Network Development Statement 2010/11 to 2019/20 - Gaslink

NETWORK
DEVELOPMENT
STATEMENT
2010/11 to 2019/2020

DISCLAIMER
Gaslink 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 Network Development Statement (NDS) and should not rely solely upon data and information contained therein.
Information in this document does not purport to contain all the information that a prospective investor or participant in
Ireland’s gas market may need.

CONTENTS
NETWORK DEVELOPMENT STATEMENT
1. Introduction 2
2. Executive Summary 4
2.1 ROI Gas Demand 4
2.2 Gas Supplies 4
2.3 Network Development 5
3. Demand 6
3.1 Record Peak Gas Demands in 2010 6
3.2 Historic ROI Demand – 2005/06 to 2009/10 7
3.3 Forecast ROI Gas Demand 13
4. Gas Supply Outlook 18
4.1 Historical gas supplies 18
4.2 Future gas supply outlook 19
5. The ROI Transmission System 22
5.1 Overview of the existing ROI gas network 23
5.2 New connections and New Towns 24
5.3 System Reinforcement 24
5.4 System Refurbishment 27
6. Network Analysis 28
6.1 Overview of Network Analysis 28
6.2 The Network Model 29
6.3 Entry Point Assumptions 29
6.4 System Configuration 30
6.5 Summary of Modelling Results 30
6.6 Physical Exports to GB 35
6.7 Conclusions 37
7. Asset Management 38
7.1 Compressor Stations 38
7.2 AGIs & DRIs 40
7.3 Meters 41
7.4 Communications and Instrumentation 43
7.5 Pipelines 44
7.6 Asset Integrity 45
7.7 Gas Quality 46
7.8 Natural Gas as a transport fuel 47
8. Security of supply 48
8.1 Overview of Legal Framework 48
8.2 Existing Operational and Planning arrangements 48
9. Commercial Market Developments 50
9.1 Gaslink: Independent System Operator 50
9.2 European Developments 50
9.3 New Connections 52
9.4 Moffat 52
9.5 CAG Summary 53
Appendix 1: Demand Forecasts 54
Appendix 2: Historic Demand 57
Appendix 3: Energy Efficiency assumptions 59
National Energy Efficiency Action Plan (NEEAP) 59
Glossary 61
1

1. Introduction
The publication of the Network
Development Statement (NDS) covers
the 10 year period from 2010/11 to
2019/20. It has been prepared by Gaslink
(the independent Gas System Operator),
with assistance from Bord Gáis
Networks (BGN). Previous publications
of this document were referred to
as the Transmission Development
Statement (TDS).The document was
renamed to reflect all aspects of
the Bord Gáis system, not just the
transmission system.
2

NETWORK DEVELOPMENT STATEMENT
Gaslink is required to produce a Long-term Development
Plan under Condition 11 of its Transmission System
Operator Licence. The publication of the NDS is designed
to meet this obligation, and also serves as the Gaslink
input into the Joint Gas Capacity Statement (JGCS)
consultation process.
Natural gas continues to play a very important role
in the Republic of Ireland (ROI) energy mix. It brings
considerable economic and environmental benefits
such as being cheaper than oil, having the lowest CO 2
emissions of any fossil fuel and providing the most
efficient form of thermal power generation.
It is hoped that the NDS will inform market participants
about gas usage, and thereby, maximise the resulting
economic and environmental benefits to the ROI
economy. It is intended to provide existing and potential
users of the ROI system with an overview of future
demand, likely sources of supply and the capacity of the
existing system.
The main focus of the NDS is the ROI transmission system,
which for the purposes of the NDS is defined to include
both the onshore ROI transmission system and the BGE
Interconnector (“IC”) system, which includes:
• The two subsea interconnectors from Loughshinny and
Gormanston in Ireland, to Brighouse Bay in Scotland;
and
• The Brighouse and Beattock compressor stations
and connecting transmission pipeline, which connect
the two subsea interconnectors to the Great Britain
(GB) National Transmission System (NTS) at Moffat in
Scotland.
This year the NDS discusses other assets in the ROI system
and reports on significant projects completed on the
distribution system.
The Northern Ireland (“NI”) and Isle of Man (“IOM”)
peak-day and annual demands are also included in the
NDS demand forecasts for completeness, as they have a
material impact on the capacity of the IC system. These
forecasts are based on information provided by Premier
Transmission LTD (PTL) in NI and the Manx Electricity
Authority (MEA) on the IOM.
In order to complete the detailed analysis and modelling
required to produce this document, the demand and
supply scenarios were defined in November 2010, based
on the most up to date information at that time.
July 2011
3

2. Executive Summary
2.1 ROI Gas Demand
The 2009/10 gas year proved to be a year of records
for ROI gas demand. The gas demand for the 12
month period was up +6.4% on the previous year, and
the record peak demand day occurred on the 7th of
January 2010, realising a +8.8% increase on 2008/09.
Annual demand growth was primarily driven by gas
demand from the power generation sector, despite
a reduction in electricity demand. Power generation
gas demand grew by +9.3% on 2008/09, which can
be attributed to favourable gas prices relative to
other fuels for power generation, and low wind levels
resulting in low wind generation.
The very cold weather experienced in December 2009
and January 2010, resulted in high demand from the
primarily weather sensitive non-daily metered (NDM)
sector, comprising of residential and small to medium
size Industrial and Commercial (I/C) customers. A record
NDM demand peak, 95.2 GWh/d, occurred during this
cold weather period, on the 7th of January 2010, an
increase of 19.4% on the previous NDM peak.
Despite the severe cold weather I/C gas demand
remained flat on 2008/09, which can be attributed to
the ongoing economic recession.
The gas demand outlook for the next 10 years is
positive, with growth being driven primarily by the
power generation sector. I/C gas demand is anticipated
to experience some growth in line with economic
recovery, while residential gas demand is expected
to slightly contract as a result of increasing energy
efficiency.
2.2 Gas Supplies
Over 93% of ROI gas supplies will continue to be
sourced from GB imports over the next 2 years, until
2013, when Corrib is assumed to commence commercial
operation.
Celtic Sea storage and production operations are
expected to continue in the short to medium term,
though uncertainty surrounds the medium to long
term future.
4

NETWORK DEVELOPMENT STATEMENT
There are also a number of proposed supply projects,
including two separate salt cavity storage projects in
the Larne area of Northern Ireland and the Shannon
Liquefied Natural Gas (LNG) terminal in Co. Kerry.
The two Larne project developers have indicated a
start state for commercial operations in the 2016 and
2017 period. Shannon LNG have indicated they cannot
currently provide a likely start date for commercial
operation of the LNG facility.
However, due to the uncertainty surrounding the
timing of the various proposed supply projects, it
should also be emphasised, if there is any significant
change to the future supply outlook, resulting in the
likelihood of Moffat being the only source of supply to
ROI, NI and IOM in the short to medium term, it is likely
the “South West Scotland On Shore System” (SWSOS)
will require reinforcement. Based on demand forecasts
and the capacity at Moffat, this reinforcement would
need to be in place for 2013/14.
2.3 Network Development
The network analysis detailed in chapter 6 examined
the capacity of both the onshore ROI transmission
system and the onshore Scotland system (including
the subseas Interconnectors). Results indicate there is
sufficient capacity available on the existing onshore
ROI transmission system to meet the required forecast
peak-day demand over the forecast period, and equally,
the local transmission systems have sufficient capacity
to meet the forecast peak day demands (subject to local
growth not exceeding assumed national growth levels).
5

3. Demand
3.1 Record Peak Gas Demands in 2010
2010 was a record year for gas demand, December 2010
was a record month for gas demand and the 7th of
January 2010 was a record day for gas demand. These
record gas demands coincided with some of the most
severe cold weather conditions on record, particularly the
month of December, which was the coldest month on
record at Dublin Airport, according to Met Éireann.
Gas demand in the month of December 2010, 6,671 GWh
(c. 605 mscm/m) grew by 6.0% on January 2010 (the
previous record month) and 11.7% on December 2009.
Demand on the 7th of January, 253 GWh/d (23.0 mscm/d)
was 9.5% up on the previous peak, 7th of January
2009. Even though a number of days in December
2010 realised similar levels of gas demand to the 7th of
January, they were slightly short on the 7th of January
peak demand record.
The electricity system also experienced record peak
demands during both January and December 2010. The
record demands combined with very low wind levels
and favourable gas prices relative to coal for electricity
generation, resulted in record gas demand for the power
generation sector.
The month of December 2010 was the coldest December
on record, corresponding with the coldest record day at
Dublin airport on the 24th of December, since records
commenced in 1942. The average temperature over a
24 hour period on the 24th of December was -8.6°c.
Similar freezing conditions occurred in early January,
particularly on the 7th and 8th of January, with an
average temperatures of c. -5.0°c.
The weather sensitive non-daily-metered sector, which
comprises of residential and small Industrial and
Commercial (I/C) customers, experienced record peak
daily demands of c. 95 GWh/d, in both January and
December.
Gas flows through the subsea inter-connectors (ICs)
exceeded 188.2 GWh (17.0 mscm/d), the design capacity
of IC1 on a number of days during the January and
December peak demand periods. Both gas supplies and
the Bord Gáis transmission system were sufficient in
meeting demand throughout the high demand periods.
Fig. 3.1: Actual demand by sector for January and December 2010
Demand (GWh/d)
January December 2010 Daily Demand
270
240
210
180
150
120
90
60
30
01 JAN 10
03 JAN 10
05 JAN 10
07 JAN 10
09 JAN 10
11 JAN 10
13 JAN 10
15 JAN 10
17 JAN 10
19 JAN 10
21 JAN 10
23 JAN 10
25 JAN 10
27 JAN 10
29 JAN 10
31 JAN 10
22 NOV 10
24 NOV 10
26 NOV 10
28 NOV 10
30 NOV 10
02 DEC 10
04 DEC 10
06 DEC 10
08 DEC 10
10 DEC 10
12 DEC 10
14 DEC 10
16 DEC 10
18 DEC 10
20 DEC 10
22 DEC 10
24 DEC 10
26 DEC 10
28 DEC 10
30 DEC 10
Power Tx DM I Dx DM I NDM Shrinkage Jan & Dec 09 Demand

NETWORK DEVELOPMENT STATEMENT
Fig. 3.2: Historical daily ROI gas demand summarised by sector
300
Historic ROI Demand by Sector
Demand (GWh/d)
250
200
150
100
50
0
01 OCT 05 01 APR 06 01 OCT 06 01 APR 07 01 OCT 07 01 APR 08 01 OCT 08 01 APR 09 01 OCT 09 01 APR 10
I/C RES Power
3.2 Historic ROI Demand – 2005/06 to 2009/10
3.2.1 Overall ROI demand
The historical ROI daily gas demand is shown in Fig. 3.2,
together with the corresponding peak-day and annual
demand statistics in Table 3.1. The peak-day and annual
demand has grown by +6.9% p.a. and +4.8% p.a.
respectively, between 2005/06 and 2009/10.
The power generation sector was the largest user of
natural gas and accounted for 67.5% of total ROI annual
gas demand in 2009/10, followed by the I/C sector which
accounted for 17.9% and the residential sector which
accounted for 14.6%.
The weather sensitive nature of the residential demand
means that it makes a bigger contribution to peakday
demand (27.0% in 2009/10). The corresponding
contributions of the power and I/C sectors on the peak-day
were 54.2% and 18.8% respectively.
Table 3.1: Historic ROI Peak-day and annual gas demand (actual demands) 1
2005/06 2006/07 2007/08 2008/09 2009/10
(GWh) (GWh) (GWh) (GWh) (GWh)
Peak-day
Power 2 96.8 111.2 119.7 126.4 134.3
I/C 43.4 43.1 43.4 44.4 46.3
RES1 49.4 50.4 52.5 56.7 67.0
Total 189.6 204.7 215.7 227.5 247.6
Annual
Power 29,775 34,688 37,758 36,007 39,338
I/C 10,352 10,486 10,507 10,415 10,409
RES 8,149 7,716 8,239 8,312 8,492
Total 48,276 52,890 56,504 54,734 58,239
1
Actual demands shown (no weather correction), with RES estimated as % of NDM demand
2
Power sector demand includes Aughinish gas demand
7

3. Demand continued
Fig. 3.3: Historical fuel-prices
30.0
Historic Fuel Prices
25.0
Fuel Prices (€/GJ)
20.0
15.0
10.0
5.0
0.0
01 DEC 03
01 APR 04
01 AUG 04
01 DEC 04
01 APR 05
01 AUG 05
01 DEC 05
01 APR 06
01 AUG 06
01 DEC 06
01 APR 07
01 AUG 07
01 DEC 07
01 APR 08
01 AUG 08
01 DEC 08
01 APR 09
01 AUG 09
01 DEC 09
01 APR 10
01 AUG 10
Gas LSFO Coal
*LSFO = Low Sulphur Fuel Oil, i.e. the main fuel burned by oil-fired power stations
3.2.2 Power sector gas demand
Despite declining electricity demand, power generation gas
demand grew by approximately 9.25% on 2008/09 levels.
This increase in power sector gas demand was attributed to;
• Low wind levels, resulting in relatively low wind generation.
• Relatively low gas prices, resulting in modern gas fired
generation been more competitive than coal and oil
generation throughout 2009/10 (see fig. 3.3).
• Two new gas fired entrants to the SEM in the Cork area,
Aghada and Whitegate CCGTs.
EirGrid have indicated wind generation exports during
2009/10 were down on 2008/09 levels despite increased wind
generation capacity. This can be attributed to the lower than
normal wind levels for the year.
In 2009/10 the gas demand of the power sector on the ROI
peak-day increased by +6.3% to 134.3 GWh/d on 7th January
2010. This corresponded with a record ROI electricity system
demand peak of 4,950 MW. This high demand coincided with
low levels of wind generation (83 MW at the time of the system
peak), and resulted in record power generation gas demand.
(This record was subsequently broken on the 21st of December
2010, 5,090 MW, though power generation gas demand was
only 121.4 GWh/d, due to unscheduled outages at a number of
gas fired power stations).
8

NETWORK DEVELOPMENT STATEMENT
Fig. 3.4: I/C gas demand monthly growth by connection type
30.0%
Month on Month % Change 2009/10 and 2008/09 I&C Demand
20.0%
Month on Month % Change
10.0%
0.0%
-10.0%
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP
-20.0%
-30.0%
TRANSMISSION
DISTRIBUTION
3.2.3 I/C gas demand
The annual gas demand of the I/C sector remained on
par with 2008/09 levels, however, there were significant
differences between the trends for transmission and
distribution connected sites (which respectively accounted for
43.6% and 56.4% of total I/C gas demand in 2009/10):
• Annual gas demand of the transmission connected I/C sites
rose by +5.2%.
• Annual gas demand of the distribution connected I/C sites
fell by -1.4%.
The transmission connected I/C sector includes the larger
manufacturing, pharmaceutical and dairy co-op sites, which
primarily use natural gas to provide heat for manufacturing and
processing purposes.
The distribution connected I/C sector includes the small I/C
sector, offices, retail units, hospitals and schools etc, which
would primarily use gas for space-heating purposes and
therefore, their gas demand would be much more weather
sensitive.
Fig. 3.4 illustrates the trend divergence between transmission
and distribution I/C gas demand. Distribution I/C demand
demonstrated growth during winter, particularly in early 2010,
in response to the very cold weather conditions experienced in
this period.
Transmission I/C gas demand recovered strongly in the second
half of 2009/10. This recovery coincides with Irish economic
growth detailed in the CSO’s Quarterly National Accounts
for Q3 2010, driven primarily by the export sectors of
manufacturing and industry.
9

3. Demand continued
3.2.4 Historical residential gas demand
Total residential gas demand grew by +2.2% during 2009/10,
and annual gas demand per residential customer increased
slightly by 0.7%. The contraction in demand per customer
experienced in 2008/09 was expected to continue in 2009/10,
as a result of enhanced building regulations for new houses,
increasing energy efficiency initiatives for existing houses and
the ongoing economic recession.
The slowdown in the construction sector can also be seen in the
new connection numbers. The total number of new residential
connections dropped from approximately 13,294 in 2008/09
to 5,939 in 2009/10, a reduction of -55.3%. The latest house
building data published by the Department of the Environment,
Heritage and Local Government indicates, new housing
completions fell by approximately 46% in 2010.
However, the very cold weather conditions experienced during
the winter period, particularly in January 2010, which resulted
in higher demand from the residential sector is likely to have
affected this trend.
Table 3.2: Residential gas demand per customer
2005/06 2006/07 2007/08 2008/09 2009/10
(GWh) (GWh) (GWh) (GWh) (GWh)
No. of customers
On 1st October 500,837 538,822 571,485 595,740 609,034
On 30th September 538,822 571,485 595,740 609,034 614,973
Customer growth 37,985 32,663 24,255 13,294 5,939
Average for Gas Yr 1 519,830 555,154 583,613 602,387 612,004
RES Demand
Total RES demand 8,148.9 7,716.1 8,238.5 8,311.8 8,491.5
Demand per customer 2 0.0157 0.0139 0.0141 0.0138 0.0139
1
Average
for Gas Yr = Average number of residential customers connected to the distribution system over the course of the gas year (i.e. the average number of
customers at the start and end of gas year)
2
Per customer = Average residential annual gas demand per customer (before weather adjustment)
10

NETWORK DEVELOPMENT STATEMENT
3.2.5 ROI annual energy demand
Natural gas continues to make an important contribution to the
overall ROI energy-mix, and accounts for approximately 29.0%
of the ROI Total Primary Energy Requirement (TPER) in 2009 (see
Fig. 3.5 & 3.6).
The TPER includes the use of fuel for electricity generation.
Natural gas is also an important fuel for electricity generation,
accounting for 56.0% of all fuels used for electricity generation
in 2009.
Natural gas accounted for 12.9% of Total Final Consumption
(TFC). Its lower share of TFC compared to TPER, can be
explained by the fact the TFC excludes the use of energy for
electricity generation (the largest use of natural gas). Natural
gas accounted for 20.2% of the residential TFC, 26.7% of the
commercial TFC and 24.1% of the industrial TFC.
TPER by fuel (kTOE/year)
Fig. 3.5: Analysis of historical ROI TPER
Irish TPER by fuel ROI TPER analysis by fuel (2009)
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
Coal Peat Oil Gas REN E. Import
ROI TPER analysis by fuel (2009)
6%
8%
5%
29%
52%
Coal Peat Oil Gas REN E. Import
Table 3.3: Historic BGE Peak-day and annual gas demand (actual demands)
Fig. 3.6: Breakdown of ROI TPER for 2009
2005/06 2006/07 2007/08 2008/09 2009/10
(GWh) (GWh) (GWh) (GWh) (GWh)
Peak-day 1
ROI 165.7 196.7 205.9 227.5 247.6
NI + IOM 79.8 79.0 74.8 67.7 80
Total 245.5 275.7 280.7 295.2 327.5
Annual
ROI 48,276 52,890 56,504 54,734 58,239
NI+IOM 19,353 20,216 19,294 18,022 17,232
Total 67,629 73,106 75,798 72,756 75,471
1
Excludes shrinkage gas consumed on the peak day
11

3. Demand continued
Fig. 3.7: Historical daily demand on the BGE transmission system
350
Total BGE Demand
300
250
Demand (GWh/d)
200
150
100
50
0
01 Oct 02
01 Apr 03
01 Oct 03
01 Apr 04
01 Oct 04
01 Apr 05
01 Oct 05
01 Apr 06
01 Oct 06
01 Apr 07
01 Oct 07
01 Apr 08
01 Oct 08
01 Apr 09
01 Oct 09
01 Apr 10
NI & IOM
ROI
3.2.6 BGE system demand
The historical peak-day and annual demand of the overall
BGE system is shown in Table 3.3 and includes the aggregated
demands of the ROI, NI and the IOM. The historical daily
demand of the BGE system is shown in Fig. 3.7.
The overall BGE system peak-day demand increased +11.1%
during 2009/10, and the annual demand increased by +3.7%.
The ROI peak-day coincided with the BGE system peak-day on
the 7th of January 2010, which was an all time record demand
for both systems, as a result of the exceptionally cold weather
conditions experienced during this period. Very low wind levels
on this date also contributed to higher power generation gas
demand. Wind generated electricity met approximately 1.7% of
peak electricity demand on the 7th January 2010.
The ROI peak day was driven by record power generation and
NDM gas demand, of 134.8 GWh and 95.2 GWh respectively.
DM I/C gas demand at 20.8 GWh/d was not as high as previous
years, due to the current economic recession.
The annual demand on the BGE system increased by +3.7%
during 2009/10, despite NI & IOM annual demand contracting
by -4.4%. The BGE system increase is attributed to ROI annual
growth of +6.4%, resulting from power generation annual gas
demand growing by +9.25%.
12

NETWORK DEVELOPMENT STATEMENT
3.3 Forecast ROI Gas Demand
3.3.1 ROI power sector forecast
The gas demand of the ROI power sector will be determined by
a number of factors including:
• The overall demand for electricity and the order in which
power stations are despatched to meet that demand (i.e.
the “merit-order”, which is very sensitive to fuel-prices).
• National and international policies in relation to targets for
renewable electricity production, electrical interconnection
and global warming (including carbon prices).
The latest electricity demand forecasts published by EirGrid
and SONI reflect further downward revision on last year’s
forecast, as a result of the continued impact of the current
economic recession. This combined with continuing investment
in renewable electricity production, increased electricity
interconnection with GB, and rising gas prices relative to coal
prices, affects the ability for future gas demand growth in the
power sector. This is reflected in the following:
• The forecasts published by EirGrid & SONI in the 2011-2020
All Island Generation Capacity Statement assume that the
All-Island electricity peak-demand will increase from 6,308
MW in 2010 to 7,235 MW by 2020 in their median forecast
(i.e. an increase of + 927 MW);. The ROI accounts for
approximately 73% of the Island’s electricity demand.
• The forward price curve for winter gas indicates that prices
will increase from circa 50.0 p/therm in 2010/11 to 64 p/
therm in 2014/15 (an increase of +28.0%), while forward
prices indicate coal will only increase by 11% over the same
period.
• EirGrid & SONI forecast the installed All-Island on-shore
wind-capacity will increase from 1,756 MW in 2010 to
4,826 MW by 2020 (an increase of +3,070 MW), and have
confirmed that they are on schedule to complete the 500
MW East/West electricity interconnector to GB in 2012.
The global drive to reduce greenhouse gases may provide
some upside for gas demand, however, by displacing coal for
electricity generation. The carbon price is assumed to reach c.
€30/tCO 2 by 2018/19, during Phase III of the Emission Trading
Scheme (ETS). This should lead to a recovery in power sector
gas demand towards the end of the forecast period.
The NDS planning assumptions in relation to the construction
and retirement of power stations in both the ROI and NI are
tabulated in Table 3.4, and may be briefly summarised as
follows:
• Endesa plan to retire their oil-fired plants by 2013/14, and
replace them with a 440 MW CCGT at Great Island, and a
300 MW OCGT at Tarbert (and later a 430 MW CCGT).
• A number of additional gas-fired stations have also been
included in the NDS for planning purposes, including two
new CCGTs in the Midlands and Belfast, and two small
OCGTs in the Midlands.
The NDS forecast assumes that peak-day electricity demand will
increase from 6,308 MW in 2010/11 to 7,235 MW by 2019/20,
an increase of +927 MW. This level of growth in electricity
demand will be insufficient to fully utilise all of the proposed
new generation:
• The combined export capacity of all the gas-fired power
stations is assumed to increase from 5,627 MW to 6,967
MW by 2019/20 (an increase of +1,340 MW).
• The installed wind-capacity is assumed to increase from
approximately 1,756 MW to 4,826 MW by 2019/20 (an
increase of +3,070 MW).
• The level of electrical interconnection is assumed to
increase from 450 MW to 950 MW by 2012/13 (an
increase of +500 MW).
13

3. Demand continued
Table 3.4: New and retired power station assumptions
Name Type Status Export Start Location
(MW)
Date
New
Great I. CCGT CCGT Assumed 440 Oct-13 Wexford
Tarbert OCGT* OCGT Assumed 300 Oct-13 Kerry
New CCGT1 CCGT Assumed 350 Oct-13 Midlands
New CCGT2 CCGT Assumed 430 Oct-13 Belfast
New OCGT1 OCGT Assumed 100 Oct-12 Midlands
New OCGT2 OCGT Assumed 100 Oct-13 Midlands
Total 1,720
Retired
Tarbert Oil Assumed 590 Mar-13 Kerry
Great Island Oil Assumed 216 Mar-13 Wexford
Total 806
*Assumed to be converted into 430MW CCGT by 2016/17
The most likely outcome from the above assumption is that
the potential increase in gas demand from the assumed new
gas-fired power stations, will be largely offset by reduced gas
demand from the older and less efficient gas-fired stations
(which will be forced further-up the merit-order and despatched
less frequently).This can also be seen in Fig. 3.8, which shows
the NDS forecast of hourly power generation by fuel for the
2010/11 peak-day.
There is already insufficient baseload electricity demand for the
existing baseload coal, peat and gas-fired stations. The gas-fired
stations will need to be curtailed at night-time. The forecast
trends for power sector annual demand are as follows:
• It will decline until 2014/15 due to the combination of rising
gas prices, rising renewable energy, lower electricity demand
and increased electrical interconnection with GB.
• It will begin to recover from 2014/15 onwards due to the
assumptions of increasing electricity demand, rising carbon
prices and a phasing out of the Public Service Obligation
(PSO) levy for peat stations.
The annual gas demand of the power sector is expected to
increase by +8.8% over the forecast period (or by +0.9% p.a.).
The peak-day gas demand of the power sector will follow a
broadly similar trend, which may be summarised as follows:
• It is forecast to grow at a higher rate of +20.2% over
the forecast period or +1.6% p.a., primarily due to the
assumption that wind-power will have a lesser impact on the
peak-day demand of the sector (since the system peak-day
is assumed to occur on a calm day, which is the worst-case
scenario for gas system planning purposes).
• It is expected to decline from 2012/13 due to the impact
of the East/West electricity interconnector to GB, which is
assumed to commence operation from 2012/13.
• It is expected to recover from 2014/15 onwards due to the
assumptions of increasing electricity demand, rising carbon
prices and a phasing out of the peat PSO levy.
14

NETWORK DEVELOPMENT STATEMENT
Fig. 3.8: Forecast despatch of SEM power sector by fuel-type on 2010/11 gas peak-day
7,000
SEM Generation by Fuel Type for 07 Jan 11
6,000
5,000
Hourly Generation (MW)
4,000
3,000
2,000
1,000
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Hour No.
18
19
20
21
22
23
24
E. Import Peat Oil Gas REN Coal
3.3.1.1 Electricity Demand Forecast Assumption
The electricity transmission peak demand forecasts published by
EirGrid & SONI in the 2011-2020 All Island Generation Capacity
Statement are based on a temperature standard known as
Average Cold Spell (ACS), which represents an average type
winter. Currently EirGrid and SONI don’t publish transmission
peak demand forecasts for severe type winter.
The actual ROI electricity transmission peak demand, 5,090
MW, experienced during the severe weather period in
December 2010 exceeded the All Island Generation Capacity
Statement 2010 transmission peak demand forecast, 4,602
MW by approximately 10.6%.
To date this statement and previous TDS publications adopted
the electricity transmission peak demand forecasts published by
EirGrid & SONI, for both average winter peak day and 1-in-50
peak day power generation gas demand forecasts. However, it
is likely, future statements will adopt the EirGrid & SONI forecast
for average year peak day power generation gas demand
forecasts only.
The actual electricity transmission peak, 5,090 MW, which
occurred on 21st December 2010, in conjunction with the
growth rates derived from the electricity transmission peak
forecasts published by EirGrid & SONI, will be adopted for the
1-in-50 peak day power generation gas demand forecasts.
15

3. Demand continued
3.3.2 Forecast I/C gas demand
The future growth in annual I/C gas demand will primarily be
driven by the recovery in the ROI economy and the demand for
economic goods and services, which will drive the demand for
the associated primary inputs such as natural gas.
The NDS forecast uses the economic forecasts published in the
ESRI Quarterly Economic Commentary (QEC) for Autumn 2010,
which forecast that Gross Domestic Product (GDP) will reduce by
-0.25% during 2009 and grow by +2.25% during 2011.
The ‘Recovery Scenarios for Ireland: An Update’, published by
the ESRI in July 2010, and subsequent consultation with the
ESRI, have provided the economic outlook post 2011;
• The economy will come out of recession by 2010/11, and
will slowly recover, growing at approximately 2.5% in the
first two years.
• Economic growth will then revert back to its long-term trend
potential of between 3.0% and 3.5% p.a. post 2011/12.
The NDS forecast assumes that the annual I/C gas demand
will grow at 80% of the GDP growth rate, but this will be
offset by both rising gas prices and increasing energy efficiency
(particularly post 2016). The forecast trends in the annual I/C
gas demand may be summarised as follows:
• I/C gas demand is anticipated to experience further decline
in 2010/11 due to weak economic growth, increasing
energy efficiency and the assumption of rising gas prices.
• It will recover from 2011/12 onwards due to rising economic
growth, however, this will be increasingly offset by rising
energy efficiency (particularly post 2016).
• Overall I/C annual gas demand is assumed to grow by 7.7%
(or +0.8% p.a.) over the forecast period, with the peak-day
gas demand following a similar trend.
Assumptions regarding I/C energy efficiency savings are similar
to those published in last year’s TDS, which are the energy
efficiency savings identified in the National Energy Efficiency
Action Plan (NEEAP) for Ireland. The NDS forecast assumes
annual energy efficiency savings of 65 GWh/y up to 2015/16,
and 266 GWh/y from 2015/16 onwards (equivalent to 0.6%
and 2.6% respectively of the I/C annual gas demand in
2009/10).
The forecast peak-day and annual gas demand of the I/C sector
are summarised in Appendix No.1, and the assumptions in
relation to the I/C energy efficiency savings are explained in
more detail in Appendix No.3.
16

NETWORK DEVELOPMENT STATEMENT
Table 3.5: New residential connection assumption by gas year
10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20
New 3,125 3,375 4,625 6,875 8,625 10,125 11,625 13,125 13,500 13,500
One-off 3,900 3,975 4,375 4,875 5,000 5,000 5,000 5,000 5,000 5,000
Total 7,025 7,350 9,000 11,750 13,625 15,125 16,625 18,125 18,500 18,500
3.3.3 Forecast residential gas demand
The future gas demand of the residential sector will be driven
by both the number of new connections, and the impact of the
various proposed energy efficiency measures. The assumptions
in relation to new connections are summarised in Table 3.5.
New residential connection numbers reflect further downward
revision on last year’s forecast, as a result of the continued
impact of the current economic recession, and the uncertainty
surrounding the level of recovery in the construction sector over
the short to medium term.
The total number of residential customers is forecast to grow
from 614,973 at the start of 2009/10 to 750,598 by the end
of 2019/20, an increase of +22.1% over the forecast period
(+2.2% p.a.). Residential annual gas demand is forecast to
reduce by -9.5% over the forecast period (-1.1 % p.a.), for a
number of reasons:
• The incremental gas demand of new residential customers
has been falling due to tighter building regulations.
• The average gas demand of existing residential customers
has also been falling due to increasing energy efficiency,
greater vacancy rates and in response to rising gas prices in
recent years.
• Further initiatives are planned for improving the energy
efficiency of existing houses in the NEEAP, including
retrofitting insulation to older houses, smart metering and
setting a new standard for more efficient boilers.
All of these trends are expected to intensify over the forecast
period. The average incremental annual gas demand of a new
customer in 2005 was approximately 12.3 MWh/y; under the
latest building regulations this is expected to reduce by 60% to
4.9 MWh/y by 2012.
The proposed standard for more efficient boilers, smart
metering and the Low Carbon Homes, Warmer Homes and
Home Energy Savings schemes are designed to improve the
energy efficiency of the existing housing stock. It is estimated
that these measures could lead to an reduction of -1.8% p.a. to
the existing residential gas demand.
It should be emphasised that there is still considerable
uncertainty surrounding the rollout and implementation of the
energy efficiency initiatives for existing housing. The energy
efficiency assumptions regarding the residential sector are
similar to those published in last year’s TDS, which are the
savings identified in the National Energy Efficiency Action Plan
(NEEAP) for Ireland.
The NEEAP energy efficiency savings are detailed in Appendix 3.
The peak-day and annual residential gas demand forecasts are
tabulated in Appendix 1.
17

4. Gas Supply Outlook
4.1 Historical gas supplies
Approximately 93.0% of the ROI gas demand was
supplied from GB gas imports through the Moffat
entry point in south-west Scotland during 2009/10. The
remaining 7.0% of 2009/10 ROI gas demand was supplied
from Celtic Sea production and storage gas through the
Inch entry point.
Moffat gas was also supplied through the Inch entry
point to help refill the Kinsale storage facility during the
summer (supplementing the offshore production). The
historical indigenous gas production is shown in Fig. 4.1,
together with GB imports.
Fig. 4.1: Historical annual indigenous (IND) gas production
and GB imports
Supplies (kTOE/year)
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
1990
1992
1994
Sources of ROI gas supplies
1996
1998
2000
2002
2004
2006
2008
The peak-day and annual entry supplies through Moffat
and Inch are shown in Table 4.1. It can be seen that gas
supplies through the Inch entry point made a bigger
contribution to the peak-day demand compared to
annual demand (supplying 13.8% of the ROI peak-day in
2009/10 compared to 7.0% of annual demand), due to the
operation of Kinsale storage.
IND
GB
Table 4.1: Historical peak-day and annual supplies through Moffat and Inch
2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10
(GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh)
Peak-day
Moffat 2 190.2 169.5 175.8 197.7 234.5 245.6 251.4 292.5
Inch 41.1 60.9 46.8 40.6 43.6 40.0 35.6 34.8
Total 231.2 230.4 222.6 238.3 278.1 285.6 287.0 327.3
Annual
Moffat 2 53,221 51,982 56,890 64,023 69,236 72,645 70,446 73,843
Inch 6,637 9,705 6,397 5,451 4,976 4,772 4,259 4,128
Total 59,858 61,687 63,287 69,474 74,212 77,417 74,705 77,971
1
Daily supply data taken from Gas Transportation Management System (GTMS)
2
Table shows total Moffat supplies including supplies to ROI, NI and IOM
18

NETWORK DEVELOPMENT STATEMENT
4.2 Future gas supply outlook
4.2.1 General overview
In the short-term the majority of the ROI gas demand will
continue to be met from GB imports through the Moffat
entry point. It is likely to change significantly from 2013/14
onwards, with a number of new gas supply projects at
various stages of completion:
• The Corrib gas field off the Mayo coast is expected to
commence commercial production in late summer 2013.
• Shannon LNG has received all the relevant permits and
licences required to develop a LNG terminal on the river
Shannon, near Ballylongford in Co. Kerry.
• Islandmagee Storage and North East Storage are
separately looking into the commercial feasibility of
developing salt-cavity storage near Larne in NI.
• PSE Kinsale Energy are investigating the commercial
feasibility of developing further gas assets in the
Celtic Sea.
4.2.2 Corrib Gas
The Corrib gas field, located 83 km off the coast of Mayo,
will be the main source of future indigenously produced
gas. The project’s final stage, involves the construction of a
9 km pipeline between land-fall at Glenagad and the gas
processing terminal at Bellanaboy.
The Corrib developers have recently received the final
planning consents and permits from An Bord Pleanala, the
DCENR and the Department of the Environment, allowing
the developers to proceed with the construction of the
final stage of the onshore pipeline.
This pipeline will be routed through Sruwaddacon Bay,
and will involve building a tunnel under the bay to lay
the pipeline in. Based on the current construction and
commissioning schedule, the Corrib field operators have
indicated that the first commercial production of Corrib gas
will take place in July/August 2013.
Fig. 4.2: Glengad (Landfall) to Bellanaboy Terminal
Pipeline Route
Source: Shell E&P Ireland Ltd
For planning purposes the NDS forecast assumes first
commercial production from October 2013. The impact
of a 1 year delay is also assessed, in the event of the
construction period for the 9 km pipeline between
Glengad and Bellanaboy taking longer than assumed.
4.2.3 Shannon LNG
Shannon LNG has received planning permission for both its
proposed LNG terminal near Ballylongford in Co. Kerry, and
for the associated transmission pipeline that will deliver
the gas into the ROI transmission system. Shannon LNG has
indicated that the terminal will be developed on a phased
basis:
• Phase I will involve the construction of LNG storage
tanks, and re-gasification facilities with a maximum
export capacity of up to 127.0 GWh/d (11.3 mscm/d).
• The LNG terminal has been designed to accommodate
two additional expansion phases at a later date. The
maximum send out for the two subsequent phases are
noted as 191.1 GWh/d (17.0 mscm/d) and 314.7 GWh/d
(28.3 mscm/d).
19

4. Gas Supply Outlook continued
Shannon LNG received a TPA exemption from the CER
in November 2010. However this exemption was made
subject to a formal market test regarding Phase III capacity
at the proposed terminal. This market test is being currently
progressed by Shannon LNG, with the results expected in
mid 2011.
Fig. 4.3: Corrib Gas Field, Pipeline and Terminal
Shannon LNG have recently indicated they cannot provide a
likely start date for commercial operation of the LNG facility.
However, at the time of modelling for the NDS, in Q4 2010,
Shannon LNG facility was assumed to commence commercial
operation from 2016/17, based on consultation with the
developer. This is reflected in the network modelling, detailed in
chapter 6.
4.2.4 Larne Storage
There are currently two separate salt-cavity gas storage projects
being proposed for the Larne area in NI, by Islandmagee
Storage and North East Storage respectively. Both projects
are looking into the commercial feasibility of developing gas
storage in the salt-layers that run underneath the Larne area:
• Islandmagee Storage is a consortium of Infastrata plc and
Mutual Energy Ltd, and is looking to develop a 5,514 GWh
(500 mscm) salt-cavity gas storage facility underneath Larne
Lough, with a maximum withdrawal rate of 243 GWh/d
(22.0 mscm/d) and injection rate of 132 GWh/d (12.0
mscm/d).
• North East Storage is a consortium of Bord Gáis Energy and
Storengy (a GDF-Suez company), is looking to develop a
3,308 GWh (300 mscm) storage facility near Larne, with
maximum withdrawal and injection rates of 165-221
GWh/d (15-20 mscm/d) and 66-88 GWh/d (6-8 mscm/d)
Source: Shell E&P Ireland Ltd
Fig. 4.4: An LNG tanker transporting LNG to an LNG
regasification terminal
Source: Shannon LNG
respectively. North East Storage completed seismic testing in early 2010,
and will undertake a test drill in early 2011, with the results
expected in the 3rd quarter of 2011. Pending the outcome of
the test drill results, the storage developers have indicated a
planning submission will be made in 2012. North East Storage
has indicated 2016/17 as a likely start date for commercial
operation.
20

NETWORK DEVELOPMENT STATEMENT
Islandmagee completed seismic testing in late 2007, and
subsequently submitted a full planning application to the NI
authorities in March 2010. The Islandmagee storage developers
have indicated 2015/16 as a possible start date for commercial
operation.
Fig. 4.5: Inch Terminal, East Cork
For the purpose of the NDS, a generic salt cavity storage facility
in the Larne area has been modelled based on the flow and
volume parameters associated with the proposed Islandmagee
facility. This assumption reflects no bias to either of the two
projects, and is been utilised for modelling purposes, as it
represents the larger of the two projects, therefore constitutes
the greater stress on the transmission systems in Ireland and
Northern Ireland.
4.2.5 Celtic Sea gas storage
The existing Kinsale storage facility is Ireland’s first and only
offshore gas storage facility, which was developed and is
operated by PSE Kinsale Energy. It currently has a working
volume of c. 230 mscm, with a maximum withdrawal and
injection rate of 2.6 mscm/d and 1.7 mscm/d respectively. This
storage facility connects to the BGÉ transmission system at Inch.
PSE Kinsale Energy is investigating the commercial feasibility of
expanding its storage capacity by both increasing the storage
capacity of the Southwest Kinsale facility. The new expanded
storage facility would result in a total working volume of 400
mscm to 900 mscm, with a withdrawal and injection rate
ranging from 5 mscm/d to 12 mscm/d and 4 mscm/d to 8
mscm/d respectively.
Kinsale Energy has indicated, as Celtic Sea gas production is
gradually declining, the existing storage operations will not
be economic on a standalone basis. In the event of no further
development, it is possible that existing storage operations
may cease in the next 2 to 3 years, followed by a cessation of
operations about two years thereafter.
Source: PSE Kinsale Energy
4.2.6 Other Supply Developments
San Leon Energy has a number of exploration operations off
the West coast of Ireland, located in the Porcupine, Rockall and
Slyne basins on the Atlantic margin. They recently expanded
their operations into the Celtic Sea, through the acquisition of
Island Oil and Gas during 2010.
Providence resources are currently investigating the
development of a gas storage facility, Ulysses, in the Kish
Bank Basin offshore from Dublin in the Celtic Sea. Providence
Resources recently announced, results from initial concept
studies indicating the project is both economically and
technically feasible, and are currently progressing further
studies.
There is currently no firm data regarding these projects,
therefore, they have been omitted in the NDS forecast. This
situation will continue to be kept under review for future NDS
publications.
21

5. The ROI Transmission System
5.1 Overview of the existing ROI gas network
The ROI gas network consists of approximately
12,923kms of high-pressure steel transmission pipeline
and lower pressure polyethylene distribution pipelines,
Above Ground Installations (AGIs), District Regulating
Installations (DRIs) and compressor stations in the ROI
and Scotland. The integrated supply system is sub-divided
into 2,147kms of high pressure sub-sea & cross country
transmission pipes and approximately 10,776kms of lower
pressure distribution pipes. The distribution network
operates in two tiers; a medium pressure and a low
pressure network. The high-level system statistics are
summarised in Tables 5.1 and 5.2 and shown in Figure 5.1.
The ROI transmission system includes the IC system and
the onshore ROI system. The IC system includes two
subsea Interconnectors to Scotland; two compressor
stations at Beattock and Brighouse Bay, and the 110-km
of onshore pipeline between Brighouse and Moffat in
Scotland.
The IC system connects the onshore ROI system to the
GB National Transmission System (NTS) at Moffat in
Scotland. It also supplies gas to the NI market from
Twynholm and to the IOM market from IC2. The IC
system is also used to provide a gas inventory service
to ROI shippers (see Fig. 5.1)
The onshore ROI system consists of a ring-main
system between Dublin, Galway and Limerick, with
cross-country pipelines running from the ring-main
system to Cork, Limerick, Waterford, Dundalk and the
Corrib Bellanaboy terminal in Mayo. It also includes a
compressor station at Midleton.
Table 5.1: ROI Pipeline summary statistics
Location Current Max
MOP* Total Nominal Pipe
Pressure Length Diameter
(bar-g) (km) (mm)
Onshore ROI 85.0 160.9 650
Onshore ROI 1 75.0 60.1 450
Onshore ROI 70.0 1,132.9 900
Onshore ROI 40.0 91.6 500
Onshore ROI 2 37.5 14.6 600
Onshore ROI 3 19.0 152.0 600
Onshore ROI 7.0/4.0 15.8 600
Subtotal N/A 1,627.9 N/A
Scotland 85.0 109.9 900
Subsea 148.0 409.0 750
Total Tx N/A 2,146.8 N/A
Onshore Ireland Dx >100mBar 6,395.4 315
Onshore Ireland Dx

NETWORK DEVELOPMENT STATEMENT
Fig. 5.1: Overview of the ROI transmission system
Corrib
Gas Field
Derry City
Pwr Station
Coleraine
Ballymone
Limavady
Ballymena
Antrim
Lurgan
Craigavon
Portadown
Armagh
Banbridge
Scotland
Twynholm AGI
Ballina
Newry
Castlebar
Crossmolina
Knock
Lough Egish
Carrickmacross
Dundalk
Isle of Man
Bailieborough Kingscourt
Westport
Ballyhaunis
Virginia
Ballinrobe Claremorris
Kells Navan Drogheda
Trim
Headford
Mullingar
Tuam
Gormanston
Athlone
Athenry
Loughshinny
Enfield
Abbotstown
Kilcock Dublin
Galway
Ballinasloe Prosperous
Tullamore
Naas
5 Pwr Stations
Tynagh Portarlington Kildare Brownsbarn
Craughwell Pwr Station
Monasterevin
Bray
Loughrea
Gort
Portlaoise
Kilcullen
Wicklow
Ennis Sixmilebridge
Athy
Ballina Ballyragget
Carlow
Shannon
Arklow
Limerick
Tarbert
Cashel
Askeaton
Tipperary town
Aughinish
Kilkenny
Existing Pipelines
Pwr Station
Cahir
Planned Pipelines
Charleville
Carrick-on-Suir
Mitchelstown
Waterford
Mallow
Ardfinnan
Proposed Pipelines
Great Island
Fermoy
Tramore
Innishannon Cork
Pipelines Owned by Others
Midleton Compressor
Bandon
Ballineen
2 Pwr Stations
City
Kinsale
Lehenaghmore
Inch Entry Point
Town
Kinsale Head Gas Field
Seven Heads Gas Field
Belfast
S.N.I.P.
Interconnector 2
Interconnector 1
Town (proposed)
Entry Points
City Gate Entry Points
Landfall Station
Power Station
Moffat
Entry Point
Beattock Compressor
Brighouse
Bay
Compressor
Pwr Station
23

5. The ROI Transmission System continued
5.2 New connections and New Towns
Various projects were completed during the course of 2009/10,
which will facilitate the connection of various large I/C sites and
new towns to the gas transmission and distribution systems.
The list of projects completed during 2009/10 includes:
• The connection of the following towns from the New Towns
Review (Phase II): Gort and Loughrea.
• Planning and front-end engineering works commenced
on the proposed Endesa gas-fired station at Great Island
with construction planned to commence during the first
half of 2012.
A number of new connections and new town projects are
planned for 2010/11 gas year, including:
• The connection of the following town from the New Towns
Review (Phase II): Cahir.
• The following towns will be connected under the New
Towns Review (Phase III): Kinsale, Innishannon and Macroom
(Brinny AGI), Kells (Burrencarragh AGI), Tipperary Town
(Raheen AGI).
5.3 System Reinforcement
It is necessary from time to time to reinforce the existing gas
transmission to facilitate local development etc. Reinforcement
projects that were either completed during 2009/10 (or are in
the final phases of commissioning) include:
• Completion of the new 24” Curraleigh West to Midleton
pipeline and the associated Midleton to Lochcarrig Lodge
pipeline, these pipelines were commissioned during latter
end of 2010.
• Substantial completion of capacity upgrades to Glebe West
AGI (Blessington), Loughboy AGI (Kilkenny), Nessans Road
AGI (Limerick) and Ballinacurra Bridge AGI (Limerick).
• Volume control was installed in Midleton compressor station
to increase the operating envelope of the turbo compressor
units to accommodate the recent pipeline reconfiguration in
the Cork area.
• A bypass system was installed in Brighouse Bay compressor
station connecting the Onshore IC1 system to subsea IC2
to allow a complete bypass of Brighouse Bay compressor
station.
The twinning of the Curraleigh West to Midleton Pipeline and
the construction of the associated Lochcarrig Lodge to Midleton
Pipeline has transferred the Cork area transmission system to
the discharge side of Midleton compressor station. This has
brought significant benefits in terms of enhanced pressures to
the customers connected to the system.
24

NETWORK DEVELOPMENT STATEMENT
The old Aghada power station and the Whitegate and Long
Point AGIs remain connected to the transmission system
between Midleton compressor station and the Inch Entry Point.
Any Inch gas in excess of these demands will be compressed at
Midleton into the 70-bar system in the Cork area.
Fig. 5.2: River Suir Estuary crossing & Waterford/
Rosslare railway line
The upgrades to Hollybrook AGI and Loughshinny AGI are
scheduled to be completed in 2011. Further capacity upgrades
have been identified and are scheduled to commence detailed
design in early 2011.
A volume control system is to be installed in Beattock
compressor station in 2011 in anticipation of Corrib flows and
higher suction pressures from National Grid.
11kms of reinforcement to the distribution network was
carried out during 2010. One of the more significant projects
completed last year was the trenchless crossing of the River
Suir Estuary and the Waterford / Rosslare railway. The crossing
was just under 0.6 km in length and the pipeline was laid
approximately 45 metres below the river. The polythleyne (PE)
pipe was constructed of SDR 9 material with a wall thickness
of 38 mm and the pipeline operates at a design pressure of 4
bar. The pipeline was required to reinforce the network on the
northside of Waterford City and parts of south Kilkenny.
The pipeline had been the subject of detailed design and
engineering analysis which commenced in July 2008 and
identified the most advantageous option of crossing the
River Suir east of Rice Bridge in the city. A number of other
construction techniques were investigated, from micro
tunnelling, thrust boring, and open cut techniques.
25

5. The ROI Transmission System continued
The selection criteria for the crossing included but was not
limited to the following:
• Health and safety.
• Proximity to centres of population and future developments.
• Environmental issues minimising impacts on wildlife, habitats
and environmentally designated areas such as:
- Special Areas of Conservation (SAC).
- Special Protection Areas (SPA).
- Natural Heritage Areas (NHA).
• Impacts on archaeology and cultural heritage.
• Cost.
• Minimising visual impact.
• Pipeline design and operation.
• Minimising construction impacts.
• Minimising pipeline length.
Fig. 5.3: 250 tonne rig to drive the drill motor
Once the drilling was completed the PE pipe was pulled
into position beneath the river bed over a period of 24 / 48
hours. The pipeline then underwent further testing before
commissioning of the pipeline and connecting into the existing
network on the Waterford side of the river. Phase 2 of the
project consisted of laying 2.7 km of 250 mm PE100 SDR17
mains reinforcement from the Horizontal Directional Drill (HDD)
to the New Ross Road on the Kilkenny side and from the HDD
to the Inner Ring Road on the Waterford City side.
Fig. 5.4: 17 ¼” Pilot, used to drill the profile
26

NETWORK DEVELOPMENT STATEMENT
5.4 System Refurbishment
There is a continuous programme to review and refurbish the
gas transmission system, to ensure that it continues to comply
with all of the relevant legislation, technical standards and
Codes of Practice. This refurbishment work is coordinated with
reinforcement work (where possible), to minimise overall costs
and to limit disturbance to local communities.
Increases in population density in the vicinity of transmission
pipelines may require preventative measures to be taken such
as the diversion of pipelines, the provision of impact protection
and the installation of “heavy-wall” pipe. The following
refurbishment and diversion projects were undertaken during
2009/10:
• The Dublin-4 pipeline replacement project is progressing
well – the project is a 2 year build and is expected to be
completed in 2010/11.
• A remotely actuated emergency bypass was installed around
Midleton compressor station for the purposes of supplying
the 30 barg Cork network in the event of a failure of the
MCS Pressure Reduction System.
• Completion of Kilshane block valve refurbishment.
The following transmission system refurbishment and diversion
projects are planned for the 2010/11 gas year:
• Detailed integrity and capacity assessments have been
carried out on the Limerick 19 barg network which has
identified the need to refurbish and reinforce the network.
Preliminary engineering is progressing with a view to
construction commencing next year.
• Santry to Eastwall pipeline replacement project; Optimal
solution for the refurbishment of the 6.5kms Santry –
Eastwall pipeline is being progressed.
• Waterford pipeline replacement project; Optimal solution for
the refurbishment of the 4.5kms Waterford City pipeline is
being progressed.
• 4 diversions are required to facilitate the M20 Cork to
Limerick motorway. The 1st of these diversions, on the 6”
pipeline near Mallow Hospital is due to be carried out this
year with the remaining 3 diversions to follow.
27

6. Network Analysis
Fig. 6.1: Total system demand peak day forecasts
Peak Day 1-in-50 Forecast Comparison
300
290
280
270
260
250
240
230
220
210
200
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/20
NDS 2010/11 JGCS 2010 TDS 2009/10
6.1 Overview of Network Analysis
Network analysis is undertaken to determine the
adequacy of the existing gas network to transport the
required levels of gas for a forecast period of ten years,
under a number of supply scenarios. Three demand type
days are analysed for each supply scenario over a ten year
period, from 2010/11 to 2019/20 inclusive, to assess the
system on days of different demand profile:
• Severe 1-in-50 winter peak.
• Average year winter peak.
• Average year summer minimum.
Fig. 6.1 illustrates the strong correlation between
1-in-50 peak day demand forecasts generated for this
publication, the 2009/10 TDS and the 2010 Joint Gas
Capacity Statement. The assumptions surrounding the
future gas supply projects on the Island remain relatively
unchanged from last year. On this basis, the results and
conclusions detailed in this chapter, are representative of
the results and conclusions from the analysis completed
for last year’s TDS and the 2010 Joint Gas Capacity
Statement.
These demand days, which are generated from the
gas demand forecast, investigate the capability of the
existing infrastructure to cater for the various supply/
demand scenarios, including injection and withdrawal
to/from storage.
28

NETWORK DEVELOPMENT STATEMENT
Table 5.1: Entry point assumptions
Unit Moffat Inch Corrib Shannon Larne
Pressure
Contractual barg 42.5 30.0 up to 85.0 N/A N/A
Assumed barg 47.0 30.0 up to 85.0 up to MOP up to 85.0
Other
GCV MJ/scm 39.7 37.6 37.5 40.5 39.7
Flow profile Flat Flat Flat Flat Flat
6.2 The Network Model
Network analysis involves constructing a single hydraulic
model of the ROI and NI and SWSOS transmission systems
in Pipeline Studio ® software. This software is configured
to analyse the transient 24 hour demand cycle over a
minimum period of 3 days to obtain consistent steady
results, for each of the ten years, under a number of
supply scenarios. The results from the network modelling
are validated against a series of boundary conditions,
establishing if there are locations on the network with
insufficient capacity to transport the necessary gas. The
boundary conditions are defined as follows:
• Maintaining the specified minimum and maximum
operating pressures at key points on the transmission
systems, including:
- Minimum of 55 barg at the Dublin city gates.
- Minimum of 56 barg at the inlet to Twynholm.
- Not to exceed the Maximum Operating Pressure
(MOP) of the onshore transmission systems, currently
70 barg in Ireland and 75 barg in NI.
• Ensuring gas velocities do not exceed their design limit
of 10 – 12 m/s.
• Operating the compressor stations within their
performance envelopes.
6.3 Entry Point Assumptions
The main assumptions regarding the entry (supply) points
included in the network modelling are summarised in the
above table;
As per the existing Pressure Maintenance Agreement
(PMA), National Grid is required to provide gas at a
minimum pressure of 42.5 barg at Moffat. They have also
advised a higher Anticipated Normal Off-take Pressure
(ANOP) pressure for Moffat of 47 barg (i.e. the expected
pressure under normal circumstances). The ANOP pressure
has been used in the network modelling for the 1-in-50
peak day analysis.
A minimum pressure of 30 barg is provided at Inch, and
the Corrib Operator is required to provide up to 85 barg
at Bellanaboy. No contractual arrangements have been
discussed with Shannon LNG, but it is assumed that they
will be able to deliver up to the Maximum Operating
Pressure (MOP) of the ring-main.
Similarly no contractual arrangements have been agreed
with either of the proposed Larne gas storage projects;
however, it is assumed that they will be able to deliver gas
at 85 barg. This higher pressure is considered necessary to
make these storage projects viable. It also assumes that
the MOP of the NI transmission system can be raised from
75 to 85 barg.
29

6. Network Analysis continued
6.3.1 Future review of Moffat entry point assumptions
To date a 1-in-50 peak day peak day source pressure of 47.0
barg has been assumed for network modelling purposes. This
assumption was validated by actual pressures on the peak days
that occurred in early January 2010, when hourly pressures at
Moffat ranged between 50.0 and 56.7 barg, averaging at 54.4
barg for the day. However, during the peak demand period
in December 2010 lower daily average pressures approaching
47.0 barg were observed on occasion.
Gaslink are currently engaging with National Grid regarding
the contractual and ANOP pressures at Moffat. Subject to
the outcome of these discussions, certain future network
modelling scenarios may adopt the contractual minimum
pressure at Moffat of 42.5 barg.
Also, the assumption recording the flat flow profile at Moffat
maybe revised to reflect the actual flow profiles that occurred
on the record peak days during the severe weather periods in
2010. Adopting actual peak day flow profiles in the network
modelling will better identify any reinforcement requirement to
the SWSOS.
6.4 System Configuration
Under the current configuration, the Irish and Northern Ireland
transmission systems are physically separated at Gormanston,
and operate as two separate markets.
For certain years included in the analysis, due to the availability
of multiple supply sources on the Island, there is a requirement
to transfer surplus gas between the two jurisdictions. For these
relevant years, it is assumed the necessary infrastructural,
operational, commercial and market arrangements are in place,
under the CAG (Common Arrangements for Gas) project, to
facilitate the option of inter-jurisdictional flows between the
North and South.
6.5 Summary of Modelling Results
6.5.1 Overall Results
The network analysis results indicate that there is sufficient
capacity available on the existing onshore ROI transmission
system to transport the necessary gas to meet the required
forecast peak-day demand over the forecast period; however,
this conclusion is subject to a number of restrictions depending
on timing of the new gas supply sources and the balance of
supply between these various new supply sources. Should
these restrictions be considered unacceptable, then system
reinforcement would be required.
There are a number of scenarios where the existing network
cannot simultaneously accommodate the proposed maximum
flows from all of the assumed supply sources for a number of
reasons;
• The combined maximum flow from all of the proposed new
supply sources on the Island exceeds the forecast peak day
demand of the ROI and NI markets, i.e. there is insufficient
demand to absorb the total supply.
• There are a number of physical constraints regarding the
transportation of large volumes of gas from the west coast
(Corrib and Shannon LNG) and/or the south coast (Inch),
to the majority of the demand on the east coast, while
maintaining system pressure requirements.
Gas supplies entering the ROI ring-main in the west and south
are restricted to the system’s maximum operating pressure of 70
barg, while a minimum pressure of 55 barg is required at Dublin
city gates. Increasing the flow of gas from the west and/or
south to the east, increases the pressure drop across the system,
eventually resulting in maximum and/or minimum pressure
requirements being breached.
• The maximum withdrawal rate of Larne storage
is potentially limited by the NI peak day demand.
Modifications would be required to the existing
transmission system to physically export gas to the ROI.
30

NETWORK DEVELOPMENT STATEMENT
Fig. 6.2: Corrib Sensitivity - 1 year delay and no Inch supply after 2012/13
Demand/Supply (GWh/d)
500
450
400
350
300
250
200
150
100
50
0
Peak Day 1-in-50 Demand & Supply
2010/11
2011/12
2012/13
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/20
Inch Corrib Moffat Peak Demand
Indigenous gas supplies (Corrib and Inch production) are
assumed to dispatch ahead of all other supply sources. It should
be noted; this assumption has been applied solely for demand/
supply and network modelling purposes. The actual orders in
which supplies will be dispatched will be determined by shipper
nominations and commercial arrangements between the
shippers and suppliers at the various entry points.
A slightly different approach has been adopted in presenting
the modelling results and conclusions for this year’s NDS. This
year’s statement presents the results by supply source, rather
than the previous format of supply scenario.
6.5.2 Corrib
Corrib supply is assumed to be available from 2013/14,
providing up to 103 GWh/d (10 mscm/d) for the first three
years, and then slowly declining from 2016/17 onwards.
A sensitivity has also been included in the analysis to assess
the impact of a 1 year delay to the Corrib project, with first
gas assumed in 2014/15. This sensitivity also excludes Inch
supply, in the event Celtic Sea storage operations cease (or are
unavailable) during this period.
As illustrated in fig. 6.2, Moffat supply is required to meet all of
the forecast peak day demand in 2013/14, resulting in capacity
limits at Beattock and Brighouse Bay compressor station being
reached.
It should be noted the capacity of Beattock compressor
station, 353 GWh/d (32 mscm/d), is based on ANOP of 47
barg (and the station operating in ‘Series’ mode). If a lower
pressure is assumed the capacity of the station reduces, e.g. if
the contractual (PMA) pressure of 42.5 barg is assumed, the
capacity of the station reduces to 302 GWh/d (27.4 mscm/d).
The NDS assumes Corrib supply is fully available on the
respective days analysed in the network analysis. However, the
risk of an outage is inherent with any piece of infrastructure.
On this basis, future network analysis may consider a sensitivity
scenario analysing the impact of an outage to Corrib supply.
The inclusion of this sensitivity would not suggest or reflect the
likelihood of a supply outage at Corrib.
31

6. Network Analysis continued
6.5.3 Inch Supply
Under the existing network configuration the maximum volume
of gas that can be transported from the Inch entry point is
determined by the capacity of Midleton compressor station,
6 mscmd/d, and demand from the Cork area (upstream of
Midleton compressor station).
If gas supply from the Inch entry point was to significantly
increase on current levels, due to further developments in the
Celtic Sea, there would need to be a number of modifications
to the existing infrastructure;
• The existing pipeline between Inch and Midleton compressor
station would need to be up-rated if supply pressures at Inch
were to exceed the current MOP of this pipeline, 37.5 barg.
• Midleton compressor station would need to be upgraded
to accommodate flows in excess of its current capacity.
Alternatively, if compression is relocated to Inch entry point,
there is the possibility of Midleton compressor station being
bypassed.
It must be emphasised, considerable detailed engineering
studies would need to be undertaken to determine the
feasibility and optimum approach to such modifications.
Assuming this work could be completed in the event of
increased Celtic Sea supplies, the volume of gas that can be
transported from Inch then depends primarily on two factors;
• Cork area demand.
• The volume of gas that can be exported into the Ring-Main
at Curraleigh West.
6.5.3.1 Cork Area Demand
Cork area gas demand impacts on the volume of gas that can
be transported from Inch. An increase in Cork area demand
allows for an increase in Inch supply.
6.5.3.2 Exports into the Ring-Main at Curraleigh West
Curraleigh West is the point on the network, where the Ring-
Main and Cork spur connect. The volume of Inch gas that can
flow into the Ring-Main at Curraleigh West depends on;
• Pressure at Curraleigh West.
• Level of west coast supplies.
• Ensuring the minimum pressure of 55 barg at Dublin city
gates is not breached.
The volume of Inch gas that can be exported into the Ring-
Main, depends on the pressures at Curraleigh West; higher
pressures (below the MOP) imply higher volumes. Any change
to the location of compression between Inch and Curraleigh
West, will impact on pressures at Curraleigh West, and
consequently supply volumes from Inch.
Network analysis also highlighted a significant pressure drop in
the 16” pipeline between Curraleigh West and Goatisland. This
section of pipeline is the limiting restriction on the ring-main
with respect to its diameter, and is consequently a ‘bottleneck’
for high flows. Twinning this pipeline will remove this
‘bottleneck’ and consequently increase the volume of gas that
can flow west at Curraleigh West. The twinning of this pipeline
also benefits the west to east transfer limit (see section 6.5.5.2).
6.5.3.3 Injections to Celtic Sea gas storage
Gas is injected into storage during the summer months through
Inch, which is effectively acting as an exit point on the network
for this period.
The volume of gas the can be transported to Inch for injection
into storage is potentially restricted by the volume of gas that
can flow south from Curraleigh West less Cork area demand.
Any increase in Cork area demand will reduce the volume of
gas that can be transported to Inch for injection into storage.
32

NETWORK DEVELOPMENT STATEMENT
When Inch is acting as an exit point, pressures at Curraleigh
West are dictated by pressures at Shannon LNG or Corrib, or
in the absence of these supplies, pressures at the ICs landfall in
North Dublin. Higher pressure at Curraleigh West increases the
flow potential to the south.
West coast gas supplies supports/increases the volume of gas
that can flow south at Curraleigh West, and consequently the
volume of gas that can be transported to Inch for injection into
storage.
Network analysis also highlighted significant pressure drops
across the Goatisland to Curraleigh West pipeline. Twinning
this pipeline, result in higher pressures at Curraleigh West and
consequently will increase the volumes of gas that can flow
south to Inch.
6.5.3.4 Minimum flows through Midleton Compressor Station
The level of Celtic Sea production gas has been declining in
recent years and may fall below the minimum design-flow
criteria of Midleton compressor units in certain scenarios.
Gaslink are currently engaging with the Inch operator regarding
the transportation of smaller volumes of gas, and further
analysis will be required.
It should also be noted, in the event of existing Celtic Sea
assets ceasing operation in the future, PSE Kinsale Energy
and Gaslink would need to investigate any potential issues
which may arise with the transportation of gas during the
decommissioning phase.
It is envisaged that the Inch connection agreement will be
reviewed and amended as necessary.
6.5.4 Larne Supply
The maximum volume of gas that can be withdrawn from
Larne storage, is limited by
• NI peak day demand.
• The volume of gas which the existing transmission system
can transport to the ROI via the SNP and SNIP pipelines.
It was assumed in the analysis undertaken for Larne that the
existing NI transmission system could be upgraded to 85 barg,
and the onshore Scotland system could be configured to
accommodate reverse flows from SNIP. It must be emphasised,
considerable detailed engineering studies would need to be
undertaken to determine the feasibility of these assumptions.
Analysis indicates that under certain conditions, it is feasible to
withdraw up to 22 mscm/d from Larne storage, when NI peak
day demand is approximately 10 mscm/d.
6.5.4.1 Exporting Larne Gas to the ROI
The requirement to maintain a minimum pressure of 55 barg
at Dublin city gates combined with the demand profiles in NI
and on the SNP will determine the capacity available for gas
to flow via the SNP into the Irish market. Analysis indicates
approximately up to 4 mscm/d of Larne gas can be exported to
the ROI via the SNP, under certain conditions.
Depending on the flow requirement, the assumed available
pressure from Moffat and the need to maintain a minimum
pressure lift across Beattock compressor station will determine
the maximum reverse flow capability at Twynholm, whilst
maintaining the minimum inlet pressure of 52 barg at Brighouse
Bay. Analysis indicates up to 8.5 mscm/d can be exported to the
ROI via the SNIP and subsea ICs, under certain conditions.
33

6. Network Analysis continued
6.5.4.2 Injecting gas into Larne Storage
The volume of gas that can be injected into Larne storage is
restricted by the volume of gas that can be imported via the
SNP and SNIP less NI demand
The volume of gas that can be imported through the SNP
partly depends on the pressure available at the southern end of
the pipeline. Higher pressures imply a higher import capacity.
Pressures can range from 55 barg to 85 barg, depending on
supply conditions in the ROI. 85 barg would be available if the
subsea IC system was supplying the gas, however, if there was
no interconnector supply, supply pressure would be equal to
Dublin area pressures, which may be 55 barg, depending on
the daily demand profile.
SNIP capacity is restricted to the capacity available at Tywnholm.
Under existing contractual arrangements, this capacity is 8.08
mscm/d. Analysis has indicated if this restriction is removed
(with Twynholm modified/bypassed), and depending on onshore
Scotland conditions, flows up to 11.5 mscm/d may be
feasible.
Analysis indicates based on the above, injection rates can vary
between 6.0 mscm/d and 8.5 mscm/d.
6.5.5 Shannon Supply
6.5.5.1 West coast to east coast transfer limit
There is a physical limit to the quantity of gas that can be
transported from the west to the east coast while maintaining
the ring-main’s maximum operating pressure of 70 barg and
the minimum pressure requirement of 55 barg at Dublin city
gates. This implies a restriction on the volume of gas that can
supplied from west coast supply sources.
Previous statements have indicated this restriction is
approximately 210 GWh/d (18.6 mscm/d) assuming no supply
from Inch, reducing to 192 GWh/d (17.0 mscm/d) if current
Inch supply levels are included. An increase in Inch supply on
current levels would further reduce this limit.
It should be emphasised that these limits are subject to forecast
demands and assumed demand profiles. Also, an increase in
local west coast demand will result in an increase in these limits,
and equally, a decrease in local demand reduces the limit.
6.5.5.2 Shannon LNG development phases
Shannon LNG has indicated the intention to develop the LNG
facility on a phased basis. Only phase I with a supply capacity of
11.3 mscm/d applies to the review period in the NDS, with first
commercial production assumed from 2016/17.
34

NETWORK DEVELOPMENT STATEMENT
Fig. 6.3: West coast gas supply and west coast transfers limits
West Coast Peak Day gas flows & Transfer Limits
200
150
Supply (GWh/d)
100
50
0
2013/14
2014/15
2015/16
2016/17
2017/18
2018/19
2019/20
Corrib Shannon Transfer Limit (with Inch Supply) Transfer Limit (no Inch Supply)
Fig. 6.3 illustrates the requirement to restrict west coast gas
supplies for years 2016/17 to 2017/18, with the level of
restriction depending on the level of Inch supply.
The existing network has the ability to accommodate the
supply volume associated with phase II, 17.0 mscm/d,
providing its timing coincides with the expiry of Corrib, and
Inch supplies do not exceed current levels.
Even in the absence of Corrib and Inch supply, the existing
network would not be able to accommodate the supply volume
of 28.3 mscm/d associated with phase III, without significant
reinforcement.
Preliminary analysis indicates twinning the existing Goatisland to
Curraleigh West pipeline will increase the west to east transfer
limit. In addition to this,
up-rating the western section of the ring-main (Pipeline to the
West (PTTW)) from 70 barg to 85 barg (MOP review required
to confirm if this is possible) would further increase the west to
east coast limit.
6.6 Physical Exports to GB
6.6.1 Overview
Depending on the timing of the proposed supply projects
on the Island, the assumed maximum flows from the various
supply sources may exceed the combined demand of the ROI,
NI and IOM, even during severe weather conditions.
If such a scenario arises, the relevant producers and storage
operators may wish to physically export the surplus supply from
Ireland to GB.
6.6.2 Infrastructural Requirements
In order for gas to flow from Ireland into Great Britain, it needs
to leave the island. Therefore it first needs to get to one of
three beach stations, namely, Loughshinny, Gormanston or
Ballylumford (NI). Any additional infrastructure that may be
necessary to get the gas to the beach is primarily dependant on
the supply location, volume & pressure.
35

6. Network Analysis continued
The ability to physically export gas from the ROI supply sources
in the west (Corrib and Shannon) and south (Inch) depends on;
• The physical capacity of the ROI transmission system to
transport the gas to Loughshinny and Gormanston on the
east coast.
• Suitable pressures at Loughshinny and Gormanston to
transport the gas through the sub-sea inter-connector
system to Brighouse Bay in south west Scotland.
This would require significant reinforcement to the existing
on-shore ROI transmission system, in order to transport
the gas from the west and south coast to the east coast. In
addition to this, a new compressor station would be required
on the PTTW near Ballough in Co. Dublin, to provide the
required pressure for transporting the gas through the subsea
interconnector system to Scotland. Modifications would
also be required at Brighouse Bay and Beattock compressor
stations in order to enable bi-directional flow.
The Larne facilities may have an advantage in so far as they are
relatively close to Ballylumford and any associated compression
facilities may be utilised for export through the SNIP. However,
raising the SNIP operating pressure from 75 to 85 barg and the
modifications to Beattock compressor station, to facilitate bidirectional
flow, would also be required for Larne exports.
In addition to the above, National Grid (NG) maybe required
to complete modifications at Moffat to facilitate bi-directional
flows.
Twinning the Cluden to Brighouse Bay pipeline would allow
for significant operational flexibility of the Scottish system,
and consequently enhance the systems ability to facilitate the
physical export of gas to GB.
It must be emphasised the above conclusions are indicative and
are based on high level conceptual studies. Significant detailed
engineering studies would be required to determine the
feasibility and cost associated with such a project.
6.6.3 Gas Quality Issues and National Grid (NG)
requirements
Moffat is currently classified as an exit point on the NG NTS.
In order for Moffat to be classified as an Entry point, the
physical connection arrangements and the gas composition
requirements would need to be agreed with NG.
The principal difference between Ireland’s transmission system
and the NG transmission system is Ireland’s transmission system
is odourised, whereas NG system is odourless. In GB odour is
added to the gas at the point of entry to distribution networks
(LDZs).
NG publishes an indicative gas quality specification for entry
points in their annual ten year statement, which refers to the
presence of odorant in gas. Any gas exported from Ireland to
GB, may potentially conflict with this entry point gas quality
requirement.
NG have indicated that the export of odorised gas in the NTS,
would be of material change to the indicative gas quality
specification and the Gas Safety Management Regulations
(GSMR) requirements, and would require consultation and
the agreement with the affected users of the NTS. These users
include power generation stations, manufacturing and industrial
consumers and distribution network vendors.
36

NETWORK DEVELOPMENT STATEMENT
An alternative to physically exporting odorised gas into the NG
NTS, would be to adopt a similar approach to NG, by flowing
un-odorised gas in the ROI and NI transmission system, and
odorising the gas at the point of entry to the various distribution
networks, i.e. move the odorisation units from the entry points
on the transmission system to the relevant city gates and
distribution off-takes.
A second alternative may also be considered as a solution to
the odorisation issue. Twinning the Cluden to Brighouse Bay
pipeline may allow for a limited odourless system to operate,
from Moffat to Ireland via one or more of the sub-sea pipelines,
while operating an odourised system in parallel. This would
significantly reduce the requirement for odourisation units at
the city gates and distribution off-takes.
More detailed studies would need to be carried out by the
system operators in ROI, NI and GB to establish the feasibility,
impact and costs associated with each of the above options.
6.7 Conclusions
Network analysis results indicate that there is sufficient capacity
available on the existing on-shore ROI transmission system to
transport the necessary gas to meet the required forecast peakday
demand over the forecast period.
Equally, network analysis indicated that the local transmission
systems had sufficient capacity to meet the forecast peak
day demands. However, the growth levels assumed in the
models for the local transmission systems are uniform with
national growth levels. If localised growth was to exceed the
assumed national growth levels, there maybe a requirement
for reinforcement at the relevant location on the transmission
network.
Greater uncertainty surrounds the timing of the various
proposed supply projects and consequently the optimum
reinforcement solution(s) required to accommodate their
associated flows.
It should also be emphasised, if there is any significant change
to the future supply outlook, resulting in the likelihood of
Moffat being the only source of supply to ROI, NI and IOM in
the short to medium term, it is likely the SWSOS will require
reinforcement. Based on demand forecasts and the capacity
at Moffat, this reinforcement would need to be in place for
2013/14.
In addition to this, the capacity of Beattock compressor station
is subject to the available pressure at Moffat. The capacity of
353 GWh/d (32.0 mscmd) is based on the ANOP pressure of
47.0 barg. If pressures lower than the ANOP are assumed for
the winter peak day, it is likely the requirement to reinforce the
SWSOS will need to be accelerated, or other options would
need to be investigated.
The requirement to reinforce the SWSOS is also sensitive to the
assumed flat flow profile at Moffat. If this assumption is revised
to reflect the actual stepped/swing flow profile observed at
Moffat, it is likely the requirement to reinforce the SWSOS may
need to be accelerated.
37

7. Networks Asset Management &
Development
The operation of a gas network is dependent on the
entirety of the asset base of the network performing
to required levels from the point of entry on a network
through to the point of delivery. In order to safely and
efficiently deliver gas to customers, as well as maintain a
satisfactory level of system performance, the performance
and care of those assets used in the transportation of
gas is continually reviewed and analysed by the Asset
Management function within BGN.
For ease of management of these assets, Bord Gáis
Networks have defined five asset categories:
• Compressor Stations.
• AGIs & DRIs.
• Meters.
• Communications & Instrumentation.
• Pipelines.
Each asset class has been assigned a dedicated
“Asset Owner” who is responsible for optimising the
performance of their asset class while ensuring a quality
customer service is delivered safely in a cost efficient
manner. While these five asset categories have assets
which are specific to these categories, other assets have
interdependent relationships and multiple “Asset Owners
“may hold a common vested interest in the performance
and care of such assets.
In addition to the Asset Owner role of Asset
Management, the Asset Integrity function is responsible
for maintaining and maximising the integrity of all of the
asset categories. Asset Integrity also ensures the quality of
the natural gas which enters and passes through the BGN
pipeline network is to a satisfactory standard in terms
of its composition for delivery to customers while also
monitoring levels of impurities within the gas.
Asset Management also looks at new ways of utilising the
BGN asset base to best serve their customers and examine
areas in which natural gas can be used to aid sustainable
development, including developing natural gas as a
transport fuel in the Irish market.
7.1 Compressor Stations
Compressor stations are used in high pressure gas networks
to raise the pressure of the gas within the system and
therefore increase the capacity of the pipelines. Bord Gais
operates three compressor stations within the Network,
two located in the UK and one in Cork.
• Midleton compressor station (12 MW),
Built 1986.
• Brighouse Bay compressor station (42MW), Built 1993
(Phase 1), 2003 (Phase 2).
• Beattock compressor station (40MW),
Built 2000.
While the stations were constructed at different times
the technology used and the station layout is similar in
all cases.
7.1.1 Station Design
The compressor stations consist of three primary
components
• Turbo Compressor Units.
- Gas turbine Prime Mover
- Centrifugal Compressor
- Associated Pipework and Valves
- Turbo Compressor Control System
• Above Ground Installation (AGI).
- Station Filters
- Metering Streams
- Fuel Gas Treatment System
- Station Valves
• Site.
- Station Control room containing
• Station Control System, ESD, and Fire and Gas Systems.
• Network SCADA Connection.
- Administration Offices
- Workshop and Stores Facilities
- Security Systems
38

NETWORK DEVELOPMENT STATEMENT
7.1.1.1 Turbo Compressor Units
1. Gas Turbine: The gas turbine provides a relatively
compact low maintenance prime mover to drive the
gas compressor. The fuel source is natural gas and
BGE employs the latest low emission technology here
applicable on the gas turbine units.
Fig. 7.1: Filtration system at Brighouse Bay compressor
Station.
2. Natural Gas Compressor: The gas compressor is a multi
stage centrifugal type designed around the specific
requirements of the site; suction/discharge pressure,
flow rates etc. The other major component of the
compressor is the gas seals at either end of the drive
shaft which prevents the high pressure gas from
leaking to atmosphere.
3. Turbine Ancillary Equipment: Included in the turbine
package is the necessary ancillary equipment, this
includes;
• Lubrication oil systems.
• Servo Oil Systems.
• Fuel Measurement/Control package.
• Control system / Feedback equipment.
Fig. 7.2: Administration Building
4. Enclosure: For safety the entire turbine is encased in a
protective enclosure, this contains both fire detection
and suppression systems.
7.1.1.2 AGI
As the compressor stations tend to be at the points of
highest flows within the network they contain some
of the largest filtration systems, metering and AGI
components within the Network.
7.1.1.3 Site
As well as offices the Administration Building contains the
control room. This area contains all the control systems,
electrical distribution panels, communications systems and
emergency backup systems. The control room is protected
by an advanced fire detection and suppression system.
The compressor stations have a high degree of security
including remote alarms, and CCTV systems.
39

7. Networks Asset Management &
Development continued
7.2 AGIs & DRIs
The network consists of a number of Above Ground Installation
(AGI) assets, on the transmission system where the pressure
of the gas in the system is controlled and delivered to large
consumers such as power stations or reduced to be put
through the distribution system for delivery to domestic end
users. The complexity of these systems varies. In the intricate
interconnector stations, gas passes though filtering systems
to remove any particulate matter and capture any liquids prior
to metering. Once metered the gas is heated to overcome the
Joules-Thompson effect of pressure reduction this is carried out
in stages and via multiple streams.
A further refinement in the Interconnector sites is the ability
to control both gas flow and pressure so as to allow load
balancing across the network; this is carried out via an on-site
station control system. The on-site control system accepts
set point commands from the national grid control centre.
This is particularly important to facilitate the gas market in
accommodating Shippers’ instructions.
Fig. 7.3: Gormonstown IC2 Landfall AGI
On the distribution systems further pressure reduction occurs
to supply high density locations such as those found within
city and town centres. In these District Regulating Installations
(DRI’s) gas pressure is further reduced via regulating stream(s) to
domestic inlet pressures.
AGI’s supplying a regional town or city gate also consist of
filtering, heating and gas pressure reduction via multiple
streams to a fixed value for imputing in to the transmission and
distribution systems.
The redundancy of the pressure reducing streams is a critical
factor in all AGI’s as it allows for the continuous supply of gas
while servicing and inspections are carried out, or in the event
of a fault developing on a stream. These individual streams also
contain many important safety elements to ensure that pressure
is maintained and delivered safely and within pre-prescribed
limits, the SCADA system continually monitors these limits to
ensure the correct pressures are maintained.
40

NETWORK DEVELOPMENT STATEMENT
7.3 Meters
7.3.1 Meter Replacement Programme
Bord Gáis Networks has agreed with the CER and the
Director of Legal Metrology to carry out a Meter Replacement
Programme to replace the oldest domestic gas meters with
meters which have ‘Smart Ready’ capabilities.
These new meters can be upgraded to ‘Smart Meters’ when
required at some point in the future by the addition of a
communications module to the front of the meter. ‘Smart
Meters’ will allow consumers to monitor and record how much
gas they use and when they use it. ‘Smart Meters’ will give the
customer more time-of-use information regarding their gas
consumption and in turn it is anticipated will encourage energy
efficiency.
The replacement programme is being carried out in sections
by geographical areas throughout the country. The upgrade
is free of charge with no hidden costs for the tenant / home
owner and includes a free gas safety inspection within the
property. The upgrade takes less than an hour to complete with
minimum disruption to the customer.
The simple installation of a communications module to enable
the full ‘Smart Meter’ capability will take place at a future date
in line with the National Smart Metering rollout plan.
Ever conscious of safety, contract personnel working on behalf
of Bord Gáis Networks bear and present photo ID on calling to
houses. This is particularly appropriate in respect of this project
as the majority of meters being replaced happen to be in
households occupied by older people.
Fig 7.4 Smart Meter
7.3.2 Smart Metering Solution
Bord Gáis Networks is currently supporting the National Smart
Metering programme which is focussed on both gas and
electricity. The programme includes Customer Behaviour Trials
utilising smart metering technology, time of use tariffs, and
in-home displays. These trials, along with a public and industry
consultation process will help to validate the consumer benefits
of smart metering solutions. The full business and infrastructure
requirements, as well as the rollout schedule will also be defined
and agreed in the current phase of the programme (2011).
Gas and Electricity smart metering will be rolled out (subject
to the validation of a cost benefit analysis) on a shared
communication infrastructure in order to benefit from
combined efficiencies and leveraging of costs. The Department
of the Environment, Heritage & Local Government is
considering whether or not to also include water metering in
this infrastructure at a later stage.
The final upgrade to smart metering will allow a dwelling to
have more accurate and frequent meter readings. Furthermore,
it will ultimately allow households to better manage their
energy consumption and costs; and will also assist households
contribute towards National targets for improved energy
efficiency carbon emission reduction.
41

7. Networks Asset Management &
Development continued
7.3.3 Prepayment Metering
Bord Gais Networks with the agreement of the Commission for
Energy Regulation and the Natural Gas Suppliers introduced
its’ Prepayment Metering System in 2008. The Natural Gas
Prepayment Meter allows customers to purchase an amount of
gas credit on a Gas Card, which is then inserted into the meter
and the monetary credit is transferred directly from the card
to the meter. The Prepayment Meter can assist a customer in
budgeting their gas usage and payments. The system is very
efficient and reasonably easy to use.
The Prepayment solution offers many benefits to the customer:
• Customers have improved management of gas bills.
• Smaller payment amounts spread over a longer period of
time.
• No unexpectedly large bills and associated problems.
• Better monitoring and awareness of energy consumption
leading to improved energy conservation.
• Control of own usage and payment. Ability to build up
credits for periods of higher usage.
• Greater participation in the billing process leads to increased
customer satisfaction.
• There is no requirement for regular meter reading and
associated access problems, no meter disconnection or
reconnection fees along with Improved Social Welfare
payment receipt system.
• Pre-Pay meters also help landlords avoid large bills issues
when tenants move out.
The Roles of Bord Gáis Networks, the Gas Supplier, Payzone and
the Customer can be summarised as follows:
• Bord Gáis Networks: The prepayment meters are owned
by Bord Gáis Networks. They measure usage of gas which
facilitates the supply of a quantity of gas as designated
by the customer’s gas supplier for the amount of credit
purchased.
• The “Gas Supplier” sells gas to the customer based on
the billing tariff rate agreed between the supplier and the
customer. The gas supplier receives the customer’s meter
reading and gas consumption on a regular basis from Bord
Gáis Networks. In line with the CER’s guidelines for customer
billing, gas suppliers are required to supply their prepayment
customer with an annual statement of the gas usage and
payments.
• Payzone are a customer payments acceptance company,
with extensive retail point facilities throughout the country.
Payzone facilitate prepayment gas customers in ‘topping-up’
credit at selected shops which display both Payzone and the
Gas Card logo.
• The “Customer” must sign up with a gas supplier to obtain
a supply of natural gas and agree to pay for gas consumed
by means of a credit prepayment system using a ‘Gas Card’.
The customer is also obliged to provide Bord Gáis Networks
with reasonable access to their prepayment gas meter when
required.
42

NETWORK DEVELOPMENT STATEMENT
7.4 Communications and Instrumentation
7.4.1 SCADA
Supervisory Control and Data Acquisition (SCADA) is used
extensively to monitor and control the pipeline network.
The central equipment is located in a purpose built facility in
Gasworks Road, a control room is also located in this building
to facilitate control and monitoring of the pipeline network on a
24/7/365 basis.
The SCADA system uses remote terminal units (RTU) to retrieve
information from the transmission network. The RTU typically
measures gas flows, pressures, temperatures, valve status
signals, cathodic protection voltages and utility signals. The
RTU have output capability which is used to remotely control
strategically placed line valves which can be used in emergency
to shutdown pipeline sections. Low cost dialup solutions are
used to monitor distribution assets. There are approximately
130 transmission connected RTUs and 250 distribution SCADA
nodes. A Honeywell Experion system with Plant Historian is
used for transmission SCADA and a Wonderware and Industrial
SQL Server is used to drive distribution SCADA.
Communications is by means of digital leased lines, dialup lines
and by use of text and mobile data calls over GPRS.
7.4.2 Cathodic Protection Monitoring
Cathodic Protection (CP) is used to mitigate the effects
of corrosion on buried steel pipe work. Impressed current
techniques are used for the majority of transmission cross
country pipelines with sacrificial techniques used in urban areas
covering transmission and distribution. There are over 4,000
test points and 90 transformer rectifiers.
The care regime for the maintenance and upkeep of the CP
assets is a combination of annual survey of all test points and
rectifiers and monthly monitoring using remote CP measuring
devices strategically located in all of the transformer rectifiers
and approximately 5% of the test posts. Close interval surveys
are used to provide close and detailed inspection of pipelines
once every five years. Differential current voltage gradient
surveys (DCVG) are used to locate coating anomalies.
7.4.3 Instrumentation
Instrumentation is in place at all transmission installations to
monitor process gas pressure, temperature, flow information,
cathodic protection voltages and general ancillary signals
such as 220V AC mains incomers, generator faults, intrusion
detection etc. Sophisticated flow computers are used to correct
for pressure and temperature at the metering element and
so provide accurate billing data. All of these systems are tied
into the telemetry units which are then relayed to Cork via the
SCADA systems.
43

7. Networks Asset Management &
Development continued
7.5 Pipelines
The pipeline system is composed of transmission and
distribution mains. The transmission system transports gas at
high pressure through steel pipes, typically at 70 barg or greater
from the producers through the interconnectors across the Irish
Sea and throughout the country to pressure reduction stations
at cities and towns. Distribution mains carry the gas at a lower
pressure from the transmission stations for delivery to the end
users. There are approximately 11,000 kilometres of distribution
mains in the state and they are constructed primarily of high
density polyethylene. Service pipes carry the gas from the
main to the customer’s meter. In addition to the line pipe both
systems contain many valves, bends and connections.
There is a continuous programme to ensure the network
continues to comply with the relevant legislation, technical
standards and codes of practice and that the pipeline assets are
maintained in accordance with best international practice.
It is recognised that third party damage is the highest risk to
both the transmission and distribution networks. A variety of
measures, work practices and dedicated resources are in place
to face this challenge. Nonetheless recent years have seen an
increase in the number of third party encroachments on the
transmission system. A closer review of the individual incidents
shows that there appeared to be an increase in the volume of
drainage works being performed by landowners, most likely
in response to serious flooding over the past winter. In urban
areas there was also a significant increase in encroachments
related to water pipe repairs and upgrades performed by local
authorities again as a result of the extreme cold weather. Given
the potential for a national water metering project being rolled
out over the coming years, a similar trend of activity is possible.
Fig 7.5 Pipeline Marker
Consequently a significant upgrade of current pipeline
markers is proposed to reduce the number of encroachments
and the likelihood of a serious incident as a result of damage.
Under the proposed new pipeline marking policy which is
closely aligned with other systems in use on continental
Europe and the UK, Bord Gáis Networks will aim to install
above ground markers on pipelines such that a marker can
be seen in the line of sight at any point along the pipeline.
Furthermore there will be considerably more marking in
urban areas. Prior to a national upgrade project, a pilot of this
approach on a smaller area has been identified. The lessons
learnt from this pilot can then be used to finalise a detailed
marking policy/procedure and roll it out across the network.
Given the age profile of the network, the relatively dense
concentration of rural pipeline and urban lines, the Cork
County and City has been selected for the pilot project.
44

NETWORK DEVELOPMENT STATEMENT
Work also continues on a number of specific measures which
were adopted to further improve public safety, the Dublin-4
pipeline refurbishment programme is substantially complete
and this will significantly reduce the potential for an incident in
this location. Further initiatives have been identified for Limerick
and for Waterford and options are under consideration.
Leakage and damage to the distribution system by third parties
is modelled on the Geographical Information System, (GIS).
Analysis of these data indicates that a significant number of
these damage incidents are caused by small contractors doing
works at domestic premises, consequently this has resulted in
specific awareness training campaigns with tool hire outlets
which are utilised by many of these contractors.
The completion of the accelerated renewals programme in
Dublin and Cork has significantly reduced the risk posed by
older type cast and ductile iron mains. A small programme to
investigate mains still indicated as iron on the mapping system
is in progress. The completion of the renewals project has
facilitated a new distribution leak survey policy based on risk
rather than network material. A pilot of this policy is currently
underway. The new approach utilises the GIS system to model
distribution pipelines, based on the adjoining population
density; material type and the leakage density data to construct
a risk based model of the network. Accordingly the frequency
of survey is based on the indicated risk.
7.6 Asset Integrity
BGN designs, constructs and operates the natural gas pipeline
network to the highest safety standards. As a result of
extensive capital investment in recent years, together with very
stringent operating and management procedures, the Irish
pipeline network is amongst the most modern and safe in the
world. BGN has set safety as its top priority and considerable
resources have been invested to ensure that our operations,
procedures and processes benchmark favourably with the best
of international utility safety standards.
The Asset Integrity department in conjunction with the Asset
Owners are responsible for formulating and implementing
strategies which maximise the integrity of all asset categories
within BGN in the safest, most reliable and cost-effective
manner.
In line with best international practice, it is the intention
of BGN to move towards a risk based maintenance and
inspection regime and the Asset Integrity department will have
an integral role in this process. A risk based regime will allow
BGN to focus maintenance and inspection resources where
they are most effective, resulting in increased asset safety and
reliability while constraining costs. The recent introduction
of new technologies such as Decision Support Tool and the
Maximo Work and Asset Management system will support the
move to such a regime.
BGN currently internally inspect approximately 70% of the
gas transmission system using intelligent in-line inspection
vehicles, a percentage which is high in international terms.
The remainder are checked using above ground inspection
techniques. The Asset Integrity department are examining ways
to further increase this percentage through the use of new
in-line inspection technologies. Current inspection intervals will
also be assessed in terms of a risk based approach.
45

7. Networks Asset Management &
Development continued
7.7 Gas Quality
7.7.1 Physical and Chemical Properties
All gas entering the transmission network must comply with the
gas quality specification as prescribed in the Code of Operations
(available on the Gaslink website) at www.gaslink.ie.
The Gas Combustion Characteristics are measured online
(calorific value, wobbe – index and relative density) by
process gas chromatographs. These process gas analysers
and associated software comply with relevant international
standards and the online measurements are available live
through SCADA to our Grid Control Centre in Cork.
The natural gas impurities are measured offline. Spot samples
are taken monthly and analysed by an accredited laboratory to
the appropriate standard methods.
A decision paper CER/09/035 issued by the CER details a
revised gas quality specification which is to be applied in the
ROI. A modification to the Code of Operations will be required
to implement the revised specification and this process is
currently underway. The new specification includes additional
constituents and specifies a narrower Wobbe range.
Gaslink are currently carrying out a comprehensive review
of all entry point measurement arrangements to ensure that
gas entering the network is fully compliant with the revised
specification.
7.7.2 Odour
Natural gas is odourless and for safety reasons a proprietary
odorant is added to the gas entering the Bord Gáis network.
This differs from practice in the UK and most other European
transmission networks where the gas remains unodourised until
it enters the lower pressure distribution networks
Gas delivered into the network is odorised on the basis of a
logarithmic delivery scale at the rate of approximately 6 mg/m³
to achieve an Odour Intensity (OI) of 2 on the Sales Scale.
To verify the odour intensity of gas delivered to consumers,
gas samples are taken from locations throughout the network,
analysed by a gas chromatograph and odour intensity
calculated. Odour Intensity reports are issued monthly.
7.8 Natural Gas as a transport fuel
Bord Gáis Networks has a strategic objective to grow the size of
the Irish natural gas market and, thereby, improve the utilisation
of its gas transmission and distribution system. In accordance
with this objective, Bord Gáis Networks is developing the
application of Natural Gas as a transport fuel.
Natural Gas as a transport fuel - known as Compressed Natural
Gas (CNG) is used across the world within Natural Gas Vehicles
(NGV).
Since 2000 there has been substantial growth of NGVs
worldwide, with an annual growth of approximately 30%.
According to the Natural Gas Vehicle Association of Europe, in
2010 there were over 12million NGVs worldwide.
46

NETWORK DEVELOPMENT STATEMENT
This growth of NGVs is driven by a number of important factors
especially the economic and environmental benefits:
• Economic – According to NGVA Europe CNG is typically 30
– 60% cheaper than traditional fuels (petrol or diesel) across
Europe.
• Environmental – Significant reductions in emissions including
substantially reducing Carbon Dioxide, Particulate Matter
and Nitrogen Oxide.
Fig. 7.6: Natural Gas Vehicle
Bord Gáis Networks is currently involved in a number of
activities including:
• Researching the CNG and NGV markets in Europe and
across the world.
• Learning lessons from developed CNG markets.
• Analysing CNG through its use within the Bord Gáis
Networks fleet.
• Installed a trial CNG refuelling unit in Finglas, Dublin.
.• Planning a ‘fast-fill’ refuelling unit for the commercial use
of CNG within Bord Gáis Networks fleet. This will refuel
vehicles in approx. 2-4minutes.
• Working with NSAI, amongst others, to develop a CNG
refuelling station standard for Ireland.
• Meeting with stakeholders to ensure a cross-functional
industry partnership.
• Liaising with interested parties to commercially use CNG
within captive fleets.
The use of CNG will also reduce the dependency on oil and
diversify the energy mix within the Irish transport system.
47

8. Security of supply
8.1 Overview of Legal Framework
Ireland’s natural gas market is substantial, with more that
50% of electricity generation fuelled by gas. Therefore
maintaining secure supplies of gas to Ireland is essential, in
order to support economic recovery.
The vast majority of Ireland’s gas is supplied through
the UK. There are two sub-sea pipelines interconnecting
Ireland with Scotland. A third sub-sea pipeline links
Northern Ireland to Scotland. All three sub-sea pipelines
are supplied from a single onshore pipeline in Scotland.
Studies indicate that the likelihood of a major supply
interruption, resulting in a prolonged and severe shortfall
in gas supply to the island of Ireland is very low. Whilst the
risk is remote, it nonetheless remains, particularly in the
absence of a supply from the Corrib gas field.
In December 2010, the European Commission issued
EU Regulation No 994/2010, which concerns measures
to safeguard security of gas supply. The legislation puts
several obligations on member states and deals with a
variety of gas security matters. For example, the regulation
puts forward the principal of N-1, namely that the member
state competent authority shall ensure that in the event
of a disruption of the single largest gas infrastructure, the
capacity of the remaining infrastructure is able to satisfy
the total gas demand of the calculated area during a day
of exceptionally high demand statistically occurring once
every twenty years. This obligation may be considered
fulfilled where the competent authority demonstrates
that such a supply disruption may be compensated for
by appropriate market-based demand side measures.
The competent authority may deem the obligation to be
fulfilled at a regional level instead of at a national level,
where appropriate according to a risk assessment.
The competent authority shall carry out a security of
supply risk assessment, running various high demand
& supply disruption scenarios and assessing the likely
consequences of these scenarios. Where applicable, the
competent authorities shall also perform a joint risk
assessment at regional level. Work has commenced on
conducting Ireland’s risk assessment.
8.2 Existing Operational and Planning
arrangements
The CER has designated Gaslink to act as the National
Gas Emergency Manager (NGEM) under Section 19(B) of
SI 697. Gaslink has produced a Natural Gas Emergency
Plan (NGEP), which has been approved by the CER and
details the roles and responsibilities of all natural gas
undertakings in the event of a potential or actual gas
supply emergency.
The NGEM will be responsible for managing any potential
or actual gas supply emergency, in accordance with the
provisions of the NGEP. The NGEM will act as the incident
controller and will be responsible for declaring an
emergency.
BGN would support the NGEM by acting as the interface
with other natural gas undertakings, producers, storage
operators and any connected system operators, and by
implementing the NGEM instructions.
BGN has put in place emergency arrangements with other
connected systems operators, e.g. PSE Kinsale Energy,
PTL, the MEA and NG in GB. BGN has also clarified with
the Network Emergency Coordinator (NEC) in GB, the
arrangements that will apply in the event of a gas supply
emergency in GB.
48

NETWORK DEVELOPMENT STATEMENT
A Gas Emergency Response Team (GERT) is in place as
part of the NGEP. This group convenes in the event of an
actual emergency and includes representatives from BGN,
Gaslink, Eirgrid and CER/DCENR.
The CER chairs the Task Force on Emergency Procedures
(TFEP), which also includes representatives from the
Department of Communications, Energy and Natural
Resources (DCENR), Gaslink, BGN, EirGrid and ESB
Networks.
The TFEP is responsible for ensuring that coordinated
procedures are in place to manage a supply emergency on
the gas and electricity systems, and that an emergency on
one system does not lead to an emergency on the other.
The first TFEP report was published in 2007 and included
recommendations to enhance the existing arrangements
and procedures, including:
• Giving EirGrid a role in the curtailment of gas
supplies to power stations during a natural gas supply
emergency, in order to mitigate as far as possible the
impact on electricity supplies.
• Requiring power stations to hold adequate stocks of
secondary fuels, and testing their ability to switchover
to these secondary fuels in an emergency.
As part of the NGEP a Gas Emergency Planning Team
(GEPT) meets with a view to further developing the
emergency arrangements contained in the NGEP. This
team includes BGN, Gaslink, EirGrid and CER/DCENR. This
team also discusses forthcoming gas emergency exercises
and exercises already conducted.
Exercise Avogadro was conducted between operators/
regulators and Government Departments in Ireland
and the UK in the summer of 2010. This exercise tested
the communications protocols between government
and industry in the event of a major gas emergency.
The exercise also included liaison with the equivalent
authorities in Northern Ireland. The exercise was deemed
a success and a number of initiatives have stemmed from
the lessons learned.
In addition to planning arrangements for potential or
actual gas supply emergency’s, BGN put in a place a
number of preventative measures to reduce the risk of an
emergency.
Grid Control, a department within BGN, are responsible
for the 24 hour technical operation and supervision of
the gas network using a sophisticated Supervisory Control
and Data Acquisition (SCADA) system which captures and
presents live data from each above ground installation
(AGI). Alarm limits are set on all key parameters in
SCADA and when a process variable falls outside of these
alarm limits it is escalated to a Field Operations team to
remedy, where a 24 / 7 on-call rota is operated all year
round. Emergency repair arrangements are maintained
with contractors that would allow the timely repair of
any damage to the transmission network if required. In
addition to this 24 hour operation and supervision of the
network, security cameras are installed and monitored at
various key stations and the transmission pipeline network
is monitored regularly by helicopter and line walks.
BGN also encourage public gas safety awareness through
advertising campaigns a presence at major trade shows
and the Ploughing Championships, and operates dial
before you dig and 24 hour emergency lines.
49

9. Commercial Market
Developments
9.1 Gaslink: Independent System Operator
In accordance with licences granted by the Commission
for Energy Regulation (CER), Gaslink, as the Independent
System Operator operates, maintains and develops the ROI
transportation system. BGÉ, as System Owner, holds a licence
relating to its ownership of the transportation system.
The key role and responsibilities of Gaslink are as follows:
• To operate, maintain and develop, under economic
conditions secure, reliable and efficient transmission and
distribution systems with due regard to the environment.
• To provide any natural gas undertaking with sufficient
information to ensure that transport of natural gas on
the transmission system may take place in a manner
compatible with the safe, secure and efficient operation
of the network.
• To provide users of the transmission system with the
information they need for efficient access to the
transmission and distribution systems.
• To procure the energy it uses for the carrying out of its
functions according to a transparent, non-discriminatory
and market based procedure subject to CER approval.
• To adopt rules for the purposes of balancing the gas
system which are objective, transparent and nondiscriminatory.
• To report to the CER, as outlined in the Gas (Interim)
(Regulation) Act, 2002, and in respect of any other
matters as the CER may specify.
Gaslink is independent of BGÉ in terms of its organisation
and decision making processes, when executing its
responsibility for the operation of the transmission and
distribution systems.
Gaslink identifies all work necessary for the operation,
maintenance and development of the transportation
system, and instructs BGÉ to carry out works in accordance
with the Operating Agreement (specified in the legislation
and approved by the CER). Gaslink holds two Licences from
the CER for the operation of the ROI transmission and
distribution systems, which inter alia cover the following
areas:
• Connection to the transmission and distribution systems.
• Transmission and distribution system standards.
• Operating security standards.
• Provision of metering and data Services.
• Provision of services pursuant to the Code of Operation
(the “Code”).
9.2 European Developments
The passing into law of the 3rd Energy package in
September 2009 represented a key milestone for the
development of the gas markets within each EU member
state. In addition the implementation of the new
legislative requirements will serve as a major step towards
a single European gas market. The package prescribes
extensive changes to the legislative and regulatory
frameworks covering gas transportation and will also
result in considerable redefinition of the transportation
arrangements themselves particularly at interconnection
points across Europe such as Moffat. The 3rd package
consists of the following key elements:
• Directive 2009/73/EC which from March 2011 will
supersede Directive 2003/55.
• Regulation (EC) No. 713/2009 which from March 2011
mandates a new Agency for the Co-operation of Energy
Regulators (ACER).
• Regulation (EC) No. 715/2009 which from March
2011 requires the setting up of European Network
Transmission System Operators in gas or ENTSOG.
50

NETWORK DEVELOPMENT STATEMENT
The European Transmission System Operators (TSO) have
already put in place the organisation which will ultimately,
once approved by the Commission in 2011, constitute
the ENTSOG. All European TSOs will be legally obliged to
co-operate with this group once the Directive comes into
effect. Gaslink, as the Irish TSO, is a founding member of this
organisation and is already participating actively in the work
of ENTSO-G. The ENTSO-G foundation meeting took place
on the 1st of December 2009 in Brussels.
At the heart of the 3rd Energy package legislation is the
development of EU-wide network codes for 12 areas, aiding
the integration of European gas markets and to facilitate
effective cross-border trade and competition to develop
across the EU member states. Framework guidelines will
be developed by ACER for the Cooperation of Energy
Regulators (The Agency) and will form the basis for the
Network Codes.
ACER will have a role in reviewing, based on matters of
fact, draft network codes, including their compliance
with the framework guidelines, and it will be enabled to
recommend them for adoption by the Commission. ACER
will assess proposed amendments to the network codes and
it will be enabled to recommend them for adoption by the
Commission. Transmission system operators should operate
their networks in accordance with those network codes. This
process, which will include a mandatory public consultation,
is set out in Article 6 of EC/715/2009.
The ENSTO-G is responsible for developing the 12 binding
Network Codes based on the framework guidelines. Once
adopted by the Commission the application of the network
codes will become mandatory in all member states
The network codes referred to Article 6 of the Regulation
shall cover the following areas, and, where appropriate,
those rules will evolve over time, taking into account the
special characteristics of national and regional markets with
a view to ensuring the proper functioning of the internal
market in gas
(a) network security and reliability rules.
(b) network connection rules.
(c) third-party access rules.
(d) data exchange and settlement rules.
(e) interoperability rules.
(f) operational procedures in an emergency.
(g) capacity-allocation and congestion-management rules.
(h) rules for trading related to technical and operational
provision of network access services and system
balancing.
(i) transparency rules.
(j) balancing rules including network-related rules on
nominations procedure, rules for imbalance charges and
rules for operational balancing between transmission
system operators’ systems.
(k) rules regarding harmonised transmission tariff structures.
(l) energy efficiency regarding gas networks.
Further development across Europe of arrangements
relating to the definition and management of capacity
products together with enhanced balancing will be given
priority by the various stakeholders in 2011. During 2011
transparency requirements of EC 715 will be implemented.
Gaslink will continue to participate in these various
initiatives and will work with other Irish stakeholders in
advancing the new arrangements.
51

9. Commercial Market
Developments continued
9.3 New Connections
Gaslink continues to engage with parties looking to connect
to the transmission and distribution networks. In accordance
with the Operating Agreement, Gaslink undertakes all the
large connections agreements to the transmission system and
manages the provision of all other connections agreements
undertaken by Bord Gáis Networks on Gaslink’s behalf.
All new connections are managed in compliance with the CER
approved Connections Policy. This Policy sets out the criteria for
connecting new customers to the gas network.
In 2010 Gaslink and BGN, in conjunction with the CER
reviewed various elements of the current policy. One area that
was reviewed was the treatment of new large gas connection
with an expected low load factor under the Connections Policy.
Gaslink has been approached by various developers requesting
gas connections to fuel peaking power generation plants to
compensate the intermittent nature of wind. The CER published
a decision paper in April 2010 amending the definitions of
customer classifications so that it is now based on the size of
connection rather than projected annual load.
In 2011 further review of the policy will take place in
conjunction with BGN and the CER. One of the main areas
to be reviewed is the connection process for those interested
in connecting bio-methane generating facilities. Gaslink has
been engaging with the CER on this matter – it is our intention
in 2011 to consider the inclusion of specific requirements
in the Policy that governs the terms for connection of such
entry points to the gas network. In conjunction with the CER,
Gaslink will review an appropriate mechanism for renewable
gas entry points and together develop proposals as appropriate.
These proposals will endeavour to bring clear and transparent
arrangements which will clarify the approach for these facilities
which should assist the wider use of renewable gas ensuring
non discriminatory access to the gas network.
9.4 Moffat
9.4.1 Selling Gas at the NBP
In response to requests from the market for the facility to sell
gas into Great Britain (GB) at the National Balancing Point (NBP)
from the Irish market, Gaslink is in the process of developing a
virtual reverse flow product at the Moffat Entry Point. Physically
the flow is unidirectional but through virtual reverse flow,
contractual reverse flow of the gas is possible.
Moffat is currently designated as an Exit Point from the GB
Transmission System. It will be necessary for Moffat to also be
designated as an Entry Point in order to allow ROI Shippers to
sell their gas in GB.
9.4.2 NTS Exit Reform
92.3 % of the Irish gas requirements and 100% of Northern
Ireland and Isle of Man gas is supplied via the Moffat
interconnection point with the GB system operated by National
Grid. The current arrangement for booking capacity to ship
gas through the inter-connector pipelines is a ‘Ticket to ride’
Process. This means that GB parties can only book capacity
at Moffat if they were nominated to do so by a counter party
downstream of Moffat.
As part of what is commonly termed NTS Exit Reform, the Office
of Gas and Electricity Markets (OFGEM), approved a modification
(UNC 195AV) to the GB code in early 2009 which puts in place
a user commitment model at Moffat where ultimately, parties
will be required to book exit capacity several years in advance in
order to ensure access to such capacity. The new arrangements
come into full effect in 30th of September 2012 and will result
in substantial changes to the allocation of NTS exit capacity at
Moffat. One key impact is the abolition of the Downstream
Capacity Register which facilitated the ticket to ride required by
upstream shippers in order to procure exit capacity.
Stakeholders in the GB gas market will continue throughout
2011 to develop further initiatives pursuant to NTS Exit Reform.
On 31st March 2011 Ofgem published a decision paper
stating that it would be appropriate to exclude capacity at GB
interconnectors from exit capacity subsitution.
52

NETWORK DEVELOPMENT STATEMENT
9.5 CAG Summary
Background
“The All-island Energy Market Development Framework” paper
(agreed by Irish and Northern Irish Ministers in November 2004
November 04) set the scene for the review of Energy markets
on an All-Island basis. The Single Electricity Market (SEM) was
the first phase in this development. In establishing Common
Arrangements for Gas (CAG), the CER and the Northern Ireland
Authority for Utility Regulation (NIAUR), plan, subject to the
approval of the relevant authorities, to progress phase two of
this energy management harmonisation work through the
facilitation of the operation of the natural gas market in Ireland
and Northern Ireland on an all-island basis.
Potential benefits of CAG include:
• enhanced interconnectivity of gas networks on the island.
• enhanced competition.
• more optimised investment.
• increased Security of Supply.
Current Status
• The Regulatory Authorities has initiated a number of
preliminary CAG work streams.
• Gaslink has worked closely, throughout 2010, with the
CER and NIAUR to advance the approach to development
of a Single Network Code for CAG. Work in this area is
continuing in 2011.
• Work on the 2011 Joint Gas Capacity Statement (JGCS) is
being currently progressed, with an expected publication
date of July 2011. The 2011 JGCS has been expanded to
cover a 10 year period, from 2010/11 to 2011/20.
The CAG work plan is aimed to be aligned with legislative
timetables with respect to CAG Governance Structure if and
when it is finalised.
The first JGCS was produced in 2009, as part of the CAG
project. The JGCS examines forecasts of customer demand for
natural gas, the relevant sources of supply and the capacity of
the gas transmission system on the island for the period 2008/9
to 2015/16. It constitutes an important step in developing a
harmonised approach to security of supply on the island under
the CAG project. This work will be central to the CAG project
and the systems operations function going forward.
53

Appendix 1: Demand Forecasts
The demand forecasts are summarised in Tables A1.1 – A1.3.
Table A1.4 presents the various supply sources by entry point,
both existing and proposed. The values represent the maximum
supply volume each source could potentially provide.
The ROI demand is broken down by sector, while the total
demand is given for NI and the IOM. The forecasts are based on
the following weather scenarios:
• Table A1.1: Peak-day gas demand under severe 1 in 50
weather conditions, i.e. weather so severe that it only occurs
once every 50 years.
• Table A1.2: Peak-day gas demand under ‘average year’
weather conditions, i.e. the weather conditions that typically
occur each year.
• Table A1.3: Annual gas demand in average year weather
conditions.
The NI peak-day demand used for both the 1 in 50 and
average year weather forecast is based on the latest available
NI Postalised tariff data (extrapolated forward), plus provision
for a new CCGT at Kilroot. The IOM peak-day is based on
information provided by the Manx Electricity Authority (MEA).
The weather correction is only applied to the distribution
connected load, i.e. primarily to the residential and small I/C
sectors. There is no weather correction applied to the power
sector gas demand forecast and, therefore, its peak-day
demand is the same for both the 1 in 50 and average year
weather conditions.
Table A1.1: Peak-day demand (1 in 50 weather) & Base Supply by gas year (in GWh/d)
10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20
(GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh)
Demand
Power 130.8 130.6 129.2 128.3 130.3 131.5 137.0 140.4 151.5 151.0
I/C 49.3 50.1 51.1 52.2 53.5 53.6 53.7 54.6 53.7 53.8
RES 69.7 68.8 67.8 66.9 66.1 65.4 64.8 63.3 63.6 63.1
Own use 4.7 4.8 4.7 5.2 3.8 4.0 4.1 4.1 4.5 4.7
Sub total 254.6 254.3 252.9 252.6 253.7 254.5 259.5 262.3 273.3 272.6
Injection 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
IOM 5.8 6.2 6.3 6.4 6.5 6.6 6.6 6.7 6.8 7.0
NI 85.1 86.2 87.3 88.4 89.1 108.3 109.0 109.6 110.3 111.0
Total 345.4 346.7 346.4 347.3 349.2 369.4 375.1 378.7 390.5 390.6
Notes
1
Injection refers to storage injections from the transmission system into Kinsale and Larne Storage
2
Own-use
refers to fuel-gas used by the transmission system to transport the gas, e.g. fuel-gas used the compressor stations and heat exchangers at Above Ground
Installations (AGIs)
54

NETWORK DEVELOPMENT STATEMENT
Table A1.2: Peak-day demand (average year weather) & Base Supply by gas year (GWh/d)
10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20
(GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh)
Demand
Power 130.8 130.6 129.2 128.3 130.3 131.5 137.0 140.4 151.5 151.0
I/C 42.4 43.1 43.9 44.8 45.9 46.0 46.0 46.8 46.1 46.1
RES 55.3 54.5 53.7 53.0 52.4 51.8 51.3 50.2 50.4 50.0
Own use 3.4 3.4 3.4 3.7 2.7 2.8 2.8 2.8 3.2 3.3
Sub total 231.8 231.6 230.3 229.8 231.3 232.2 237.2 240.1 251.2 250.5
Injection 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
IOM 5.1 5.4 5.5 5.5 5.6 5.7 5.8 5.8 5.9 6.0
NI 80.3 81.3 82.1 83.1 83.6 102.7 103.3 103.8 104.4 105.0
Total 317.2 318.3 317.9 318.5 320.5 340.6 346.3 349.7 361.5 361.5
Table A1.3: Annual demand (average year) & Base Supply scenario by gas year (TWh/y)
10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20
(TWh) (TWh) (TWh) (TWh) (TWh) (TWh) (TWh) (TWh) (TWh) (TWh) (TWh)
Demand
Power 38.51 35.70 34.19 33.11 35.98 36.01 37.76 38.64 41.81 41.92
I/C 10.30 10.45 10.63 10.84 11.08 11.09 11.09 11.09 11.09 11.09
RES 7.93 7.82 7.70 7.60 7.51 7.43 7.36 7.29 7.23 7.17
Own use 0.83 0.81 0.82 0.79 0.44 0.44 0.47 0.48 0.58 0.63
Sub total 57.57 54.77 53.35 52.34 55.01 54.97 56.68 57.50 60.70 60.81
Injection 1.74 1.90 2.08 2.19 2.32 2.38 2.43 2.48 2.51 2.54
IOM 1.34 1.41 1.42 1.44 1.46 1.47 1.50 1.52 1.54 1.56
NI 16.79 17.39 18.39 18.37 18.54 24.42 24.54 24.66 24.77 24.88
Total 77.44 75.47 75.21 74.33 77.32 83.25 85.14 86.15 89.53 89.79
The forecast assumes that the peak-day gas demand of the power sector is coincident with that of the residential and I/C sectors, as
this gives the worst case scenario for gas system planning purposes.
The power peak-day gas demand forecast assumes that all of the non gas-fired thermal power stations are available on the day, i.e.
all of the peat, coal and oil-fired power stations. If there is a forced outage one or more of the non gas-fired thermal power stations,
then the peak-day gas demand of the sector may be higher than indicated in the above forecasts.
55

Appendix 1: Demand Forecasts continued
Table A1.4: Maximum Daily Supply Volumes
10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20
(GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh)
Supply
Corrib 0.0 0.0 0.0 104.5 104.5 102.5 102.5 85.7 71.1 59.6
Inch 1 34.3 33. 2 32.1 31.0 30.2 29.4 29.0 28.7 28.4 28.1
Shannon 2 0.0 0.0 0.0 0.0 0.0 0.0 127.0 127.0 127.0 127.0
Larne 3 0.0 0.0 0.0 0.0 0.0 66.2 110.5 243.0 243.0 243.0
Larne 4 0.0 0.0 0.0 0.0 0.0 0.0 165.6 165.6 165.6 165.6
Moffat 5 353.0 353.0 353.0 353.0 353.0 353.0 353.0 353.0 353.0 353.0
Total 387.3 386.2 385.1 488.5 487.7 551.1 887.6 1,003 988.1 976.3
1
Combination of existing storage and forecast production levels
2
This volume represents phase I of the proposed Shannon LNG facility
3
Refers to the proposed Islandmagee La storage facility
4
Refers to the proposed North East storage facility
5
The capacity of Moffat is based on the capacity of Beattock compressor station
56

Appendix 2: Historic Demand
NETWORK DEVELOPMENT STATEMENT
Historic Daily Demand by Metering Type
The historic demand data in Section No.3 is presented by
sector (i.e. residential I/C and power), as this is more useful
for forecasting purposes and is also considered to be a more
familiar classification for the users of this document. The actual
daily demand data is collected by metering type:
• Large Daily Metered (LDM) sites with an annual demand of
57.0 GWh/y or greater, and includes all the power stations
and the large I/C sites.
• Daily Metered (DM) sites with an annual demand greater
than 5.6 GWh/y and less than 57.0 GWh/y, and includes the
medium I/C, hospitals and large colleges etc.
• Non-Daily Metered (NDM) with an annual demand of 5.6
GWh/y or less, and includes the small I/C and residential
sectors.
The daily demands of the above categories are then
recombined into the following categories for reporting and
forecasting purposes, using the monthly billed residential data
to split the NDM sector into its residential and I/C components:
• Power sector: The individual power stations are separated
out from the LDM total.
• The I/C sector: Which is comprised of the demand from the
remaining LDM sites, the DM sector and the NDM I/C sector
(calculated as the residual of the total NDM demand and the
residential demand).
• Residential sector: Which is calculated as a percentage of
the NDM demand, using the ratio of the total billed monthly
NDM and residential demand.
The historical daily demand on the transmission and distribution
systems is shown in Fig. A2.1 and A2.2, with the corresponding
peak-day, minimum-day and annual demands tabulated in
Table A2.1. The transmission and distribution daily demands
have been broken down into the following sub-categories:
• Transmission demand has been subdivided into the power
sector demand, with all of the remaining LDM and DM I/C
demand combined into the TX DM I/C category.
• Distribution demand has been subdivided into the NDM
demand, with all of the remaining LDM and DM I/C demand
combined into the DX DM I/C category.
It can be seen from Fig. A2.1 that the distribution connected
demand is very weather sensitive, peaking in the colder winter
period and falling off in the warmer summer period. The NDM
demand is particularly weather sensitive, as it includes the
residential and small I/C sectors, which primarily use gas for
space heating purposes.
The transmission connected demand on the other hand, does
not appear to be particularly weather sensitive. The gas demand
of the power sector in particular is driven by relative fuel prices
rather than the weather (although the gas price can be weather
related as well).
The peak-day demands shown in Table A2.1 represent the
coincident peak-day demands, i.e. the peak-day demand
of each sector on the date of the overall system peak-day
demands. Each sector may have had a higher demand on a
different date. The non-coincident peak-day demand of each
sector is shown in Table A2.2.
57

Appendix 2: Historic Demand continued
Fig. A2.1: Historical daily demand of
transmission connected sites
Table A2.1: Historical coincident peak-day and annual demands
Demand (GWh/d)
160
140
120
100
80
60
40
20
Historic Transmission (TX) Demand
2005/06 2006/07 2007/08 2008/09 2009/10
(GWh) (GWh) (GWh) (GWh) (GWh) (GWh)
Peak Day
TX Power 96.8 111.2 119.7 126.4 134.3
TX DM I/C 12.3 11.2 10.7 10.4 9.1
DX DM I/C 10.8 10.8 11.2 11.0 11.7
DX NDM 69.7 71.4 74.1 79.7 92.5
Total ROI 189.6 204.7 215.7 227.5 247.6
0
01 Oct 09
01 Nov 09
01 Dec 09
01 Jan 10
01 Feb 10
01 Mar10
01 Apr 10
TX DM I/C
01 May 10
01 Jun 10
01 Jul 10
TX Power
01 Aug 10
01 Sep 10
Annual
TX Power 29,775 34,688 37,758 36,007 39,338
TX DM I/C 4,004 4,029 3,793 3,518 3,701
DX DM I/C 2,597 2,827 2,828 2,835 2,858
DX NDM 11,900 11,345 12,125 12,374 12,530
Total ROI 48,276 52,890 56,505 54,734 58,427
Fig. A2.2: Historical daily demand of the
distribution connected sites
Table A2.2: Historical Non-coincident peak-demands by sector
Demand (GWh/d)
120
100
80
60
40
20
Historic Distribution (DX) Demand
2005/06 2006/07 2007/08 2008/09 2009/10
(GWh) (GWh) (GWh) (GWh) (GWh) (GWh)
Peak Day
TX Power 110.2 123.1 129.3 135.7 134.3
TX DM I/C 13.7 13.7 12.9 12.7 13.7
DX DM I/C 10.8 11.3 11.3 11.2 11.8
DX NDM 71.4 72.1 74.1 79.7 95.2
Total ROI 206.1 220.2 227.6 239.3 255.0
0
01 Oct 09
01 Nov 09
01 Dec 09
01 Jan 10
01 Feb 10
01 Mar10
01 Apr 10
DX DM I/C
01 May 10
NDM
01 Jun 10
01 Jul 10
01 Aug 10
01 Sep 10
Peak Day by Sector
Power 110.2 123.1 129.3 135.7 134.3
I/C 46.6 47.1 46.9 46.8 51.8
RES 49.3 50.0 51.4 56.8 68.9
Total ROI 206.1 220.2 227.6 239.3 255.0
58

Appendix 3: Energy Efficiency
assumptions
NETWORK DEVELOPMENT STATEMENT
National Energy Efficiency Action Plan (NEEAP)
The NEEAP for Ireland sets out the Government’s strategy for
meeting the energy efficiency savings targets identified in the
energy White Paper (2007) and the EU Energy Services Directive
(ESD). These targets include:
• The White Paper target of a 20% reduction in ROI energy
demand across the whole economy by 2020, with a higher
33% target for the Public Sector.
• The ESD target of a 9% reduction in energy demand by
2016.
Table A3.1: NEEAP Energy efficiency savings targets
2010 2016 2020
PEE target PEE target PEE target
(GWh) (GWh) (GWh)
Residential Sector
Building Regulations 2002 1,015 1,015 1,015
Building Regulations 2008 130 1,425 2,490
Building Regulations 2010 0 570 1,100
Low carbon homes 0 130 395
SEI house of tomorrow 30 30 30
Warmer homes scheme 115 155 170
Home Energy Savings programme 450 600 600
Smart metering 0 650 690
Greener Homes scheme 265 265 265
Eco-design for energy appliances (lighting) 200 1,200 1,200
More efficient Boiler Standard 400 1,600 2,400
Total residential savings 2,605 7,640 10,355
Business & Commercial sectors
SEI public sector retrofit programme 140 140 140.0
Building Regulations 2005 185 370 560.0
Building Regulations 2010 0 630 1,360.0
SEI energy agreements (IS 393) 465 685 4,070.0
SEI small business supports 160 330 565.0
Existing ESB DSM programmes 380 410 435.0
Renewable Heat Deployment programme 360 410 410.0
ACA for energy efficient equipment 100 400 800.0
Total business and commercial savings 1,790.0 3,375.0 8,340.0
Other sectors
Transport 775 3,105 4,670
Energy Supply sector 275 300 365
Total measures identified above 5,445 14,420 23,730
White Paper target (20% reduction by 2020) 31,925
Additional measures yet to be identified 8,195
59

Appendix 3: Energy Efficiency
assumptions continued
Impact on residential gas demand
The proposed energy efficiency measures for the residential
sector will clearly have a material impact on annual gas demand
of the residential sector. The TDS forecast for the residential
sector includes the following assumptions:
• Incremental gas demand from new residential connections
will continue to reduce due to tighter building regulations
and will fall to 40% of 2005/06 levels by 2012/13.
• Existing residential gas demand will also reduce due to
the introduction of more efficient boiler standards (e.g.
condensing boilers), smart metering and the combined
impact of the Low Carbon Homes, Warmer Homes & Home
Energy Saving schemes.
The average annual gas consumption of all new residential
customers connected during the 2005/06 gas year was
approximately 12.3 MWh/y. The TDS forecast assumes the
average gas consumption of each new customer connected by
2012/13, will reduce by 60% to 4.9 MWh/y.
The NEEAP assumes a total reduction of 4,255 GWh in
residential energy demand, due to the introduction of more
efficient boiler standards, smart metering and the combined
impact of the Low Carbon Homes, Warmer Homes and Home
Energy Saving schemes.
In addition it also identifies the potential for a further energy
efficiency reductions of 1,920 GWh from the retrofitting attic,
cavity-wall and wall-lining insulation to existing houses (after
adjusting for the impact of the Warmer Homes and Home
Energy Savings schemes).The TDS forecast assumes that:
• Total energy efficiency savings of 5,614 GWh in residential
heat demand between 2010/11 and 2019/20 from the
above measures (annual reduction of 561 GWh/y).
• Approximately 27% of this target reduction will be
achieved in gas-fired residential homes, based on the gas
share of residential heat in 2009, i.e. the gas share of total
residential TFC after excluding the electricity and renewable
components.
• This would lead to a reduction of 152 GWh/y in residential
annual gas demand, which is equivalent to 1.8% of the
residential gas demand in 2009/10.
Impact on I/C gas demand
The NEEAP assumes a total reduction of 3,375 GWh in I/C gas
demand by 2016, and a total reduction of 8,340 GWh by 2020.
Some of this reduction may have already occurred since the
2002-2005 baseline period. The TDS forecast assumes:
• That the total I/C energy demand will reduce by 3,375 GWh
by 2016 and a further 4,965 GWh by 2020 (per the NEEAP),
an annual reduction of 338 GWh/y up to 2016 and 1,174
GWh/y up to 2020.
• The gas share of these reductions is assumed to be 19.3%
up to 2016 and 21.4% up to 2020, based on gas share of
total I/C TFC in 2008 (of 23.0%) and adjustments to exclude
initiatives which are specific to electricity (e.g. ESB demand
reduction programmes).
• This would lead to an annual reduction of 65.1 GWh/y in I/C
annual gas demand up to 2014/15, and 266 GWh/y from
2015/16 onwards (which is equivalent to 0.6% and 2.6% of
the 2009/10 I/C annual demand respectively).
60

Glossary
NETWORK DEVELOPMENT STATEMENT
AC
ACER
ACS
AGI
ANOP
AQ
Bar-g
BGÉ
BGN
BGSI
CAG
CCGT
CCTV
CER
CNG
CP
CSO
DCENR
DCVG
DD
DM
DRI
DX
E/W
EC
ENTSOG
ESB
ESD
ESRI
ETS
EU
GATG
GB
GCS
GCV
GDP
GEPT
GERT
GPRS
GSMR
GTMS
GWh
GWh/d
HDD
I/C
IBP
IC
IOM
IS
JCS
JGCS
km
LDM
LDZ
LF
LNG
LSFO
m/s
MCS
MEA
MJ/scm
mm
MOP
- Alternating Current
- Agency for the Co-operation of Energy Regulators
- Average Cold Spell
- Above Ground Installation
- Anticipated Normal Offtake Pressure
- Annual Quantity
- Unit of gauge pressure
- Bord Gais Éireann
- Bord Gais Networks
- Bord Gais Strategic Investments
- Common Arrangements for Gas
- Combined Cycle Gas Turbine
- Closed Circuit Television
- Commission for Energy Regulation
- Compressed Natural Gas
- Cathodic Protection
- Central Statistics Office (ROI)
- Dept of Communications, Energy and Natural Resources
- Differential Current Voltage Gradient
- Degree Day
- Daily Metered
- District Regulating Installations
- Distribution System
- East/West electricity interconnector
- European Commission
- European Network Transmission System Operators in gas
- Electricity Supply Board
- Energy Services Directive
- Economic and Social Research Institute
- Emission Trading Scheme
- European Union
- Gas Advisory Task Group
- Great Britain
- Gas Capacity Statement
- Gross Calorific Value
- Gross Domestic Product
- Gas Emergency Planning Team
- Gas Emergency Response Team
- General Packet Radio Service
- Gas Safety Management Regulations
- Gas Transmission Management System
- Giga-Watt hours
- Giga-Watt hours per day
- Horizontal Directional Drill
- Industrial Commercial
- Irish Balancing Point
- Interconnector system
- Isle of Man
- Irish Standard
- Joint Capacity Statement
- Joint Gas Capacity Statement
- Kilometre
- Large daily metered
- Local Distribution Zone
- Load Factor
- Liquefied Natural Gas
- Low Sulphur Fuel Oil
- Metres per second
- Midleton Compressor Station
- Manx Electricity Authority
- Mega Joules per standard cubic metres
- Millimetre
- Maximum Operating Pressure
mscm
mscm/d
mscm/m
MTR
MW
MWh/y
N/W
NBP
NDM
NDS
NEC
NEEAP
NEM
NG
NGEM
NGEP
NGV
NGVA
NHA
NI
NIAUR
NSAI
NTS
OCGT
OFGEM
OI
P.A.
PE
PMA
PSO
PTL
PTTW
RES
ROI
RTU
S/N
SAC
SCADA
SDR
SEI
SEM
SI
SNIP
SNP
SONI
SOS
SPA
SQL
SRMC
SWL
SWSOS
tCO2
TDS
TFC
TFEP
TPA
TPER
TSO
TWh/y
TX
UK
V
yr
- Millions of standard cubic meters
- Millions of standard cubic meters per day
- Millions of standard cubic meters per month
- Medium Term Review
- Mega Watts
- Mega Watt Hours per year
- North West Pipeline
- National Balancing Point
- Non - Daily Metered
- Network Development Statement
- Network Emergency Coordinator (in GB)
- National Energy Efficiency Action Plan
- Network Emergency Manager (in the ROI)
- National Grid
- Natural Gas Emergency Manager
- National Gas Emergency Plan
- Natural gas Vehicle
- Natural and Bio-gas Vehicle Association (EU)
- National Heritage Area
- Northern Ireland
- Northern Ireland Authority for Utility Regulation
- National Standards Authority of Ireland
- National Transmission System (in GB)
- Open Cycle Gas Turbine
- Office of the Gas and Electricity Markets (UK)
- Odour Intensity
- Per Annum
- Polyethylene
- Pressure Maintenance Agreement
- Public Service Obligation
- Premier Transmission Ltd
- Pipeline to the West
- Residential
- Republic of Ireland
- Remote terminal units
- South / North Pipeline
- Special Areas of Conservation
- Supervisory Control and Data Acquisition
- Standard Dimension Ratio
- Sustainable Energy Ireland
- Single Electricity Market
- Statutory Instrument
- Scotland Northern Ireland Pipeline
- South North Pipeline
- System Operators Northern Ireland
- Security of Supply
- Special Protection Areas
- Structured Query Language
- Short Run Marginal Cost
- South West Lobe
- South West Scotland On Shore
- Tonnes of carbon dioxide
- Transmission Development Statement
- Total Final Consumption
- Task Force on Emergency Procedures
- Third Party Access
- Total Primary Energy Requirement
- Transmission System Operator
- Terra Watt hours per year
- Transmission System
- United Kingdom
- Voltage
- Year
61

Gasworks Road,
Cork, Ireland
Tel 021 500 6100
Email info@gaslink.ie
www.gaslink.ie
62