most likely delay the increase in SNSP. Given that both

projects (generator RoCoF studies and the TSOs’ alternative solutions study) can

progress simultaneously, they should do so to ensure any possible increase in SNSP is

achieved as quickly as possible.

9 It should be noted that many of the respondents with conventional generation units are companies that

also have wind farms (existing and planned) and explicitly support increasing the SNSP limit.

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4.3 Conditions for giving effect to MPID 229

Responses regarding the implementation of the RoCoF standard generally focused on

the 18 month timeline set out in CER/13/143. Some respondents expressed concern that

the implementation of a higher RoCoF standard was already significantly behind

schedule and a further 18 month delay would result in higher curtailment than had been

previously forecast. A majority of respondents expressed concern that the 18 month

timeline was unrealistically short. In support of this position respondents noted that the

studies are complex, will require assistance from their OEMs and will require further

input from the TSO. They go on to state that given the specialised nature of the studies

they expect OEMs to face resource constraints making it difficult to carry out multiple

studies simultaneously.

4.3.1 The CER’s View

The CER acknowledges that the 18 month timeline will result in the SNSP remaining at

the current level for longer than previously forecast. However, given the complexity of

the issue the CER is of the view that it is not reasonable to impose a timeline of any less

than 18 months. It is also noted that the level of complexity associated with RoCoF was

not anticipated at the time the DS3 project plan for RoCoF was first drafted by the TSOs.

The CER acknowledges that the technical studies required are complex and significant

pieces of work. However, as noted by some respondents the implementation of a higher

RoCoF standard is a key factor in the ability of the TSO to increase the SNSP limit and

to consequently reduce curtailment. Therefore the CER wishes to determine the viability,

and if possible implement, RoCoF in as short a time as is possible. The CER considers

the 18 month timeline optimistic but not unrealistic. Generators have indicated that

studies will take between 12-18 months. Accordingly it should be possible for a number

of generators to complete their studies before the 18 month deadline. Notwithstanding

this the CER, having considered the responses and further information provided by

generators since the close of the consultation period, consider that some flexibility

around the timelines is reasonable. Therefore as outlined in section 3 the CER is taking

a phased approach. This phased approach should facilitate those generators who may

not be able to complete the studies within 18 months due to factors outside their control

such as the resource constraints of an OEM with several units on the system.

4.4 Implementation Project for Generator Studies

Respondents were generally in favour of establishing a project structure to facilitate a co-

ordinated implementation. A key issue for many respondents was the role of the TSO.

Those respondents expressed the view that an independent party should fill the role of

co-ordinating the generator studies but that the project management of the studies

should be left to the individual generators themselves. Some respondents felt that given

the role of the TSO in proposing the modification the TSO could not be considered to be

an independent third party. Some respondents considered that the CER, or independent

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expert with knowledge of plant behaviour, should fulfil this role. Several respondents

also requested further detail in how the project would be conducted.

4.4.1 The CER’s View

The CER welcomes respondents’ support for the proposal to establish an

implementation project and notes the concerns raised. In response to these concerns

the governance structure has been refined. An independent expert will report to the CER

and take a co-ordination and monitoring role. Generators will be responsible for the

management of their own projects. However, the CER considers the involvement of the

TSO to be necessary. Therefore the TSO will have an involvement at the initial stage of

each generator study, at pre-agreed interim milestones and at the conclusion of the

study. It will be up to the generator to declare its compliance or non-compliance with

MPID 229 but it will be the responsibility of the TSO to make a recommendation to the

CER, on the basis of the studies completed, that the CER should, or should not, give

effect to MPID 229 in the Grid Code.

Regarding the requests for further detail, this paper sets out the project structure. The

CER does not consider it appropriate to be overly prescriptive in this paper in setting out

the project details. These will be agreed in the initial stages of the implementation

project.

4.5 Cost Recovery

One respondent supported the CER’s proposal not to allow cost recovery, one did not

present a view and the remainder supported the introduction of cost recovery for the

studies. Those supporting cost recovery were strongly in favour of doing so on the basis

of the costs involved, the difficulty in carrying out the studies, that the introduction of a

higher RoCoF standard is to the benefit of wind generators and will commercially

disadvantage conventional generators. Accordingly respondents argued that not

providing for cost recovery was inequitable and discriminatory.

4.5.1 The CER’s View

The CER notes respondents concerns regarding the proposal regarding cost recovery.

As discussed in Section 3 the CER acknowledges that the implementation of MPID 229

raises difficulty for conventional generators. It is for this reason that the CER has

considered the possibility of cost recovery – which is exceptional for Grid Code

modifications. However, having considered the issue the CER is of the view that on

balance the unique aspects of MPID 229 are not sufficient rationale to impose the costs

of grid code compliance on customers. In addition to the reasons set out in Section 3 the

CER notes that not providing for cost recovery is not discriminatory. Wind generators are

not receiving preferential treatment. All generators will be required to comply with the

new RoCoF standard, including wind generators. Current policy – that no cost recovery

is provided for Grid Code modifications – has applied equally to-date. In this regard it is

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noted that other Grid Code modifications associated with DS3, which apply only to wind

farms, have been implemented and all costs associated with investigating compliance

and remedying non-compliance must be covered by the generator in question.

The changes to the RoCoF standard are required for system security and in order to

deliver consumer benefits associated with a higher SNSP. European and national policy

are driving the increase in the connection of renewable sources of generation, primarily

wind which is a non-synchronous technology. As a result of this the generation mix of the

system will be different than currently and also the technical needs of the system will be

different. Therefore the Grid Code must change to reflect these new technical

requirements and ensure the continued safe operation of the system.

However, in recognition of the potential for a higher RoCoF standard to impose higher

operational costs the Regulatory Authorities will recommend to the SEM Committee that

a mechanism, such as HAS rate, for RoCoF performance be introduced.

4.6 Generator Performance Incentive

Two respondents, both representing renewable generation, were in favour of the

proposed GPI. The remainder of respondents were not in favour of the GPI in its

proposed form. Although some respondents considered that a GPI (of a different form)

may be appropriate where generators were refusing to remedy non-compliance. In

general views on the GPI were linked to respondents’ views that the modification should

not be approved until after the studies were completed and the viability of the standard

demonstrated. Accordingly, a GPI, if one were to be implemented, should only be

introduced after the studies had been completed and the new standard approved (if the

studies demonstrated it could be). Notwithstanding this point some respondents had

concerns with the GPI itself, stating that the level of the GPI was too high. Particularly as

generators will already be facing the costs of the technical studies. Concern was raised

that the introduction of this GPI introduced investor uncertainty. Some respondents also

questioned the effectiveness of the GPI on the basis that the OEMs would not be

affected and generators are reliant on their OEMs to complete these studies. Some

respondents also queried the process regarding the GPI, arguing that it was arbitrary

and should be introduced on an all-island basis because Harmonised Ancillary Services

and Other System Charges have been harmonised on an all-island basis. An alternative

to a GPI was suggested: that a units RoCoF capability would be considered during unit

commitment during periods of high wind.

4.6.1 The CER’s View

The CER notes that the proposal in CER/13/143 was that the GPI be applied against the

prevailing RoCoF standard. Therefore, following the 18 month deadline, if the TSO was

unable to confirm that the new standard could be safely moved to the modification would

not take effect in the Grid Code. In this case the existing standard would still apply – a

standard which all units have confirmed their compliance. Accordingly, the CER

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considers that the application of this GPI is appropriate. After 18 months it will be clearer

if the new standard can be implemented. If it can be implemented the GPI will apply, if it

cannot the GPI will not apply at that time. In the CER’s view this balances providing an

incentive to generators to ensure the timely completion of studies required to determine

compliance against placing an unreasonable burden on generators to comply with a

standard that cannot be implemented.

The CER notes the concerns of respondents regarding the size of the GPI. However,

given the importance of the issue, the need to resolve the technical uncertainties in a

timely manner, the need to determine the capability of all generators and the costs to the

consumer in terms of foregone savings require any incentive to have a significant impact

on the generator. In response to comments the CER has revised its proposed GPI – it is

now lower and will be phased in over a period of 36 months. These changes to the

structure of the GPI combined with the phased implementation of the modification itself

results in both a lower GPI and a longer period of time in which to determine compliance.

Notwithstanding these changes the CER remains of the view that the GPI should be

significant enough to incentivise compliance with what is an admittedly complex issue.

The CER considers that generators are best placed to manage their relationship with

their OEMs, it is noted that the CER does not have a regulatory relationship with the

OEMs and accordingly does not have an instrument to incentivise their performance.

Therefore any incentives must be placed on the generator. No exemptions from the GPI

due to OEM delays are envisaged.

It is noted that the Harmonised Ancillary Services and Other System Charges is a SEM

matter. However, this does not preclude jurisdictional arrangements where appropriate.

Since the publication of CER/13/143 the Regulatory Authorities have agreed a common

position on the RoCoF decision, accordingly the Regulatory Authorities consider it

appropriate to progress both the introduction of a remuneration mechanism (such as a

HAS rate) and a GPI for RoCoF through the usual SEM process. Therefore the

Regulatory Authorities will recommend that the SEM Committee request the TSO to

consider and propose such mechanisms.

The CER will consider the possibility of considering RoCoF capability when determining

the availability of units during periods of high wind. Whether this is possible will require

further work by the TSO to determine the critical mass of compliant generators required

to safely operate the system during a high RoCoF event. A decision on that issue will be

made upon review of the TSO report following the 18 month deadline.

4.7 Alternative Solutions to RoCoF

All respondents agreed with the CER’s proposal that EirGrid explore alternative solutions

to RoCoF. As discussed above some see the conclusion of this project a prerequisite to

the approval of RoCoF in principle and the commencement of studies.

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4.7.1 The CER’s View

The CER welcomes respondents’ support of this proposal.

4.8 Other Issues

4.8.1 Protection Settings:

EirGrid, in their response, noted the issue raised by PPA in relation to RoCoF protection

settings. Such protection settings could exacerbate system instability during a high

RoCoF event. EirGrid suggests that the Grid Code should explicitly prohibit the

installation of protection settings for a RoCoF level below that required by the Grid Code.

The CER notes these concerns and invites EirGrid to bring forward a modification

proposal to the Grid Code Review Panel. The CER will take a view on the matter at the

conclusion of the Grid Code Review Panel process.

4.8.2 RoCoF Definition:

In January 2014 industry presented findings of ESB GWM analysis of the KEMA study

previously commissioned by EirGrid. One of the issues they raise is that MPID 229

defines RoCoF as 1Hz/s over 500ms. Generators argue that the time period of 500ms is

significant because since the 1Hz/s standard is an average rate of change over a set

period of time, the rate of change at a given period within that period could be much

higher (e.g. the same event if measured over 100ms could have a RoCoF of 2Hz/s or if

measured over 500ms could have a RoCoF of 1Hz/s). Generators note that the

generation unit sees the frequency during the event regardless of how it is measured

and so may trip during an event measured as a 1Hz/s RoCoF because the actual

frequency changes were more severe than the average over 500ms suggested.

The CER notes these concerns but does not propose to change the definition at this

time. It is also noted that the definition including the 500ms period was discussed

extensively by the Working Group. It will be necessary as part of the studies to

determine an agreed set of scenarios with associated RoCoF traces. Therefore the

appropriateness of the 500ms time period can be examined when the results of the

studies are available. If the evidence shows that 500ms is not the most appropriate

period to measure over (given the expected events that the system will need to ride

through) then the CER may change the measurement period to a more suitable time

period before giving effect to MPID 229 in the Grid Code. It should be noted however

that the hertz per second figure may have to consequently increase if the measurement

period decreases.

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4.8.3 Study Scenarios and Network Models

Several respondents requested that EirGrid provide dynamic models and additional

information clarifying the expected RoCoF traces that a generator would see over 500ms

during a 1Hz/s RoCoF event. Generators argue that this information is a necessary

prerequisite to undertaking the technical studies. Subsequent to the close of the

consultation period on CER/13/143 EirGrid has published additional information on

RoCoF traces. EirGrid states that it is not possible to exhaustively define all possible

RoCoF traces and in any event any traces provided are merely indicative. They further

argue that (similar to other Grid Code requirements) generators are required to meet the

standard (i.e. 1Hz/s over 500ms) regardless of the RoCoF trace associated with that

event.

The CER notes the concerns and agrees both with the generators that additional

information is required and with EirGrid that it not possible to exhaustively define all

possible scenarios. Compliance will be determined in the first instance through the

technical studies and then (assuming implementation of MPID 229) on-going

performance monitoring. Such studies by their nature will require the selection of

scenarios and assumptions. The CER envisages that as part of the initial phase of the

implementation project the generator and EirGrid will agree a set of scenarios they

consider will reasonably demonstrate the capability of the unit in question. However, it is

noted that whatever scenarios are chosen they will not be the only possible scenarios

and that the determination of compliance with the Grid Code standard would not be

limited to meeting the RoCoF standard under those scenarios only.

4.8.4 Derogations

Several respondents requested clarification regarding the derogations process for MPID

229.

As part of the current derogations process a unit must prove the nature of their non-

compliance in addition to demonstrating that remedies to that non-compliance have

been explored. In relation to the RoCoF standard this will not be possible without the

completion of technical studies. Any unit seeking a derogation would have to include

their technical study to support their application. Therefore no change to the existing

derogations process is required.

In relation to exempted units discussed in Section 3 no derogations will be processed by

the CER until the implications for system security of such a derogation are clearer – at

least 18 months from the date of this decision.

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4.8.5 Demand loads

One respondent raised concern that demand loads may be adversely impacted were

there to be more frequent severe-frequency events and that the SNSP should not be

increased if this were the case.

The CER agrees with the respondent that it is important that customers should not be

adversely impacted as a result of the implementation of MPID 229. However, the CER is

not aware of any evidence suggesting that demand customers would be adversely

impacted. Notwithstanding this the CER has decided to direct the TSO and DSO to

monitor the impact of the new RoCoF standard as part of the implementation project,

further information is set out in Section 3.

4.8.6 Testing and Compliance

Several respondents requested clarification regarding testing of and compliance with the

new RoCoF standard.

As previously discussed it is not possible to conclusively test for RoCoF compliance,

although some tests can be carried out (such as injection tests). Therefore the technical

studies are particularly important in determining the capability of a given unit. It will be for

the generator in question to confirm its compliance, or otherwise, and for the TSO to

determine whether the new standard can be safely implemented. EirGrid, through its

existing responsibilities, will develop appropriate performance monitoring and testing for

RoCoF.

4.8.7 Long Term O&M Costs

Respondents raised concern that an increase in the frequency of high RoCoF events

would increase the operation and maintenance (O&M) costs of units.

The CER notes these concerns and accepts that O&M costs may indeed increase due to

a higher frequency of high RoCoF events. In response to these concerns the CER will

recommend that the SEM Committee request the TSOs to consider and propose a

remuneration mechanism relating to the new RoCoF standard.

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5 Next Steps

Implementation of this decision will be publicly notified by the CER shortly. In the coming

weeks the CER will engage with industry and EirGrid to establish the RoCoF

Implementation Project. High level project plans for the three work streams (System

Operator Implementation Project, Generator Implementation Project, and TSO

Alternative Solutions Project) will be agreed and published by the end of July 2014.

Three months from conclusion of the 18 month deadline set out in this Decision paper

EirGrid will submit a report to the CER with its recommendation on whether to implement

MPID 229 in the Grid Code. The CER will review EirGrid’s recommendation and will

decide on the implementation, or otherwise, of MPID 229.

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Appendix: Project Governance

CER

Project Oversight

TSO/DSO

System Operator

RoCoF Committee

Independent Expert

Project Co-ordination

TSO

TSO Alternative

Solutions Project

TSO

TSO Implementation

Project

DSO

DSO Implementation

Project

Generators

Generator

Implementation

Projects

TSO

Input at tripartite

meetings with

Generators