Privatisation in Ireland: The Divestiture of Bord Gáis Energy
Commission for Regulation of Utilities Water and Energy - … · 2019. 1. 24. · Bord Gáis Energy...
Transcript of Commission for Regulation of Utilities Water and Energy - … · 2019. 1. 24. · Bord Gáis Energy...
1
Networks Tariff Liaison Group Meeting
18th & 19th September 2018
Location: Ashling Hotel Dublin
1. Background & Context
The CRU (CEPA consultancy support) and GNI (Frontier consultancy support)
presented on the slides attached below.
Slides below discussed.
180913 TAR NC NTLG 1&2 - slides.pdf
List of attendees
180927 NTLG Attendee List 18Sept18.pdf
180927 NTLG Attendee List 19Sept18.pdf
2. Reference Price Methodology (RPM)
CEPA presented principles in TAR NC and those which underpinned previous tariff
reform.
Broad support for proposal of maintaining Matrix RPM.
From later discussions: Shannon LNG raised possibility of multiplicative rescaling,
with support from Pardus and counter argument from SSE on the basis that the
additive approach maintained the diversity premium between the entry points. CEPA
queried why this would be a better approach in the context of the principles.
CEPA asked for feedback on the material presented and the expectations of
participants. Manx Utilities stated that they were supportive of the approach taken and
noted that all aspects of RPM didn’t need to be reopened. Bord Gáis Energy stated
that they were supportive of the RPM as tariffs have been stable to date and worked
as expected. SSE echoed this view. Electroroute stated that market is changing and
that needs to be considered.
2
Action:
o Frontier to examine effect of the rescaling approach for next NTLG and provide
an optional LNG discount functionality so that the effects can be modelled.
3. Entry/Exit split
CEPA presented background and TAR NC position.
Broad support for proposal of maintaining split.
4. Multipliers & Seasonal Factors (M & SF)
CEPA presented TAR NC principles and current multipliers.
CEPA highlighted the effect of moving the multipliers into the bounds of 1-1.5.
Vermilion questioned whether each individual month had to be within the range. CEPA
to review.
CEPA indicated the effect of moving to the TAR NC calculation and the flattening of
the profile. Potential trade off in terms of the principles set out in Art. 28.
Potential for further reduction in multiplier bounds post-2023 was raised and if
transition has been considered. CEPA stated that if any change was significant a
transition would be considered, also there is a possibility to update annually through
the Art 28. consultation.
SSE highlighted that the effect on different customer types should be examined, e.g.
milk drying in summer and whether the rationale of when the M&SFs were set still
holds.
Electroroute questioned how the multipliers would transition to full compliance by 2023.
From later discussions: This topic was discussed further under the Demands
segment. CEPA raised the influence of M&SF on the demand calculations. Also
changing M&SF may lead to a change in shipper behaviour. The effect of M&SF on
LNG was discussed.
Actions:
o CEPA to review Vermilion’s query on whether each individual month has to be within the range.
o GNI to provide information on the level of short term bookings. Quarterly multipliers to be considered. Transition to full compliance by 2023 to be considered.
5. Initial Modelling results
Frontier presented initial modelling results and outlined that a detailed model
walkthrough will be provided at the next NTLG.
3
6. Demands
GNI presented the methodology for demand forecasts.
Vermilion queried the merit order. GNI stated that Moffat is assumed to be the marginal
source but open to input from participants.
Vermilion highlighted that multiple gas sources should increase overall bookings as
bookings will be less optimised. GNI stated that is possible but total bookings are
assumed stable over all scenarios.
Action:
o IOOA queried why 19/20 demand is much higher than 18/19. GNI to review.
7. Expansion constant and Annuitisation factor
GNI presented updates to both.
IOOA queried index and stated that full SWSOS costs should be used. GNI stated that
HICP is used and that PC4 allowance was included. GNI to update SWSOS costs to
reflect the gross estimated cost (i.e. including grant) as outlined in the PC4 decision.
IOOA highlighted previous discussions with GNI and the difference between actual
flow on linkline and modelled flow. GNI stated that it is a theoretical flow and therefore
not suitable for comparison with individual pipes.
IOOA queried whether GNI could calculate the dry expansion constant to reflect the
actual flow on the network for comparison against the theoretical flow calculation. GNI
to consider.
IOOA requested that the 2015 expansion constant and annuitisation factor calculations
are circulated so that the updates can be reviewed.
IOOA raised the possibility of indexing annually. GNI stated that they are open to
annual indexation.
SSE highlighted that in five years it may no longer be appropriate to send an expansion
signal, in that the methodology itself may not be appropriate for Ireland in terms of
sending entry signals (if no new entry was required).
Vermilion questioned the methodology for how fuel opex costs are determined.
GNI/CRU to review the methodology and update calculation to take account of 2018
gas prices.
Pardus pointed out that LNG compression is carried out upstream and that this should
be considered when reviewing the fuel opex methodology, Ormonde Organics (OO)
stated that this is also the case for biogas. GNI noted that Corrib also compresses
upstream.
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Action:
o GNI to update SWSOS costs to reflect the gross estimated cost (i.e. including
grant) as outlined in PC4 decision
o GNI to circulate 2015 expansion constant and annuitisation factor calculations.
o GNI/CRU to further consider as part of this NTLG process updating the
annuitisation factor methodology to take account of 2018 gas prices.
o GNI to provide information with respect to the compressibility calculation.
o GNI to consider annual indexation of expansion constants.
8. VRF
CEPA presented on VRF; its view on network codes, principles, and requested
feedback on the role of VRF in the Irish gas market.
SSE queried firm price to which discount is applied. GNI stated that this could either
be applied to Moffat entry or Moffat exit which has been built into the model. SSE of
view that it should be applied to Moffat entry, as VRF wouldn’t exist without Moffat
forward flows (FF). SSE also indicated that from the perspective of the EU target
model, the European Commission views forward and virtual reverse flow as being in
competition in terms of gas wholesale price discovery.
ElectroRoute’s interpretation of the TAR NC is that the probability of interruption should
be applied to the direction of the product it refers to. If talking about Moffat Entry, then
probability of interruption should be applied to the forward product, as opposed to a
virtual reverse product. Following same logic, probability of interruption for VRF
product in Moffat should be applied to Moffat Exit.
ESB stated that VRF gives domestic production a route to exit and access to a more
liquid NBP.
IOOA stated that if the price is too high no one will use it, resulting in swaps which may
then reduce capacity bookings.
GNI stated that everyone has different uses for it, e.g. balancing, domestic shippers
exporting.
GNI stated that seasonal influence shouldn’t reflect probability of interruption as its
availability is based on FF nominations increasing over the day.
Equinor requested that probability of interruption is analysed over 12 months. GNI to
examine this.
CEPA highlighted that economic “A” factor may need to be transitional. Nephin stated
that it has to be cost-reflective.
SSE stated that if other examples of VRF pricing is to be examined CRU should
consider if the interconnectors are merchant as that would not be a like for like
comparison. SSE noted that the intent of the TAR NC is to capture and remunerate
TSO regulated assets and not merchant interconnectors.
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Action:
o GNI to examine probability of interruption over 12-month period.
o CEPA to reflect on discussion and present findings at NTLG 3.
9. Entry point discounts (LNG)
CEPA presented the principles and context of discounts within the TAR NC.
Discussion of impact of LNG on wholesale gas price vs Moffat setting price as marginal
source.
Shannon LNG and Pardus requested the inclusion of LNG discounts in the model.
Discussion on LNG Security of Supply (SoS) benefit. SSE indicated that a SoS issue
would have to be identified by CRU as the competent authority and GNI as the NGEM
before a discount for LNG should be considered.
CEPA asked for feedback on importance of locational signals. OO stated it doesn’t
effect biogas production signal, may influence injection point. SSE highlighted the
importance of diversity premium last time and that it incentivises new entry being close
to demand centres and that there should be no preferential treatment for a certain type
of new entry. SSE also noted that where a discount on top of the diversity premium
was applied, this would have the effect of leading to a higher wholesale price in Ireland.
Action:
o GNI to include an optional discount for LNG entry point in the model with a view
to informing results for consultation.
10. Small scale entry
CEPA presented on possible treatment of small scale entry.
GNI note it’s important to take into account scale as there could be many small-scale
entry points.
Ceres note that in the UK most biogas production is Dx connected and locate where it
is technically viable with required demand. Tend to avoid trucking gas as it’s not
economic. Of view that locational signals wouldn’t be a factor in commercial decision
making relative to overall cost of project and that simplicity is important to producers.
Action:
o CRU to consider discussion and present at NTLG 3.
o CRU/GNI committed to analysing notional point for biogas entry.
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11. Capacity/commodity split
CEPA presented on current approach and TAR NC with GNI presenting the impact
assessment. GNI will circulate their impact analysis to participants.
Vermilion believe optimisation of bookings would be required in analysis. GNI note
these are the extremes so the answer lies somewhere in between the two.
Tynagh believe 80:20 should be examined. CEPA highlighted that this would be
difficult to justify as cost-reflectivity is key component of TAR NC and capacity is the
network cost driver.
Vermilion raised issue of shrinkage being smeared across entry regardless of fact that
Corrib already compress upstream. Nephin agree those who cause costs should incur
them. Pardus of view this needs to be considered.
SSE highlighted importance of considering domestic customer. NDM must book 1in50.
SSE also noted that whilst there was guidance from Europe the purpose of the TAR
NC was to ensure a robust consultation process, which the NTLG process was so that
each Member State drove a decision that was right for its own particular
circumstances.
Tynagh note that balancing market price will be lower in ISEM, reducing ability of
powergen to recover short run marginal cost. The comment was in support of lower
capacity percentage.
GNI confirmed that the 90:10 capacity/commodity split is applied to the Allowable
Revenues which are mostly fixed and not variable costs.
Actions:
o GNI to circulate capacity/commodity impact analysis to participants.
o Shrinkage to be examined further.
12. Next Meeting
The next NTLG is scheduled to meet on 9th October 2018 in the Crowne Plaza
Dublin Airport, Northwood Park, Santry Demesne, Dublin 9.
www.cru.ie
Network Tariff Liason Group 1 & 2
September 18th and 19th 2018
TAR Network Code Workshop
www.cru.ie
Introduction
Update and goals for NTLG 1 & 2
1
Opening stakeholder forum on 8th of August.
CRU/GNI took stakeholder responses into account
GNI further developed model topology
Discussion informed agenda for NTLG 1 & 2
NTLG high-level goals
Over these two days the NTLG will examine the tariff structure and its parameters
NTLG participants feedback is essential to optimise for TAR-NC
This will inform preparation of impact analyses of potential changes, and a detailed examination of models at NTLG 3(Models to be scrutinised by CRU/CEPA and shared with participants at NTLG 3)
Page 2
OUTLINE OF THE WORKSHOP
Page 3
Outline of the workshop
Purpose
To ensure that the
interests of Irish gas
consumers are
protected…
…in the context of the
requirements set out
within the TAR Network
Code.
Page 4
Agenda
10:30 – 11:00 Introductions and outline of the day (CRU/CEPA)
11:00 – 12:00 High level model methodology (CRU/CEPA)
12:00 – 13:00 Presentation on tariff modelling (GNI/Frontier)
13:00 – 14:00 Lunch
14:00 – 14:30 Demands (GNI/Frontier)
14:30 – 15:15 Expansion constants and annuity factor (GNI/Frontier)
15:15 – 15:30 Break
15:30 – 16:45 Virtual reverse flow (CRU/CEPA)
16:45 – 17:00 Summary (CRU/CEPA)
17:00 End of day 1
Day 1
Page 5
Agenda
09:00 – 09:30 Re-cap (CRU/CEPA)
09:30 – 11:00 Treatment of new entry points (CRU/CEPA)
11:00 – 11:15 Break
11:15 – 12:00 Capacity/Commodity split (CRU/CEPA and GNI/Frontier)
12:00 – 13:00 Optional (contingency time and/or overall summary)
13:00 – 14:00 Lunch
14:00 – 15:00 Overall summary and way forward (CRU/CEPA)
15:00 End of day 2
Day 2
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METHODOLOGY AND KEY PARAMETERS
Page 7
Reference price methodology (RPM)
• The TAR NC does not specify a RPM that must be applied.
• It only requires that the chosen RPM is compared against the Capacity Weighted Distance (CWD) counterfactual.
• However, the TAR NC includes a number of principles (see Figure 1) that should be considered in determining an RPM.
TAR Network Code requirements
Source: ENTSO-G Implementation Document
Figure 1: TAR NC RPM design principles
ACER comments on other Member State tariff consultations refer to these principles.
Page 8
Reference price methodology (RPM)
There are many methodologies that an RPM could be based on. When the TAR NC was in development, five RPM options were considered.
RPM options
• Backward looking
• Tariffs are a function of capacity and distance from Entry to Exit
• Being considered for use in GB (9/10 UNC 0621 variants)Capacity weighted distance
• Forward looking *
• Tariffs are a function of capacity and distance from Entry to Exit
• Currently in use in IrelandMatrix
• Forward looking *
• Tariffs are defined relative to a virtual point on the system
• Existing methodology in GB
Virtual point (with two variants)
• Backward looking
• Tariffs equal regardless of location
• Proposed in consultation for both Netherlands and SwedenPostage stamp
* Unlike CWD and postage stamp, will not recover allowed revenues without secondary adjustments
Page 9
Reference price methodology (RPM)
CRU developed and consulted on proposals for choice of an RPM in 2015. The Matrix methodology was considered to have a number of advantages:
• Cost-reflectivity (locational signals): The matrix methodology can be used to provide locational signals through gas transmission tariffs (in contrast to ‘postage stamp’).
• Cost-reflectivity (forward looking signals): Stable/rising gas demand and the potential for new supply sources meant that forward looking signals were considered important.*
• Stability: Modelling identified greater stability of the tariffs across scenarios produced by the Matrix model relative to the CWD and Virtual Point methodologies.
• Transparency and predictability: The Matrix approach was considered more transparent than the Virtual Point methodology.
The Matrix methodology
* This drew on a decision made by CRU in 2012 that a forward-looking signal was most appropriate for the Irish context.
Matrix RPM developed to reflect the objectives and circumstances in Ireland.
Page 10
Reference price methodology (RPM)
The Matrix methodology
Initial position is to retain the Matrix RPM going forward.
The Matrix methodology was considered most appropriate for meeting the principles set out by CRU, and in the context of the Irish market.
These principles are broadly aligned with those contained in the TAR NC. The key issues that led to 2015 CRU decision continue to apply:
• Stable / rising gas demand
• New supply sources
• Matrix RPM provides stability of tariffs / tariff differentials
ACER framework guidelines noted that ‘incremental costs may be appropriate in expanding systems, either resulting from an increase in demand, or triggered by a change in the general system sourcing’
Page 11
Entry/Exit split
TAR Network Code requirements
• The TAR NC does not specify an appropriate Entry/Exit split.
• It only specifies that the CWD counterfactual should have a 50/50 split.
Existing position
• In 2015, CRU originally consulted on a 50/50 split.
• Decided to introduce a 33/67 split based on the following:
• This split better reflected GNI’s asset and revenue split.
• Reduced the potential for redistributive effects on certain network users.
Initial position
Initial position is to retain the status quo.
Page 12
Multipliers and seasonal factors
• TAR NC sets out that multipliers and seasonal factors should consider the following:
• Balance between facilitating short-term gas trade and long-term investment signals.
• The impact on transmission services revenue and recovery.
• The need to avoid cross-subsidisation and enhancement of cost-reflectivity.
• Situations of physical and contractual congestion.
• Facilitating economic and efficient utilisation of infrastructure.
• TAR NC also contains requirements for limits on multipliers for short-term products.
TAR Network Code requirements
Page 13
Multipliers and seasonal factors
TAR Network Code requirements
Source: ENTSO-G Implementation Document
NB: The ‘Post April 2023’ requirements are dependent on ACER publishing a recommendation
Figure 2: TAR NC multiplier requirements
Page 14
Multipliers and seasonal factors
• Existing multipliers and seasonal factors have developed over a number of years.
• They are based on a fundamental methodology which accounts for the likelihood of the top 5 – 25 gas demand days occurring in a given month.
• Daily tariffs are then defined as a percentage of monthly tariffs, with a further disincentive included to encourage longer term bookings.
• Updates over the years which have:
• Reduced the monthly tariffs to encourage use of short-term products.
• Introduced a quarterly capacity product as a simple sum of the respective monthly tariff.
Existing approach
Product Multiplier In bounds of TAR NC?
Daily 2.89 Yes
Monthly and quarterly 1.55 No
Page 15
Multipliers and seasonal factors
• Existing methodology is in line with the principles set out within the TAR NC while possible alternatives raise issues.
• At a minimum, we intend to bring the multipliers within the bounds of that required in the TAR NC.
• We seek NTLG views on additional changes that should be made to ensure enduring stability of the arrangements:
Initial position
Does the underlying analysis need to be updated?
Do changes in gas demand profiles need to be incorporated?
Are any other changes necessary?
Still based on 2007 analysis but to what extent does this need to
reflect changing demand patterns?
For example, the use of gas capacity in the summer to meet falls in wind generation output.
Quarterly seasonal factors are compliant but are a simple arithmetic mean. Is change
needed to this?
Page 16
Multipliers and seasonal factors
Impact
Figure 3: Current profile Figure 4: Multiplier limits
Source: GNI Source: GNI
The impact of moving the multipliers into the bounds of the TAR NC is relatively small.
35.3%
13.2%
34.2%
12.8%
1.0% 1.0%
17.6%17.1%
25.6%
12.8%
29.9%26.5%
13.2%
30.9%
Page 17
Multipliers and seasonal factors
Further changes?
Source: GNI
Figure 5: Potential for flattening of profile
• Further changes to
reflect TAR NC and
changing Irish context
may lead to a
flattening of the
seasonal profile.
• To what extent would
this be desirable?
18 September 2018
Model for NC TAR consultation
NTLG workshop
19frontier economics
Contents
1. Modelling exercise 3
2. Expansion constant and annuitisation factor 10
20frontier economics
1. Modelling exercise 3
2. Expansion constant and annuitisation factor 10
21frontier economics
The model is being prepared to inform the NC TAR consultation
Implementation of the
methodology as outlined in
CER/15/140, i.e. matrix approach
Implementation of counterfactual
methodology outlined in NC TAR,
i.e. capacity weighted distance
approach
Implemented for 5 years (19/20 to
23/24) and different supply
scenarios
Main characteristics of the model
Building on the existing tariff
model, but adjusted for the
purpose of this consultation
22frontier economics
This model will be made publicly available for stakeholders
Allows users to tweak or define
their own booking scenariosParameters are flexible
Opportunities and options for the users
Understand and replicate
calculations made as part of the
consultation process
As part of this process we will
provide guidance and a
workshop on how to use the
model
23frontier economics
There is a range of inputs needed for the tariff calculation
Inputs on revenue recovery
Allowed revenue
Entry-exit split
Capacity-commodity splitCapacity-commodity split
Inputs on network development and
useInputs on costs
Expansion constant
Annuitisation factor
Network topology
Projected bookings
24frontier economics
For today we have applied assumptions for these inputs. Stakeholders
will be able to input their own assumptions (1/3)
Inputs on revenue recovery
Allowed revenue
Entry-exit split
Capacity-commodity split
Assumptions used
Updates to PC4 allowed revenue
33-67
as per CER/15/140
90-10
as per CER/15/140
Stakeholders can input other
assumptions
Additional information
More detailed presentation to follow
as part of NTLG agenda
25frontier economics
For today we have applied assumptions for these inputs. Stakeholders
will be able to input their own assumptions (2/3)
Inputs on revenue recovery
Expansion constant
Annuitisation factor
Assumptions used
€7782 (per GWh/Km)/€8783 (per
GWh/Km)
Updated inputs into methodology
applied for CER/15/140
9.8%
Updated inputs into methodology
applied for CER/15/140
More detailed presentation to follow
as part of NTLG agenda
More detailed presentation to follow
as part of NTLG agenda
Stakeholders can input any
assumptions
Additional information
26frontier economics
For today we have applied assumptions for these inputs. Stakeholders
will be able to input their own assumptions (3/3)
Inputs on revenue recovery
Network topology
Projected bookings
Assumptions used Additional information
Updated topology to include
network expansion and VRF
Updated aggregated bookings Being completed
Stakeholders can input other
assumptions
Testing and verification process
ongoing
27frontier economics
We have run the model to allow for an assessment of the preliminary
results using the following three scenarios
Entry from:
▪ Moffat
▪ Bellanaboy (Corrib)
▪ Biogas
▪ Innisfree (from 21/22)
▪ Inch
Scenario 3Scenario 1
Entry from:
▪ Moffat
▪ Bellanaboy (Corrib)
▪ Biogas*
▪ Inch
Scenario 2
Entry from:
▪ Moffat
▪ Bellanaboy (Corrib)
▪ Biogas
▪ Foynes (from 21/22)
▪ Inch
*User is able to run sensitivities without biogas, see also next slide
28frontier economics
Potential scenarios to be considered in the consultation process and
expected bookings
28
Scenario 1
19/20 - 23/24
Exits
Moffat
Bellanaboy
Inch
Biogas
Foynes
Innisfree
Scenario 2
19/20 - 23/24
Scenario 3
19/20 - 23/24
Projected
bookings 18/19
(for reference)
128
Bookings above represent Annualised GWh’s
82
6
280
152-207
81-45
0-5
4-0
280-300 280-300 280-300
4-0 4-0
0-5 0-5
81-45 81-45
152-101
0-106
152-22
0-185
• Table represents supply range at individual
entry points (Moffat, Bellanaboy, Biogas,
Inch, Foynes, Innisfree)
• Table also represents aggregated demand
range at exits
• Bookings in table represents Annualised
GWh’s
• Range of supply/demand is over 5 year
period (e.g. for Scenario 1, Moffat supply
increases over the 5 year period from 152
GWh’s in 19/20 to 207 GWh’s in 23/24)
• Red circles in table represent entry points
that are not included in certain scenarios
(e.g. Foynes excluded for Scenario 1 & 3,
included in scenario 2)
• Scenarios for modelling and presentation
purposes – users will have flexibility to input
other assumptions within models
29frontier economics
The preliminary results based on the working assumptions suggest that
future tariffs are in line with current tariffs, but moving with bookings
Because of its relatively small
volume the introduction of
biogas leads to changes in
the other entry tariffs of less
than €1 in 19/20 and less
than €5 in 23/24
In this scenario the tariffs fall
over time because more gas
is being imported through
Moffat. Moffat has the highest
tariff (excluding the Linkline
element). This means that the
price per booking for all entry
points can go down when
more bookings pay this
higher tariff
LinkLine
element
Current tariffs (17/18) Scenario 1 (19/20) Scenario 1 (23/24)
30frontier economics
For the different scenarios we also observe that projected tariffs are close
to current tariffs, with limited variation between scenarios
€0€100€200€300€400€500€600€700€800
Matrix Approach - 2021/22
Scenario 1 Scenario 2 Scenario 3 Current tariff
Difference
between
scenario 1 and 2
just over €1002020/21
Difference
between
scenario 1 and 2
just over €100
Difference
between
scenario 1 and 2
just over €100
Difference
between
scenario 1 and 2
just over €100
Again we observe that a
movement away from Moffat
bookings increases tariff levels
for all points. In scenario 2 more
bookings move away from Moffat
than under scenario 3
31frontier economics
Within the scenarios the tariffs remain stable after new entry has occurred
€ 0
€ 100
€ 200
€ 300
€ 400
€ 500
€ 600
€ 700
€ 800
2019/20 2020/21 2021/22 2022/23 2023/24
MA - Scenario 3
Bellanaboy Innisfree Moffat Foynes
Biogas Inch Gormanston Exit
€ 0
€ 100
€ 200
€ 300
€ 400
€ 500
€ 600
€ 700
€ 800
2019/20 2020/21 2021/22 2022/23 2023/24
MA - Scenario 2
Bellanaboy Innisfree Moffat Foynes
Biogas Inch Gormanston Exit
In both of these scenarios we
assume new entry takes
place in 21/22,and a shift in
tariffs occurs. After this shift
the tariffs are stable.
Another way to interpret this
is to say that in 19/20 and
20/21 all scenarios are the
same
Scenario 2
Scenario 3
32frontier economics
€0€100€200€300€400€500€600€700€800
Matrix Approach - 2021/22
Scenario 1 Scenario 2 Scenario 3 Current tariff
The modelling considers a number of anticipated developments. Users
will be able to adjust these as they see fit
For entry potentially
requiring NTS
connections we apply
simplified NTS charges.
For entry potentially
requiring NTS
connections we apply
simplified NTS charges
2020/21
33frontier economics
The model allows for a comparison with the CWDA methodology
€0€100€200€300€400€500€600€700€800
CWDA - 2021/22
Scenario 1 Scenario 2 Scenario 3
The level of the tariffs
under CWDA is
comparable to the level
of tariffs using MA when
the same parameters
are used
The user can set the
parameters
Current tariff
34frontier economics
1. Modelling exercise 3
2. Expansion constant and annuitisation factor 10
35frontier economics
We provide a high-level discussion to explain how the concepts relate to
each other and their impact. A detailed discussion of each concept will follow
Expansion constant:
Unit costs of expanding the
system to allow one unit (GWh) of
gas to flow over a distance (km) Onshore expansion constant
Offshore expansion constant
Annuitisation factor :
Factor (%) to convert the
investment costs into annual costs
per GWh/km
Finance costs
Operating costs
36frontier economics
The LRMC costs all routes are determined using these concepts
Route A to B
200 km
offshore
100 km
onshore
€7,782
Onshore expansion constant
€8,783
Offshore expansion constant
Costs per GWh/km CAPEX for route per GWh
9.8%
Annuitisation factor
LRMC per GWh for route per
year
€1,756,600
€778,200
Annual costs as % of CAPEX
€2,534,800
€248,410
37frontier economics
The annual costs for all routes are the basis for the calculation of the tariff
in the matrix approach
Tariffs cannot be set by route, so the MA
approximates the costs with the
combination of entry and exit tariffs
A C E
B
D
€248,410 €200,000 €300,000
€400,000 €300,000 €200,000
38frontier economics
Higher expansions constants and a higher annuitisation factor will increase
the cost differences between routes, and differences between tariffs
Base caseRoute C to B
Route C to D
Higher
expansion
constant
Higher
annuitisation
factor
DistanceExpansion
constant
Higher
annuitisationCost of route
€10,000 10%200 km
300 km
Simple values assumed for
illustration
€200,000
€300,000€100,000
Difference
Route C to B
Route C to D
€20,000 10%200 km
300 km
€400,000
€600,000€200,000
Route C to B
Route C to D
€20,000 20%200 km
300 km
€800,000
€1200,000€400,000
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Economics Ltd.
Demand Methodology for Tariff Calculation
18th September 2018
Introduction
• Forecasts of Capacity and Commodity at Entry and Exit used to calculate Transmission Tariffs within the Matrix model
‒ These forecasts represent a commercial view of capacity and not physical peak flow.
• Peak day flows of the relevant exit points within the model are used to apportion demand geographically - these weightings are then applied to a commercial forecast for use in the calculation of the Exit Tariff.
‒ Exit points are identified and peak day flows are assigned based on a combination of actual and forecast data.
‒ Some exit points represent a number of smaller non daily metered exit points.
41
Demand Forecasts
• When forecasting capacity and commodity
demand is split into three sectors, Power,
Industrial/Commercial and Residential
• The following underlying demand
assumptions drive the forecast:
▪ Power driven by assumptions around
electricity demand, renewables, price of
coal, constraints, interconnector flows.
▪ Industrial & Commercial driven by
historic demand, GDP and forecasted
commercial growth
▪ Residential driven by historic demand,
forecasted growth, efficiency
➢ Non Daily Metered (NDM) required to
book for a 1-in-50 gas year.
42
Power58%
I&C29%
Residential13%
2017 Demand (Non Weather Corrected)
Power I&C Residential
Supply Forecast
• Supply is forecast using a merit order
assuming demand is met by indigenous gas
first. It is assumed in the modelling that the
following merit order will exist
‒ Indigenous Renewables (Biogas)
‒ Indigenous Production (Corrib and
Inch)
‒ LNG
‒ Moffat
• Actual flows based on commercial
arrangements between Shippers and
Producers.
• In 2017 61% of demand was met by Corrib43
Inch7%
Corrib61%
Moffat32%
2017 Supply
Inch Corrib Moffat
Annualised Capacity
• Shippers book capacity using Annual, Quarterly, Monthly, Daily and Within-Day products.
• Once demands are forecast GNI next estimate the least cost solution to booking capacity –this will result in a combination of short-term bookings at Entry and Exit
‒ The calculation of capacity considers shippers past behaviour including trades at entry because the price of these products is derived as a multiple of the annual tariff
• Short-term prices are a multiple of the annual tariff – As such, to derive this annual tariff, Short-term bookings are annualised for input into the Matrix model.
‒ This process uses the current multipliers to give the short-term booking a weighting to convert it into an equivalent booking. See following example
▪ Forecast of daily bookings in June = 200,000MWh
▪ Daily Multiplier for June = 0.661765%
▪ Annualised equivalent = 200,000MWh * 0.661765% = 1,324MWh
44
Key Points
• Forecasting the demand for capacity and commodity requires multiple approaches and will depend on the market segment
• Exit forecasts need to consider Power, I&C and NDM
‒ NDM required to book for a 1-in-50
• Entry will take account of what is required at exit but will also look at Trades at the entry points
• Shippers have a variety of products, including Annual, Quarterly, Daily, Within-Day and Entry trading
45
Expansion Constant & Annuitisation Factor Review
Network Analysis
TAR NC Workshop
18th September 2018
Contents
• Expansion Constant Calculation Results
• Expansion Constant – Background and Approach to Calculation
• Expansion Constant – Components and Results
• Changes to GNI Network – Impact on Modelling
• Summary / Conclusion
47
Expansion Constant Calculation Results
• The purpose of the Expansion Constant is to provide a numerical value to the cost of expanding the capacity of the system so that one unit of gas can travel over a specified distance (€/GWh km)
• Requirement for Inputs and Assumptions to be Stable, Transparent and Enduring
• Expansion constants have been updated to account for both inflation and recent changes on the transmission network (2015 to 2018)
• Results in table below;
48
Expansion Constant – Background & Approach toCalculation
• The purpose of the Expansion Constant is to provide a numerical value to the cost of expanding the capacity of the system so that one unit of gas can travel over a specified distance (€/GWh km) 1
‒ Forward-looking approach based on the Matrix Expansion Constant (MEC) methodology2
• The methodology for calculating expansion constants is based around 2 key components:
‒ The pipeline cost of expanding capacity on the network
▪ Pipeline cost is related to the capacity of the pipeline, which in turn is related to the pipeline parameters
‒ The cost of compression (energy) required to move the gas through the pipeline
▪ In order for there to be any flow in a pipeline, the gas must be raised to the head pressure in the first place. The cost of compression is in large part determined by the size (or motive power) of the compressor
• In CER/14/455 the CRU considered it appropriate to consider applying two distinct expansion constants, namely a “wet” and a “dry” expansion constant.
• The expansion constant is calculated for each pipeline size.
• A wet expansion constant is calculated by taking the average of the expansion constants for each pipeline size
• A dry expansion constant is calculated by taking the weighted average of the expansion constants for each pipeline size
49
1 Actual Project Costs need to be determined on a case by case basis
2 CER/15/057 Decision on Future of Gas Entry Tariff Regime
𝐸𝑥𝑝𝑎𝑛𝑠𝑖𝑜𝑛 𝐶𝑜𝑛𝑠𝑡𝑎𝑛𝑡 =𝑃𝑖𝑝𝑒𝑙𝑖𝑛𝑒 𝐶𝑜𝑠𝑡 + 𝐶𝑜𝑠𝑡 𝑜𝑓 𝐶𝑜𝑚𝑝𝑟𝑒𝑠𝑠𝑖𝑜𝑛
𝑃𝑖𝑝𝑒𝑙𝑖𝑛𝑒 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦
Expansion Constants - Components and Results
• Calculation of Wet Expansion Constants (2018 results)
50
• Calculation of Dry Expansion Constants (2018 results)
51
Expansion Constants - Components and Results
Impact of Network Changes on Modelling
52
• Changes to the GNI Transmission Network since CER/15/057:
Network Element Impact on Tariff Modelling
Twinning of the South West Scotland Onshore System (PCI 5.2) is
currently in the construction phase
Additional 50 km of 900 mm pipeline will be
accounted for in the weighted average of the ‘dry’
expansion constant
Extension of the gas network to:
• Nenagh, Co Tipperary
• Wexford Town, Co Wexford
• Listowel, Co Kerry
Tx Matrix Model will be updated to incorporate
distance between entry and exit points (offtake points
to new DX networks)
Mungret to Inchmore transmission pipeline replacement Tx Matrix Model will be updated to incorporate
distance between entry and exit points
Gas to Glanbia transmission pipeline Tx Matrix Model will be updated to incorporate
distance between entry and exit points
• Update to ‘Pipeline Cost’ and ‘Cost of Compression’ since CER/15/057:
‒ Project costs have been re-indexed to 2018 value
Summary / Conclusion
53
Questions & Feedback welcome
• Expansion Constant - provides numerical value to the cost of expanding the capacity of the system
so that one unit of gas can travel over a specified distance (€/GWh km)
• Inputs and Assumptions - Stable, Transparent and Enduring
• Retention of 2 specific Expansion Constants (Wet & Dry)
• Exp. Constants updated for inflation and recent changes on the transmission network (2015 to
2018)
54
Annuitisation Factor
• Annuitisation Factor (%) is the annual payment made to remunerate the return of and on capital plus associated
operating costs of delivering gas to the system, while taking account of the depreciation profile of an asset
• Annuitisation Factor formula – WACC * (Pipeline CAPEX & Pipeline OPEX) + WACC * (Compressor CAPEX &
Compressor OPEX) + Fuel Costs + Depreciation
• Annnuitisation Factor updated for PC4 allowed WACC - 4.63% vs 5.2% as per previous calculation
• Decrease in WACC accounts for 0.4% of the total 0.7% reduction in the A.Factor % from previous number
• Further areas of review include updating Pipeline & Compressor CAPEX and Fuel OPEX
• Fuel OPEX – Cost which feeds into overall A.Factor calculation
• Fuel OPEX - Updated cost €9.88m vs €10.8m (based on all known updates to calculation)
• Areas reviewed include - Compression required (MW’s)/Average gas consumption volumes for compressors/Gas prices
Annuitisation Factor calculated at 9.80% (or €9.80 per €100 initial CAPEX) vs 10.50% as per previous calculation
Page 55
VIRTUAL REVERSE FLOW
Page 56
Virtual reverse flow (VRF)
• The TAR NC does not explicitly refer to VRF.
• However, it does contain requirements for the treatment of interruptible products.
• ENTSO-G has subsequently set out its interpretation of VRF as an interruptible product in the context of the TAR NC.
• The TAR NC contains two options for the treatment of interruptible product tariffs:
TAR Network Code requirements
‘Ex ante’ discounts
• Applied wherever interruption
has occurred in previous year
• Applies a forward looking
adjustment to tariffs
‘Ex post’ discounts
• May be applied where no
interruption has occurred in
previous year
• Provides ex post compensation
where interruption occurs
Page 57
Virtual reverse flow (VRF)
• The Moffat VRF product has been interrupted in the previous year.
• As the Gormanston VRF product has not been utilised, no interruption has technically occurred.
• However, given the likelihood of interruption of a VRF product at Gormanstonthat was used, an ex ante discount approach appears most sensible for both products.
• CRU has also previously set out its intention to move from the existing registration fee to a VRF tariff which reflects the probability of interruption.
• The ex-ante discount should be calculated as follows:
𝐷𝑖𝑒𝑥−𝑎𝑛𝑡𝑒 = 𝑃𝑟𝑜 × 𝐴 × 100%
• Where ‘Pro’ is the probability of interruption (0 ≤ Pro ≤ 1); and
• ‘A’ is an Adjustment factor (1 ≤ A).
Ex ante discounts
Page 58
Virtual reverse flow (VRF)
• There is a formulae for determining ‘Pro’ in the TAR NC:
𝑃𝑟𝑜 =𝑁 × 𝐷𝑖𝑛𝑡
𝐷×𝐶𝐴𝑃𝑎𝑣.𝑖𝑛𝑡𝐶𝐴𝑃
• N is the expectation of the number of interruptions over D
• Dint is the average duration of the expected interruptions expressed in hours
• D is the total duration of the interruptible capacity product in hours
• CAPav.int is the expected average amount of interrupted capacity for each interruption
• CAP is the total amount of interruptible capacity
• The TAR NC does not prescribe what can or should be incorporated into the A factor.
• ENTSO-G give the example of the need for hedging against the probability of interruption which may be necessary to incorporate
The ‘Pro’ and ‘A’ factors
Page 59
Virtual reverse flow (VRF)
• Assuming the definition of VRF as an interruptible product as interpreted by ENTSO-G, there are two key issues:
1. How to determine the probability of interruption ‘Pro’?
a) How should seasonality be taken into account?
b) Is the formulae for calculation proportional in the Irish gas market case?
c) How should this be estimated given recent introduction of the VRF product?
d) How should this be determined at Gormanston where there is no experience of product use and interruption?
2. What should be included in the adjustment factor ‘A’?
a) The need for hedging against interruption?
b) Anything else?
Key issues
Page 60
Virtual reverse flow (VRF)
• Further issues have been raised by stakeholders previously and will need to be considered:
• How do interactions with ‘swaps’ need to be taken into account?
• What impact do different options have on IBP liquidity?
• How should differences between the Moffat and Gormanston products be included?
Previous considerations raised by stakeholders
61
• Data sourced from GNI GTMS system
• Data period assumed to represent most relevant period for
analysis (introduction of Trading Platform Apr’18)
• Probability of interruption based on following formula;
• Above formula assumed as basis for initial application of
interruptible % to VRF tariff
• Initial approach doesn’t currently include an estimated
adjustment (A) factor
Probability of Interruption - Initial calculation
Assumptions
Number of days in period (Apr’18 – Aug’18) 144
Of which VRF allocations were recorded 121
Number of days where interruptions occurred 17
% of days interrupted (17/121) 14%
Potential tariff would be 86% of firm price (VRF Tariff X 86%)
Number of days where interruption(s) were experienced
Number of days where VRF allocations were recorded
Possible method of determining Interruptible %
Page 62
SUMMARY OF DAY 1
Page 63
SummaryDay 1
10:30 – 11:00 Introductions and outline of the day (CRU/CEPA)
11:00 – 12:00 High level model methodology (CRU/CEPA)
12:00 – 13:00 Presentation on tariff modelling (GNI/Frontier)
13:00 – 14:00 Lunch
14:00 – 14:30 Demands (GNI/Frontier)
14:30 – 15:15 Expansion constants and annuity factor (GNI/Frontier)
15:15 – 15:30 Break
15:30 – 16:45 Virtual reverse flow (CRU/CEPA)
16:45 – 17:00 Summary (CRU/CEPA)
17:00 End of day 1
Page 64
DAY 2
Page 65
Agenda
09:00 – 09:30 Re-cap (CRU/CEPA)
09:30 – 11:00 Treatment of new entry points (CRU/CEPA)
11:00 – 11:15 Break
11:15 – 12:00 Capacity/Commodity split (CRU/CEPA and GNI/Frontier)
12:00 – 13:00 Optional (contingency time and/or overall summary)
13:00 – 14:00 Lunch
14:00 – 15:00 Overall summary and way forward (CRU/CEPA)
15:00 End of day 2
Day 2
Page 66
RE-CAP
Page 67
TREATMENT OF NEW ENTRY POINTS
Page 68
Treatment of new entry points
The TAR NC allows for a number of adjustments to tariffs defined by the chosen RPM. Of relevance are:
TAR Network Code requirements
• At least 50% discount must be applied to storage
• Discounts may be applied to:
• LNG entry points
• Entry points ending isolation of a gas transmission system
Discounts (TAR NC, Article 9)
• Equalisation applies the same reference price to some or all points within a homogeneous group
• It takes place after determination of tariffs under the RPM (‘ex post’)
• E.g. domestic Exit points are currently equalised in Ireland
Equalisation (TAR NC, Article 6, 4(b))
• Allows for a group of homogeneous entry or exit points to be considered as one point for the determination of tariffs
• Can be applied to homogeneous points or to points which are located within the same vicinity
• The same tariff is identified within the RPM (‘ex ante’)
Clustering (TAR NC, Article 3 (19))
Page 69
Treatment of new entry points
• Other than storage, discounts may be considered under the TAR NC for:
• LNG entry points
• Entry points ending isolation of a gas transmission system
• The current Matrix RPM has been designed to balance a number of criteria, including transparency, stability, etc.
• One of the key criteria is the provision of locational signals for entry (supply) sources (new and existing) connected to the transmission system.
• Any provision of discounts would impact on these signals.
• For a given Entry/Exit split, it would also require an increase in the tariffs at other entry point tariffs and may therefore place upwards pressure on the wholesale gas price.
Discounts
We are interested in NTLG views on the need and justification for any discounts.
Page 70
Treatment of new entry points
• In future, it is possible that a number of small scale sources of gas supply (e.g. biogas) may enter onto different points across the transmission system.
• These supply sources may be in a position to make a choice about whether they connect to the transmission or distribution system.
• The interactions between the two are therefore important:
Small scale entry points
Transmission level
• Forward looking locational signal under the Matrix RPM
Differential between tariffs may lead to sub-optimal connection decisions.
Should there be some form of common treatment for these points at transmission level (e.g. some form of clustering) which allows for consistency with distribution entry tariffs?
Distribution level
• No locational signal
Page 71
CAPACITY/COMMODITY SPLIT
Page 72
Capacity/Commodity split
• The TAR NC specifies that tariffs should be capacity based with the exception of:
a) A ‘flow-based’ charge for covering the costs of gas flow quantities; and
b) A complementary revenue recovery charge for managing under and over recovery
• Many Member States are moving further towards capacity based charges:
• ACER approved the Netherland’s tariff design which recovered all revenues from capacity based tariffs.
• Sweden and Poland also intend to recover 100% of revenues from capacity charges.
• The Utility Regulator (NI) has set out its intention to move to 95% capacity based charging.
• Denmark appears as an outlier within its consultation, with an intention to recover only 52% of revenues from capacity charges. The Danish split is based on capex/opexwith capex recovered from capacity and opex from commodity charges.
TAR Network Code Requirements
Page 73
Capacity/Commodity split
• We are considering an appropriate capacity/commodity split between 90/10 and 100/0.
• We are interested in NTLG views on the following:
• How important is the direction of travel in Europe?
• …and particularly, interactions with neighbouring transmission systems – i.e. the 95/5 split suggested by the Utility Regulator?
• What might the impact be on the I-SEM for example?
• What are the distributional effects of increasing the proportion recovered from capacity charges?
• Informed by GNI’s impact analysis.
Considerations
Justifiable bounds somewhere between 90/10 and
100/0 for Ireland
90% 100%0%
Customer Impact Analysis Capacity Commodity Split
19th September 2018
• Tariffs currently designed to collect 90% of revenue through capacity tariffs and 10% through commodity tariffs
• High level analysis on impact of alternative split such as 95:5 and 100:0 split as outlined in the Tariff Network Code
• Conducted high level analysis using generic examples.
• Effect and result will vary depending on booking strategy
• Welcome discussion and feedback on this analysis
75
Review of Capacity/Commodity Spilt
• Assuming 18/19 demands the 18/19 tariff was re-run using both 95:5 and 100:0 capacity commodity split, all other things being equal.
• Load factor represents the relationship between a users average daily consumption and their peak day consumption. The higher the load factor the flatter the profile i.e. average usage closer to peak
• GNI looked at a user with an Estimated Annual Consumption (EAC) of 5,000,000 KWh and derived their profile using three different load factors
‒ 90% load factor
‒ 50% load factor
‒ 20% load Factor
• Looked at Transmission Transportation costs only.
• Assume Entry and Exit bookings match
‒ In reality Shippers can vary their bookings using aggregate profiles, trades etc.
• Repeated the analysis where the Shipper is assumed to book only daily
76
Analysis - Assumptions
Initial Findings Assuming Annual Bookings…..
95:5• 90% LF = -3.0%
• 50% LF = +0.5%
• 20% LF = +3.0%
100:0
• 90% LF = 5.0%
• 50% LF = 0.9%
• 20% LF = 6.0%
77
• In this analysis a customer with a 90%
load factor is likely to see a fall in
overall cost.
‒ Moving from 3% reduction under a 95:5
split to a 5% reduction with a 100:0
split.
• The higher the load factor the greater
weighting commodity has relative to
capacity
‒ As you move towards a zero
commodity charge the increase in
capacity charges will not offset the
reduction in commodity charge.
• Conversely the lower the load factor
the higher the cost will be as you move
towards a zero commodity charge
Initial Findings Assuming Daily Bookings…..
95:5• 90% LF = +2.0%
• 50% LF = +3.3%
• 20% LF = +4.3%
100:0• 90% LF = 4.0%
• 50% LF = 6.6%
• 20% LF = 8.6%
78
• In this analysis because the shipper is
booking all daily the commodity
weighting is not as large as in the
previous example
‒ In practice users are likely to book
a combination of annual and short-
term
• A move towards a zero commodity
charge suggests the cost increases
under all scenarios
‒ And also increases as the load
factor reduces
• Effect is dependent on individual booking behaviour and load factors of the Shipper/Customer
• Results will vary depending on individual analysis
• Can utilise their portfolio to reduce capacity costs through utilising a combination of capacity
products and trades at entry.
• However, from this analysis trends have emerged based on;
‒ the impacts that a users load factor has,
‒ the commodity used relative to booked capacity.
• Each individual Shipper/Customer will need to asses its own effects/impact
• Welcomes views and feedback on this analysis
79
Conclusion
Page 80
WAY FORWARD
Page 81
Way forward
• 9th October 2018: NTLG 3 – Discussion of key issues and tariff models
• Early November 2018: Consultation published
• Early January 2019: Consultation closes
• Early February 2019: Summary of responses published
• March 2019: Final decision published
• May 2019: Final tariffs published
Key dates
Thank you for your input
1
Networks Tariff Liaison Group Meeting
9th October 2018
Location: Crowne Plaza, Northwood, Dublin
1. Background & Context
The CRU (with CEPA consultancy support) and GNI (with Frontier consultancy
support) presented on the slides attached below.
Slides below discussed.
181009 NTLG 3 Slidedeck.pdf
List of attendees
181010 NTLG Attendee List 09Oct18.pdf
2. Review of minutes from NTLG 1&2
GNI presented an overview of the actions from NTLG 1&2.
IOOA noted that at the last NTLG it had queried whether GNI could calculate the dry
expansion constant to reflect the actual flow on the network for comparison against the
theoretical flow calculation. This was not reflected in the actions.
GNI responded that this will be covered off in the compressibility calculation.
3. Information on compression calculation
GNI presented on the compression calculation.
Vermilion highlighted that Corrib pay for their own upstream compression costs to
bring gas to 86 bara and that compression of entry points up to this pressure should
be reflected in the compressibility calculation.
GNI responded that this issue was debated through the 2015 process, noting that the
summary from that time was to maintain stability of expansion constants. GNI don’t
see a basis to revisit unless any new information is presented. The CRU believes
principles laid out in 2015 still holds and this will be further detailed in the
consultation paper.
2
Pardus questioned whether a new entrant would be expected to deliver gas at 86 bar
and whether the theoretical and actual costs could be compared.
GNI stated that it is a forward-looking approach (calculates the projected costs) and
any new costs are only known after a full tender has been completed. The purpose of
the calculation is to send economic signals.
SLNG stated that they take the view of Corrib. Would need more technical
background on the matter.
Nephin stated that it seems intuitively there is a mis-match between people putting
gas in at different pressures.
Pardus queried whether we can compare the historical costs that have been used for
the calculation and the actual costs.
GNI stated that to inform costs, GNI take the most recent historical project costs to
inform calculations.
Pardus highlighted that from an LNG perspective they will be providing compression.
GNI stated that even if it is dry expansion – there is a compressibility cost to ensure
operability of the gas transmission system. They also emphasised the importance of
considering a single transmission system for the purposes of designing the tariff
methodologies.
GNI restated that the issue is about marginal costs and the creation of locational
signals. They stated their view that no new information has been evidenced to
change the decision.
Pardus noted that there must be an opex saving from Corrib carrying out its own
upstream compression and that this should be reflected in the expansion constant
calculations.
CEPA stated that the tariff methodology is designed to reflect the economic costs of
the GNI system. The important consideration is about the differentials between
Moffat and the other entry points, including compression and how this impacts
competition between entry points.
Pardus requested that compression at LNG is taken into consideration going forward.
The CRU requested that participants respond in detail through the consultation
process if with any views and evidence that they consider should be taken into
consideration. On this matter, the CRU requested stakeholders to focus contributions
on the purpose of the dry expansion constants i.e. the theoretical expansion of the
onshore transmission network.
Frontier presented their review of the demand profiles used in the model, as actioned
by IOOA. Refer to Slide 12.
Vermilion requested that the Bellanaboy Entry Tariff be broken-down into the linkline
tariff element and the Cappagh South tariff element this should also be presented in
the consultation.
IOOA queried difference in capacity bookings (almost 20%) between this year and
that assumed for 2019-20.
GNI agreed with the need to consider the capacity bookings further and stated that
they are liaising with their demand team to finalise capacity booking estimates.
3
4. LNG and small-scale entry discounts
Frontier presented an explanation and impact assessment of a possible discount for
new entry points.
SLNG questioned whether there has been an analysis on the impact of cost to gas
consumer of a large-scale entry point such as an LNG entry point.
GNI stated that they would not have sight of gas sales agreements to carry out such
an impact analysis.
CEPA highlighted that as Moffat is the marginal source of gas it sets the wholesale
cost of gas. The analysis therefore implicitly includes consideration of the impact on
the gas market by applying the increased tariff to the full volume of gas bookings (i.e.
237 GWh), not only bookings on the Moffat interconnector.
Nephin pointed out that for an LNG project to alter the marginal source of gas the
assumption would have to be made that Ireland is disconnected from the GB market
which could only be the case if there were high levels of friction between IBP and
NBP.
IBEC noted that if LNG needed to be incentivised at some future time due to
concerns over security of gas supply, providing an entry point tariff discount would
potentially be more costly than a straightforward PSO support because it would raise
the marginal cost of all delivered gas. IBEC pointed out that there are no such
concerns at present, hence it is premature to consider instituting either option.
SLNG of the view that now is an appropriate time for the discussion of SoS benefits
of LNG.
RGFI discussed the PSO levy that is being collected from energy consumers. A PSO
fund should be used to support renewable gas projects as a lot of industries have
targets to be carbon neutral by 2030.
5. Multiplicative versus additive approach
Frontier presented an impact assessment of multiplicative rescaling versus additive
rescaling.
SLNG welcomed calculation of figures noting they are similar to figures they have
calculated.
SLNG stated that there are precedents in Europe of the multiplicative approach and
that these need to be considered in light of the principles of the TAR-NC.
6. Treatment of small scale entry points
CEPA presented a slide on key takeaways from last NTLG and key remaining issues.
Ormonde Organics (OO) questioned the purpose of having an interruptible product for
Biogas. The incentive should be for producers to get the maximum volume on the
system. There shouldn’t be a dis-incentive to connect to the Tx network which provides
firmer access. One also doesn’t want to be in the position of paying people to flare the
gas. Suggested there should be a cost on Distribution injection to counter
4
Transmission compression costs and to reflect the potentially non-firm nature of
capacity.
RGFI stated that any such problems should be identified beforehand through the
connections application process (i.e. either pipeline overloading or lack of demand
within a local network).
GNI responded that this was the case, however, there are two separate issues, i.e.
production and injection.
Ceres (Nephin’s advisor) indicated that, from its GB experience biogas producers are
very unlikely to want to or be able to build a business case around an interruptible
connection point. In the UK biogas producers receive a rebate for bringing on gas close
to customers (for avoiding transportation investments).
OO stated that if the proposed notional point is used it takes away the incentive for
producers to locate close to their customers whilst undermining the principle of sending
locational signals, adding that this applies to both Transmission and Distribution.
7. Virtual Reverse Flow (VRF)
CEPA presented on VRF, outlining considerations which may apply to a decision of
how high to set any discount to reflect the interruptible nature of the product.
GNI presented update on probability of interruption data which is set out in two ranges.
IOOA queried why there isn’t one seamless 12-month range of data.
GNI responded that they are waiting to retrieve data from old database which is time
consuming.
BGE questioned whether M&SF apply to the VRF based tariff.
GNI stated that the VRF product will be interrupted for technical reasons very rarely
when the new algorithm is put in place.
Nephin stated need to consider the market objectives of changing VRF product.
IBEC stated that the efficient use of the market is to the benefit of the consumer and
questioned what the effect would be on the consumer.
CEPA stated that currently VRF is a relatively cheaply priced product. If it moves to a
more expensively priced product – there needs to be an understanding of the trade-
offs and impacts on the market.
Energia stated that Shippers have had 3-4 years of a benefit from a low cost of VRF.
The regulator gave a commitment to address this within one year at that time and failed
to do so.
IOOA stated that it might be more applicable to use the Entry tariff as a basis when
calculating VRF.
Vermilion stated that the VRF product is completely different from a standard exit
product. For VRF it can be the case that on one day 40 GWh is available and next day
only 10 GWh, based on available forward flow. If initial 10 GWh is available and 5 GWh
is booked and in a later stage only 6 GWh is available, GNI stated that this is not an
interruption. These characteristics should be reflected in the A-factor.
5
IOOA added, that if the full forward capacity would have been offered, then there would
be an interruption every day.
GNI questioned what type of VRF charge would encourage a more liquid IBP.
Nephin stated that as a general principle, the more trading you can do, the more
liquidity you will have, and hence the more integrity in the price.
Energia stated that where there is a low level of liquidity, this shouldn’t be split across
markets.
IBEC stated that the only divergence from IBP and NBP is the wedge of transport costs
so whatever keeps that as low as is possible for customers is best.
IOOA stated that from the perspective of new entrants, VRF is a helpful product in
terms of signing up with new counterparties. Also, helpful from a balancing perspective.
Nephin asked in the context of the presentation, whether the objective of any change
was revenue recovery or development of the market. CEPA agreed with views that
the revenue recovery impact of any decision was likely to be low given the low volume
of use of VRF.
8. Capacity/Commodity split and shrinkage
CEPA presented slides on the capacity/commodity split and shrinkage.
Energia stated that the only market with bidding rules is the non-energy balancing
market. The capacity/commodity split is less relevant now for power generators in I-
SEM due to the fact that there are no bidding rules for most products (in multiple
markets). Constrained generators are moving to mix of products.
Unclear what incentives are if you compete in a number of markets.
No daily products in NI so has always been a different treatment. This is perhaps a
bigger potential source of distortion than the potentially different capacity/commodity
splits in Northern Ireland in comparison to RoI.
Energia stated that there would need to be a good reason to move away from 90:10
split.
Vermilion stated that there should be a distinction within shrinkage for compression
and unaccounted for gas. Vermilion’s opinion is that shrinkage is not applicable at the
Corrib Entry Point.
GNI stated that if shrinkage is paid for through tariffs this may increase tariff volatility.
Nephin questioned how much capacity/commodity split would change if shrinkage was
included in allowed revenues.
GNI stated that if you bring in shrinkage into allowed revenues could see an increase
in the capacity element as much of the commodity element would be accounted for by
shrinkage.
GNI highlighted that a change in the general principle of how shrinkage is charged
would require a change to the Code of Operations.
6
Vermillion noted that shrinkage was discussed recently at the Code Modification
Forum in terms of invoice issues. The slides shown at the Code Modification Forum
show that since Corrib came on stream, shrinkage volumes purchased have reduced
due to Corrib compressing gas upstream of its entry point, reducing flows at the Moffat
entry point and associated Moffat shrinkage volumes. Moreover, all non Bellanaboy
shippers have benefited from lower GNI shrinkage charges due to Corrib supplying its
gas at 86bara.There is a question as to whether this is fair, equitable and cost
reflective.
9. Multipliers & Seasonal Factors
GNI presented slides on the historic use of short-term products.
Energia pointed out that we may start to see more of a blend between annual and
short-term products in the power sector within I-SEM.
Energia pointed out that constrained power generators are centrally dispatched by
TSO. There is uncertainty and lack of information. Could be dispatched for long period
of time.
Energia questioned whether there would be any adjustment if you were to book
monthly product each month for 12 months i.e. a rebate because if you had full
information you would have booked yearly.
CEPA stated not necessarily covered under TAR NC and that implications would need
to be considered before identifying a position.
GNI stated that this could add to tariff volatility i.e. could discourage the booking of
annual products.
Vermilion questioned how this would impact secondary market trading of capacity and
that could introduce challenges of under-recovery for GNI.
Energia responded stating that on the first point regarding secondary market trading
the market would determine the outcome.
Vermilion stated that they would think a booking rebate would be a distortion of the
market.
IOOA pointed out that action regarding indexation of expansion constants had not been
covered off.
GNI stated their view was that they would be reviewed as part of periodic review every
five years.
IOOA stated that the gas prices range that is being used is giving a particular gas price.
If we were to use 16/17 data could be an increased price.
IOOA questioned whether the gas prices should be forward looking.
BGE of the view that a broader range makes more sense.
GNI and CRU stated that the price volatility and uncertainty to both the upside and
downside would need to be considered.
7
10. Workshop model and methodologies
Frontier presented a workshop on model and methodologies.
11. Next Meetings
An open stakeholder forum will be convened during the consultation period to
discuss the policy positions outlined. The date is yet to be decided and will be
dependent on the date of release of the consultation paper to allow sufficient time
for paper review but also to allow time to consider consultation responses after the
session.
GNI will organise a support teleconference for detailed use of the tariff model in the
consultation phase. This will be arranged after the model is released to allow users
time to work with the model and gather questions to be addressed.
www.cru.ie
Network Tariff Liaison Group 3
October 9th 2018
TAR Network Code Workshop
www.cru.ie
IntroductionUpdate and goals for NTLG 3
1
Following NTLG 1&2 on 18/19 September.
GNI carried out further analysis of issues and added additional functionality to models.o These models are now being reviewed in detail by CRU/CEPA.
CRU Gas Team highlighted to Commission its initial views, which incorporated feedback received from participants.o Their initial guidance and further CRU/CEPA analysis has informed the slides for today.
NTLG 3 high-level goals
CRU/CEPA to further highlight its minded to position on some items.
NTLG participants’ feedback is essential to informing the CRU’s proposed approaches within the TAR NC Consultation document.
www.cru.ie
Agenda NTLG Day 3
2
09:30 – 09:45 Introductions (CRU/CEPA)
09:45 – 10:15 Review of actions from NTLG 1&2 (GNI/Frontier)
10:15 – 11:15 Entry Points (All)
11:15 – 11:30 Break
11:30 – 12:15 VRF (All)
12:15 – 12:30 Capacity/Commodity Split & Shrinkage (CRU/CEPA)
12:30 – 13:00 Multipliers & Seasonal Factors (All)
13:00 – 13:45 Lunch
13:45 – 14:00 Wrap up on first half of day
14:00 – 14:15 Introduction to Training (GNI/Frontier)
14:15 - 16:00 Tariff Model –Training Session (GNI/Frontier), including Break at 15.00
16:00 Close – (Contingency to 17:00 if required)
www.cru.ie
NTLG 1&2 Actions
3
4
Table of Actions from NTLG 1&2
Topic Action Status
Reference Price MethodologyFrontier to examine effect of the rescaling approach for next NTLG and provide an optional LNG discount functionality so
that the effects can be modelled.To be presented at NTLG #3
Multipliers & Seasonal Factors GNI to provide information on the level of short term
bookings. Quarterly multipliers to be considered. Transition to full compliance by 2023 to be considered
To be presented at NTLG #3
Demands GNI to review demand profiles used in model To be presented at NTLG #3
VRFGNI to examine probability of interruption over 12-month
period. To be presented at NTLG #3
Entry Point Discounts (LNG)GNI to include an optional discount for LNG entry point in the
model with a view to informing results for consultationCompleted
Small scale entry CRU/GNI committed to analysing notional point for biogas
entryIdentification of notional point ongoing - potential approach
to be presented at NTLG #3
Capacity/commodity splitGNI to circulate capacity/commodity impact analysis to
participantsCirculated with NTLG #3 material
Expansion Constant & Annuitisation Factor
GNI to update SWSOS costs to reflect the gross estimated cost (i.e. including grant) as outlined in PC4 decision
Review completed - confirmed that total estimated costs were included in model as communicated at NTLG #1/2.
GNI to circulate 2015 expansion constant and annuitisation factor calculations.
Links to the 2015 Exp.Constant (CER15060) & A.Factor (CER15059) circulated
GNI/CRU to further consider as part of this NTLG process updating the annuitisation factor methodology to take
account of 2018 gas prices.Inclusion of 2018 Gas Prices (Actuals to Sep'18)
GNI to provide information with respect to the compressibility calculation.
To be presented at NTLG #3
GNI to consider annual indexation of expansion constants. To discuss at NTLG #3 as part of overall presentations
Information on Compression Calculation
Network Analysis
TAR NC Workshop
9th October 2018
Calculation of Expansion Constants
• The purpose of the Expansion Constant is to provide a numerical value to the cost of expanding the capacity of the system so that one unit of gas can travel over a specified distance (€ / GWh km)
‒ Forward-looking approach based on the Matrix Expansion Constant (MEC) methodology1
• The methodology for calculating expansion constants is based around 2 key components:
‒ The pipeline cost of expanding capacity on the network
▪ Pipeline cost is related to the capacity of the pipeline, in turn related to the pipeline parameters
‒ The cost of compression (energy) required to move the gas through the pipeline
▪ In order for there to be any flow in a pipeline, the gas must be raised to the head pressure in the first place. The cost of compression is in large part determined by the size (or motive power) of the compressor
• In CER/14/455 the CRU considered it appropriate to consider applying two distinct expansion constants, namely a “wet” and a “dry” expansion constant.
• The expansion constant is calculated for each pipeline size.
• A wet expansion constant is calculated by taking the average of the expansion constants for each pipeline size
• A dry expansion constant is calculated by taking the weighted average of the expansion constants for each pipeline size
61 CER/15/057 Decision on Future of Gas Entry Tariff Regime
𝐸𝑥𝑝𝑎𝑛𝑠𝑖𝑜𝑛 𝐶𝑜𝑛𝑠𝑡𝑎𝑛𝑡 =𝑃𝑖𝑝𝑒𝑙𝑖𝑛𝑒 𝐶𝑜𝑠𝑡 + 𝐶𝑜𝑠𝑡 𝑜𝑓 𝐶𝑜𝑚𝑝𝑟𝑒𝑠𝑠𝑖𝑜𝑛
𝑃𝑖𝑝𝑒𝑙𝑖𝑛𝑒 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦
Calculating ‘Cost of Compression’
• Calculation of Wet Expansion Constants:
7
Compression
Required (MW) Cost of
Compression
per km
(€ / km)Cost of
Compression / MW
(€/MW)
Isentropic
Head
Eqation
GNI Compressor
Station
Costs
Calculating ‘Compression Required’
8
• Gas Throughput
• Inlet Pressure
• Outlet Pressure
• Other constants
Isentropic
Head
Equation
Compressor
Power
Requirement
1. Isentropic Head
Equation
2. Model Inputs and
Output
23.7 MW
3. Worked Example
43.5 bara 131 bara 43.1 MW43.5 bara 131 bara
174 GWh/day 316 GWh/day
600 mm 750 mm
Calculating ‘Cost of Compression’
• Calculation of Wet Expansion Constants:
9
• Calculation of Dry Expansion Constants:
Impact of Pressure Assumptions
10
1. Wet Expansion Constant: €8,783 /GWhd/km
23.7 MW43.5 bara 131 bara
174 GWh/day
600 mm
43.1 MW43.5 bara 131 bara
316 GWh/day
750 mm
2. Dry Expansion Constant: €7,810 /GWhd/km 1
10.4 MW43.5 bara 86 bara 13.2 MW43.5 bara 86 bara
123 GWh/day 155 GWh/day
600 mm 650 mm
19.0 MW43.5 bara 86 bara 30.6 MW43.5 bara 86 bara
223 GWh/day 361 GWh/day
750 mm 900 mm
1 Value updated since NTLG 2 (18th September 2018)
11frontier economics
1. Sensitivity around entry bookings
2. LNG and small scale entry discounts – explanation and impact assessment
3. Multiplicative versus additive revenue recovery – impact assessment
4. Treatment of small scale entry points
5. VRF tariff results
6. CWDA counterfactual
7. CWDA and MA: intuition and examples
12frontier economics
We have reviewed a sensitivity in which Moffat bookings are in line with
18/19 projections
In this sensitivity, projected bookings for 2019/20 are in line with 2018/19 projected bookings and an increase over time
is applied to the 19/20 base that is in line with 2018/19 projected bookings
Reduced entry bookings sensitivity – Scenario 1 Base case – Scenario 1
The reduction in entry bookings leads to a tariff increase as revenue is being recovered over fewer bookings.
In scenario 1, the reduction leads to tariff increases of €28 in 2019/20 for all entry points. This reduces to €24 in 2023/24
as the volume of bookings increases over the years, allowing the tariff increase to be spread over more bookings.
The tariff increase ranges from €19 to €33 across all years and scenarios.
13frontier economics www.cru.ie
Entry points
13
14frontier economics
1. Sensitivity around entry bookings
2. LNG and small scale entry discounts – explanation and impact assessment
3. Multiplicative versus additive revenue recovery – impact assessment
4. Treatment of small scale entry points
5. VRF tariff results
6. CWDA counterfactual
7. CWDA and MA: intuition and examples
15frontier economics
Introduction to a possible approach to discounts for new entry points
Article 9 of the TAR NC provides for the use of discounts in tariff setting.
It indicates:
▪ a discount of at least 50% must be applied to storage; and
▪ a discount may be applied to the transmission tariffs of:
LNG facilities; and
entry points developed to end the isolation/increase security of supply.
On the following slides, we will cover:
1. how a discount could be applied;
2. the results of applying a discount to LNG and small scale entry on these points as
well as the Moffat entry point.
TAR NC
Implementation Example
16frontier economics
Discount leads to an initial under-recovery, and therefore an adjustment
needs to be implemented – indicative calc. as per TAR NC example
LNG
Pre-discount
Ta
riff in
€
LNG
Indicative Post- discount
Adjustment only to non-discounted point
Imagine a world with two entry points with the
same tariff, e.g. two entry points at exactly the
same location, but one is supplied by LNG
whereas the other is supplied by a piped gas
Simply taking 50% from the LNG tariff pre-
discount and recovering it from the non-
discounted points leads to the following
situation:
• The LNG point has a 50% discount
compared to the situation pre-discount
• However, post-discount the LNG facility has
a 67% discount compared to the non-
discounted point. The tariff of the non-
discounted point is now adjusted for all tariff
revenue removed from the LNG point. This
adjusted tariff will be higher than in the pre-
discount situation, creating a greater wedge
between the two points
LNG
Recovering the discount-affected revenue from
all points proportionally (also applying the
discount to this revenue for discounted points)
creates a situation in which:
• The LNG discount relative to a situation
without discounts is less than 50%
• But in a world with LNG discounts it creates a
50% discount relative to an entry point not
supplying LNG at that same location
Indicative Post- discount
Adjustment to both points
67%
dis
count
50%
dis
count
50
%
33 %
17frontier economics
Discounts of 50% on LNG and small scale entry points drive an increase in the Moffat tariff,
leading to increased costs for consumers
*We have estimated the total impact of offering a discount on LNG and small scale entry points as the
difference between the Moffat tariff with and without discounts multiplied by the annual bookings
Scenario 1
Scenario 2
Scenario 3>€1
€43
19/20
23/24
237 GWh
256 GWh
€14k p.a.
€11m p.a.
Increase in
Moffat tariff
(€/MWh)
Annual
bookings
Impact of
discount per
annum*
>€1
>€1
19/20
23/24
237 GWh
256 GWh
€14k p.a.
€122k p.a.
>€1
€126
19/20
23/24
237 GWh
256 GWh
€14k p.a.
€32m p.a.
Moffat tariff
w/out
discounts
Moffat tariff
with
discounts
€291
€265
€291
€392
€291
€342
€291
€266
€291
€518
€291
€385
There are no LNG
bookings and low small
scale entry bookings under
scenario 1, leading to a
relatively low total impact
of the discount.
The larger the proportion
of LNG and small scale
entry bookings, the larger
the increase in the Moffat
tariff as there is more
revenue to be recovered.
This in turn leads to a
higher overall impact on
gas consumers.
For this reason, the total
impact of the discount is
highest under Scenario 2.
18frontier economics
The total impact of a discount for LNG is significant because of its scale
The table below shows the impact of a 50% discount only offered to LNG
50% discount – LNG only
Scenario 119/20
23/24
Scenario 219/20
23/24
Scenario 319/20
23/24
Increase in
Moffat tariff
(€/MWh)
Moffat tariff
with
discounts
Impact of
discount per annum
NA
NA
NA
€122
NA
€41
NA
NA
NA
€31m p.a.
NA
€10m p.a
Moffat tariff
w/out
discounts
NA
NA
NA
€514
NA
€383
NA
NA
NA
€392
NA
€342
In scenario 2 the tariff for LNG
decreases from €254 to €207, the
differential therefore changes from
€138 to €307, an increase of €169
In scenario 3 the tariff for LNG
decreases from €160 to €102, the
differential therefore changes from
€182 to €281, an increase of €99
19frontier economics
The total impact of a discount for small scale entry is significantly smaller than for LNG due
to the volume of bookings
The table below shows the impact of a 50% discount only offered to small scale entry
▪ In addition to the much smaller scale, the projected tariff for small scale entry is lower than for LNG so the discount also
has a smaller effect
50% discount – small scale entry only
Scenario 119/20
23/24
Scenario 219/20
23/24
Scenario 319/20
23/24
>€1
>€1
€14k p.a.
€122k p.a.
>€1
>€2
€14k p.a.
€426k p.a.
>€1
>€2
€14k p.a.
€308k p.a.
Increase in
Moffat tariff
(€/MWh)
Moffat tariff
with
discounts
€291
€265
€291
€392
€291
€342
Moffat tariff
w/out
discounts
Impact of
discount per annum
€291
€266
€291
€393
€291
€344
In this scenario the tariff for biogas
decreases from €178 to €90, the
differential therefore changes from
€214 to €303, an increase of €89
20frontier economics
1. Sensitivity around entry bookings
2. LNG and small scale entry discounts – explanation and impact assessment
3. Multiplicative versus additive revenue recovery – impact assessment
4. Treatment of small scale entry points
5. VRF tariff results
6. CWDA counterfactual
7. CWDA and MA: intuition and examples
21frontier economics
The use of multiplicative rescaling leads to higher Moffat tariffs than the use of additive
rescaling, leading to higher costs for consumers
We have estimated the total impact of multiplicative rescaling as the increase in the Moffat tariff resulting from switching
away from additive rescaling multiplied by the annual bookings. This assumes that Moffat will remain the marginal source of
gas.
Moffat tariff –
multiplicative
rescaling
Increase in
Moffat tariff
(€/MWh)
Impact of
multiplicative
rescaling p.a.
Scenario 1€65
€21
19/20
23/24
237 GWh
256 GWh
€15m p.a.
€5m p.a.
Scenario 2€65
€437
19/20
23/24
237 GWh
256 GWh
€15m p.a.
€112m p.a.
Scenario 3€65
€210
19/20
23/24
237 GWh
256 GWh
€15m p.a.
€54m p.a.
Annual
bookings
Moffat tariff –
additive
rescaling
€291
€265
€291
€392
€291
€342
€356
€286
€356
€829
€356
€553
Most significant impact
under scenario two
▪ Under multiplicative rescaling, the absolute tariff differential between entry points varies while the proportional difference
remains the same
▪ As a result, the higher an entry point’s primary tariff, the higher the absolute value of the rescaling is for that point.
▪ Moffat has the highest primary entry tariff and therefore faces a significantly larger increase under multiplicative than
additive rescaling
22frontier economics
1. Sensitivity around entry bookings
2. LNG and small scale entry discounts – explanation and impact assessment
3. Multiplicative versus additive revenue recovery – impact assessment
4. Treatment of small scale entry points
5. VRF tariff results
6. CWDA counterfactual
7. CWDA and MA: intuition and examples
Page 23
Treatment of small-scale entry points
• There was support for a notional point approach as a pragmatic solution for small-scale entry points.
• We are interested in your views on the following:
• Should there be one or a small number of notional points and tariffs to retain some locational signal?
• Where should (the) notional point(s) be located?• Close to demand centre?
• Based on location of expected biogas entry?
• Some other approach?
• Implications for distribution tariffs may need to be considered, e.g. in relation to the treatment/ probability of interruption. However, this is not in scope of TAR NC.
Takeaways from NTLG and key remaining issues
Action: development of detailed arrangements for notional point(s) following feedback from today.
24frontier economics
Treatment of small scale entry points
Transmission level charges
▪ At transmission, the NTLG feedback was that locational
signals are less important for small scale entry, and that
it would be better to avoid the administrative complexity
associated with setting multiple entry tariffs for each
individual site
▪ The following arrangements could follow from this:
Small scale entry tariffs should be based on a single
notional entry point, and all plant, regardless of
location, pay that single charge
The notional point will be chosen on the assumption
that small scale producers will choose to inject into
the grid close to demand
Distribution level charges
▪ The current tariff work does not need to establish exact
distribution charges. However, the following principles
could be applied:
Where the product offered to small scale producers is
identical – i.e. zero probability of interruption – then
the entry tariff should be the same across
transmission and distribution
Where the product is not the same – i.e. there is a >0
probability of interruption, a discount could be offered
for distribution entry tariffs.
There are two issues considered below:
▪ The treatment of small scale entry for the purposes of setting a transmission level entry tariff; and
▪ The treatment of small scale entry for the purposes of setting distribution level entry tariffs
25frontier economics
Moving the notional small scale entry point from Corracunna to Gormanston lowers the
tariff by a small amount
Scenario 1
Scenario 2
Scenario 3€74
€125
19/20
23/24
Small scale entry
tariff at Gormanston
€74
€48
19/20
23/24
€74
€175
19/20
23/24
Small scale entry
tariff at Corracunna
€77
€51
€77
€178
€77
€128
The table below shows the impact of moving small scale entry from Corracunna to Gormanston – holding all other inputs
constant.
26frontier economics
Distribution level charges
Transmission Distribution
Small scale tariffSmall scale tariff
50% Interruptibility discount
Scenario 2
19/20
23/24
€38
€89
€77
€178
Scenario 3
19/20
23/24
€38
€64
€77
€128
Scenario 1
19/20
23/24
€38
€25
€77
€51
An interruptibility
discount of 50% is
used in this
example.
The final discount
will depend on the
calculation of the
probability of
interruption.
The application of distribution level charges equal to the transmission tariff, but discounted for the probability of
interruption, would result in the tariffs in the table below.
27frontier economics www.cru.ie
Virtual Reverse Flow
27
Page 28
Virtual reverse flow
• Alignment with treatment of VRF as an interruptible product within the TAR NC.
• Some debate regarding whether the interruptible discount should be applied to the Moffat Entry tariff or Moffat Exit tariff.
• Stakeholders requested that the P-factor is analysed over 12 month period.
• Also debate regarding the level of discount. Arguments made for and against a relatively large discount were as follows:
Takeaways from NTLG 1-2
For Against
A high tariff (i.e. low discount) would lead the market to use swaps resulting in lower reverse and forward bookings
Value of VRF to shippers is high giving them access to a liquid NBP
Marginal costs of providing VRF service may be considered low
Ability to use VRF product is dependent on forward flow product existing
Page 29
Virtual reverse flow
• We intend to interpret VRF as an interruptible product.
• Treated as an exit product with tariff defined relative to the equivalent firm Exit tariff. Reflects fact that VRF represents (virtual) gas existing the system.
• GNI are developing analysis to propose the P-factor.
• We will consider an A-factor which reflects:
• the ‘economic value’ of the product;
• the impact on the market; and
• the impacts on other tariffs.
• The same principles will be applied to define an interruptible discount for Gormanston as for Moffat.
Intended way forward
Page 30
Virtual reverse flow
Consideration of absolute discount
Impact of relatively high tariff (low discount) Impact of relatively low tariff (high discount)
Could increase Exit revenue recovery, reducing Exit tariffs*
Little revenue recovery from the VRF product so Entry and Exit tariffs similar to under existing registration fee
But, if a high tariff incentivises a shift to swaps may reduce Entry revenue recovery (given reduction in forward flows), increasing Moffat Entry tariff
Encourages use of VRF product, and hence retains forward flow bookings relative to use of swaps
Greater use of swaps may increase IBP liquidity?
VRF product may help manage risk in the presence of low liquidity on the IBP – may attract new market participants
Provides a mechanism for market participants to self-balance reducing GNI balancing requirements
* Although current level of use of VRF product means impact could be small
Page 31
• Increasing liquidity of IBP may lead to a shift from VRF to swaps regardless of the level of the VRF tariff?
• However, in the short term, VRF product supports integration with the GB market?
Virtual reverse flow
Consideration of absolute discount
32frontier economics
1. Sensitivity around entry bookings
2. LNG and small scale entry discounts – explanation and impact assessment
3. Multiplicative versus additive revenue recovery – impact assessment
4. Treatment of small scale entry points
5. VRF tariff results
6. CWDA counterfactual
7. CWDA and MA: intuition and examples
33
• Available data sourced from GNI GTMS system
• Periods used represent available data as per GTMS system
• Probability of interruption based on following formula:
• Two periods of analysis show a similar % of interruptible ‘days’
Probability of Interruption - Initial calculation
Assumptions
Number of days in period (Apr’18 – Aug’18) 144
Of which VRF allocations were recorded 121
Number of days where interruptions occurred 17
% of days interrupted (17/121) 14%
Number of days where interruption(s) were experienced
Number of days where VRF allocations were recorded
Possible method of determining Interruptible %
Probability of Interruption - Additional Date Range
Number of days in period (May’17 – Nov’17) 210
Of which VRF allocations were recorded 143
Number of days where interruptions occurred 22
% of days interrupted (22/143) 15%
34frontier economics
VRF tariffs with no discount applied are significantly higher than
current VRF charges
35frontier economics www.cru.ie
Capacity/Commodity split
& Shrinkage
35
Page 36
Capacity/Commodity split
• On balance, stakeholders had concerns with the re-distributive impacts of moving away from the existing 90/10 split.
• GNI analysis demonstrated that customers with low load factors (e.g. electricity generators and residential consumers) in particular could face increased costs from a move to a higher capacity share of charges.
• An increase in the capacity element may also discourage certain consumers from shifting to gas use from other, less environmentally friendly fuels.
Takeaways from NTLG 1-2
Justifiable bounds somewhere between 90/10 and
100/0 for Ireland
90% 100%0%
Page 37
Capacity/Commodity split
• There was good discussion of interactions between the gas network tariff regime and the all-island electricity market at the last NTLG.
• For example, we heard from participants that may be will be more difficult for power generators to recover short-run marginal costs. Thus, a lower capacity element may be preferred by some stakeholders.
• We would like to understand implications of the move from SEM to I-SEM and interactions between capacity/commodity split and the electricity market further.
• Under I-SEM, how might gas network tariffs, in particular the capacity/commodity split, interact with:
• Bidding behaviour;
• Merit orders; and
• Market outcomes?
Interactions with electricity market
Page 38
Capacity/Commodity split
• The Utility Regulator in Northern Ireland has consulted on a 95/5 capacity/commodity split.
• What impact might this have on the I-SEM and the merit order if Ireland adopts an different capacity/commodity split?
Interactions with electricity market – further discussion
Page 39
Shrinkage
• Shrinkage is currently not included within GNI’s allowed revenues which are recovered via transmission network capacity and commodity tariffs.
• Instead, GNI recover the costs of Shrinkage from Shippers on a monthly throughput basis (set out in the Code of Operations).
• Use of compressors on the transmission system and unaccounted for gas are both inherent costs of operating the gas transmission system. It may therefore be considered appropriate that all those who make use of the transmission system contribute to these costs.
• However, the approach for cost recovery of Shrinkage, and the interactions with transmission tariffs need to be considered.
Current arrangement
Action: Explore further how Shrinkage may be captured within the TAR NC
Page 40
Shrinkage
Option 1: Include shrinkage within commodity element of network tariff structure:
• Define as a transmission service under the TAR NC.
• Shrinkage recovered through existing commodity charge.
Consideration of role within TAR NC
Pros Cons
• Likely to be compliant with requirements of the TAR NC
• Would support justification of 90/10 capacity/commodity split.
• May introduce potential for under/over-recovery for GNI based on volatility of Shrinkage costs. *
• A large chunk of the commodity element may be driven by Shrinkage, effectively reducing the commodity element relative to the status quo.
* Also potential to increase the volatility of gas network tariffs through annual K-factor adjustments
Page 41
Shrinkage
Option 2: Have separate Shrinkage, Commodity and Capacity charges:
• Define as a transmission service under the TAR NC.
• Separate flow based charge for shrinkage.
• May be possible to retain monthly charging structure?
Consideration of role within TAR NC
Pros Cons
• Dedicated flow-based Shrinkage charge which may allow status quo to broadly be retained.
• Dedicated (e.g. monthly) charge administered so as to mitigate volatility issues with Option 1.
• Need to consider whether approach strictly complies with TAR NC (e.g. Article 4).
• Role of 90:10 capacity/commodity split in wider tariff structure?
Page 42
Shrinkage
Option 3: Retain a separate charging approach as non-transmission service
• Define shrinkage as a non-transmission service under the TAR-NC.
• Separate flow based charge for shrinkage.
• Possible to retain monthly charging structure?
Consideration of role within TAR NC
Pros Cons
• May allow status quo to be broadly retained.
• Unclear whether approach would comply with TAR NC (e.g. Article 4).
Page 43
Shrinkage
Option 4: Consider outside of allowed revenues
• There is a question about whether and how shrinkage should be captured within the TAR NC tariff arrangements.
• Another option might be to contend that in Ireland context shrinkage should not be contained within TAR NC transmission tariff requirements.
Consideration of role within TAR NC
Pros Cons
• Would allow the status quo to retained
• Potentially highest risk of non-compliance if shrinkage is considered to be a transmission service
Page 44
Shrinkage
• Some of the options discussed above could lead to redistribution / incidence effects relative to current arrangements.
• For example, option 1 may lead to a greater allocation of network operation costs to high capacity / low throughput users compared to how GNI currently recover costs of Shrinkage from Shippers (monthly throughput basis).
• A number of the options above would also change the basis on which shrinkage costs are recovered from the market – how will this impact upstream / downstream contract arrangements?
Wider impacts of including shrinkage in gas network tariffs
We are interested in the views of the NTLG on the importance of these impacts
Page 45www.cru.ie
Multipliers & Seasonal Factors
45
Short-Term ProductsHistoric Usage
03/10/2018
• GNI were asked to present on the level of utilisation of short-term products in recent years
‒ The following slides outline the usage from 2014-15 to 2017-18
• GNI Looked at the absolute level of bookings and the weighted average (weighted by price)
‒ Also looked at the Power sector and Industrial and Commercial sector separately.
• The analysis will show a high level of usage over the period reviewed.
• The impact on different customer segments will need to be considered before transitioning to a new set of multipliers.
47
Introduction
Total Short-term usage October 2014 – Sep 2018
48
• Significant amounts of short-term
usage over that last four years
• Highest utilisation in the summer while
highest revenue generated in the
winter -see dotted lined
‒ This curve is influenced by the price of
short-term
• Next slides look at the Power and I&C
sectors separately -
2,000
4,000
6,000
8,000
10,000
12,000
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
Tx Exit Cap - Total Annualised Short Term MWh
2015/16 2014/15 2016/17
2017/18 Average Weighted Average
Short-term usage _ POWER
• Significant use of short-term by power
all year round
‒ Summer and Shoulder periods showing
heavier usage in this analysis
• Short-term usage is dominated by
“Constrained On” plants.
• Variability of wind, Interconnector flows,
money point outages and weather will
have an impact on usage
• I-SEM may affect booking pattern.
49
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
2,000,000
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
Total Annualised Short Term at EXIT _ POWER MWh
2014/15 2015/16 2016/17 2017/18 Average
Short-term usage _Industrial & Commercial
• Average curve of I&C shows significant
usage of Short-term in the summer
• Key principle of the short-term
multipliers was to encourage summer
time usage
• Usage in the summer is driven by
particular load types e.g. Dairy Industry
‒ a number of dairy processing units
have connected to the gas networks in
recent years.
50
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
Total Annualised Short Term at EXIT _ LDM MWh
2014/15 2015/16 2016/17 2017/18 Average
• Significant amount of short-term used which can be seen from the analysis
• Any movement away from the current set of multipliers will need to occur on a phased basis
• Customer impact analysis will need to be undertaken to avoid price shocks
• I-SEM and the impacts on short-term bookings will need to be considered.
51
Summary
Page 52
Multipliers and seasonal factors
• Stakeholders generally agreed with limiting the extent of change from the current approach.
• They queried the transition path towards the potential limits which may be set by ACER in 2023.
• They also suggested that quarterly multipliers may be the most important to consider.
Takeaways from NTLG 1-2
Action: Intend to retain the existing approach but consider the points raised at the NTLG
Page 53
Multipliers and seasonal factors
Transition
• Intend to align with immediate multiplier limits. I.e.
• 1.5 for monthly and quarterly product.
• 3.0 for daily product.
• 2023 multiplier limits will be dependent on an ACER recommendation in 2021.
• Multipliers can be revised annually under Article 28.
• Therefore, intention is to keep daily product multiplier limits under review and consider gradual transition to the potential 1.5 limits.
• Before further change, it may be preferable to monitor impacts of broader TAR NC change on the market.
Consideration of issues
Page 54
Multipliers and seasonal factors
Quarterly multipliers
• The existing quarterly multipliers are simply an arithmetic mean of the relevant monthly multipliers within that quarter.
• They do not provide a strong incentive for quarterly bookings.
• We are therefore interested in your views on whether a stronger incentive for use of the quarterly product is needed.
• For example, a multiplier around 1.4 could perhaps be justified by the benefits of encouraging quarterly as opposed to monthly bookings.
Consideration of issues
There are currently very low bookings for the quarterly product
Page 55
WRAP UP ON FIRST HALF OF DAY
Page 56
Way forward
• Early November 2018: Consultation published
• Early January 2019: Consultation closes
• Early February 2019: Summary of responses published
• March 2019: Final decision published
• May 2019: Final tariffs published
Key dates
Thank you for your input
57frontier economics
1. Sensitivity around entry bookings
2. LNG and small scale entry discounts – explanation and impact assessment
3. Multiplicative versus additive revenue recovery – impact assessment
4. Treatment of small scale entry points
5. VRF tariff results
6. CWDA counterfactual
7. CWDA and MA: intuition and examples
58frontier economics
The TAR NC requires the chosen reference price methodology to be
compared to the CWDA with an entry/exit split of 50/50, as shown below
59frontier economics
A comparison of the reference price methodology and the CWDA with
an entry/exit split of 33/67 can also be done, as shown below
60frontier economics
1. Sensitivity around entry bookings
2. LNG and small scale entry discounts – explanation and impact assessment
3. Multiplicative versus additive revenue recovery – impact assessment
4. Treatment of small scale entry points
5. VRF tariff results
6. CWDA counterfactual
7. Workshop model and methodologies
61frontier economics
Disclaimer
This workshop will be organised as follows
Home page model (on screen)
Model inputs (on screen)
MA explained and worked example
MA applied in model (on screen)
CWDA explained and worked example
CWDA applied in model (on screen)
62frontier economics
Disclaimer
This Consultation Transmission Tariff Model (including the enabling logic and input data contained therein)
is made available for the sole benefit of parties who are engaged in the Tariff Network Code consultation
process. GNI has and shall retain exclusive ownership of the Consultation Transmission Tariff Model and all
intellectual property rights in or relating to it, including the copyright and all other protected intellectual
property rights. The information contained in the Consultation Transmission Tariff Model is provided by
GNI “as is” and GNI reserves the right to amend the information at any time at its discretion. GNI makes
no representations or warranties of any kind, express or implied, in relation to the information and hereby
excludes all such representations or warranties, express or implied, to the fullest extent permitted by
law. GNI does not accept any responsibility, liability or duty of care to you or to any other person in
respect of the information, and any reliance you or any other person places on such information is
therefore strictly at your own or their own risk. In no event will GNI be liable for any loss or damage
including, without limitation, indirect or consequential loss or damage of any nature, arising out of or in
connection with the use of the Consultation Transmission Tariff Model or any information contained in it.
Model Disclaimer
63frontier economics
1km 1km
1km
Entry point A
Forecasted cap : 50
Forecasted cap: 100
Entry point B
Exit point 1
Exit point 2
Forecasted cap: 90
Forecasted cap: 60
1.4 km
1km
We will use the following simplified network in our worked example
Shortest path Exit 1 Exit 2
Entry A 1 2
Entry B 1.4 1
64frontier economics
We will go through the following steps of the calculation in turn:
The matrix approach captures the specific costs of each path (as much
as possible) but does not directly recover all allowed revenue
Calculate the costs of each path
Calculate entry and exit tariffs minimising the difference between the costs of the paths and the
sum of the entry and exit tariff. This results in primary tariffs
Adjust the tariff to recover all allowed revenue with secondary adjustments (and discounts)
Matrix
65frontier economics
Calculate the costs of each path using Long Run Marginal Costs (Expansion constant and
annuitisation factor)
1km 1km
1km
Entry point A
Forecasted cap : 50
Forecasted cap: 100
Entry point B
Exit point 1
Exit point 2
Forecasted cap: 90
Forecasted cap: 60
1.4 km
1km
Costs of shortest path Exit 1 Exit 2
Entry A 1*€5 = €5 2*€5 = €10
Entry B 1.4*€5 = €7 1*€5 = €5
In this example, assume
every km of pipeline has a
cost of €5/GWh capacity per
annum
Matrix
66frontier economics
Calculate entry and exit tariffs minimising the difference between the costs
of paths and the sum of both tariffs, i.e. best approximation of costs
Costs of shortest path Exit 1 Exit 2
Entry A 1*€5 = €5 2*€5 = €10
Entry B 1.4*€5 = €7 1*€5 = €5
Determine tariffs Costs Entry tariff Exit tariff Difference
costs and
tariffs
Squared
difference
Entry A to Exit 1 €5 €4.13 €2.62 €-1.75 €3.06
Entry A to Exit 2 €10 €4.13 €4.13 €1.75 €3.06
Entry B to Exit 1 €7 €2.62 €2.62 €1.75 €3.06
Entry B to Exit 2 €5 €2.62 €4.13 €-1.75 €3.06
Total €12.25
By using the squared
differences, positive and
negative deviations are
both considered and
large deviations are more
important than small
ones
Matrix
Let the computer find a
stable and unique
solution mimizinfg the
squared differences
Let the computer find a
unique solution
minimizing the squared
differences
67frontier economics
Adjust the tariff to recover all allowed revenue
Point Primary tariff
Collected from
primary tariff Adder Tariff after adjustment
Collected revenue
after adder
Entry A € 4.13 € 412.50 € 3.04 € 7.17 € 716.67
Entry B € 2.62 € 131.25 € 3.04 € 5.67 € 283.33
Exit 1 € 2.62 € 157.50 € 3.14 € 5.77 € 346.00
Exit 2 € 4.13 € 371.25 € 3.14 € 7.27 € 654.00
Total € 1,072.50 Total € 2,000.00
It is unlikely that the primary tariffs (the tariffs calculated earlier) recover all allowed revenue. By adding a
fixed value to each of the entry (exit) tariffs, the differential between points is maintained but also all allowed
revenue to be recovered
Matrix
The regulator sets the amount of revenue recovered from entry and exit, assume €1000 from entry, €1000
from exit
68frontier economics
The CWDA allocates allowed revenue across entry/exit points based on:
▪ the average distance gas travels if gas flows from an entry (exit) point to (from) all exit (entry) points proportionally to the demand (supply) at the exit
(entry) points
▪ the forecasted capacities at those points
We will go through the following steps of the calculation in turn:
The CWDA allocates allowed revenue across entry/exit points. It does not
directly account for costs of different routes but for the length of routes
Calculate capacity weighted average distances for all points using the forecasted booking
and the routes to the points
Calculate the proportion of distance travelled by gas to (from) a point relative to all
travelled distance (as assumed in this methodology)
Determine the revenue to be recovered from all exit and all entry points (50/50 is the
default counterfactual)
Use the proportion calculated in (2) to determine the revenue to be recovered from a
specific point. Tariffs are revenue per point divided by the bookings at that point
CWDA
69frontier economics
Calculate capacity weighted average distances for all points using the
forecasted booking and the routes to the point
1km 1km
1km
Entry point A
Forecasted cap : 50
Forecasted cap: 100
Entry point B
Exit point 1
Exit point 2
Forecasted cap: 90
Forecasted cap: 60
1.4 km
1km
▪ Average distance entry point A = 1 km*(60/150) + 2 km * (90/150) = 1.60 km
▪ Average distance entry point B= 1.4 km*(60/150) +1 km *(90/150) = 1.16 km
▪ Average distance exit point 1 = 1 km *(100/150) +1.4 km *(50/150) = 1.13 km
▪ Average distance exit point 2 = 2 km *(100/150) +1 km *(50/150) = 1.66 km
The weights for entry are
based on exit point
bookings and visa versa
If injected gas at entry point A
were to serve the exit points in
proportion to their demands,
gas from entry point A would
travel 1.6 km on average
CWDA
70frontier economics
Calculate the proportion of distance travelled by gas to (from) a point
relative to all travelled distance (as assumed in this methodology)
1km 1km
1km
Entry point A
Forecasted cap : 50
Forecasted cap: 100
Entry point B
Exit point 1
Exit point 2
Forecasted cap: 90
Forecasted cap: 60
1.4 km
1km
▪ AD EpA = 1*(60/150) + 2* (90/150) = 1.60 * (100/150) / ( 1.60* (100/150) + 1.16 * (50/150)) = 73.4%
▪ AD EpB = 1.4*(60/150) +1*(90/150) = 1.16 * (50/150) / ( 1.60* (100/150) + 1.16 * (50/150)) = 26.6%
▪ AD Xp1= 1*(100/150) +1.4*(50/150) = 1.13 * (60/150) / ( 1.13* (60/150) + 1.66 * (90/150)) = 31.2%
▪ AD Xp2 = 2*(100/150) +1*(50/150) = 1.66 * (90/150) / ( 1.13* (60/150) + 1.66 * (90/150)) = 68.8%
Average travel of gas from point A
and the share of supply from point A
Travel of gas from all entry
points weighted by supply
Proportion of
travel of gas
from point A
relative to all
travel
CWDA
71frontier economics
Determine the revenue split between entry and exit and calculate a tariff for
each of the points
▪ Proportion EpA = 73.4% * €1000 = €734 so €734/100 bookings = €7.34 per booking
▪ Proportion EpB = 26.6%* €1000 = €266 so €266/50 bookings = €5.32 per booking
▪ Proportion Xp1 = 31.2%* €1000 = €312 so €312/60 bookings = €5.02 per booking
▪ Proportion Xp2 = 68.8%* €1000 = €688 so €688/90 bookings = €7.64 per booking
The regulator sets the amount of revenue recovered from entry and exit, assume €1000 from entry, €1000
from exit
1km 1km
1km
Entry point A
Forecasted cap : 50
Forecasted cap: 100
Entry point B
Exit point 1
Exit point 2
Forecasted cap: 90
Forecasted cap: 60
1.4 km
1km
Total revenue collected from point Tariff per booking
CWDA
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