Generation Adequacy Report 2010-2016 - Eirgrid

DISCLAIMER 

EirGrid has followed accepted industry practice in the collection and analysis of data available. 

However, prior to taking business decisions, interested parties are advised to seek separate and 

independent opinion in relation to the matters covered by the present Generation Adequacy 

Report and should not rely solely upon data and information contained therein. Information in 

this document does not amount to arecommendation in respect of any possible investment. This 

document does not purport to contain all the information that a prospective investor or 

participantin Ireland selectricitymarket mayneed. 

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All rights reserved. This entire publication is subject to the laws of copyright. This publication may 

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photocopyingwithoutthe priorwritten permission of EirGrid. 

© EirGrid Plc 2009 

Front coverimage:An aerial photograph of the upper and lower reservoirs atTurlough Hill 

pumped storage station, located inthe Wicklow Mountains.Image provided by ESB Power 

Generation.

EirGrid - Generation Adequacy Report 2010-2016 

FOREWORD 

EirGrid, as Transmission System Operator (TSO), is pleased to 

present the2009 Generation Adequacy Report. 

This report assesses the generation adequacy situation for the 

period 2010 to 2016. Since last year, there has been adramatic 

change in the economic climate and this has been reflected in a 

reduction in electricity demand. We forecast that demand will not 

return to2008 levels until 2013. 

This, coupled with the connection of new generation, improved generator availability, and 

increased interconnection, means that there is adequate capacity to meet demand in 

accordance with the loss of load standard over the next seven years. While this is not a 

guarantee that therewillnot be load shedding, it does mean that theprobabilityis verylow. 

There has been a major change in the electricity industry in the last 10 years with 

deregulation, strong growth in demand, divestment of assets, entry by new generators and 

the successful establishment of Single Electricity Market. In parallel with this, the need to 

address climate change is driving new targets for renewable and low carbon generation. It is 

appropriate to consider the future direction of the electricity industry and plan for aplant 

portfolio incorporating high amounts of renewable generation. 

EirGrid has anumber of major studies on-going that can input to this. The Facilitation of 

Renewables study is identifying the dynamic issues associated with operating a power 

system with high levels of renewable generation, and how to best solve these issues. EirGrid 

has also commissioned astudy examining generator technologies and plant portfolio option 

in the longer-term to meet Ireland sneed for secure energy at acompetitive price with 

low/zero carbon emissions. I look forward to sharing the results of these studies with 

everyonein the industry. 

There is growing interest in developing electricity storage facilities on thepower system, 

both in Ireland and abroad. EirGrid has addeda special interest section on electricity storage 

to this year s report.Insection 6, different storage technologies are described.We showhow 

storage can be is utilised on thepower system. Based on an EirGrid study of the operation of 

varyinglevels of storage on the Irish power system, an illustrative setof results are 

presented. 

In the shorter-term, our analysis shows that Ireland will meet its 2010 targets of 15% of 

electrical energy from renewable sources. EirGrid remains fully committed to its part in 

delivering40% of electricity generated from renewable sources by 2020. 

Dermot Byrne 

Chief Executive, EirGrid 

1


Table ofContents 

FOREWORD .........................................................................................1 

EXECUTIVESUMMARY........................................................................6 

1 INTRODUCTION...........................................................................12 

2 ADEQUACYASSESSMENTMETHODOLOGY ..................................14 

2.1 INTRODUCTION ....................................................................................................14 

2.2 ADEQUACYSTANDARDAND CALCULATION METHODOLOGY....................................14 

2.3 APPLICATION OF METHODOLOGY ..........................................................................15 

2.4 INTERPRETATION OF RESULTS...............................................................................18 

2.5 DATAFREEZE........................................................................................................19 

3 DEMANDFORECAST....................................................................21 

3.1 INTRODUCTION ....................................................................................................21 

3.2 THE ELECTRICITY FORECAST MODEL.......................................................................21 

3.3 RESULTS OF ELECTRICITY FORECAST..................................................................... 24 

3.4 ENERGY DEMAND PERCAPITA ...............................................................................25 

3.5 THE PEAK DEMAND FORECAST MODEL...................................................................25 

3.6 PEAK FORECAST RESULTS.................................................................................... 26 

3.7 COMPARISON WITH PREVIOUS FORECASTS .......................................................... 26 

3.8 ANNUAL LOAD SHAPE...........................................................................................27 

3.9 CHANGESIN FUTURE DEMAND PATTERNS............................................................. 28 

4 ELECTRICITYSUPPLY...................................................................31 

4.1 INTRODUCTION ....................................................................................................31 

4.2 PLANTTYPES........................................................................................................31 

4.3 CHANGESIN FULLY DISPATCHABLEPLANT.............................................................32 

4.4 FORECASTS FOR PARTIALLY OR NON-DISPATCHABLE PLANT....................................36 

4.5 PLANTAVAILABILITY............................................................................................ 42 

5 ADEQUACYASSESSMENTS .........................................................45 

5.1 INTRODUCTION ....................................................................................................45 

5.2 IMPACT OF DEMANDGROWTH...............................................................................45 

5.3 IMPACT OF PLANTAVAILABILITY........................................................................... 46 

5.4 COMPARISON WITH GAR2009-2015..................................................................... 46 

6 ELECTRICAL STORAGE................................................................ 49 

6.1 TYPES OF STORAGE ............................................................................................. 49 

6.2 HOW ELECTRICITY STORAGEIS USED.....................................................................52 

6.3 ENERGY STORAGEANDTHE IRISH SYSTEM.............................................................53 

6.4 ECONOMICS OF ELECTRICITY STORAGE..................................................................54 

6.5 EIRGRIDSTUDY ON LARGE PUMPED STORAGE........................................................56 

7 KEYMESSAGES.......................................................................... 59 

APPENDIX 1 DEMANDFORECAST ...................................................61 

APPENDIX 2 GENERATION PLANTINFORMATION ...........................63 

APPENDIX 3 

APPENDIX 4 

SUPPLEMENTARYNOTESONMETHODOLOGY.............70 

ADEQUACYASSESSMENTRESULTS............................72 

2


List ofFigures 

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Figure6-6 

Figure6-7 

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3


List ofTables 

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TableA-1Electricitydemandgrowthforecastfrom economicandpopulationprojections(basedonCSO 

dataandESRIforecasts). .........................................................................................................61 

TableA-2 Highdemandforecast......................................................................................................62 

TableA-3Combinedforecastfor the All-Islandsystem......................................................................62 

TableA-4Comparisonofthe medianTERgrowth forecasts from this year sGAR,andGAR2009-2015.62 

TableA-5 Historical energyandpeak,withforecastfor2009. Theactualpeakfor2009 will have 

appearedat the start of theyear the figures here givethe peaks for Winter09/10 ...................62 

TableA-6Generationplantcapacity,for thebasecaseassumptions.Pleasenote that these capacity 

figuresareindicativeonly,asadvised bythe generatingcompanies.Theydo notnecessarily 

reflectwhatisinthe generators connectionagreements. .........................................................64 

TableA-7Informationon plant technologyfor fullydispatchableplant..............................................65 

TableA-8Existingwindfarms,as of 1October2009.........................................................................67 

TableA-9Windprojects withasignedconnectionoffer,asof 1October2009, withtheir target 

connectiondates.....................................................................................................................69 

TableA-10System for LOLE example................................................................................................70 

TableA-11Probability table..............................................................................................................71 

TableA-12Thesurplusof plantresultingfrom the different scenariosstudied.Allfigures aregivenin 

MWofperfectplant.These scenariosassume thefollowing:......................................................72 

4


EXECUTIVESUMMARY 

INTRODUCTION 

This report is produced in accordance with the requirements of the Electricity Regulation Act 

1999 and Statutory Instrument No. 60 of 2005, European Communities (Internal Market in 

Electricity) Regulations. It sets out estimates of the demand for electricity in the period 2010- 

2016, the likely production capacity that will be in place to meet this demand, and assesses 

the consequences in terms of the overall supply/demandbalance. 

The general form of the document has been approved by the Commission for Energy 

Regulation. 

Thisreportsupersedes the previous Generation Adequacy Report 2009-2015. 

METHODOLOGY 

The methodology adopted is similar to that used in previous reports. 

Generation adequacy is essentially determined by comparing electricity supply with 

demand. To measure the imbalance between them, astatistical indicator called the Loss of 

Load Expectation (LOLE) is used. When this indicator is at an appropriate level, called the 

generation adequacy standard, the supply/demand balance is judged to be satisfactory. The 

accepted generation adequacy standard for Ireland is 8 hours LOLE per year. 

The studies used for this report show whether there is enough electricity supply to meet the 

adequacy standard. Specifically, they give the amount of generation required when there isa 

shortage, or the amount of excess generation when there is asurplus. So, for example, when 

surpluses emerge in some years, the approximate amount of extra generation capacity that 

could be removed while still meeting the 8 hour standard is clearlyshown. 

Currently, limited connection means that Ireland only has formal capacity reliance of 

200 MW with Northern Ireland. However by 2013, asecond high capacity transmission link to 

Northern Ireland should be completed. This enables demand and supply for Northern Ireland 

and Ireland to be consolidated from 2013 onward. This all-island assessment is carried out 

againstanagreed all-island security standard of 8 hours LOLE per year. 

Given the uncertainty that surrounds any forecast of electricity supply and demand, the 

report examines anumber of different scenarios. It is intended that the results from these 

scenarios would provide the reader with enough information to draw their own conclusions 

regardingfuture adequacy. 

Akey factor in the analysis is the treatment of plant availability. Plant can be out of service 

either for regular scheduled maintenance or due to an unplanned forced outage. Forced 

outages have agreater adverse impact on adequacy than scheduled outages, as they may 

coincide with each other in an unpredictable manner. The modelling technique utilised here 

takes account of all combinations of forced outages with appropriate probability weights 

assigned to each. Periods of scheduled maintenance are provided by the generators and are 

also accounted for. 

Wind generation requires aspecial modelling approach to capture the effect of its variable 

nature. The approach used in this study bases estimated future wind performance on 

historical records of actual wind power output. 

6


DEMAND FORECAST 

The Irish economy has undergone adownturn in the past 12 months. This has been reflected 

in electricity demand figures, which dropped sharply in 2009. Based on monthly figures to 

date, demand in 2009 will be significantly lower than 2008 levels the first yearly drop in 

electricity usage in decades. 

An econometric process is used to forecast the future demand for electricity. The energy 

forecast model is amultiple linear regression model which predicts electricity sales based 

on changes in Gross Domestic Product (GDP), Personal Consumption of Goods and Services 

(PCGS), and population. Relating the electricity demand of a country to its economic 

performance is standard international practice. Three main electricity sales forecasts (high, 

median and low) are produced for Ireland for the next seven years. Forecasts provided by the 

Central Bank and the Economic and Social Research Institute (ESRI) are used as inputs to the 

model. 

45,000 

40,000 

All-Island 

Demand 

35,000 

2008 level 

30,000 

25,000 

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 

LowDemand Median Demand High Demand 

As would be expected, the demand forecast for this report is very different to that used in 

GAR 0915. The Median forecast does not see an increase on 2008 levels until 2013. Similarly, 

the High and Low demand forecasts do not see an increase on 2008 levels until 2012 and 

2014 respectively. 

The model for calculating yearly peak demand is based on the historical relationships 

between yearly peaks and total demand. The peak demands therefore show asimilar trend 

to the totaldemand. 

ELECTRICITY SUPPLY 

The assumptions around the generation portfolio are based on responses from the 

generatorsand connection agreements thatwere inplace at the datafreeze. 

The next few months will see two large CCGT plants commissioning in Cork. The Aghada and 

Whitegate units will add 877 MW of exported capacity to the system. The Dublin Waste to 

Energy plant at Ringsend will add 72 MW by the end of 2010. Another Waste to Energy plant 

in Meath will provide 17 MW. OCGT units at four sites are also due to start operating over the 

next fewyears, addinga combined 405 MW of exported capacity. 

7


The new East-West Interconnector will commission in 2012. While this will have amaximum 

export capacity of 500 MW, aprudent assumption of 250 MW has been made for its capacity 

for the studies in this report. 

The only change in fully dispatchable capacity in 2009 to date was caused by the closure of 

the steam turbine in Marina, reducing the capacity there by 27 MW. Following this winter, 

219 MW will be decommissioned with the closing of two units at Poolbeg. The end of 2012 

will see the removal of 806 MW from the system, as Great Island and Tarbert cease 

operation. 

The second high voltage transmission tie-line between Ireland and Northern Ireland will be 

completed by the end of 2012, enabling aswitch to an all-island assessment for 2013. This 

will combine the total generation for the two regions. Northern Ireland has seen the addition 

of two 40 MW units at Kilroot this year. A440 MW CCGT is expected to commission at the 

same location in 2015. Three units at Ballylumford will decommission by 2016, leading to a 

loss of 540MW. 

The effect all these changes have on the total dispatchable capacity can be seen in Figure 1-2 

below. Shortly prior to the publication of this document, connection agreements have been 

signed for a445 MW CCGT in Louth, a58 MW OCGT in Co. Meath, and a70 MW pumped 

hydro station in Cork. However, since these were signed outside the data freeze date, they 

havenot been included in our studies, or in any figures and tables contained in this report. 

10000 

9000 

8000 

7000 

6000 

5000 

2009 2010 2011 2012 2013 2014 2015 2016 

The Government of Ireland have set a target of 40% of electricity to be produced from 

renewable sources by 2020. At times of higher demand, it was calculated that this would 

require approximately 5,800 MW of wind generation to be installed in Ireland by 2020. The 

connection offer process used to connect windfarms to the grid was built around this target, 

and the assumptions for this report were developed on that basis. However, the change in 

forecasted demand means that the amount of wind generation required to meet the 40% 

target by 2020 has now dropped to just over 4,600 MW. This assumes that wind generation 

has a capacity factor of31%. 

Two availability forecasts are used in this report. The first is based on the prediction of 

availability provided by the generators. The second forecast is based on amodel that has 

8


been developed by EirGrid. This model takes into account the generators forecast as well as 

factoring in atrend of historical availability across the generation portfolio. It therefore takes 

account of high-impact, low probability (HILP) events that are not captured in the generators 

own availability forecast. After dropping steadily in the years up to 2007, plant availabilities 

have started to rise in the past two years. This level of performance is expected to be 

maintainedas newer generators get commissioned. 

ADEQUACY ASSESSMENTS 

In determining future system adequacy, the impact of varying demand growth and 

availability was examined. The adequacy position for each of the demand forecasts over the 

next seven years is shown in Figure 1-3. A positive adequacy situation is seen for all 

scenariosand all years. 

2,000 

Great Island 

Tarbert 

Ballylumford 

SteamTurbines 

1,500 

1,000 

AghadaAD2 

Edenderry OCGT 

All-Island 

System 

Suir OCGT 

KilrootCCGT 

Nore OCGT 

Cuilleen OCGT 

EWIC 

500 

0 

2010 2011 2012 2013 2014 2015 2016 

LowDemand MedianDemand HighDemand 

9


KEY MESSAGES 

• The adequacy situation is strongly positive for the next seven years. Asurplus of at least 

700 MW is observed for all scenarios studied for each of the seven years. This is due to 

new generation commissioning, increased interconnection, improved generator 

availability, as well asa reductionin demand. 

Even though there is sufficient capacity to comfortably exceed the standard of 8hours 

loss of load expectation used, this does not guarantee that load shedding could not 

occur.It does howevermean thatthe probability of load shedding isvery low. 

• The economic climate has lead to asignificant drop in actual and forecasted demand. 

The median forecast used in this document does not show an increase on 2008 levels 

until 2013. For the high and low demand scenario an increase on 2008 levels is not seen 

until 2012 and 2014 respectively. This is due to lower economic activity than previously 

forecast but also due to a lowerlevel of energy intensityper unit of GDP. 

This lower energy intensity level is due to greater energy efficiency and amaturing 

knowledge-based economy. In the long term, there is likely to be greater emphasis on 

energy efficiency but, for the electricity sector, this will be counter-balanced by greater 

use of electricity asanenergysource in the transportation and heating sectors. 

• Increased interconnection contributes to the adequacy position. The East-West 

Interconnector is due to be commissioned in 2012. This interconnector will connect the 

Irishand British transmission systems, and can carry up to 500 MW in either direction. 

The second high voltage transmission line between Ireland and Northern Ireland is due 

to be completed by 2013. As well as increasing efficiency and stability, this will allow a 

consolidation of the generation and demand of the two systems for capacity adequacy 

calculations. 

• Analysis shows that the target of 15% electricity from renewable sources in 2010 will be 

achieved. This is contingent on at least 120 MW of wind generation connecting during 

2010.It is expected that this figurewill be exceeded. 

10


1 INTRODUCTION 

This report is produced with the primary objective of informing market participants, 

regulatory agencies and policy makers of the likely generation capacity required to achieve 

an adequate supply and demand balance for electricity for the period up to 2016 1 . 

Generation adequacy is a measure of the capability of electricity supply to meet the 

electricity demand on the system. The development of new generation capacity and 

connection to the transmission system involves long lead times and high capital investment. 

Consequently this report provides informationcovering a seven-year timeframe. 

EirGrid, the Transmission System Operator (TSO), is required to publish forecast information 

about the power system, (as set out in Section 38 of the Electricity Regulation Act 1999 and 

Part 10 of S.I. No. 60 of 2005 European Communities (Internal Market in Electricity) 

Regulations). This report supersedes the previous Generation Adequacy Report published in 

December 2008, covering the period 2009 to 2015, and the Update to GAR 2009-2015 

published in July 2009. All input data assumptions have been updated and reviewed. Any 

changes from the previous report, including those to the input data and consequential 

results, areidentified and explained. 

This report is structured as follows. Section 2 outlines the methodology and security 

standard employed. This section also includes adescription of the methodology adopted 

when the scope of analysis changes from two systems with limited capacity reliance on each 

other to an all-island basis. Details of the economic-based median forecast as well as the 

alternative high and low demand scenarios are given in Section 3. Section 4describes the 

assumptions in relation to electricity production. Adequacy assessments are presented in 

Section 5. Section 6examines electrical storage technology and its potential for use in the 

Irish system. The report concludes with Key Messages in Section 7. Aglossary of technical 

terms is included at the end of this report, as well as several appendices which provide 

further detail of the data, results and methodology used in this study. 

1 

12


Replace with Divider for2ADEQUACYASSESSMENT METHODOLOGY 

13


2 ADEQUACYASSESSMENT METHODOLOGY 

2.1 INTRODUCTION 

In theory, determining system adequacy should simply consist of weighing up electricity 

supply against electricity demand. In reality, it is more complicated than this. Generators 

undergo sudden failure, wind generation is uncontrollable and hard to predict, and pumped 

storage is energy limited. This section gives an overview of the methodology used to 

calculate system adequacy, and how it dealswith such issues. 

2.2 ADEQUACY STANDARD AND CALCULATION METHODOLOGY 

Generation adequacy is assessed by determining the likelihood of there being sufficient 

generation to meet customer demand. It does not generally take into account any limitations 

imposed by the transmission system, reserve requirements or the energy markets. The 

adequacy model used here estimates the available generation for every half hour of ayear, 

and compares it to theexpected demand at that period. 

In practice, when there is not enough supply to meet load, the load must be reduced. This is 

achieved by cutting off electricity from customers. The Irish system is well supplied and 

operated, and such loss of load events are practically non-existent 2 . In adequacy 

calculations, if there is predicted to be asupply shortage at any time, there is aLoss Of Load 

Expectation (LOLE) for that period. 

LOLE can be used to set asecurity standard. The Irish system has an agreed standard of 8 

hours LOLE per annum if this is exceeded, it indicates the system has ahigher than 

acceptablelevel of risk. 

With any generator, there is always arisk that it may suddenly and unexpectedly be unable 

to generate electricity (due to equipment failure, for example). Such events are called forced 

outages, and the proportion of time a generator is out of action due to such an event gives its 

forced outage rate (FOR). 

Forced outages mean that the available generation in asystem at any future period is never 

certain. At any particular time, several units may fail simultaneously, or there may be no 

such failures at all. There is therefore aprobabilistic aspect to supply, and to the LOLE. The 

model used for these studies works out the of LOLE for each half-hour period it 

is these that are then summed to get the yearly LOLE, which is then compared to the 8-hour 

standard. 

Figure 2-1 illustrates the effect of LOLE being outside or within standard. With this typical 

curve, ahypothetical system with 7500 MW of installed capacity meets the standard exactly. 

However, asystem with just 7250 MW results in 45 hours LOLE per year, and is therefore 

outside standard and the system is in deficit. Conversely, asystem of 7750 MW experiences 

an LOLE of 1.5 hours per year and this being well within the standard, means that the system 

has surplus plant. 

2 

14


50 

40 

30 

System 

in 

Deficit 

20 

10 

8hrs/yr= Adequacy Standard 

System in Surplus 

0 

7000 7250 7500 7750 8000 

InstalledPlant Capacity (MW) 

The use of deterministic approaches, such as requiring afixed capacity margin (ratio of 

installed capacity to peak demand), cannot accurately capture the impact of this random 

behaviour. In addition, LOLE calculations have the advantage of taking the following factors 

into account: 

• The load at every hour of the year is considered to have an influence on generation 

adequacy,not just thehours of peak demand. 

• Thenumber and relative sizes of generation units impacton the LOLE calculation.A large 

number of small units will provide more security than asmall number of large units, 

other factors being equal. This is due to the fact that the probability of all units failing at 

oncedecreases asthenumber of individual units increases. 

2.3 APPLICATION OF METHODOLOGY 

On 1November 2007, the Single Electricity Market began trading, incorporating the whole 

island power system. However, until the second large-scale North-South transmission link is 

completed, there is atransmission constraint between the two jurisdictions. This must be 

taken into account when conducting adequacy calculations. After consultation with the CER, 

it has been agreed that afirm reliance of 200 MW on Northern Ireland can be assumed in 

adequacy assessments until 2012. After that, it is presumed that the North-South 

transmission link is in place and all transmission constraints are removed. The all-island 

system can then be assessed as awhole, allowing the complete generation portfolio to meet 

the combined load demand. This all-island assessment is carried out against an agreed allisland 

security standard of 8 hours per year 3 . 

The inherently variable nature of wind power makes it necessary to analyse its adequacy 

impact differently from that of other generation units. The contribution of wind generation to 

generation adequacy is referred to as the capacity credit of wind. This capacity credit has 

been determined by subtracting aforecast of wind shalf hourly generated output from the 

3 

15


customer electricity demand curve. The use of this lower demand curve results in an 

improved adequacy position. The amount of conventional plant which leaves the system with 

the same improvement in adequacy as the net load curve is taken to be the capacity credit of 

wind. 

600 

500 

400 

2005 Wind Profile 




Average Wind Profile 

70 MW 

300 

200 

100 

0 

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 

Installed Wind (MW) 

Analysis of wind data has established that this capacity credit is roughly equivalent to its 

capacity factor at low levels of wind penetration. However, the benefit tends towards 

saturation as wind penetration levels increase. This is because there is asignificant risk of 

there being very low or very high wind speeds simultaneously across the country. This will 

result in all wind farms producing practically no output for anumber of hours (note that 

turbines switch off during very high winds for safety reasons). In contrast, the forced outage 

probabilities for all thermal and hydro units are assumed to be independent of each other. 

Therefore,the probability of theseunits failing simultaneously is negligible. 

The capacity credit of wind will vary from year to year, depending on whether there is alarge 

amount of wind generation when it is needed most. For the studies in this report, capacity 

credits were calculated based on annual wind profiles from 2005 to 2008. The average 

values of these were then taken. The four profiles, and their average, are shown in Figure 

2-2. 

It can be seen in Figure 2-3 that there is abenefit to the capacity credit of wind when it is 

determined on an all-island basis. The reason for this is that agreater geographic area gives 

greater wind speed variability at any given time. If the wind drops off in the south, it may not 

drop off in the north, or at the very least there will be atime lag. The result is that the 

variation inwind is reduced and the reliabilityincreases. 

16


600 

500 

All-IslandWind 

ROIWind 

Capacity Credit (MW) 

400 

300 

200 

100 

0 

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 

Installed Wind (MW) 

Historically, generation adequacy has been assessed without reference to any limits that 

might be imposed by the bulk electricity transport system (the Transmission System). 

However, if the transmission infrastructure in aregion is insufficient to cope with the flows 

from generators at certain times, then those generators might be curtailed to match the 

ability of the transmission lines. This would mean that a generator s output would be 

constrained. 

Such asituation might occur if new generation plant were to connect before appropriate 

deep reinforcement of the transmission system was possible. In this case, the contribution 

of the new generation plant is reduced. In 2010, two large CCGT plants are commissioning in 

the Cork region. However, existing infrastructure will be unable to allow all plants in the 

region to simultaneously export to their full capacity. This has been accounted for in the 

studies presented in this report. 

EirGrid sTransmission Forecast Statement 4 seeks to identify areas where additional capacity 

exists on the transmission system, and thus where any new plant would not be constrained 

by transmission limitations. 

The pumped storage plant at Turlough Hill operates on adaily cycle, using electricity at night 

to pump water from alower to an upper reservoir. The potential energy stored as aresult of 

this pumping is then released to generate electricity during high demand periods. The 

amount of energy which can be produced during the generation period of the pump storage 

cycle is largely limited by the physical size of the reservoir. This places alimit on the amount 

of energywhichcan bestored and then released in any24hour period. 

The adequacy assessment model (AdCal) does not utilise the full installed capacity (292 MW) 

of the pumped storage station for every hour of the day because of this energy limitation. 

4 

17


Instead, the model optimises the cycle on adaily basis, so that the energy is used when it is 

needed most. Pumped storage is discussed inmore detailin section 6.1(a). 

The base case scenario presented in this report is considered to be the most likely outlook. 

However, it is prudent to examine the effect other situations would have on adequacy. 

Studies are therefore carried out on arange of scenarios. These different scenarios are as 

follows: 

• Demand growth -low and high demand scenarios are also presented, which use the 

same generation portfolio as in the base case, but different demand forecasts 

• Plant availability variations inplant availability areconsidered 

Theresultsfrom thesescenariosare presented in section 5. 

2.4 INTERPRETATION OF RESULTS 

While the use of LOLE allows a sophisticated, repeatable and technically accurate 

assessment of generation adequacy to be undertaken, understanding and interpreting the 

results may not be completely intuitive. If, for example, in asample year, the analysis shows 

that there is aloss of load expectation of 16 hours, this does not mean that all customers will 

be without supply for 16 hours or that, if there is asupply shortage, it will last for 16 

consecutive hours. 

It does mean that if the sample year could be replayed many times and each unique outcome 

averaged, that demand could be expected to exceed supply for an annual average duration 

of 16 hours. If such circumstances arose, typically only asmall number of customers would 

be affected for ashort period. Normal practice would be to maintain supply to industry, and 

to use a rolling process to ensure that any burden is spread. 

In addition, results expressed in LOLE terms do not give an intuitive feel for the scale of the 

plant shortage or surplus. This effect is accentuated by the fact that the relationship 

between LOLE and plant shortage/surplus is highly non-linear. In other words, it does not 

take twice as much plant to return asystem to the 8hour standard from 24 hours LOLE as it 

would from 16 hours. 

In the real-time operation of the power system, acombination of events, such as very high 

coincident scheduled and forced outages, can occur, even though the statistical probability 

of such occurrences is very small. This can lead to supply shortages during periods when the 

balance ofprobabilitywould havesuggesteda supply surplus. 

On the other hand, aperiod for which there is avery high loss of load expectation can pass 

without failure provided actual conditions are benign, i.e. the dice fall kindly. However, 

valuable conclusions can be drawn from probabilistic analysis. For example, if LOLE is 

greaterthan standard, thena higher than acceptablerisk of supply failure is indicated. 

In order to assist understanding and interpretation of results, afurther calculation is made 

which indicates the amount of plant required to return the system to standard. This 

effectively translates the gap between the LOLE projected for agiven year and the standard 

into an equivalent plant capacity (in MW).If the system is in surplus, this value indicateshow 

much plant can be removed from the system without breaching the LOLE standard. 

Conversely, if the system is in breach of the LOLE standard, the calculation indicates how 

much plantshould be added to thesystem tomaintain security. 

The exact amount of plant that could be added or removed would depend on the particular 

size and availability of any new plant to be added. The amount of surplus or deficit plant is 

therefore given in terms of Perfect Plant. Perfect Plant may be thought of as aconventional 

generator with no outages. For example, 100 MW of Perfect Plant would be able to supply 

18


100 MW for each hour of the year. In reality, no plant is perfect, and the amount of real plant 

in surplus or deficitwill alwaysbehigher. 

2.5 DATA FREEZE 

To carry out the detailed analysis required to produce this report, data relating to the 

performance of the Irish economy, generator capacity, and availability was collected from 

various sources, and then frozen on the 1 st October 2009. Following this, the data was 

checked and confirmed before detailed analysis and modelling commenced. All quantitative 

analysis, the results of which are presented in this report, is based on data unchanged from 

this date. 

However, any changes that have come to EirGrid sattention since that date have been noted 

in the corresponding sections. The impacts of such changes are assessed in qualitative 

terms where appropriate. 

5 

19


3 DEMAND FORECAST 


Aforecast of how much electricity will be needed in the future is essential for determining 

generation adequacy. EirGrid uses models based on economic forecasts and historical 

trends to predict future electricity demands, as well as future peaks. These models are 

outlined in this section, alongwiththe results they produce. 

The state of Ireland seconomy has shifted considerably since the release of the previous 

GAR in December 2009. Growth rates have plummeted over the past twelve months, as 

Ireland entered one of its most severe recessions ever. This has been reflected in electricity 

demand figures, which dropped sharply in 2009. Based on monthly figures to date, demand 

in 2009 will be significantly lower than 2008 levels the first yearly drop in electricity usage 

in decades. 

Due to this unforeseen change in demand, EirGrid released an update to GAR 0915 6 inJuly 

2009. This outlined arange of revised forecasts that were shifted downward from those 

presented in GAR 0915. Since then, new economic forecasts have been released from both 

the ESRI and the Central Bank. As has been the trend since spring 2007, the predictions in 

these quarterly updates were more pessimistic than those in the previous issues. As such, a 

new set of demand figures have been calculated for use inthis report. 

Following the proposed completion of the second major transmission link to Northern 

Ireland by 2013, generation adequacy studies can be carried out for the whole island as a 

single system without any transmission constraints. Therefore, the demand forecasts from 

both jurisdictions are added together to form acombined load for the years 2013-2015. 

Forecasts for future Northern Ireland demand have been provided by System Operators 

Northern Ireland (SONI). 

The results obtained are compared with previous forecasts, and finally, information on 

typical load shapes is presented. Forecasted demand figures are given in terms of Total 

Electricity Requirement(TER).All calculatedTER and peakvalues are listed inAppendix 1. 

3.2 THE ELECTRICITY FORECAST MODEL 

The energy forecast model is amultiple linear regression model which predicts electricity 

sales based on changes in GDP 7 ,PCGS 8 ,and population. Relating the electricity demand of a 

country to its economic performance is astandard international practice. Three electricity 

sales forecasts (high,median and low) are produced for Ireland forthe next seven years. 

Over the past few years, the energy intensity of Ireland seconomy has decreased. Energy 

intensity is calculated by dividing the total electricity sales by the GDP for each year. This is 

outlined in Figure 3-1, which shows asteady drop in electrical energy intensity from 1994 

onward. Government targets of achieving energy efficiency savings of 20% by 2020 (33% for 

6 

7 

8 

21


the public sector) 9 mean that this drop is set to continue. Initiatives to promote efficiency in 

areas such as domestic electricity use and home heating are already coming into effect. 

Also, it is expected that any recovery from the current recession would be less dependent on 

energy-intensive industries such as construction. For this reason, the relationship between 

economic growth and electricity sales is reduced from 2012 onward in our low and median 

scenarios. 

0.22 

0.20 

0.18 

0.16 

0.14 

0.12 

0.10 

1980 1984 1988 1992 1996 2000 2004 2008 

Year 

Transporting electricity from the supplier to the customer invariably leads to losses. These 

losses must be added to the forecasted sales figures to give the amount of electricity needed 

to be generated. Based on analysis of historical production and sales figures, it is estimated 

that 8.3% of power produced is lost as it passes through the electricity transmission and 

distribution systems. 

Some large-scale industrial customers produce and consume electricity on site. This 

electricity consumption, known as self-consumption, is not included in sales or transported 

across the network. Consequently an estimate 10 ofthis quantity is added to the energy which 

must be exported by generators to meet sales. The resultant energy is known as the Total 

Electricity Requirement (TER). As all generation sources are considered in the analysis, it is 

this TER that is utilisedfor generation adequacy calculations. 

The electricity model is trained using historical data. For GAR 2010-2016, the most recent 

figures at the time of the data freeze were used; economic data and population figures from 

the Central Statistics Office (CSO) and Economic and Social Research Institute (ESRI), as well 

as demand data supplied by the Distribution System Operator and ESB Public Electricity 

Supply. 

In order for the trained energy model to make predictions, it needs forecasts of GDP, PCGS, 

and population. These forecasts are based on publications by both the ESRI and the Central 

Bank. The ESRI, who have expertise in modelling the Irish economy, were consulted during 

the modelling process. 

9 

10 

22


Short term forecasts were based on quarterly economic commentaries published by both the 

Central Bank and ESRI. These are outlined in Table 3-A. To model growth for 2012 and 

beyond, we have used GDP predictions from the 'Recovery Scenarios for Ireland' (RSfI) 

report 11 produced by the ESRI. Recent signs of recovery in world markets would indicate that 

the WorldRecovery scenario outlined in thisdocument looks to be the most likely outcome. 

GDP (volume) 

Personal 

Consumption 

2009 2010 2009 2010 

ESRI (Autumn) -7.2% -1.1% -7.0% -2.0% 

Central Bank (Autumn) -7.8% -2.3% -7.6% -4.0% 

Central Bank (Summer) -8.3% -2.7% -8.0% -4.9% 

The depth of the recession is reflected in EirGrid sown demand figures, shown in Figure 3-2. 

These show a5.4% drop in Jan-Sept 2009 when compared with the same period in 2008 

the drop for Sept alone was 6.1%. This fall has brought us back down to around the same 

levels as seen for 2006. The model was unable to predict such asharp drop in demand for 

2009. It was therefore decided to base our 2009 figures on real data. As only figures up until 

September were available by the data freeze date, estimates were made for the remaining 3 

months.These varied slightly for the low, median andhigh forecasts. 

2700 

2600 

2009 

2008 

2006 

Exported Demand (GWh) 

2500 

2400 

2300 

2200 

2100 

6.4% 7.2% 

6.1% 

2000 

1900 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

These figures give energy values lower than those predicted by the model for 2009. To 

balance this, we have adjusted 2010 figures so that the total energy for this year matches 

that given by the model in each scenario. 

The median growth scenario utilises the Central Bank sEconomic commentary released in 

September 2009 12 .Growth rates for 2012 and beyond follow predictions from the 'World 

11 

12 

23


Recession Scenario' from the RSfI report. From 2012 the model is modified to give less 

energy intensive economic growth. Areturn to 2008 demand levels is not observed until 

2013. 

The high growth scenario gives the most optimistic viewpoint. The growth rates for 2009 and 

2010 are based on ESRI s Quarterly Economic Commentary 13 released in October 2009. 

Growth rates past 2012 follow the predictions outlined in the 'World Recovery Scenario' from 

the RSfI report, leading to a rapid increase in electricity sales once economic recovery 

begins. 

This scenario assumes that relationships between electricity sales and economic growth will 

be similar to those seen historically. Areturn to 2008 demand levels is not observed until 

2012. 

The low growth scenario utilises the Central Bank sEconomic commentary released in July 

2009 14 .In this scenario, a recovery from the recession isnot seen untilwell into2011. Growth 

rates for 2012 and beyond follow predictions from the 'Prolonged Recession Scenario' from 

the RSfI report, with the model modified to give less energy intensive economic growth. A 

return to2008 demand levels is not observed until 2014. 

3.3 RESULTS OF ELECTRICITY FORECAST 

The demand model forecasts the electricity sales over the next seven years. These sales 

forecasts are then converted to TER values, which are shown in Figure 3-3. The transition to 

an all-island assessment from 2013 onwards means that loads from Ireland and Northern 

Ireland are combined. Figure 3-3 includes the annual demands for the combined all-island 

system. Further details on the demand forecast, including tabulated figures, can be found in 

Appendix 1. 

45,000 

40,000 

All-Island 

Demand 

35,000 

2008 level 

30,000 

25,000 

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 

LowDemand Median Demand High Demand 

13 

14 

24


3.4 ENERGY DEMANDPER CAPITA 

In analysing Ireland selectricity usage, it is worthwhile to make comparisons with the other 

EU states. Figure 3-4 shows the electricity usage per head of population for Ireland, and also 

the average of the first 15 EU members and for the EU as a whole. Predicted values for Ireland 

were calculated using the Median demand forecast. For other EU countries, alinear trend 

was used. 

7.5 

7.0 

EU-27 

EU-15 

Ireland 

6.5 

6.0 

5.5 

5.0 

4.5 

1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 

Year 

Towards the end of the nineties, rapid economic growth closed the gap between Ireland and 

the EU average. However the current downturn in the economy has hit Ireland much harder 

than the rest of Europe on average, and it is likely that this gap will widen again over the next 

few years. 

3.5 THE PEAK DEMAND FORECAST MODEL 

The peak demand model is based on the historical relationship between the annual 

electricity consumption and the winter peak. This relationship is defined by the Annual Load 

Factor, which is simply the average load divided by the peak load. For the purposes of this 

report, thewinter period is defined as November through to February. 

Historically, the winter peak is somewhat erratic and difficult to model as it is subject to 

many disparate influences, including 

• temperature and weather conditions 

• changingcustomer habits, especially domestic customers 

• Demand-Side Management (DSM) schemes 15 

While predicting future variations in weather and customer habits is beyond the scope of 

this study, the effects of DSM are estimated and corrected for. In recent years, the amount of 

peak load reduction achieved by the Winter Peak Demand Reduction scheme has been 

estimated at 138 MW for the purposes of the peak demand forecast model. This DSM value is 

15 

25


assumed for future years. Were the incentives removed in the future, the peak load should 

increase by approximately this amount. Since all study scenarios show a surplus of 

generation in excess of this figure, this would not have a detrimental effect on system 

adequacy. 

3.6 PEAK FORECAST RESULTS 

Using the forecast electricity demand values and the DSM assumptions in the peak demand 

model, the winter peaks for the next seven years were calculated for three demand 

scenarios. In terms of the TER peak, which consists of the exported power plus estimate of 

self-consumption, the forecasted winter peaks are given in Figure 3-5 and are detailed in 

Appendix 1. 

Historically, it has proven difficult to forecast the peak increase in any particular year. The 

forecasting models assume an average annual load factor for future years. Over the last five 

years however, the annual load factor has varied from 63.3% to 66.3%. Calculating peak 

values using thesetwo figures would give a difference ofover 200MW. 

In 2013-2016, loads from Ireland are combined with the Northern Ireland load to determine 

an all-island peak forecast. As the load shape is not the same for the two regions, the peaks 

are not necessarily coincident. Therefore, the peak of the combined load is slightly less than 

the simple addition of the individual peaks. This is just one of the benefits of operating the 

all-island system as awhole. Figure 3-5 shows thecombinedTER peak forecast. 

7600 

7000 

All Island TER Peaks 

6400 

5800 

2007 Peak 

5200 

4600 

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 

Low Median High 

3.7 COMPARISON WITH PREVIOUS FORECASTS 

The forecast in last years report, GAR 0915, was based on data received before the extent of 

the downturn was realised. The future demand figures presented in that report were far 

higher than would be expected now. EirGrid released an update to GAR 0915 in July 2009 

which outlined a range of revisedforecasts. 

The previous year sGAR predicted TER growth rates of 2.1% for both 2008 and 2009. In 

reality, the growth for 2008 was more modest at 1.7%, while 2009 is now expected to show 

TER declining by around 5.5%. 

26


Figure 3-6 shows this year sdemand forecasts compared to those used in the GAR 0915 

update. While the current forecast shows asharper dip for the next two years, aslightly 

swifter recovery means that future demand levels are roughly equivalent for the low and 

median scenarios. The current high scenario gives higher demand rates than its equivalent 

as presented in the GAR 0915 update. This gives alarger range to the forecast, and enables 

examination of generation adequacy in theevent of a rapid energyintensive recovery. 

34000 

32000 

Demand (GWh) 

30000 

28000 

26000 

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 

Low Median High 

Low (GAR 0916 update) Median (GAR 0916 update) High (GAR 0916 update) 

3.8 ANNUALLOAD SHAPE 

To accurately model the Irish system, projections of electricity demand are required for each 

hour of the study period. Electricity usage generally follows some predictable patterns. For 

example, the peak demand occurs during winter weekday evenings while minimum usage 

occurs during summer weekend night-time hours. Peak demand during summer months 

occurs much earlier in the day than it does in thewinter period. 

Figure 3-7 shows atypical daily demand profile for Ireland, for both asummer and winter 

weekday in 2008. Winter peak and summer minimum load days are also included in order to 

illustrate the range of possible demand levels. Many factors impact on this electricity usage 

pattern throughout the year. Examples include weather, sporting or social events, holidays, 

and customer demandmanagement. 

27


5000 

4500 

4000 

Winter Max 

Typical Winter 

Typical Summer 

Summer Min 

3500 

3000 

2500 

2000 

1500 

1000 

0 3 6 9 12 15 18 21 24 

Hour 

The demand in 2008 followed an unusual shape. The recession caused demand to drop 

towards the end of the year. This can be seen in Figure 3-8, where demand for the first few 

months is much higher in 2008 than in 2007. However by the end of the year the demand for 

the two years is very similar. The skewed 2008 demand profile was therefore not used for as 

a base shape for futureyears instead 2007, deemed to be a typical year,was used. 

2007 

2600 

2008 

2400 

2200 

2000 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

3.9 CHANGES IN FUTURE DEMAND PATTERNS 

While load patterns are quite predictable in the short term, social and technological changes 

may occur which could affect the demand curve. For example, there are plans to introduce 

Smart Metering in Ireland. Smart meters would give real-time information to individual 

customers regarding their electricity usage. If this were combined with an appropriate 

pricing structure, it should cause aflattening of the daily demand curve. Higher charges at 

28


peak periods would encourage customers to switch consumption to other times. This would 

reduce theneed for generation atpeak and increase system adequacy. 

Last year sGAR examined how the uptake of electric vehicles could affect the typical daily 

load shape. It is expected that electric and plug-in hybrid cars will begin to take alarger 

proportion of market share in the near future, and almost every manufacture is planning the 

release of such amodel over the next two years. Government targets aim for 10% of vehicles 

on Irish roads to be electric by 2020. Calculations showed that this should not create amajor 

increase in peak electricity demand, and may actually make generation more efficient by 

filling in the night-valley .Figure 3-9 shows how the daily load profile would be affected if 

250,000 vehicles werecontrollably charged on the Irishsystem in 2020. 

6000 

5500 

5000 

4500 

4000 

3500 

3000 

2500 

00:00 06:00 12:00 18:00 00:00 

Load without Evs 

Load with controlled charging of 250,000 vehicles 

29


4 ELECTRICITYSUPPLY 


Generation adequacy describes the balance between demand and supply. This section 

describes all significant sources of electricity connected to the Irish system, and how these 

will change over the next few years. Issues that effect security of supply, such as installed 

capacity, plant availability, and capacitycredit of wind, are examined. 

Predicting the future of electricity supply in Ireland will never be fully accurate. Scenarios are 

therefore introduced to show what effects particular events or portfolio changes would have 

on Ireland s adequacy position. 

At this point in time, the following significant changes to the plant portfolio can be forecast 

for thenextseven years: 

• Two new combined cycle gas turbine units (CCGTs) in Cork are due to connect over the 

coming months.Thesewill have acombinedcapacity of 877 MW. 

• Four new open cycle gas turbine (OCGT) power stationsare to be connected over thenext 

four years,giving an additionalcapacity of405 MW. 

• Anew distribution-level Combined Heat and Power (CHP) plant will be opening in Dublin. 

This Waste-to-Energy converter, located at Ringsend, will be able to supply 72 MW. A 

smaller 17MW Waste-to-Energyconverterwillbe commissioning in Meath. 

• ESB Power Generation will be decommissioning 2units at Poolbeg in March 2009. These 

give areduction in capacity of 219 MW. This is in addition to a 3 rd 242 MW unit at 

Poolbeg which has already been decommissioned. 

• Great Island and Tarbert will be decommissioned at the end of 2012. This will give a 

reduction of 806 MW in capacity. 

• There will be alarge amount of wind generation added to the system over the next seven 

years. While the exact amount is as yet uncertain, it is assumed to be in the region of an 

additional3,000 MW. 

Interconnection will also play an important role in future supply security. The East-West 

Interconnector, connecting the Irish and British transmission systems, is due for completion 

in 2012. This will be able to transmit 500 MW in either direction. The second major North- 

South Interconnector connecting Northern Ireland and Ireland will enable aconsolidation of 

the two system sdemand and supply for assessing system adequacy. This will lead to a 

more secure, stable, and efficient system. For the purpose of this report, we assume that this 

will be inplace by 2013. 

4.2 PLANT TYPES 

The generation portfolio is made up of many different plant types. These all have different 

operational characteristics, and contribute differently towards generation adequacy. One of 

the most important categorisations, from ageneration adequacy perspective, is whether or 

not the plant is fully dispatchable .For aplant to be fully dispatchable, EirGrid must be able 

to monitor and control its output from the National Control Centre (NCC). Since customer 

demand is also monitored from the NCC, EirGrid can adjust the output of fully-dispatchable 

plant in order to meet this demand. 

31


There is an amount of generation connected to the system whose output is not currently 

monitored in the NCC and whose operation cannot be controlled. This non-dispatchable 

plant, known as embedded generation, has historically been connected to the lower voltage 

distribution system and has beenmade up of many unitsof small individual size. 

Large wind farms fall into adifferent category. Since the maximum output from wind farms is 

determined by wind strength, they are not fully controllable. However, their output can be 

reduced by EirGrid when required, and they are therefore categorised as being partiallydispatchable. 

In accordance with the Grid Code and the Distribution Code 16 ,wind farms with 

an installed capacity greaterthan 5 MW must be partially-dispatchable. 

4.3 CHANGES IN FULLYDISPATCHABLE PLANT 

This section describes the changes in fully dispatchable plant capacities which are forecast 

to occur over the next seven years. Plant closures and additions are documented. Only new 

generators which have asigned connection agreement 17 with EirGrid by the data freeze date 

are included in adequacy assessments. Similarly, only planned decommissionings that 

EirGrid have been officially notified of by thedata freezedate are considered. 

Table 4-A lists conventional generators that have signed agreements to connect to the grid 

over the next seven years. The largest of these are the CCGTs at Aghada and Whitegate, 

which are both due to start commercial operation in 2010. Both of these CCGTs are located in 

close proximity to each other in the south-west of Ireland (see Figure 4-1). 

AghadaCCGT Jan 2010 432 MW 

WhitegateCCGT Jun 2010 445 MW 

Edenderry OCGT Jul 2010 111 MW 

Dublin Waste-to-Energy Aug 2010 72 MW 

Meath Waste-to-Energy Jan 2011 17 MW 

Nore OCGT Nov 2011 98 MW 

Cuileen OCGT Jul 2012 98 MW 

Suir OCGT Jan 2013 98 MW 

There is also alarge amount of new wind generation capacity due for connection in the 

south-west over the next number of years. As a result, significant reinforcement of the 

transmission system will be required here to enable this power to be exported. In the 

absence of such reinforcement, the output of generation in this region will have to be 

constrained from time to time.Thiswould impact on the capacitybenefit of this generation. 

Analysis of the existing transmission system s capability has indicated, for generation 

adequacy purposes, that the generation in the Cork area should be de-rated by 270 MW to 

take account of the shortage of export capability. Shallow reinforcements 18 have been 

constructed to allow the new CCGT units to export their rated power. However, there will still 

be constraints on south-west generation until such time as deep reinforcements are 

16 

17 

18 

32


completed. The permanent 19 solution to remove this transmission constraint is likely to 

includetheconstruction of additional highcapacity lines. 

It is thought that the shallow reinforcements will allow Whitegate to export its full capacity, 

while there will be a collective export limit of 690 MW from the Aghada site. This site 

comprises of Aghada AD1 (258 MW), Aghada CT 1, 2and 4(3 X90MW), and the new Aghada 

AD2 (432 MW),with a total exportcapacity of960 MW. 

Plant Type 

Fuel 

Conventional steam 

HFO 


Coal/HFO 


Peat 


Gas 


Gas/HFO 

Open cycle combustion turbine 

DO 

Open cycle combustion turbine 

Gas/DO 

Combined cycle combustion 

Turbine 

Gas/DO 

Combined heat and power 

Gas/DO 

Hydro generation 

Hydro 

Pumped storage 

Hydro 

HFO=Heavy Fuel Oil; DO=Distillate Oil 

ERNE 

(66 MW) 

NORTHERN 

IRELAND 

COOLKEERAGH (455 MW) 

BALLYLUMFORD (1213 MW) 

MOYLE INTERCONNECTOR (450 MW) 

KILROOT (614 MW) 

TAWNAGHMORE 

(104 MW) 

LOUGH REE POWER (91 MW) 

NORTH WALL 

(163+104=267 MW) 

CUILEEN (98 MW) 

HUNTSTOWN 

(740 MW) 

RHODE (104 MW) 

WEST OFFALY POWER 

(137 MW) 

EDENDERRY 

TYNAGH (384 MW) 

(111+118 =229 MW) 

LIFFEY (38 MW) 

TURLOUGH 

HILL (292 MW) 

POOLBEG 

(463MW) 

EWIC 

(250 MW) 

DUBLIN BAY (403 MW) 

MONEYPOINT 

(849 MW) 

ARDNACRUSHA (86 MW) 

SEALROCK (161 MW) 

NORE NOIR (98 (98 MW) MW) 

SUIR (98 MW) 

LEE (27 MW) 

MARINA 

(85 MW) 

AGHADA 

(258+270+432=960 MW) 

WHITEGATE (445 MW) 

TOTAL FULLY DISPATCHABLE ROI PLANT: 

6676 MW +200MW from NI = 6426 MW 

There are also plans to connect new OCGTs at four sites 20 over the next four years, with a 

combined capacity of 405 MW. OCGTs, while usually less efficient than CCGTs, are faster 

acting, and can be brought up to (or down from) full capacity relatively quickly. Their 

flexibility makes them well-suited for asystem with high amounts of wind generation, where 

19 

20 

33


they can be ramped up if wind levels drop quickly. Two Waste to Energy plants will also be 

added to the system,with a combined capacity of 89 MW. 

Shortly prior to the publication of this document, connection agreements have been signed 

for a445 MW CCGT in Co. Louth, a58 MW OCGT in Co. Meath, and a70 MW pumped hydro 

station in Co. Cork. However, since these were signed outside the data freeze date, they 

havenot been included in our studies, or in any figures and tables contained in this report. 

As well as the new plant mentioned above, some older generators will come to the end of 

their lifetimes over thenext 7 years. Confirmed decommissionings areshown in Table 4-B. 

Poolbeg 1 & 2 Mar 2010 219 MW 

Great Island Dec 2012 216 MW 

Tarbert Dec 2012 590 MW 

It is likely that new generators will start operating at the Great Island and Tarbert sites at the 

end of 2012. The existing units in Great Island and Tarbert sites would only be 

decommissioned once the new units were ready for commercial operation. It is also possible 

that one of the larger 241 MW units at Tarbert may be kept open until the end of 2015 

depending on market conditions. However, for the purposes of the base case GAR portfolio, 

it is assumed that all generation at Tarbert and Great Island stops at the end of 2012, and no 

new plant is assumed to come on at these sites for the duration of the study period. 

Interconnection allows the transport of electrical power between two transmission systems. 

EirGrid is due to complete two large interconnection projects by the end of 2012. The 

completion of the second high capacity transmission link between Ireland and Northern 

Ireland will allow the consolidation of demand and supply on an all-island basis for 

assessment of system adequacy. Therefore, for 2013-2016, an all-island generation 

adequacy assessment has been carried out. In this all-island assessment, the demand and 

generation portfolios for Northern Ireland and Ireland are aggregated. Prior to the 

completion of this project, capacity reliance on supply from Northern Ireland is limited to 

200 MW due to transmission constraints. 

Information on the installed capacity and availability of plant in Northern Ireland has been 

supplied by SONI. In 2013 these forecasts indicate that there will be 2,732 MW of centrally 

dispatched capacity available in Northern Ireland. This figure includes 450 MW over the 

existing Moyle interconnector to Scotland. Anew 440 MW CCGT is due to open in Kilroot in 

2015,with 540 MW being decommissioned atBallylumford the end of this year. 

The East-West interconnector (EWIC) will connect the Irish and British transmission systems, 

and is due to be completed in 2012. The interconnector can carry up to 500 MW in either 

direction. However, it is not easy to predict whether or not imports for the full 500 MW will be 

available to the Irish market at all times. While EirGrid has calculated the capacity value of 

the interconnector to be 440MW, alower figure of 250MW has been used as aprudent 

measure. 

34


During year: 2009 2010 2011 2012 2013 2014 2015 2016 

Capacity added +1060 +115 +98 +98 

Capacity withdrawn 21 -28 -219 -806 

Northern Irelandreliance -200 

All-Island Portfolio +2732 +440 -540 

EWIC +250 

Minor Degradation -2 -2 -2 -2 

Net Impact -28 +839 +115 +346 +1824 -2 +440 -542 

Capacity change from 

+839 +954 +1300 +3124 +3122 +3562 +3020 

2009 

The combined impacts of capacity added and withdrawn, moving to an all-island generation 

portfolio, and the EWIC on the total dispatchable capacity are illustrated in Figure 4-2. These 

are tabulated in further detail in Appendix2. 

10000 

9000 

8000 

7000 

6000 

Northern Ireland 

North-South 

Interconnection 

Peat 

5000 

Distillate Oil 

4000 

3000 

2000 

1000 

Hydro/Pumped 

Storage 

Coal 

HeavyFuel Oil 

Gas 

0 

2009 2010 2011 2012 2013 2014 2015 2016 

Amap showing the location of the fully-dispatchable plant appears in Figure 4-1, while more 

detail on each unit can be found in Appendix 2. For information purposes, this map also 

includes the capacities of plant inNorthern Ireland. 

At year end: 2009 2010 2011 2012 2013 2014 2015 2016 

Dispatchable capacity 6171 7010 7125 7471 9295 9293 9733 9191 

21 

35


4.4 FORECASTS FOR PARTIALLYORNON-DISPATCHABLE PLANT 

Non-fully-dispatchableplantconsists of: 

1. Industrial back-up generation 

2. Small-Scale Combined Heat andPower (CHP) 

3. Small-Scale Biomass (Renewable) 

4. Small-Scale Hydro (Renewable) 

5. Wind Generation (Renewable) 

For non-renewable generation, estimates of future quantities have been made using industry 

conditionsand historical trends. 

Forecasts for renewable generation have been compiled to align with Government policy. In 

March 2007, the Irish government released aWhite Paper entitled Delivering aSustainable 

Energy Future for Ireland 22 .This paper sets out the following action item: We will achieve 

15% of consumption on anational basis from renewable energy sources by 2010 and 33% by 

2020 .In October 2009 the Government superseded this target by announcing atarget of 

40% of energy production to be met by renewables by 2020. For the purpose of this report, it 

is assumed that this target will be achieved largely 23 through the deployment of additional 

wind powered generation (see Section 4.4(e)). 

The position with other emerging technologies such as wave and tidal power is being 

monitored, but asignificant contribution is not expected within the next seven years. This 

assumption is without prejudice to the Government starget of having 500 MW of installed 

ocean energy capacity by 2020. Given that such technology is now at the research, 

development and demonstration stage it is likely that large-scale commercial deployment 

will only occur at alater time than that covered in this report. For the purposes of projecting 

the amount of renewables required to meet the 40% target, wave was assumed to be making 

a contribution in that timeframe 24 . 

Industrial generation refers to generation, usually powered by diesel engines, located on 

industrial or commercial premises, to act as on-site supply during peak demand and 

emergency periods. It is estimated that the total installed capacity of such generation is over 

50 MW. However, as the condition and mode of operation of this plant is uncertain, industrial 

generationhas been ascribed a capacity of 9MW for thepurposes of this report. 

Combined Heat and Power utilises generation plant to simultaneously create both electricity 

and useful heat. Due to the high overall efficiency of CHP plant, often in excess of 80%, its 

operation provides benefits in terms of reducing fossil fuel consumption and CO 2 emissions. 

To date, the deployment of CHP in Ireland has been modest. Estimates give a current 

installed CHP capacity of roughly 120 MW, (not including the 161 MW centrally dispatched 

CHP plant operated by Aughinish Alumina). As an indication of current activity by developers 

of CHP, there are 60 MW of unsigned applications in the queue for network connections, as 

well as a 72 MW Waste-to-Energy plant due to commission in 2010. The base case 

22 

23 

24 

36


assumption for this report is that 5 MW of CHP will be added per annum over the next seven 

years. 

The Government targets 25 for CHP are for 400MW by 2010 and for 800 MW by 2020. Given 

the current amount of CHP applications in the queue, it is evident that there is aneed for 

significant increaseinCHP development to meet these targets. 

It is estimated that there is currently 21 MW of installed small-scale hydro capacity, with very 

few requests for connection (< 1MW). Such plant would generate roughly 50 GWh per year, 

making up approximately 0.2 % of total annual generation. While this is a mature 

technology, the lack of suitable new locations limits increased contribution from this source. 

It is assumed that when this capacity connects there are no further increases in small hydro 

capacity over the remaining yearsof the study. 

At the time of the data freeze, there was 34 MW of installed biomass generation (mainly in 

the form of land-fill gas). There is significant interest in biomass, indicated by 146 MW of 

applications in the queue for network connections at the time of the data freeze. For the 

purpose of this report it has been assumed that 9 MW of additional biomass capacity is 

added to the system for each of the next seven years. 

Government policy states that it is setting the target of 30% co-firing, (with biomass), at the 

three State-owned peat power generation stations to be achieved progressively by 2015, 

beginning with immediate development by Bord na Móna of its pilot project at Edenderry 

Power Station .However, while net carbon emissions will be improved through this measure, 

it will not impact on generation adequacy as no new generation capacity would have been 

added to the portfolio. 

In the last number of years there has been arapid increase in installed wind generation. 

Installed capacity has grown from 145 MW at the end of 2002 to 1167 MW at the time of 

writing. There is also afurther 1348 MW of wind generation committed 26 toconnection. The 

location and capacity of all connected and committed wind farms can be seen in Figure 4-3, 

whileAppendix2 contains detailed tables. 

There remains very significant interest in the construction of additional windfarms. Beyond 

committed projects, there are approximately 3.9 GW of wind applicants awaiting a 

connection offer as part of the Gate 3offer process. Afurther 11 GW of applications have 

been received outside of this process. While it would be impossible to accommodate this 

amount of wind generation capacity by 2020, it nevertheless gives an indication of the 

impetus todevelop further wind generation. 

25 

26 

37


MW EXISTING WIND FARM 

(MW) COMMITTED WINDFARM 

110 kV NODE 

MEENTYCAT 

85.0 MW 

TRILLICK 

23.8 MW 

(10.0 MW) 

LETTERKENNY 

41.9 MW 

(3.4 MW) 

SORNE HILL 

45.4 MW 

(15.8 MW) 

BINBANE 

22.8 MW 

(23.6 MW) 

GOLAGH 

15.0 MW 

CATHALEEN’S FALL 

5.4 MW 

(89.9 MW) 

GLENRE 

E(62.2 MW) 

SLIG 

(28.0 O MW) 

CORDERR 

Y30.2 MW 

(69.1 MW) 

BELLACORRICK 

6.5 MW 

MOY 

6.0 MW 

CUNGHILL 

23.8 MW 

(11.1 MW) 

ARIGNA 

11.0 MW 

(5.4 MW) 

SHANKILL 

6.0 MW 

RATRUSSAN 

78.6 MW 

(22.0 MW) 

DUNDALK 

8.0 MW 

CASTLEBAR 

24.2 MW 

(19.6 MW) 

DALTON 

(2.6 MW) 

TONRO 

E5.9 MW 

(3.6 MW) 

LANESBORO 

(5.0 MW) 

MEATH HILL 

15.0 MW 

NAVA 

(5.0 N MW) 

DRYBRIDGE 

1.7 MW 

(2.5 MW) 

ATHLONE 

(4.3 MW) 

GRANGE 

(0.3 MW) 

GALWAY 

4.6 MW 

SOMERSET 

7.7 MW 

DERRYBRIEN 

59.5 MW 

(29.8 MW) 

DALLOW 

6.8 MW 

IKERRIN 

5.1 MW 

OUGHTRAGH 

(9.0 MW) 

TULLABRACK 

12.6 MW 

TRIEN 

51.4 MW 

(79.9 MW) 

TRALEE 

47.9 MW 

(58.1 MW) 

KNOCKEARAGH 

9.4 MW 

(4.5 MW) 

COOMAGEARLAHY 

&GLANLEE 

110.8 MW 

(6.0 MW) 

BOOLTIAGH 

19.5 MW 

(12 

MW) 

MONEYPOINT 

(21.9 MW) 

RATHKEALE 

(32.5 MW) 

ATHEA 

(119.0 MW) 

CLAHANE 

37.8 MW 

GARRO 

W59.2 MW 

(10.0 MW) 

CLONKEEN 

(5.0 MW) 

ENNIS 

(24 

MW) 

ARDNACRUSHA 

10.9 MW 

CHARLEVILLE 

(3 

MW) 

GLENLARA 

26.0 MW 

(214.0 MW) 

CLASHAVOO 

N(81.0 MW) 

MACROOM 

(24.0 MW) 

MALLOW 

(20.0 MW) 

KILBARRY 

(0.9 MW) 

TOEM 

(95.0 MW) 

NENAG 

H(9.7 MW) 

TIPPERARY 

(3.0 MW) 

MIDLETON 

(1.7 MW) 

LISHEEN 

55.0 MW 

BUTLERSTOWN 

1.7 MW 

DUNGARVAN 

(1.7 MW) 

WATERFORD 

(0.5 MW) 

CARLOW 

7.5 MW 

(27.2 MW) 

BALLYCADDEN 

(45.9 MW) 

GREAT ISLAND 

4.3 MW 

(6.0 MW) 

CRANE 

4.9 MW 

(43.9 MW) 

WEXFORD 

38.9 MW 

ARKLOW 

25.2 MW 

BALLYWATER 

42 

MW 

BALLYLICKEYDUNMANWAY 

28.1 MW 20.8 MW 

(10.4 MW) (24.1 MW) 

BANDON 

4.5 MW 

TOTALS 

: 

EXISTING WIND FARMS 

COMMITTED WIND FARMS 

1167.1MW 

1348.7MW 

38


As can be seen from Figure 4-4, energy supplied from wind generation has increased in 

recent years. In 2002, just 1.6% of Ireland selectricity needs came from wind generation. 

Despite rapid electricity demand growth in the interim period, at the end of 2008 the share 

provided by wind generation had grown to 8.8%. The figure for 2007 compares with an EU 

average 27 of3.1% for that year (3.6% for EU-15 countries) only in Denmark, Spain and 

Portugal did wind make up a greater share of electricity production. 

3000 

2500 

8.8% 

2000 

7.1% 

6.0% 

1500 

4.3% 

1000 

500 

1.6% 

1.9% 

2.6% 

0 

2002 2003 2004 2005 2006 2007 2008 

Year 

Wind generation does not produce the same amount of energy all year round due to varying 

wind strength. The wind capacity factor gives the amount of energy actually produced in a 

year relative to the maximum that could have been produced, had windfarms been 

generating at full capacity all year. Historical capacity factors are shown in Figure 4-5. 2007 

was considered to be apoor wind year in terms of nationwide average wind speeds. Wind 

conditions recovered in 2008. An average capacity factor of 31.2% was used for future wind 

years forcalculations in this report. 

27 

39


36.0% 

35.0% 

34.0% 

34.1% 

34.7% 

33.4% 

33.0% 

32.5% 

32.0% 

31.0% 

31.4% 

31.7% 

30.0% 

29.0% 

29.1% 

28.0% 

2002 2003 2004 2005 2006 2007 2008 

Year 

Installed capacity of wind generation has grown by roughly 900MW since 2002. This value is 

set to increase rapidly over the next few years as Ireland strives to achieve its target of 40% 

electrical energy from renewables by 2020. The actual amount of renewable energy this 

requires will depend on the demand in future years. Since last year sGAR, the economic 

downturn has led to asharp drop in forecasted future demand (see Section 3), meaning less 

wind will need to be installed to meet the target. 

6000 

5,800 

5000 

4,121 

4000 

3000 

4,642 

2000 

3,314 

1000 

0 

2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 

GAR1016 input 

Hi i l V l 

2020 target requirements 

In November 2008, the Commission for Energy Regulation released adocument 28 giving 

direction for Ireland s renewables connection regime. This estimated that approximately 

5,800 MW of wind would need to be installed by 2020 to meet the Government s40% target. 

28 

40


For this report, it has been assumed that the amount of wind generation installed will 

increase linearly to meet this figure. 

Figure 4-6 shows the amount of installed wind presumed for GAR 1016, compared to the 

required installed wind capacity to meet the 40% target 29 in2020. The estimate of the value 

needed to meet the 40% renewables for 2020 assumes that demand will follow the same 

long term trend as outlined in the median forecast (see Section 3.2(d)). Wind generation is 

assumed to have acapacity factor of 31.2%, with asmall constraint level. The amount of 

energy produced from large-scale hydro is assumed to stay at current levels. Assumptions 

for other renewable sources, including the co-firing of the Edenderry peat plant with 

biomass, are as outlined in Sections 4.4(c) and 4.4(d). For the purposes of this calculation, 

Waste to Energy projects are not counted as contributing to the total energy generated from 

renewablesources. 

In Figure 4-6, the two curves differ by around 800 MW of installed wind in 2016. However, 

this difference does not have alarge effect on adequacy. The capacity credit increase for an 

installed capacity increase from 3,300 MW to 4,100 MW is in the region of just 50 MW (see 

Figure 2-2). Also, it can be seen that another 3,500 MW or so of wind generation will need to 

be installed by 2020 to meet the 40% target. Given that there are already 1,389 MW 

contracted to connect by this date, and 3,900 MW awaiting offers through the Gate 3 

process, this is certainly achievable. 

The contribution of wind generation towards generation adequacy (i.e. capacity credit of 

wind generation) as a percentage of installed capacity has inevitably declined as the 

installed wind generation has grown. In fact, over the last 7years the capacity credit has 

fallen from 35 to 22 % (see Figure 4-7). 

40% 

38% 

36% 

2002 

34% 

2003 

32% 

30% 

2004 

28% 

2005 

26% 

24% 

22% 

2006 

2007 

2008 

20% 

0 200 400 600 800 1000 

Wind Generation Capacity(MW) 

Due to Ireland s small geographical size, wind levels are strongly correlated across the 

country. This means that if wind levels are low in one part of the country, they are likely to be 

low nearly everywhere. All wind generation in Ireland tends to act more or less in unison as 

wind speeds rise and fall. The probability that all wind generation will cease generation for a 

period of time limits its ability to ensure continuity of supply and thus its benefit from a 

29 

41


generation adequacy perspective. The completion of the North-South Interconnector will 

allow wind to be treated on an all-island perspective, increasing its capacitycredit. 

Despite its limited contribution towards generation adequacy, wind generation has other 

favourablecharacteristics, such as: 

• The ability to provide sustainableenergy 

• Zero carbon emissions 

• Utilisationof an indigenous, free energyresource 

• Relativelymature renewable-energy technology 

This, combined with Ireland s excellent natural wind resources, will ensure that wind 

generation will be developed extensively to meet government renewable energy targets for 

2020. 

The governments White Paper on renewable energy 22 declares that 15% of electricity should 

be produced from renewable sources by 2010. For 2008, this value was already 11.1%. 

Analysis shows that just over 1,300 MW of wind needs to be connected by the end of 2010 to 

meet the 15% target.It is likely that this figure will be exceeded at the time of writing, there 

are already1167 MW connected. 

The total amount Non-Fully-Dispatchable Capacity assumed for the purpose of this report is 

illustrated in Table4-E. 

Year End 2010 2011 2012 2013 2014 2015 2016 

Industrial Generation 9 9 9 9 9 9 9 

Combined Heat and Power 126 131 136 141 146 151 156 

Small-ScaleHydro 22 22 22 22 22 22 22 

Biomass 43 52 61 70 79 88 97 

Wind Powered Generation 1943 2062 2442 2862 3282 3701 4121 

Total Partially/ 

Non-Dispatchable Plant 

2143 2276 2670 3104 3538 3971 4405 

4.5 PLANTAVAILABILITY 

The total electricity generation capacity connected to the system is unlikely to be available at 

any particular instant. Plant may be scheduledout of service for maintenance or forced out of 

service due to mechanical or electrical failure. Lack of availability due to forced outages has 

amuch greater negative impact on the ability of the system to meet demand than the same 

lack of availability arising from scheduled outages. This is a consequence of the 

unpredictable nature of forced outages as compared with the planned nature of scheduled 

outages. 

Poor plant availability has an adverse impact on generation adequacy. The amount of 

generation capacity which must be installed to meet the generation adequacy standard is 

directly related to availability within the plant portfolio. At low levels of availability more 

capacity is required to maintain the same standard of generation adequacy. Carrying 

additional capacity on the system increases costs, and these costs are ultimately passed on 

to thecustomer. 

42


Figure 4-8 shows the forced-outage rates (FOR) 30 for the Irish system since 1998, as well as 

predictedvalues for the study period of this report. FORs are simply the percentage of time in 

ayear that aplant is on forced outage. After rising steadily in the years up to 2007, FORs 

have started to drop in the past two years. This level of performance is expected to be 

maintainedas newer generators get commissioned. 

13.00 

12.00 

11.00 

10.00 

9.00 

8.00 

7.00 

6.00 

5.00 

4.00 

1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 

EirGrid AvailabilityYear 

Generator Availability 

The operators of fully-dispatchable generators have provided forecasts of their availability 

performance for the seven year period 2010 to 2016. However, in the past these forecasts 

have not given an accurate representation of the amount of outages on the system. This is 

primarily due to the effect high-impact low-probability (HILP) events. HILP events are 

unforeseen events that don toften transpire but, when they do occur, will have asignificant 

adverse impact on agenerator savailability performance, taking it out of commission for 

several weeks. The probability of this occurring to an individual generator is low. However, 

when dealing with the system as awhole, there is areasonable chance that at least one 

generator is undergoing such an event at any given time. EirGrid studies 31 have indicated 

that HILPswill make up around one third of forced outages on average. 

Two availability scenarios have been used for the studies carried out in this report. The first 

scenario incorporates the availability figures provided by the generators. The second 

incorporates availability figures calculated by EirGrid. These figures integrate the impact of 

HILP events on the system to give anew lower set of availability figures. While predicting 

availabilities will never be fully accurate, it is felt that these two scenarios will give a 

reasonablerange covering the most likely future situations. 

30 

31 

43


5 ADEQUACYASSESSMENTS 


This section reports on the scenarios that are assessed to investigate generation adequacy. 

The varying outcomes of these assessments are presented in terms of the resulting plant 

surplus or deficit. The impacts of different demand growth and availability scenarios are 

examined. The difference in results between this report and GAR 0915 are illustrated and 

explained. 

5.2 IMPACT OF DEMAND GROWTH 

The effect of different demand forecasts on the adequacy situation is illustrated in Figure 5-1, 

where the EirGrid availability forecast is assumed. Results are shown for the high, median, 

and low forecasts as presented inSection 3. 

2,000 

Great Island 

Tarbert 

Ballylumford 

SteamTurbines 

1,500 

1,000 

AghadaAD2 

Edenderry OCGT 

All-Island 

System 

Suir OCGT 

KilrootCCGT 

Nore OCGT 

Cuilleen OCGT 

EWIC 

500 

0 


LowDemand MedianDemand HighDemand 

It can be seen in Figure 5-1 that the decrease in demand, combined with the addition of new 

plant to the system, leads to arelatively large generation surplus over the next few years. 

This is even true for the high demand forecast, which predicts more rapid demand growth 

followingthe recessionary period. 

The changeover to an all-island assessment in 2013 sees an improvement in the adequacy 

position across all demand scenarios this is the despite the closure of Great Island and 

Tarbert at the end of 2012. The addition of the EWIC to the portfolio in 2012 also contributes 

to the improvement in the adequacy position. The larger difference in surplus across the 

demand scenarios for the later years of the study can be attributed to the greater divergence 

between the forecasted demand for these years (see Figure 3-3). 

45


5.3 IMPACT OF PLANT AVAILABILITY 

The effect of different plant availability scenarios is illustrated in Figure 5-2, with demand 

held at the median growth level. While in both cases deficits do not appear over the seven 

year period, the surplus is much larger in the Generator Availability scenario. There is an 

average difference of 362 MW between the surplus of the generators availability forecast and 

EirGrid s prediction ofavailabilityover 2010-2016. 

2,500 

2,000 

1,500 

1,000 

500 

0 


EirGrid Availability 

GeneratorAvailability 

5.4 COMPARISON WITH GAR 2009-2015 

Figure 5-3 compares the forecasted adequacy situation presented in this report with that 

presented in GAR 2009-2015. The median demand and EirGrid calculated availability 

scenarios are used for both sets of results, and they both move to an all-island assessment 

in 2013. The adequacy has clearly improved for all years. This difference is caused by 

changes to both the generation portfolio and the demand forecast used for this report. As 

discussed in Section 3, the forecast used for this report gives afar lower demand over the 

next 7 years. 

This report assumes that Great Island and Tarbert will remain open until December 2012, 9 

months later than was assumed for GAR 0915. The addition of the new OCGT and incinerator 

units, as well as the delay in decommissioning of the Ballylumford units, also lead to an 

improvement in the adequacy position. 

46


2000 

1500 

1000 

500 

0 

-500 

-1000 

2010 2011 2012 2013 2014 2015 

GAR1016 

GAR0915 

47


6 ELECTRICALSTORAGE 

In general, electricity needs to be produced when it is needed and used once it is produced. 

This creates challenges for power systems worldwide, as supply must exactly match demand 

on asecond by second basis. Demand for electricity varies over the day and over the year. In 

Ireland, the peak electricity demand during the day is almost twice the lowest demand 

overnight. Over the year, demand is lowest in summer and highest during cold spells in 

winter. Figure 3-7 shows typical summer andwinter daily demand curves. 

Unlike other networks such as gas, the electricity transmission system does not have a 

buffering capability to match demand with generation. However, it is possible to store 

electricity by converting it to another form that can be stored and then releasing it when it is 

needed most. In this section, the different types of electricity storage technologies that exist 

and their characteristics are described. The different ways that storage technologies can be 

utilised on the electricity system to improve security of supply and reduce electricity costs 

are also discussed. 

6.1 TYPES OF STORAGE 

By far the most prevalent type of storage worldwide is pumped hydro storage, and this is the 

only type currently operating on the Irish system. However there are other technologies 

available.This sectiongives an overview of different types 32 . 

Conventional pumped hydro uses two water reservoirs at different heights. To store energy, 

water is pumped from the lower reservoir to the upper reservoir. When required, the water 

flow is reversed to generate electricity. The amount of energy stored is adirect function of 

the amount of water in the upper reservoir. Pumped hydro is thus energy limited by the 

volume of the smaller of the two reservoirs. Ariver or open sea can be used as the lower 

reservoir. 

Pumped hydro generators have been built as large as 22.5 GW, with energy storage 

capabilities ranging from several hours to afew days. Their efficiency is in the 70% to 85% 

range. There are over 90 GW of pumped storage in operation world wide, which is about 3% 

of global generation capacity. They make avaluable contribution toward system security and 

stability, as they can come online or increase their generation output quite rapidly if 

required.Similarly, pumping canbe switched off within secondsto reduce system demand. 

Pumped storage plants are characterized by long construction times and high capital 

expenditure. The cost of construction is usually dependent on the natural resources 

available, with high mountains containing lakes, natural valleys and agood water source 

being the ideal location for such projects. Typical projects cost in the region of 0.8 to 1.6 

million euro per MW capacity, with the majority of recent projects at the high end of this cost 

range. 

32 

49


CAES utilises compressed air to improve the efficiency of agas turbine power plant. Such 

power plants will consume less than 40% of the gas used in conventional gas turbines to 

produce the same amount of electric output power. Conventional gas turbines consume 

about 2/3 of their input fuel to compress air at the time of generation. However, CAES precompresses 

air using low cost electricity from the power grid at off-peak times and utilizes 

that energylater alongwith somegas fuel to generateelectricity asneeded. 

50


To store energy, air is pumped into alarge sealed cavity. This may be adisused mine, a 

disused gas field, or acavern created by removing layers of salt from underground rock. 

There aretwo commercial CAES generators in operation worldwide.The first isa290 MW unit 

built in Germany in 1978, the second a110 MW unit built in Alabama, USA in 1991. There are 

plans for amuch larger CAES plant to be built in Ohio, USA. This plant will have ageneration 

capacity of 2700 MW. Opportunities for CAES are also currently being examined in Northern 

Ireland this is discussed in Section 6.3. 

Battery storage is usually more associated with small scale electronics than with large scale 

power systems. There are however applications for electrochemical batteries in electrical 

networks. They are mainly used as sources of reserve power in case of generator failure, as 

opposed to areliable and frequently used source of generation. Scaling up batteries for use 

in such applications usually consists of daisy-chaining alarge number of smaller batteries 

together. 

While the use of batteries as aform of power storage on electrical systems is not hugely 

common, there has been heightened interest in the past few years due to advances in 

battery technology. Batteries typically have a low life when compared with CAES and 

pumped hydro storage. 

The advent of electrical vehicles (EVs) should see developments in battery technology. It is 

hoped that future smart-grids will allow EV owners to sell power from their vehicles back to 

the grid, though it is questionable whether current batteries would be able to cope with the 

extra charge/recharge cycling that such vehicle-to-grid technologies would require. It is 

possible, however, that batteries that are no longer usable in vehicles may still able to sell 

energy back to the grid. 

The demand for Sodium-Sulphur (NAS) batteries as an effective means of stabilizing 

renewable energy output and providing ancillary services is expanding worldwide, especially 

in Japan. They have been installed at over 190 sites there, including the worlds largest NAS 

installation -a34 MW, 245 MWh unit used for wind stabilization in Northern Japan. NAS 

batteries consist of molten sulphur at the positive electrode and molten sodium at the 

negative electrode. NAS battery cells have anefficiencyof almost 90%. 

Lead-acid batteries were in common use in power grids until the 1930 s, and Puerto Rico still 

uses 20 MW of these batteries for reserve. Lead-acid batteries are limited in energy 

management applications due to the relatively shortnumber of times theycancycle. 

Nickel-Cadmium (NiCad) batteries have also found their way onto power system 

applications. A40 MW NiCad system has been installed in Alaska to provide reserve to the 

state s isolated transmission system. The rechargeable battery takes up 2,000 square 

metres andweighs 1,300 tonnes. 

Flow batteries are rechargeable electrochemical batteries in which aliquid electrolyte is 

passed over the electrodes, usually by pumping. Their efficiency ranges from 75% -85%. 

There are anumber of flow batteries used as power sources worldwide, albeit primarily in 

smaller scale industrialor researchapplications. 

Most modern flywheel energy storage systems consist of amagnetically levitated wheel in a 

vacuum environment. This ensures that rotation of the wheel is effectively frictionless, and 

very little energy is lost.To store energy, the flywheel is accelerated to spin at extremelyhigh 

speeds. Slowing the flywheel down again allows energy to be returned to the system. 

Flywheels are primarily used to provide reserve, and are generally considered suitable for 

supplying power only for short periods. 

51


6.2 HOW ELECTRICITY STORAGE IS USED 

Storage flattens out the demand profile, permitting base-load power stations to continue 

operating at capacity, while reducing the need to run less efficient peaker plants. Since 

electricity generated by base-load plant is cheaper that that generated by peaker plants, 

storage has the potential to reduce the price of electricity. 

There is alimit to how much energy astorage unit can store, and this dictates the length of 

its pump-generate cycle. For example, if aunit has apower capacity of 100 MW and an 

energy storage capacity of 300 MWh, it can at most generate at maximum output for 3hours 

before it needs to store energy again. Most storage generators operate on adaily cycle, 

taking in energy at night and releasing it during daily peak hours. Figure 6-3 shows the 

effecta large pumped storage unitcould haveon a typicaldemand profile. 

4500 

4000 

3500 

3000 

DemandProfile withoutstorage 

DemandProfile withstorage 

2500 

00:00 04:00 08:00 12:00 16:00 20:00 

Time ofday 

Storage generators can also be used to provide vital ancillary support services. As 

mentioned in Section 6.1(c), there are batteries that are used solely to provide reserve power 

in case of sudden generator failure, and also blackstart 33 support to systems. Pumped hydro 

also provide such services Turlough Hill, for example, can ramp up from zero to full output 

in lessthan one minute, and needsno external power source to start generating. 

Some intermittent generators, such as individual wind farms, may opt to use storage directly 

to optimise their power output. Such generators are referred to as hybrid generators. The 

onsite storage unit prevents wind from being curtailed, and also allows the generator to 

output electricity when it is needed most, or when it is most profitable. This has the 

advantage of not requiring extra transmission infrastructure, since the actual maximum 

power output does not increase. Figure 6-4 shows how storage can be used to avoid wind 

curtailment. 

33 

52


Demand 

a) 

Wind 

Curtailed 

b) 

Energy 

Stored 

Energy 

Released 

12:00 18:00 00:00 06:00 12:00 18:00 00:00 

12:00 18:00 00:00 06:00 12:00 18:00 00:00 

Demand 

Wind 

Demand 

Wind + Storage Generation 

6.3 ENERGY STORAGE AND THE IRISH SYSTEM 

As Ireland progresses toward meeting its target of 40% of electricity sourced from 

renewables, the amount of wind generation appearing on the system will steadily increase. 

Wind generation is intermittent the amount of power generated depends on the strength of 

the wind blowing. Periods of low wind have obvious implications for security of electricity 

supply. Conversely, there will also be periods when more electricity is being generated by 

wind than can be used or exported. When this occurs, theoutput of the windfarms is reduced 

and energyis wasted. 

One possible solution to this is the use of electricity storage, allowing excess wind 

generation to be stored until it is required. This would reduce energy wastage, and improve 

the capacity factor of windfarms. Higher capacity factors increase the penetration of 

renewables, thus reducing CO 2 emissions.Ireland s dependency on fuel from foreign sources 

is also reduced. 

Currently, there is only one significant electrical storage facility on the Irish grid. This is the 

pumped hydro storage facility at Turlough Hill in the Wicklow Mountains. It was constructed 

in the early seventies, and can generate up to 292 MW. It provides an essential contribution 

towards ancillary services, such as reserve and blackstart support. As with most pumped 

storage stations, Turlough Hill generally pumps during the night and generates during the 

day.A typical 24hour pump-generate cycle for the stationis shown inFigure6-5. 

The low levels of development of hydro storage in Ireland, relative to countries like Norway 

and Switzerland, can be explained by the island snatural resources. The energy that can be 

stored depends on the volume of the reservoirs and the height difference between the two. 

Pumped storage stations ideally require high steep mountains and deep wide valleys, as 

well as awater source. Ireland smountain ranges are typically gently sloping and are not 

particularlyhigh in comparisonwith many other countries. 

53


200 

100 

0 

-100 

-200 

Turlough Hill daily 

pump-gen cycle 

-300 

00:00 03:00 06:00 09:00 12:00 15:00 18:00 21:00 

Time 

There has been a lot of interest in recent months regarding expanding the amount of 

electrical storage currently used on the Irish system. Since the data freeze date for this 

report, aconnection agreement has been signed for a70 MW pumped hydro facility in Co. 

Cork. There are another 70 MW of pumped hydro storage in the queue under the Gate 2offer 

process. Proposals have also been put forward for large scale pumped hydro projects, using 

the ocean as the lower reservoir and pumping salt water. The only existing plant of this type 

is built in Japan (see Figure 6-1), however this plant can only generate 30 MW, far smaller 

than thesystem proposed for Ireland. 

AZnBr flow battery is currently being installed at Dundalk IT, to complement their existing 

wind turbine. The battery has arelatively small capacity (125 kW), and is intended primarily 

for research. This project will provide valuable information on the use of flow batteries in 

hybrid systems. 

CAES opportunities are also being explored in Ireland. The geology of Larne, Co. Antrim is 

believed to have the potential to support CAES, as large salt deposits in the rock could be 

leeched out to create appropriate caverns. Gas fields, such as those at Kinsale, could also be 

potential CAES sites once their gas reserves have been fully exhausted. The existing 

knowledgeand infrastructure at such sites would simplify any potential developments. 

6.4 ECONOMICS OF ELECTRICITY STORAGE 

While many technology types have been outlined above, only pumped hydro and CAES are 

currently suitable for providing areliable supply of electricity on alarge scale. The capital 

costs for both technologies are dependent on the natural resources available at each 

particular site. For pumped hydro, high mountains containing lakes, natural valleys and a 

good water source are ideal. Costswill often run at around 1.5 million /MW, though this can 

be reduced if some existing infrastructure already exists, e.g. enlargement of an existing 

scheme. CAES costs will depend on ease of access to the cavern, and the amount of effort 

involved in leeching out unwantedmaterials. 

54


Figure 6-6 shows the range of capital costs typically involved for CAES and pumped hydro, 

both per MW of power capacity and per MWh of energy storage. Two types of battery 

technology are also included for reference. As can be seen, their cost per MWh makes them 

unsuitable for energy storage, even before taking into account the lower operational life of 

batteries whencompared withtheother technologies. 

For storage projects to be economically viable, these capital costs must be recaptured 

through the sale of electricity. When storage generators function in an energy market, they 

operate on the principle of arbitrage. This means that they buy electricity when it is cheap 

(e.g. at night time, or when lots of wind is blowing), and sell when it is expensive (e.g. daily 

peak, or periods of lowwind). 

Since energy storage cannot be perfectly efficient, some energy will be lost between the time 

that the power is stored and when it is released back on to the system. The price difference 

must also be able to compensate for these losses. Figure 6-7 shows the average System 

Marginal Price 34 for each hour of the day, calculated from November 2008 to October 2009. 

The price at which storage generators with 70% and 80% efficiencies can sell to break even 

is also indicated the generators must sell when the SMPis above this rate to make a profit. 

34 

55


90 

60 

Breakevenselling 

pointforstorage 

with... 

70%efficiency 

80%efficiency 

30 

0 

00:00 04:00 08:00 12:00 16:00 20:00 

Timeof day 

6.5 EIRGRID STUDY ON LARGEPUMPED STORAGE 

EirGrid have carried out an analysis of the potential benefit of pumped storage to Ireland. 

The study examined how large scale pumped storage would operate in an Irish system based 

on aforecasted 2025 generation portfolio and demand. Abroad range of scenarios were 

studied by varying the installed wind capacity, the level of interconnection to Britain, and the 

amount of pumped storage capacity. The production costs, CO 2 emissions and amount of 

wind curtailment were determined for each scenario. These were combined with capital cost 

estimates to provide an overall comparison of the scenarios. Results were calculated in 

terms of the total cost to the Irishsystem. 

The study found that up to, 40% of electricity from renewables, very little curtailment of wind 

occurred. Consequently, there was little value in adding large pumped storage at this 

penetration level. At higher wind levels, storage does contribute to avoiding wind 

curtailment and thus reduces production costs. However, when examined in the presence of 

increased interconnection, this benefit is lessened. It may often be more economic to export 

wind than to store it using pumped hydro and incur the efficiency lossof the pumping cycle. 

56


€4,300 

€4,200 

€4,100 

€4,000 

€3,900 

€3,800 

€3,700 

No PS 1GWPS 2GWPS 3GWPS 

€0.8m/MW 

€1.6m/MW 

For illustrative purposes, Figure 6-8 shows the effect different amounts of pumped storage 

have on a2025 system with 10 GW of installed wind generation. This represents avery high 

level of wind penetration (~60%). It is not suggested that this is achievable or desirable for 

the Irish system. An interconnection capacity with Britain of 1GW is assumed. Total costs 

were considered (i.e. production plus annualised capital), with results shown for arange of 

storage capital costs of 0.8m/MW and 1.6m/MW. 

The graph shows that the addition of both 1and 2GW of pumped storage provide acost 

benefit to the system, only when lower storage capital costs are assumed. However, if the 

greatercapital cost is assumed, adding large pumped storagewould be uneconomical. 

The results presented above are asnapshot from arange of scenarios examined, and are 

shown for illustrative purposes.In general,when lower wind penetration levels are assumed, 

the effect of pumped storage on the system is less favourable. For high wind penetration 

levels, storage can be beneficial in some scenarios but only when low capital costs are 

assumed. However, when examined in the presence of increased interconnection, this 

benefit islessened. 

57


7 KEYMESSAGES 

• The adequacy situation is strongly positive for the next seven years. Asurplus of at least 

700 MW is observed for all scenarios studied for each of the seven years. This is due to 

new generation commissioning, increased interconnection, improved generator 

availability, as well asa reductionin demand. 

Even though there is sufficient capacity to comfortably exceed the standard of 8hours 

loss of load expectation used, this does not guarantee that load shedding could not 

occur.It does howevermean thatthe probability of load shedding isvery low. 

• The economic climate has lead to asignificant drop in actual and forecasted demand. 

The median forecast used in this document does not show an increase on 2008 levels 

until 2013. For the high and low demand scenario an increase on 2008 levels is not seen 

until 2012 and 2014 respectively. This is due to lower economic activity than previously 

forecast but also due to a lowerlevel of energy intensityper unit of GDP. 

This lower energy intensity level is due to greater energy efficiency and amaturing 

knowledge-based economy. In the long term, there is likely to be greater emphasis on 

energy efficiency but, for the electricity sector, this will be counter-balanced by greater 

use of electricity asanenergysource in the transportation and heating sectors. 

• Increased interconnection contributes to the adequacy position. The East-West 

Interconnector is due to be commissioned in 2012. This interconnector will connect the 

Irishand British transmission systems, and can carry up to 500 MW in either direction. 

The second high voltage transmission line between Ireland and Northern Ireland is due 

to be completed by 2013. As well as increasing efficiency and stability, this will allow a 

consolidation of the generation and demand of the two systems for capacity adequacy 

calculations. 

• Analysis shows that the target of 15% electricity from renewable sources in 2010 will be 

achieved. This is contingent on at least 120 MW of wind generation connecting during 

2010.It is expected that this figurewill be exceeded. 

59


APPENDIX 1 

DEMAND FORECAST 

Year 

GDP 

( m at 

constant 

2006 prices, 

chainlinked) 

GDP 

growth 

PCGS 

( m at 

constant 

2006 prices, 

chainlinked) 

PCGS 

Growth 

Population 

(‘000’s) 

TER 

(GWh) 

TER 

Growth 

TER 

Peak 

(MW) 

Transmission 

Peak 

(MW) 

Median DemandForecast 

2008 182,285 -3.0% 88,085 -1.0% 4,422 28,830 4,976 4,878 

2009 168,067 -7.8% 81,391 -7.6% 4,402 27,240 -5.5% 4,766 4,665 

2010 164,201 -2.3% 78,949 -3.0% 4,362 27,206 -0.1% 4,747 4,636 

2011 170,769 4.0% 81,317 3.0% 4,384 27,793 2.2% 4,843 4,725 

2012 180,332 5.6% 84,570 4.0% 4,406 28,569 2.8% 4,975 4,848 

2013 190,431 5.6% 87,953 4.0% 4,428 29,177 2.1% 5,076 4,941 

2014 201,095 5.6% 91,471 4.0% 4,450 29,798 2.1% 5,179 5,037 

2015 212,356 5.6% 95,130 4.0% 4,472 30,432 2.1% 5,284 5,134 

2016 219,364 3.3% 97,698 2.7% 4,495 31,080 2.1% 5,392 5,233 

Year 

GDP 

( m at 

constant 

2006 prices, 

chainlinked) 

GDP 

growth 

PCGS 

( m at 

constant 

2006 prices, 

chainlinked) 

PCGS 

Growth 

Population 

(‘000’s) 

TER 

(GWh) 

TER 

Growth 

TER 

Peak 

(MW) 

Transmission 

Peak 

(MW) 

Low DemandForecast 

2009 167,155 -8.3% 81,038 -8.0% 4,402 27,070 -6.1% 4,736 4,634 

2010 162,642 -2.7% 77,067 -4.9% 4,362 26,823 -0.9% 4,677 4,567 

2011 167,521 3.0% 78,609 2.0% 4,384 27,169 1.3% 4,731 4,612 

2012 175,562 4.8% 81,360 3.5% 4,406 27,725 2.0% 4,823 4,696 

2013 183,989 4.8% 84,208 3.5% 4,428 28,299 2.0% 4,915 4,781 

2014 192,821 4.8% 87,155 3.5% 4,450 28,854 2.0% 5,009 4,867 

2015 202,076 4.8% 90,205 3.5% 4,472 29,420 2.0% 5,105 4,955 

2016 208,543 3.2% 92,190 2.2% 4,495 29,997 2.0% 5,203 5,044 

61


Year 

GDP 

( m at 

constant 

2006 prices, 

chainlinked) 

GDP 

growth 

PCGS 

( m at 

constant 

2006 prices, 

chainlinked) 

PCGS 

Growth 

Population 

(‘000’s) 

TER 

(GWh) 

TER 

Growth 

TER 

Peak 

(MW) 

Transmission 

Peak 

(MW) 

HighDemandForecast 

2009 169,160 -7.2% 81,919 -7.0% 4,402 27,326 -5.2% 4,782 4,681 

2010 167,300 -1.1% 80,281 -2.0% 4,362 27,641 1.2% 4,825 4,714 

2011 176,668 5.6% 83,492 4.0% 4,384 28,421 2.8% 4,957 4,838 

2012 186,562 5.6% 86,832 4.0% 4,406 29,227 2.8% 5,093 4,966 

2013 197,009 5.6% 90,305 4.0% 4,428 30,035 2.8% 5,233 5,098 

2014 208,042 5.6% 93,917 4.0% 4,450 30,866 2.8% 5,376 5,234 

2015 219,692 5.6% 97,674 4.0% 4,472 31,719 2.8% 5,524 5,373 

2016 226,942 3.3% 100,311 2.7% 4,495 32,596 2.8% 5,675 5,516 

Year TER (GWh) TER Peak (MW) 

Low Median High Low Median High 

2013 37,530 38,408 39,266 6,575 6,735 6,891 

2014 38,223 39,167 40,235 6,694 6,863 7,059 

2015 38,930 39,942 41,229 6,816 6,994 7,232 

2016 39,650 40,733 42,249 6,939 7,127 7,408 

Year GAR 2009-2015 GAR 2010-2016 

2009 2.1% -5.5% 

2010 2.1% -0.1% 

2011 2.8% 2.2% 

2012 2.8% 2.8% 

2013 2.9% 2.1% 

2014 2.9% 2.1% 

2015 2.7% 2.1% 

2016 2.7% 2.1% 

Year 

Total Electricity 

Sales (GWh) 

TER (GWh) 

Transmission 

Peak (MW) 

Wind 

contribution at 

peak (MW) 

2001 20,821 23,511 3905 4 3995 

2002 21,208 23,912 4116 122 4335 

2003 21,891 24,673 4117 63 4278 

2004 22,692 25,581 4230 140 4485 

2005 23,751 26,676 4593 86 4777 

2006 24,972 27,974 4850 4 4951 

2007 25,643 28,427 4906 61 5004 

2008 26,048 28,830 4873 222 4976 

2009 24,589 27,240 4665 0 4736 

TER Peak (MW) 

Notes: The Total Electricity Sales are measured at the customer level, for a52-week year. To convert 

this to TER, it is brought to exported level by applying the loss factor (8.3%) and adding on an estimate 

ofself-consumption. 

The Transmission Peak is that met by centrally-dispatched generation, measured at exported level by 

the National Control Centre. It does not include the contribution of wind. To calculate the TER Peak, 

partially and non-dispatchable generation are added to the Transmission Peak, i.e. the measured 

contribution of wind at peak and an estimationof the contribution from small scale hydro, biomass and 

CHP (both exporting and self-consuming CHP). When forecasting the transmission peak, it is assumed 

that thewindcontributioniszero. 

62


APPENDIX 2 

GENERATION PLANT INFORMATION 

Station ID Export Capacity (MW) 

At yr end: 2009 2010 2011 2012 2013 2014 2015 2016 

Fully-Dispatchable Plant 

Aghada 

AD1 258 258 258 258 258 258 258 258 

AT1 90 90 90 90 90 90 90 90 

AT2 90 90 90 90 90 90 90 90 

AT4 90 90 90 90 90 90 90 90 

ADC 0 432 432 432 432 432 432 432 

Cahir OCGT 0 0 0 0 98 98 98 98 

Cuilleen OCGT 0 0 0 98 98 98 98 98 

Dublin Bay DB1 403 403 403 403 403 403 403 403 

Dublin Waste-to-Energy 0 72 72 72 72 72 72 72 

Edenderry ED1 117.6 117.6 117.6 117.6 117.6 117.6 117.6 117.6 

Edenderry OCGT 0 111 111 111 111 111 111 111 

Great Island 

GI1 54 54 54 54 0 0 0 0 

GI2 54 54 54 54 0 0 0 0 

GI3 108 108 108 108 0 0 0 0 

Huntstown 

HN1 343 342 342 341 341 340 340 339 

HN2 401 400 400 399 399 398 398 397 

Lough Ree Power LR4 91 91 91 91 91 91 91 91 

Marina MRT 85 85 85 85 85 85 85 85 

Meath Waste-to-Energy 0 0 17 17 17 17 17 17 

Moneypoint 

MP1 282.5 282.5 282.5 282.5 282.5 282.5 282.5 282.5 

MP2 282.5 282.5 282.5 282.5 282.5 282.5 282.5 282.5 

MP3 282.5 282.5 282.5 282.5 282.5 282.5 282.5 282.5 

Nore Power 0 0 98 98 98 98 98 98 

North Wall 

NW4 163 163 163 163 163 163 163 163 

NW5 104 104 104 104 104 104 104 104 

Poolbeg 

PB1 109.5 0 0 0 0 0 0 0 

PB2 109.5 0 0 0 0 0 0 0 

PBC 463 463 463 463 463 463 463 463 

Rhode 

RP1 52 52 52 52 52 52 52 52 

RP2 52 52 52 52 52 52 52 52 

Sealrock 

SK3 80.5 80.5 80.5 80.5 80.5 80.5 80.5 80.5 

SK4 80.5 80.5 80.5 80.5 80.5 80.5 80.5 80.5 

Tarbert 

TB1 54 54 54 54 0 0 0 0 

TB2 54 54 54 54 0 0 0 0 

TB3 241 241 241 241 0 0 0 0 

TB4 241 241 241 241 0 0 0 0 

Tawnaghmore 

TP1 52 52 52 52 52 52 52 52 

TP3 52 52 52 52 52 52 52 52 

Tynagh TY1 384 384 384 384 384 384 384 384 

West OffalyPower WO4 137 137 137 137 137 137 137 137 

Whitegate WG1 0 445 445 445 445 445 445 445 

Ardnacrusha Hydro AA1,AA2, 

AA3,AA4 

86 86 86 86 86 86 86 86 

Erne Hydro 

ER1,ER2 

ER3,ER4 

65 65 65 65 65 65 65 65 

Lee Hydro 

LE1,LE2, 

LE3 

27 27 27 27 27 27 27 27 

Liffey Hydro 

LI1,LI2, 

LI4,LI5 

38 38 38 38 38 38 38 38 

TurloughHill TH1, H2, 

TH3, TH4 

292 292 292 292 292 292 292 292 

NI 200 200 200 200 2732 2732 3172 2635 

EWIC 0 0 0 250 250 250 250 250 

Total Fully-DispatchablePlant 6171 7010 7125 7471 9295 9293 9733 9191 

63


Partially/Non-Dispatchable Plant 

Renewable – Wind 1396 35 1943 2062 2442 2862 3282 3701 4121 

Renewable – Hydro 22 22 22 22 22 22 22 22 

Renewable -Biomass 34 43 52 61 70 79 88 97 

CHP 121 126 131 136 141 146 151 156 

Industrial 9 9 9 9 9 9 9 9 

Renewable – Wind (NI) 306 383 514 568 663 767 824 978 

Total Partially/Non- 1888 2526 2790 3238 3767 4305 4795 5383 

DispatchablePlant 

GrandTotal 8059 9536 9915 10709 13062 13598 14528 14574 

Table A-6 Generation plant capacity, for the base case assumptions. Please note that these capacity 

figures are indicative only, as advised by the generating companies. They do not necessarily reflect 

whatisinthegenerators connectionagreements. 

35 

64


Station ID Fuel Type Cycle BoilerType Condenser 

Cooling 

Aghada 

AD1 Gas Condensing Steam Turbine Oncethrough Water 

AT1 Gas/DO OpenCycle n/a n/a 



ADC Gas/DO CombinedCycle Waste Heat Recovery Water 

Cahir CA Gas/DO OpenCycle n/a n/a 

Cuilleen CL Gas/DO OpenCycle n/a n/a 

Dublin Bay DB1 Gas/DO Single shaft CombinedCycle Waste Heat Recovery Seawater 

Edenderry ED1 Peat Condensing Steam Turbine Bubbling Fluidising Bed Water 

Edenderry OCGT EP DO OpenCycle n/a n/a 

Great Island 

GI1 HFO Condensing Steam Turbine Drum Water 



Huntstown 

HN1 Gas/DO CombinedCycle Waste Heat Recovery Air 

HN2 Gas/DO CombinedCycle Waste Heat Recovery Air 

Lough Ree Power LR4 Peat Condensing Steam Turbine Bubbling Fluidising Bed Water 

Marina MRT Gas/DO OpenCycle n/a n/a 

Moneypoint 

MP1 Coal/HFO Condensing Steam Turbine Drum Water 



Nore Power NP Gas/DO OpenCycle n/a n/a 

North Wall 

NW4 Gas/DO CombinedCycle Waste Heat Recovery Water 

NW5 Gas/DO OpenCycle n/a n/a 

Poolbeg 

PB1 HFO/Gas Condensing Steam Turbine Drum Water 

PB2 HFO/Gas Condensing Steam Turbine Drum Water 

PBC Gas/DO CombinedCycle Waste Heat Recovery Water 

Rhode 

RP1 DO OpenCycle n/a n/a 

RP2 DO OpenCycle n/a n/a 

Sealrock 

SK3 Gas/DO OpenCycle Waste Heat Recovery n/a 

SK4 Gas/DO OpenCycle Waste Heat Recovery n/a 

Tarbert 

TB1 HFO Condensing Steam Turbine Drum Water 

TB2 HFO Condensing Steam Turbine Drum Water 

TB3 HFO Condensing Steam Turbine Once-through Water 

TB4 HFO Condensing Steam Turbine Once-through Water 

Tawnaghmore TP1 DO OpenCycle n/a n/a 

TP3 DO OpenCycle n/a n/a 

Tynagh TY1 Gas/DO CombinedCycle Waste Heat Recovery Air 

West Offaly Power WO4 Peat Condensing Steam Turbine Bubbling Fluidising Bed Water 

Whitegate WG1 Gas/DO CombinedCycle Waste Heat Recovery Air 

Transmission connected 

Wind Farm 

Capacity (MW) 

Ballywater (1) 31.5 

Ballywater (2) 10.5 

Booltiagh (1) 19.45 

Clahane(1) 37.8 

Coomacheo(1) 59.225 

Coomagearlahy (1) 42.5 

Coomagearlahy (2) 8.5 

Coomagearlahy (3) 30 

Derrybrien(1) 59.5 

Glanlee(1) 29.8 

Golagh (1) 15 

Kingsmountain (1) 23.75 

65


Distributionconnected 

Lisheen(1) 55 

Meentycat (1) 70.96 

Meentycat (2) 14 

Mountain Lodge(1) 24.8 

Mountain Lodge(3) 5.82 

Ratrussan (1) 48 

Subtotal 586.105 

Altagowlan(1) 7.65 

Anarget (1) 1.98 

Anarget (2) 0.02 

Arklow Banks (1) 25.2 

Ballinlough (1) 2.55 

Ballinveny (1) 2.55 

Beale(2) 2.55 

Beale Hill (1) 1.65 

Beallough (1) 1.7 

Beam Hill (1) 14 

Beenageeha (1) 3.96 

Bellacorick(1) 6.45 

Black Banks (1) 3.4 

Black Banks (2) 6.8 

Burren(Lenavea) [Mayo] (1) 2.1 

Burtonport Harbour(1) 0.66 

Caranne Hill (1) 3.4 

Cark (1) 15 

Carnsore(1) 11.9 

Carrig (1) 2.55 

Coomatallin(1) 5.95 

Corneen(1) 3 

CorrieMountain (1) 4.8 

Crockahenny (1) 5 

Cronalaght(1) 4.98 

Cronelea(1) 4.99 

Cronelea Upper (1) 2.55 

Cuillalea(1) 3.4 

Culliagh (1) 11.88 

Curabwee(1) 4.62 

Curraghgraigue(1) 2.55 

Drumlough Hill (1) 4.8 

Dundalk IT (1) 0.5 

Dunmore(1) 1.7 

Flughland(1) 9.2 

Gartnaneane I & II 15 

Geevagh(1) 4.95 

Glackmore Hill (1) 0.6 



Glanta Commons (1) 19.55 

Gneeves (1) 9.35 

Greenoge(1) 4.9 

Inis Mean (1) 0.675 

Inverin (Knock South) (1) 3.3 

Inverin (Knock South) (2) 0.66 

Kealkil (Curraglass) (1) 8.5 

Killybegs (1) 2.55 

Kilronan (1) 5 

Kilvinane(1) 4.5 

Knockastanna(1) 7.5 

Knockawarriga (1) 22.5 

Lackan(1) 6 

Lahanaght Hill (1) 4.25 

Largan Hill (1) 5.94 

66


Loughderryduff (1) 7.65 

Lurganboy(1) 4.99 

Meenachullalan (1) 11.9 

Meenadreen(1) 3.4 

Meenanilta(1) 2.55 

Meenanilta(2) 2.45 

Meenkeeragh (1) 4.2 

Mienvee(1) 0.66 

Mienvee(2) 0.19 

Milane Hill (1) 5.94 

Moanmore(1) 12.6 

Moneenatieve(1) 3.96 

Mount Eagle(1) 5.1 

Mount Eagle(2) 1.7 

Mountain Lodge(2) 3 

Muingnaminnane(1) 15.3 

Mullananalt (1) 7.5 

Raheen Barr (1) 18.7 

Rahora(1) 4.25 

Richfield(1) 20.25 

Richfield(2) 6.75 

Skehanagh (1) 4.25 

Sonnagh Old (1) 7.65 

Sorne Hill (1) 31.5 

Sorne Hill (2) 7.4 

Spion Kop (1) 1.2 

Taurbeg(1) 26 

Tournafulla(1) 7.5 

Tournafulla(2) 17.2 

Tursillagh (1) 15 

Tursillagh (2) 6.8 


GrandTotal 1167.06 

Transmission connection 

Distributionconnection 

Wind Farm 

Capacity (MW) Yearof Target Connection 

Athea(1) 51 2010 

Athea(2) 17 2010 

Boggeragh (1) 57 2009 

Booltiagh (2) 3 2011 

Booltiagh (3) 9 2011 

Castledockrill(1) 41.4 2010 

Cloghboola(1) 46 2014 

Dromada (1) 28.5 2009 

Garvagh (1) 58.225 2009 

Glanlee(2) 6 2010 

Keelderry (1) 29.75 2010 

Kingsmountain (2) 11.05 2010 

Knockacummer (1) 87 2010 

Moneypoint 21.9 

Mulreavy(1) 82 2013 

Ratrussan 22 2010 


Ballincollig Hill (1) 15 

Ballycadden(1) 14.45 2010 

Ballyduff (1) 4 2011 

Ballymartin(1) 6 2011 

Ballynancoran(1) 4 2011 

Bantry Bay Seafoods (1) 2 2010 

Barna (1) 5.95 2012 

Beale Hill (3) 1.3 2010 

Blakefield(1) 0.85 2010 

67


Borrisnafarney (1) 2.55 2011 

Bunnyconnellan(1) 28 2011 

Burren[Cork](1) 9 2010 

Cahercullenagh Upper(1) 4.25 2013 

Caherdowney (1) 10 2010 

Cappagh White(1) 16.1 2014 

Caranne Hill (2) 1.6 2009 

Carriganimma(1) 15 2009 

Carrigans (1) 1.7 2012 

Carrigcannon(1) 20 2010 

Carrons(1) 2.5 2010 

Carrons(2) 2.5 2010 

Carrowleagh (1) 27.25 2011 

Cloghanaleskirt (1) 10 2014 

Clydaghroe(1) 5 2010 

Coolegrean (1) 18.5 2012 

Coomatallin(2) 3.05 

Cordal(1) 35.85 2014 

Corkermore(1) 15 2009 

Croaghnameal (1) 4.3 2011 

Crocane(1) 1.7 2009 

Cronelea(2) 4.5 2009 

Cronelea Upper (2) 1.7 2009 

Crowinstown(1) 4.999 2009 

Cuillalea(2) 1.7 2010 

Curraghgraigue(2) 2.44 2010 

Derryvacoreen(1) 17 2010 

Donaghmede Fr Collins Park 0.25 

Dromadda Beg(1) 2.55 2014 

Dromadda More(1) 20 2014 

Dromdeveen (1) 10.5 2010 

Dromdeveen (2) 16.5 

Drumlough Hill (2) 9.99 2010 

Dunmore(2) 2.5 2009 

Esk (1) 5.95 2010 

Falleennafinnoga (1) 4 2012 

Garracummer(1) 22 2012 

Gibbeet Hill (1) 14.8 2011 

Glanta Commons (2) 8.4 2010 

Glenduff (1) 6 2011 

Glenough (1) 33 2014 

Glentanemacelligot (1) 18 2012 

Gortahile(1) 21 2010 

Greenoge(2) 2.5 2010 

GrouseLodge(1) 15 2010 

Holyford(1) 9 2014 

Kennystown (1) 3.6 2011 

Killavoy (1) 18 2010 

Killin Hill (1) 6 2009 

Kilmacow Quarry (1) 0.499 2010 

Knockaneden (1) 9 2010 

Knocknagappagh (1) 1.7 2009 

Knocknagoum(1) 14 2013 

Knocknalour(1) 5 2010 

Leabeg(1) 4.25 2010 

Lenanavea(1) 3.4 2010 



Loughaun North(2) 24 2010 

Mace Upper (1) 2.55 2009 

Maghanknockane(1) 12 2013 

Meenadreen South(1) 3.6 2010 

68


Meenanilta(3) 3.4 2010 

Moanvaun (1) 3 2012 

Moneenatieve(2) 0.29 2009 

Mount Eagle(3) 1.7 2010 

Muingnatee(1) 10.2 2013 

Muingnatee(2) 0.9 2013 

Ounagh Hill (1) 6.9 2011 

Pluckanes (1) 0.85 2010 

Raheen Barr (2) 8.5 2010 

Rathcahill (1) 12.5 2010 

Reenascreena (1) 4 2009 

Reisk (1) 3.9 2014 

Roosky (1) 3.6 2009 

Scartaglen(1) 14 2012 

Seltanaveeny (1) 5.4 2009 

Shannagh (1) 2.55 2009 

Skrine(1) 4.999 2009 

Slievereagh (1) 3 2009 

Sorne Hill (Enros) 2.3 2010 

Templederry (1) 3.9 2010 

Three Trees (1) 4.25 2010 

Tooradoo(1) 5 2012 

Tooreen(1) 4 2012 

Tullynamoyle (1) 9 2010 

WEDcross(1) 4.5 2009 


GrandTotal 1348.692 

69


APPENDIX 3 SUPPLEMENTARY NOTES ON 

METHODOLOGY 

LOSS OF LOAD EXPECTATION (LOLE) 

Acomputer program CREEP (Capacity Requirement Evaluation by Exact Probability) is used to calculate 

LOLE. With an hourly load model as used in CREEP, the Loss of Load Expectation (LOLE) is the expected 

numberof hoursin the yearwhenthe availablegenerationplant isless than theload. 

The annualLOLEisthe sumof thecontributionsfrom each hour.Ingeneral: 

Expectation = Probability xOutcome 

E.g. A10MW generation unit has aforced outage probability (FOP) of 1% in hour .In other words, 

there sa1% probability thatthe outcomewillbe failure tomeet loadof 10MW ,so 

Expectationin hour 

=0.01x failure =0.01 hours of failure = 36seconds of failure 

The LOLE in hour is 36 seconds, i.e. in hour ,it is expected that the unit will fail to meet the load for 

36 seconds. If the unit and the load maintain the same characteristics over the course of ayear, each 

hourof the yearwillcontribute36 seconds to give a totalLOLEforthe year of: 

36s x24x365 =87.6 hours 

The sum ofall the hourly expectations of failuregives theannualLOLEin hours. 

In reality, apower system will consist of many different generators with different FOPs, and the load 

will vary each hour. Consider now the simplest case of asingle-system study, with adeterministic load 

model (that is, with only one value used for each load), and no scheduled maintenance, so that there is 

onegenerationavailabilitydistribution for the entireyear.If 

L =loadat hour onday 

G 

H 

D 

=generationplantavailable 

=numberloads/day tobe examined(i.e.1,24or48) 

=totalnumberof days in year to be examined 

then theannualLOLEisgivenby 

LOLE = 

∑ 

∑ 

d = 1, D h= 

1, H 

Prob. 

( G < L ) 

h, 

d 

This equationisusedin thefollowingpractical example. 

SIMPLIFIED EXAMPLE OF LOLE CALCULATION 

Considerasystem consistingofjust threegenerationunits,as inTableA-10. 

Capacity (MW) Forcedoutage probability Probability of being available 

Unit A 10 0.05 0.95 

Unit B 20 0.08 0.92 

Unit C 50 0.10 0.90 

Total 80 

70


If the load to be served in aparticular hour is 55MW, what is the probability of this load being met in 

this hour? Tocalculate this, thefollowingstepsarefollowed: 

1) How many different states can the system be in, i.e. if all units are available, if one is forced 

out,if two areforced out, orall three? 

2) Howmany megawattsare inservicefor eachof these states? 

3) Whatis theprobabilityof eachof these states occurring? 

4) Addup theprobabilities forthe states where theloadcannotbe met. 

5) Calculate expectation. 

1) 1) 2) 3) 3) 4) 4) 

State Units in Capacity in Probability for Probability Ability to Expectation 

service service (A*B*C) 

meet of Failure 

(MW) 

55 MW (LOLE) 

demand 

1 A, B, C 80 0.95*0.92*0.90 = 0.7866 Pass 0 

2 B,C 70 0.05*0.92*0.90 = 0.0414 Pass 0 

3 A,C 60 0.95*0.08*0.90 = 0.0684 Pass 0 

4 C 50 0.05*0.08*0.90 = 0.0036 Fail 0.0036 

5 A, B 30 0.95*0.92*0.10 = 0.0874 Fail 0.0874 

6 B 20 0.05*0.92*0.10 = 0.0046 Fail 0.0046 

7 A 10 0.95*0.08*0.10 = 0.0076 Fail 0.0076 

8 none 0 0.05*0.08*0.10 = 0.0004 Fail 0.0004 

Total 1.0000 0.1036 

The probability for each state to occur is calculated by multiplying together the probabilities for each 

generation unit, e.g. for state 5, unit A is available (0.95 probability), unit B is available (0.92 

probability),whileunit Cisforced out(0.10probability). These aremultipliedtogether to give0.0874. 

Only states 1, 2and 3are providing enough generation to meet the demand of 55 MW. All the other five 

states fail, so the probabilities for these five states are added up to give atotal probability of 0.1036. 

So in this particular hour, there is achance of approximately 10% that there will not be enough 

generation to meet the load. It can be said that this hour is contributing about 6minutes (10% of 1 

hour) to the overallLOLE forthe year. 

This analysis would be carried out for the system to meet the load at every hour of the year, and the 

individualcontributionsaddedup to get theoverall yearlyLOLE. 

If scheduled maintenance is allowed for, adifferent generation availability distribution is used for each 

hour.Otherwisethe procedureisthe same. 

Peak Carrying Capability (PCC) 

PCC is derived as follows. An adequacy standard is specified in terms of LOLE. Anew factor, F ,is 

introducedwhichismultipliedbythe load L (for every hour) such that therequiredLOLEisachieved. 

L = F x L 

If the LOLE had been outside standard, then the load would be reduced proportionally until the 

available generation could meet it. If the LOLE had been less than the standard, then the load would be 

increaseduntil the LOLE equalled the standard. 

PCCisdefinedas the originalpeakloadmultipliedbythisnewfactor. 

PCC = F 

x L 

The difference between the original peak load and the PCC is the surplus/deficit. The surplus/deficit 

therefore describes the difference in magnitude between two load curves in peak terms, however, it is 

also ausefulindicationof the amountofgenerationplantrequired to exactly meetthe standard. 

71


APPENDIX 4 

ADEQUACY ASSESSMENT RESULTS 

Demand Availability 2010 2011 2012 2013 2014 2015 2016 

Low 

EirGrid 

Availability 

983 910 1226 1,728 1,659 1,885 1,562 

Generator 

Availability 

1,452 1,349 1,659 2,073 2,022 2,263 1,902 

Median 

EirGrid 

Availability 

927 831 1104 1,598 1,513 1,742 1,404 

Generator 

Availability 

1,400 1,258 1,536 1,942 1,879 2,111 1,741 

High 

EirGrid 

Availability 

867 743 1,008 1,465 1,349 1,541 1,169 

Generator 

Availability 

1,341 1,172 1,450 1,808 1,711 1,917 1,492 

Table A-12 The surplus of plant resulting from the different scenarios studied. All figures are given in 

MW of perfect plant. These scenarios assume the following: 

200 MW reliance on Northern Ireland from 2010-2012. 

All-Island Assessment in 2013-2016. 

250 MW benefit from EWIC in 2013-2016. 

Plant closures and openings as notified. 

 

 

DSM at 138 MW. 

Constraining of export from Aghada site limited to 690 MW (960 MW installed at Aghada) and 

full export capability from Whitegate CCGT. 

72

Generation Adequacy Report 2010-2016 - Eirgrid

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