Response to questions from CRU regarding consultation CRU/20/144, ESB Networks proposal for changes to Generator Standard Charges.
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Response to questions from CRU regarding consultation
CRU/20/144, ESB Networks proposal for changes to
Generator Standard Charges.
Date: 25th February 2021
Issued by: ESB NETWORKS DAC
1|PageIntroduction
ESB Networks DAC, in its capacity as the Distribution System Operator (“DSO”) welcomes the oppor-
tunity to respond to the feedback and questions raised by the industry and the CRU during the Gen-
erator Standard Charges (GSCs) consultation. ESB Networks have sought to address all of the points
in this paper. We have structured this response by first outlining some general but important obser-
vations on the feedback provided. We then address the specific points raised in relation to particular
GSC items.
As this process is ongoing, in that the CRU are still considering their final decision on the proposals
we are available at CRU convenience to provide further information and to expand on any of the
points in this response as required. We would welcome the opportunity of a meeting to discuss this
submission and any open questions CRU may have.
1. General Observations
The detailed review carried out by ESB Networks results in more accurate, appropriate and con-
sistent GSCs. This aligns with the shared objective, as expressed in the consultation paper, of updat-
ing the GSCs to:
• Ensure the GSCs are cost appropriate based on efficient delivery of works required to facili-
tate generator connections
• Recover the costs of distribution connection works from generators where appropriate; and
• Minimise the risk to the UoS customer.
We have several important points to make regarding the feedback on the proposed GSCs, set out as
follows.
1.1 Under-recovery from Generators
A key objective and benefit of the updated GSCs is to reduce the UoS subsidy. The PR5 determi-
nation included a 72% contribution rate from generator customers which was based on the pro-
posed GSCs and removal of civils to be charged on a pass-through basis. ESB Networks estimate
to connect 2.2 GWs of generation to the distribution system over the PR5 period with 1.2GWs
where the proposed GSCs would be applied under ECP2 onwards. It is estimated that the UoS
exposure would be approximately €27m by not approving the proposed GSCs and this under re-
covery would increase in future PR periods. Any adjustments to the proposed GSCs will need to
be explained as part of the ex post PR5 review.
2|Page1.2 Costs used
ESB Networks fully stand over our costs, which have been built from the bottom up. We engaged
a consultant to benchmark a range of them, and we adjusted our methodology (as previously
outlined) to take account of feedback from the consultant. We also note that benchmarking was
carried out by consultants on behalf of CRU. This external benchmarking process addressed
these concerns by comparing ESB Networks favourably to other utilities working with the same
technical challenges (e.g. brownfield development) and were found to be reasonable when com-
pared to UK DNOs.
ESB Networks argue that the industry cost examples are too low and do not stand up to scrutiny.
In many cases the costs provided by industry barely cover the material costs that ESB Networks
requires to purchase the materials, let alone the design, management, installation and commis-
sioning costs. For example, Industry quote charges of €520k for a 5MVA Greenfield Transformer
Package, and €523.2k for a 15MVA Greenfield Transformer Package. This means that Industry
are saying that there is only a marginal cost increase of €3.2k (0.6%) between a 5MVA and a
15MVA Transformers. However, ESB Networks framework contracts for transformer supply
prices show that a 15MVA transformer is approx. 75-80% more expensive than a 5MVA, before
even considering the costs required for the design, installation, and associated commissioning
etc.
This cost delta between a 5MVA and 15MVA transformer installation as set out undermines the
numbers industry have put forward for those charges and calls into question all the other figures
that they have provided.
ESB Networks are proud of the rigour and value provided by our procurement process. It should
be noted that ESB Networks materials are procured at scale with appropriate terms and condi-
tions through highly competitive open international competitive framework contracts that en-
sure the best available material prices are secured every time. For some of the charges that In-
dustry have submitted the cost of procurement of the material alone is close to the total cost
submitted by industry - a total which should include, inter alia, design, installation and commis-
sioning. It is not clear to ESB Networks how the industry feedback reconciles the detailed design,
project management, installation and commissioning costs required to complete the work.
Again, this is not credible and raises questions on the numbers that industry has put forward.
3|Page1.3 Contingency allowance
The 10% contingency on electrical construction projects where integrating equipment into
brownfield sites is considered very low where the connection works required are based on a
desktop study and where no site investigation or detailed design has been carried out. Every
connection is different and as such grid connections are somewhat bespoke by nature, they re-
quire detailed designs. In addition, the age of and equipment in the connecting substations can
vary significantly. No project developer would consider less than 10% in these circumstances. In
fact, it is likely they would consider more. It is disappointing to see the inclusion of the 10% con-
tingency being questioned where its removal would increase the already under recovery on
GSCs. This is addressed further in the responses to questions on contingency.
1.4 Brownfield vs. Greenfield development
In this regard it is clear that Industry is clearly not comparing like with like. ESB Networks
acknowledge that Industry has developed significant experience in the delivery of new assets in
new green field sites. However, this is not comparable with developing assets in aged brown-
field substations, while maximising the need to keep customers connected, and as such the risk
in pricing projects in this scenario is much less than the exposure UoS faces with such develop-
ments. We have explained the complexities and differences between brownfield and greenfield
works previously, including at the industry workshop where we understood there was an appre-
ciation and acceptance of same.
It must be remembered in the development of new generation connection assets the generators
connection at some point will have to connect into an existing brownfield site. The technical
complexity, design and management costs of development is significantly greater than the expe-
rience set of industry. In addition, there are a number of items that add further complexity in
delivery connections at brownfield sites including, outage management, live site safety work
management, customer continuity and the vintage of equipment being interfaced with.
ESB Networks makes every effort to ensure that only the time necessary is taken to plan and de-
velop connections. However, these are live brownfield sites where the safety and wellbeing of its
staff is paramount. ESB Networks must follow national health and safety policy and governance
requirements when managing generator projects connecting to the distribution system. Industry
does not have to consider many of these live brownfield safety challenges as their greenfield
sites pose low electrical risk until initial energisation.
In addition, the complex nature and resources required with the outage management works
necessary to facilitate grid connections may not be fully appreciated. Each outage is carefully
planned to ensure minimal disruptions to connected customers during the project. For example,
protection upgrade works directly driven by new distributed generation. There is also great care
taken during the initial energisation of new assets. This can involve temporary protection
changes and network reconfiguration, all of which require attendance by ESB Networks staff at
multiple substations. This is to ensure that any failure of equipment on initial energisation or the
‘soak’ period (typically 24-48 hours post-energisation) has the minimum impact possible on
safety, other equipment, or the electricity system. For example, in a recent energisation of a
large windfarm in Cork when the power cable installed by the windfarm’s contractors failed
4|Pageshortly after energisation, ESB Networks’ other domestic and industrial customers were not con-
sequentially impacted by the fault created by the windfarm project. Therefore, these precau-
tionary measures taken by ESB Networks have proven necessary.
1.5 Treatment of civil works
The inclusion of civil work costs in the GSCs would increase the risk to the UoS customer. There
is always a significant risk and uncertainty associated with costs for civil works that would be ex-
tremely difficult to manage through a standard charge. The scale of civil works cannot be reason-
ably known until detailed site investigations determine the site-specific conditions, environmen-
tal factors, etc. Even then, the risk remains during construction phase of unexpected civils costs.
It is appropriate that the entity driving the work (i.e. generator) bears that risk and cost.
We note in the responses that they are seeking not to bear that risk and therefore this means
that the UoS customer would have to bear that uncertainty. If such costs were to be put in to
GSCs to cover the risk then the charges would need to increase accordingly and it would mean
that all generators would have to pay those increased costs even if they were not driving signifi-
cant civil works and costs. In the proposal, only the generator driving the civil costs pays those
costs and they only pay the costs associated with their connection.
In order to give more certainty on civil work costs at the connection offer stage, a detailed de-
sign and ground condition assessment would be required, in association with applying up-to-
date costing via the contractor framework agreements. An estimate for civil works costs would
need to be calculated which would require a significant amount of work not to mention uncer-
tainties and would be in excess of the 4% suggested to cover the risks in this area. Again, it is im-
portant to clarify that generator customers are only charged for civil works associated with their
connection.
1.6 Equipment specification
On several occasions in the feedback comparisons have been made between 33 kV and 38 kV
system equipment, without a fundamental understanding of ESB Networks’ system voltages.
There is a misconception that high voltage equipment is purchased to meet the nominal system
voltage i.e. 38 kV. What is more significant is the design of the insulation on the system to with-
stand surge voltages. The technical term for this insulation levels is known as the Basic Insulation
Level or (BIL). The BIL for ESB network’s 38 kV system is 250 kV, or in other words the 38 kV sys-
tem can safely withstand surges with a peak voltage of 250 kV for 1.5 microseconds. The chal-
lenge Lines, Cables and Switchgear equipment suppliers have is to provide equipment that not
only meets the nominal 38 kV voltage but also the BIL voltage of 250 kV. To meeting this BIL re-
quirement, equipment suppliers provide equipment rated for nominal voltages of 52 kV and in
some instances 72 kV (The next available IEC international standard voltage levels). What this
effectively means is direct comparison with 33 kV systems in not entirely accurate or appropri-
ate. It should be noted that 52 kV and 72 kV equipment is significantly physically larger than 33
kV equipment (typically 57% larger). The additional size of equipment has a direct impact on the
site footprint of the project and in turn has a significant impact on the costs of the installation.
5|PageFor example, much larger switchgear buildings are needed to accommodate 38 kV equipment
when compared to 33 kV equipment.
One of the challenges when connecting new generators into existing brownfield sites comes
from the existing of equipment to be interfaced with. Many of the existing substations that gen-
eration customers planned to connect to were originally designed and installed many years ago.
Through the passage of time many of the Original Equipment Manufacturers (OEM’s) are no
longer in business and those that are many no longer provide support services to extend legacy
switchgear. The challenge for ESB Networks is to design, procure and install modern equipment
within a substation that was constructed in a different era. The comparison of greenfield costs to
real life brownfield costs should not be considered applicable without making considerations for
the complexity of the specific connection.
Brownfield site interfacing is not only challenging with legacy equipment, but a new emerging
challenge is also the construction of projects interfacing with modern digital control systems.
With the life cycle of modern digital substation equipment being significantly less due to manu-
facturer’s equipment obsolescence policies, interfacing different versions of software and hard-
ware is much more complex than would present on a green field project. Highly skilled engineer-
ing and IT capability is required to be deployed on projects where these technologies are pre-
sent, which can have a significant impact on the installation costs.
6|Page2. Responses to queries on specific GSCs
Query 1 - Cost recovery:
Consultation response suggested that cost under recovery may be because some projects have not
yet paid for shared works. Please clarify.
Response: In the analysis carried out on the cohort of 22 projects, ESB Networks can confirm the
shared costs from all the projects in the cohort were included in demonstrating the cost under
recovery.
Query 2/3 – Cost efficiency:
Query 2 – Consultation responses requested the consideration of the impact of ESB Networks LEAN
connections project on GSCs. The CRU would like ESB Networks to clarify when the LEAN project will
be finished and projects implementing its conclusions; and how this will be reported for PR5.
Response: The Lean connections project is due to be completed end of Quarter 1 2022 however the
adoption of a lean approach and implementation of continuous improvements to the delivery of
major projects will continue beyond that time. The lean project is focussed on shortening the time
scales to connect customers, the cost of completing projects will be monitored and tracked but
recognising that trends in cost only become apparent over a longer period. The delivery timelines to
connect generator connections will be reported via the regulatory framework for incentives and
reporting, the format of which is currently being worked through between ESB Networks and the
CRU i.e. level of detail, frequency of reporting etc.
Query 3 - If new GSCs are being proposed post ECP-2.1, when are ESB Networks proposing this to
happen through the ECP-2 period?
Response: ESB Networks propose that any new GSCs would be submitted to CRU in between
batches with a more detailed review to be carried out in advance of ECP3 connection offer issuing in
2024. The frequency of non-standard charges will be kept under review throughout the ECP2
process
Query 4- Contingency:
A consultation response stated the GSCs were not estimates as therefore contingency shouldn’t be
considered.
What is your response to the assertion that Cost Units (both time and materials) used to build up
GSCs are averages and therefore the GSC is not an estimate and contingency shouldn’t be required?
Response: In deriving the updated GSCs, ESB Networks did use cost units which are averages, but we
also assumed standard designs. The 10% contingency is to cover the risk associated with the
unknowable non-standard elements of the design which is always likely to arise out of development
in a brownfield site. These risks include a wide range of scenarios which cannot be determined
without site investigation and include things such as: more complex/extensive wiring requirements
due to changes in design standards; bespoke solutions to accommodate different equipment to that
of the original station design, sourcing of equipment which is no longer standard and hence not
available on framework agreements.
7|PageDoes removing embedded civils from remaining GSCs and treating them as pass through costs
negate some of the justification for contingency?
Response: The removal of the civil costs means that the 10% contingency is more realistic. It reduces
the risk of trying to standardise costs that include civil works, that will by their nature differ from site
to site due to differing above-ground conditions; sub-surface considerations (e.g. rock type); and
other local environmental factors.
Section 2.4 of the joint charging policy outlines that a desktop study may not significantly
correspond to the actual build, which will reflect the outcome of the planning process, ground
conditions and local environmental factors.
A 10 % Contingency is considered low for construction projects where the cost estimate is based on
a desk top study which is necessarily a high-level study particularly where working in brownfield sites
can be extremely challenging owing to the necessity to work within live stations. The works are
designed in accordance with the requirements of the customer’s connection, however there are
inevitably considerable challenges at every station that cannot reasonably be foreseen given the
nature of a desktop study. These challenges range from safety restrictions imposed by Designated
Work Areas, tracing of existing services, relocation or adjustment of equipment to facilitate new
connection. Such risks will most likely extend the construction programme which would impact
labour costs and have an impact on the contingency.
Query 5- Contingency:
A consultation response focused on concern over contingency on non-contestable charges and
asserted that “ESBN fully understand the nature and complexity of their own network and are
familiar with the details and location of their own stations”. Please respond to this assertion.
Response: As outlined in the response to the previous question, non-contestable works in
brownfield sites can be extremely challenging due to the nature of working in an existing live station.
More often than not ESB Networks incurs significant additional cost in these areas beyond the 10%
contingency. Therefore, the generator is effectively protected from the real cost of these
connections and the under-recovery beyond the 10% contingency is picked up by the UoS customer.
Furthermore, a 10% contingency would be deemed low in circumstances where no scope or detailed
design has been completed in advance of offer issue. The implications of developers seeking more
certainty at offer stage are that detailed design and scoping would need to be carried out in
advance. This would result in much longer offer preparation times with a resulting increase in the
application fee along with the impact on other generator customers seeking an offer.
Query 6 – ESBN Work practices:
Please respond to the following consultation response. “ESB Networks to explain due to working
time regulations, this obligation to work extended hours in one area of activity appears to be
affecting ESBN’s ability to allow extended working hours in other activity areas, i.e. construction, and
provide the flexibility required for efficient build-out of grid assets. It is our view that costs
associated with inefficiencies of this nature should not be recovered as part of the GSC.”
Response: ESB Networks is bound by the Working Time Act regarding work practices. The GSCs were
calculated based on work being carried out during standard hours. We believe this is the correct
basis for preparing standard costs. ESB Networks will always aim to accommodate flexible working
arrangement to facilitate generator connecting in a timely manner. It is important to note that
where timelines to connect a project are compressed to achieve critical connection dates, additional
resources would be required and would impact on the project management costs.
8|PageQuery 7 - New charges:
Please respond to the following consultation response. “Industry do not agree that extremely high
design and PM costs can be charged against a piece of equipment simply for being bespoke. The
charges proposed for some GSCs would suggest that these are entirely new designs every time. We
expect high design and PM charges are included for other GSCs but many of these items are not
bespoke and simply come from term suppliers based on approved designs and specifications.”
Response: The designs involved in these charges are bespoke in that every connection and
substation is different. While elements of design can be similar, the challenge is integrating the
design into a unique brownfield site. As detailed previously, connecting into older stations can be
very complex, where the design and project management costs relative to the material costs can
vary significantly
Query 8 – New charges:
Following related consultation responses, please detail need for this NVD protection (quoting other
jurisdictions if possible). Also, how is this charge different from NVD protection that was charged in
ECP-1 offers that justifies the increase?
Response: Neutral Voltage Displacement (NVD) protection is needed to deal with Earth Faults on the
network because when a line is disconnected from the main ESB grid an earth fault will create a high
voltage rather than a high current. This means the overcurrent relays or fuses won’t work and we
need to have the additional NVD protection to detect this dangerous high earth fault voltage. This
protection is required and standard with UK DNOs. All of the 110kV/38kV transformers require
110kV NVD protection relays per transformer where the connected generation is 2MW or above at
the node. In the case of 110kV/MV, depending on the earthing arrangement 110kV NVD protection
maybe required and the number will depend on two or single transformer setup.
Non-standard protection has historically been charged at €29k, which was based on a PR4 BPO / Unit
cost developed back in 2014-15 for use during PR4 Period (2016-'20). For purposes of consistency
across the PR4 period this non-standard protection charge remained constant over that period, even
though it was considerably under-recovering the costs that were actually incurred in delivery. Since
then, this BPO has undergone a review in 2019 to provide a more accurate up to date cost of D&PM,
installation and commissioning, applying the same approach as PR5 Units costs & proposed GSC's. It
should be noted that the BPO/ Unit costs are based on 110kV NVD on one transformer whereas the
GSC is based on installation of two (on both sides of the transformer). If the same logic applied to
the current proposed 2020 GSC's, is replicated on the updated 110kV NVD then the gross cost would
be ~€172.3k which is ~10% less than the proposed GSC of €192.8k.
9|PageQuery 9 - Industry worked example:
Appendix 2 in the Joint association response shows a sample 4MW project - example given of €/MW
costs for 4MW and increase to 10MW. Do ESB Networks agree with the assertions made in this ex-
ample?
Response: ESB Networks notes that there are many inputs to a RESS bid price, some of which
include, Capex, Opex, Rate of return, inflation, life of the project etc. Industry have not provided
details or justification to verify their statement in relation to what they say would be the impact on
their bid price, but from ESB Networks understanding, the Industry figure does not seem correct.
The current approved GSC#31 5MVA 38kV/MV transformer into an existing station with no busbar
extension of €415k was derived back in 2007 and it not in line with 2020 costs to procure a 5MVA
transformer and the design, project management, installation and commissioning costs required to
uprate a 38kV/MV station. The industry provided costs of €520k for a 5MVA Greenfield transformer
package demonstrate that the current approved GSC#31 is significantly under recovering. The
proposed GSC#31 was built from the bottom up and applying competitively procured transformer
costs and the detailed design required to integrate into a live station which is more complex than
uprating a greenfield site as set out in detail in this paper.
In any event if a generator connecting to the system drives works then there are associated costs.
ESB Networks stands over the proposed GSCs and that they are cost reflective. If the Generator
does not pay those costs, then it is the UoS customer that has to pay same. Furthermore, it is noted
that in many cases a customer seeking to connect to the system does not drive a transformer uprate
and in other instances where uprates are required they can be part of shared works in a subgroup
with costs shared on a per MW basis as per regulated policy. Therefore, those projects that do not
drive works or less works, will not have to pay such costs, and accordingly their connection costs will
be lower which they will factor into their project modelling. With the design of the RESS auction
such that the generators who bid the lowest prices being successful for the ultimate benefit of the
end consumer.
Query 10 – Cable standard charges:
The Design and Project Management % for GSC 8 appears to be out of line with 5,7,9,10 – please ex-
plain. Also, please respond to consultation comment on GSC 12 as a rudimentary asset.
In response to the first query regarding the Design and Project Management % variance between the
proposed charges. The reason being that GSC’s 5,7,9 & 10 are at distribution level (MV & 38kV) in
which case design and project management is carried out in-house and covered as an overhead by
application of standard overhead rates. GSC 8 is at transmission level 110kV and in which case
additional professional design fees are incurred through third party consultants relating to design &
project management, giving rise to the increase in D&PM costs between 8 in comparison to 5,7,9
&10. In support of overall GSC costs (ref 8) for the 110kV 630mm XLPE (AL) Single Circuit at €379k, a
suitable comparison can be made to unit costs provide in PR5 submission - reference C110-1 or
C110-10 of €379.5k (excluding 10% contingency included in GSC's).
Secondly, regarding the query relating to GSC Ref#12 LCIM, although this charge has increased by
~50% compared to current, there has only been a marginal (5%) increase since the 2018 submission.
The statement in the CRU consultation paper that the increase is due to D&PM is not an accurate
reflection of the reason for the increase. Similar to all other GSC's the 2020 proposed costs are as a
result of a detailed review undertaken from first principles, and it should be noted that the D&PM
10 | P a g e(incl Commissioning) costs have reduced by ~32% since the 2018 submission, with previous 2018
Telecoms cost estimate being removed in their entirety. A 16% increase in construction costs is
because this particular charge includes the civils element for the mast foundation which along with
the cable termination costs have increased since 2018 and represent the majority of ~51% increase
compared to the current charge. We acknowledge that this is a relatively rudimentary apparatus /
asset, as noted in the Association report however, the civils element in both civils design & physical
civil works associated with the mast foundation can vary widely between sites; and the 2020
proposed costs provide industry with a fixed price reflecting the average civils costs associated with
the installation.
Query 11 – Cable standard charges:
What is ESB Networks proposal for GSC 9a – Arc suppression coil?
Response: ESB Networks propose to revert to including the ASC cost as part of the GSC9 on the per
km of cable charge and propose a revised charge to the CRU for approval. The cost will be spread
between customers who connect via 38kV cable and this will avoid the project which triggers the
requirement for an ASC having to pay the full cost and potentially making the project unviable.
Not all the ASC cost is being attributed to the project that drives the initial need for an ASC, rather a
pro rata fair and transparent model is proposed, with a cost per km being included in the cable costs.
Therefore, the projects that add the most capacitive current onto the network pay the most for it.
The balance of the ASC capacity is not to be paid by the generator customer driving the initial need
for it, i.e. the balance is socialised on the UoS costs with spare capacity thus available and chargeable
to new generators projects.
Following due consideration of both Industry & CRU response to the proposed introduction of a
separate ASC charge, we have reviewed and revised costs & charging methodology accordingly, in
order to minimise the impact, it may have had to smaller generator projects. As we now can see a
reasonable pipeline of ASC projects coming from RESS we have been able to drive efficiencies from
our engineering design teams. We have reduced the design and project management costs based
on the new knowledge that a secure pipeline line of ACS projects can be seen in the RESS projects
that was not available last summer when it was costed as a single one-off project without the
efficiencies of scale.
The costs per km portion of the ASC costs have now been re-calculated and apportioned back into
the per km 38kV cable charge on a pro-rata basis resulting in revised proposal of €124,880 / km for
GSC 9 38kV cable. This will result in a -3% saving on the current 38kV cable charge of 128,830. The
previously proposed charge 9a will removed from the revised proposal, and a revised charge 9 will
be included.
With this proposal the burden to the generation customer is small and proportionate to the impact
of their proposed connection technologies and length of them. Overhead lines are not considered
as their capacitive impact is negligible and the cost to administer such a cost would far outweigh the
recovery benefit.
11 | P a g eQuery 12 Station Standard Charges
Please explain in more detail the difference between the PR4/5 Unit Cost of transformers and GSC
23 and GSC 33 for uprating.
Please explain the higher amount for indicative civil construction estimate of GSC 33 versus GSC 23.
Also, please comment on industry average for this GSC and the issue of 132/33kV versus 110/38kV
benchmarking.
Response: GSC #23 is for uprating from 2*31.5MVA to 2*63MVA Transformers is comparable to the
63MVA Transformer Installation of €1,516,675 as submitted PR5 DSO Unit costs. The proposed GSC
of €3,678,490 is based on the installation of 2nr 63MVA transformer, and the following should be
considered when comparing the 2 sets of costs:
PR5 Unit costs for €1.5M, include Civils costs at ~€140k which if removed results in a cost of €1.36M
for 1nr 63MVA transformer or €2.72M for 2 transformers excluding civil works
When compared to GSC of €3.68M shows as delta of €0.96M, which is explained as follows:
• GSC includes for retirement & decommissioning of existing 31.5MVA transformers and
associated obsolete equipment (CT's, VT's, CB, Disconnects and steelwork) to the value of
€160k.
GSC includes for the following additional works which total €850k
• 2nr 38kV Line Bays (Installation Surge Arrestors, Disconnects, CT's, VT's, Cabinets, Steelwork
and associated conductor and control cabling)
• 2nr 38kV Transformers Bay (Installation of Disconnects, CT's, VT's, C&P Relays & Cabinets,
Steelwork and associated conductor and control cabling)
• 1nr 38kV Sectionaliser Bay (Installation of Surge Arrestors, Disconnects, CT's, Cabinets,
Steelwork and associated conductor and control cabling)
• 1nr 110kV Transformer Bay (Installation of Control & Protection Relays - Impedance,
Differential, Over Current and associated Cabinets and control cabling)
• 38kV Busbar Extension (Installation of Steelwork, Conductor and insulators)
This difference in scope between the PR5 Unit costs & the proposed GSC amounts to a total of
€1.01M which explains the delta of €0.96M between the two sets of costs.
Furthermore, it should also be noted that there has been a 7% (€261.5k) reduction in this charge
since 2018 submission, as a result of the detailed cost reviewed carried out as part of the 2020
submission.
Note , where transformers are removed as part of an upgrade programme and replaced by larger
capacity transformers, as per the Joint TSO/DSO GPA charging and rebate principles paper, where
such transformers are re-used elsewhere on the system the generator is entitled to a refund. The
refund will be paid once the removed asset has been successfully commissioned in its new location.
Charge #33 would follow the same logic, the PR5 Unit Cost of €689k can be doubled to reflect the
cost of the 2*MVA Transformers being installed in GSC33 equating to €1.377M V’s the €1.957M in
the proposed GSC. However as previously advised in GSC23 the following scope differences
between the two sets of costs need to be considered on a like for like comparison:
12 | P a g eo PR5 Unit costs include civils costs for the transformer base, plinth and bund (ap-
prox € 240k for 2 sets of Trafo’s).
o Excluding civils the variance electrical costs is €820k (€1.377M-240k) V’s €1.957M
in GSC.
o Excluding the 10% contingency in the GSC equates to approx €180k, reducing the
differential to €640k, which is due the following additional scope included in the
GSC but not in the standard PR5 10MVA Transformer cost:
o Switchgear & Protection Relays for:
▪ 2nr 38kV Trafo Bays
▪ 2nr MV Trafo Bays
o Busbar Uprating for
▪ 38kV busbar & steelwork
▪ MV busbar & steelwork
o Control Room Fit-Out
▪ Battery Charger
▪ Distribution Board
▪ Fit-out of control building with AAP, DC System
mimics etc. included
Associated Telecoms, Design, Supervision & Commissioning costs as a requirement of the above
additional scope
Please explain the higher amount for indicative civil construction estimate of GSC 33 versus GSC 23.
Due to differences in scope of the physical civils works between the two charges, associated design
and construction supervision:
• 23 Uprate 2*31.5MVA to 2*63MVA € 240,300
• 33 Uprate 2*5MVA station to 2*10MVA € 469,000
Delta: € 228,700
Additional Scope in GSC33 (as per SLD in Statement of Charges:
The majority of the cost differential is the requirement for a New Control Room Building as part of
GSC33. The uprate from 2*5MVA to 2*10MVA in 38kV stations drives the necessity for full control
room equipment replacement, which typically in an existing 2*5MVA station requires the construc-
tion of new larger control room to house the new larger control equipment (Batteries, Chargers, Dis-
tribution Board, Control Cabinets, Mimic Panels, & AAP). The cost for design, supervision and con-
struction of same in an existing brownfield station is included in GSC33, whereas in GSC22 the con-
trol room equipment in 110kV Stations is not uprated when going from 2*31.5MVA to
2*63MVA. The new control room represents the substantial portion of the delta, with the uprating
to the MV side of the busbar & additional bases for MV Trafo Bays also contribute to some of the
cost variance between the two civils estimates, albeit to a lesser extent. See SLD and scoping as-
sumptions from Part B below:
13 | P a g eAlso, please comment on industry average for this GSC and the issue of 132/33kV versus 110/38kV
benchmarking.
The Association, in their response have also proposed an “Industry Average” cost of €1,208,487 for
63MVA & €1,046,931 for 31.5MVA which appears to suggest that there is a €161k (13%) cost
differential between 31.5MVA & 63MVA transformer. On further review of our transformer supply
costs included in the proposed GSC’s, which are based competitively procured term contracts, the
cost differential from a 31.5MVA transformer to 63MVA would be in the region of 40-45%. This is
without any consideration for D&PM, installation costs and associated commissioning etc., not to
mention the additional equipment included in the overall transformer package (as detailed in the
Part B doc & illustrated on the accompanying SLD). We feel this raises further questions regarding
the validity and accuracy of the Industry average costs proposed in the Association report. Cost
provided by Industry based on 2018 prices on which no detail has been provided as to the scope of
their content, nor were they subject to the same level of benchmarking comparison or detailed
scrutiny by independent external consultants.
Benchmarking comparison by both GHD & WSP to UK equivalent 132/33 kV transformers is
considered broadly accurate and valid as purchase price supply costs are broadly in line, and design,
installation and commissioning costs would be similar. Such supply costs are based on material
components and manufacturing etc., as opposed to being directly proportional to the operating
voltages which seems to be suggested by industry, and it would not be accurate to adjust these
supply price costs on a pro-rata basis between the 132/33 kV when comparing benchmark costs UK
DNO’s and Irish equivalent of 110/38 kV (as per GSC's). As previously discussed, the ESB Networks
distribution voltage of 38 kV has Basic Insulation Level (BIL) of 250 kV. To meet this standard 52 kV
and in some instances 72 kV equipment is required. This has a direct impact on the cost of
equipment but also on the physical footprint costs required to install this physically larger
equipment. As such care needs to be taken when making direct comparisons to adjust for not only
the system voltage, but also the BIL and consequential additional installation costs.
14 | P a g eQuery 13 /14 38kV Station Standard Charges
Query 13 - What is the added cost of Siemens NX Plus Switchgear for 26 and 28?
Response: The cost allowed for Siemens NXPlus Switchgear represents approx. 9-10% of the overall
proposed GSC #26 of approx. €80k in value terms estimate. Siemens NXPlus is a standard design
requirement for new transformer installations at 38kV/MV in a greenfield "new build" station
scenario, in particular GSCs 26 &28.
Query 14 - Why is GSC 26 percentage increase of existing approved GSC much higher than equiva-
lent GSC 18? Also, please comment on industry average costs for these GSCs.
Response: PR5 Unit cost on which the above comparisons are made, are based on transformer
installation costs only, as opposed to the full transformer package that is included in the proposed
GSC costs - i.e. Switchgear, Bay Installation, CB's, CT's, VT’s disconnects etc. - as detailed in SLD
provided in Part B doc. There is however a further variance between the scope of the package of
works included in GSC #26 versus those in GSC #18, which result in a difference between % variance
on each when compared to PR5 Unit costs, as follows:
GSC#18 (63MVA) costs allow for one 38kV Transformer Bay, whereas GSC#26 (5MVA) includes for
two Bays on both 38kV & MV side along with the associated busbar extension on both sides.
Resulting in the additional cost of the MV Transformer Bay and Busbar ext. in GSC#26 versus that of
GSC#18. In addition to this GSC#26 includes the costs for Siemens NXPlus Switchgear (as noted
above), and the combination of these scope / cost differences give rise to the variance in the %
difference when comparing these charges back to PR5 Unit costs.
We would have serious concerns in the accuracy / appropriateness of the “Industry Average” costs
proposed in relation to these two charges: €520k for a 5MVA Greenfield Transformer Package (GSC
Ref #26) & €523.2k for 15MVAGreefield Transformer Package (GSC Ref #28). Industry appears to
suggest that there is only a marginal cost increase of €3.2k (0.6%) between a 5MVA & 15MVA
Transformers assuming this is based on full installation, commissioned & energisation. Which brings
into question the validity of the cost proposed by Industry, especially given ESB Networks framework
contracts for transformer supply prices alone for a 15MVA transformer is approx. 75-80% more
15 | P a g eexpensive than a 5MVA, before even taking into account the costs required for the design,
management, installation, and associated commissioning
Query 15 - Misc. Station Standard Charges
Please comment on the consultation responses which questions the reasoning for significant
increase over current GSCs aside from the oversight mentioned. Also, is the oversight addition the
difference between 2018 and 2020? If not, state oversight cost for each.
Response: The fundamental reasons for the increase in the 38kV cubicle charges GSC #36 (in 38kV
Stn) & GSC #37 (in 110kV Stn.) as previously noted are due to revised methodology applied to 2020
GSC review in line with PR5 Unit costing approach. The oversight is only one element of the increase
in costs difference, and detailed explanation is as follows:
• Telecoms & Commissioning costs to provide a more accurate charge specific costs based on
scope, rather than % estimate allowances for same:
o Telecoms increase from €910 - €1,250 in 2018 to €15,500 in 2020
o Commissioning increase from €25k in 2018 to €29k in 2020, based on current
framework contract rates, competitive tendered under current EU procurement
guidelines.
• There has also been an increase in Construction costs (~€44-€46.5k) based on a combination
of 2 underlying reasons:
1. Oversight in incorrect inclusion of MV equipment (CB's, VT's & CT's) in the 38kV
cubicles, which have now been corrected to account for 38kV rating of the same
equipment which has resulted in a total charge increase of ~€19k.
2. Update of construction component costs in line with the same as those applied in PR5
Unit, resulting in €20-25k increase in construction costs for these particular items.
It should be noted that the same logic was also applied to GSC #38, which reflected only a 2%
increase since 2018; based on GSC frequency in ECP1 is altogether a more commonly used charge
(38 instances of GSC#38 V's 6 of GSC#36 & 12 of GSC#37). Furthermore, both charges GSC #36 &
GSC #38 underwent a full cost benchmark comparison as detailed in WSP benchmarking, which
concluded that following the correction of the aforementioned oversight in GSC#36, construction &
direct labour costs were in line with UK DNO competitors, while previous 2018 (pre-correction) costs
were significantly below the average comparison benchmark.
16 | P a g eQuery 16 – Comms and Protection Charge
A consultation response asserted that Scada, protection, metering and communications are all areas
where technology improvements can have a major (decreasing) impact on costs. Please respond to
this.
Response: ESB Networks competitively procures all its Scada, Protection. Metering and
communications through competitively procured tender processes. ESB Networks have introduced
improvements to the communications equipment where connections under 5MW only require a
single Remote Terminal Unit (RTU).
Arc Suppression Coils are needed on the 38 kV network to limit the harmful effects of earth faults.
They are standard on all our 38 kV network and are similar to the network in Germany and other
parts of Europe. ASC are also used by Western Power DNO in the UK.
Neutral Voltage Displacement protection is needed to deal with Earth Faults on the network because
when a line it disconnected from the main ESB grid an earth fault will create a high voltage rather
than a high current. This means the overcurrent relays or fuses won’t work and we need to have the
additional NVD protection to detect this dangerous high earth fault voltage.
EGIP protection is needed because when there is a fault on the public ESB Networks lines it can be
supplied from both the ESB Networks side and from any customer generation. The fault needs to be
isolated from all sources of supply to make the lines crossing public land safe. The EGIP equipment
is owned and operated by ESB Networks as it is protecting ESB Networks assets.
Query 17 - Customer Compound Std charge
Please respond to consultation comment on scope of compound in relation to GSCs. Also, aside from
telecoms difference from 2018 to 2020 what is driving the large cost increase over current charges?
Response: Industry have proposed a cost of €280.5k in respect of GSC#54 "ESB Networks Compound
with Over-the-Fence Connection to Developer – Underground Connection", which is the same as
that previously proposed in response to the 2018 submission where there is no detailed breakdown,
nor has there been any comparison benchmarks to substantiate their claim to deliver the full scope
of works for this cost as outlined in Part B document. We would therefore question the validity of
this figure and whether it is purely based on the cost incurred of the direct physical construction
works only, or whether it includes the project management, detailed design, telecoms, supervision
and associated overheads, that would be incorporated into the proposed GSC's.
The scope of the works included in the proposed GSC costs for both GSC #53 & GSC #54 are clearly
defined in the assumptions listed below the SLD and include for both EGIP protection & fully
equipped Customer Interface Kiosk.
17 | P a g eAs previously advised the and evidence by component costs analysis provided to CRU as part of the
2020 submission, the increase between 2018 & 2020 costs is predominantly due to the more
accurate telecoms costs included in these charges. Previously telecoms costs were only estimated
based on a typical standard % of total construction costs, which did not reflect the true scope of the
telecoms works required to deliver the GSC, which is now based on the following specific telecoms
installations: Full DSO Scada RTU Installation, poling radio survey and installation works and includes
Satellite installation at OH connection & Fibre connected to 38kV Sub for underground cable
connections.
WSP carried out detailed benchmark analysis of the direct labour construction costs on the 2018
submission and based on the findings in their report, ESB Networks have since addressed the
concerns in construction delivery costs and following the 2020 review of costs were able to make a
12% reduction in construction costs to bring them in line with DNO benchmark comparisons. This is
evidenced in the comparison cost data provided to CRU as part of our 2020 submission, included in
CRU consultation paper and clearly demonstrates our commitment to produce an accurate set of
charges that are in line and comparable to other utility costs.
Query 18/19/20 Discontinued Charges
Query 18 - Discontinued Charges GSC#4
GSC-4: 38kV overhead lines 300 mm2 ACSR - should this be maintained for uprating as suggested by
industry.
Response: GSC #4 38kV SC Wood pole 300mm ACSR- has not been used over the past number of
years and would not be considered in an LCTA calculation. The uprating of 38kV OHLs are non-
standard by nature given the different terrain, pole conditions, environmental factors, difficulty with
landowners who do not want OHL on their lands, all of which increase the cost and time to build.
OHLs are becoming increasing difficult to build and becoming non-standard. In the unlikely event
this charge was needed, GSC#5 could be applied as a proxy with an updated material cost for the
Wood pole 300mm ACSR.
18 | P a g eQuery 19 - Discontinued Charges GSC#33
GSC-33: Uprate 2*5 MVA Station to 2*10 MVA. Please respond to the consultation response “By
removing the cost from the list, it may remove the option for the renewable generators to be
offered the least cost technically acceptable connection method”.
Response: GSC# 33 Uprate 2*5 MVA Stn to 2*10 MVA has not been used over the past number of
years and the more likely connection would be the installation of a third transformer. ESB Networks
can consider maintaining this charge for the purposes of an LCTA calculation and will revert with a
proposed charge for approval in advance of the CRU determination on the proposed GSCs.
Query 20 - Discontinued Charges GSC#45
GSC-45 MV Metering and Power Quality >= 10 MVA (where MV CB is being charged as part of EGIP
installation, no need for KKK) – Please respond to the consultation response that there “is a need for
greater transparency on now ESB Networks will be charging for metering and EGIP equipment for
MV connections and how it is linked to LCTA of a KKK arrangement. It should also be clear what
rebate generators will receive if MV connections are being completed contestably and based on
System Operator preferred method with MV CBs.”
Response: GSC# 45 MV Metering and Power Quality >= 10 MVA where MV CB is part of EGIP charge
has not been used over the past number of years. ESB Networks propose maintaining this charge so
it is clear what rebate generators will apply where MV connection are completed on a contestable
basis. This charge can be calculated and submitted for approval in advance of the CRU determination
on the proposed GSCs.
Query 21 - Non-Standard Items
Please comment on methodology for calculation of non-standard charges.
Response: The methodology for calculating non-standard charges is similar to how the standard
charge methodology was carried out. The cost units that were approved in PR5 are updated with the
latest time, material, others from the costing database. These costs are then grossed up applying the
same methodology as the standard charges. A comparison with similar charges from prior years is
carried out before approved for use in a connection offer.
Query 22 – Removal of embedded civil costs
Following review of joint association consultation response, please respond further on the
justification for removing remaining embedded civils.
Response: The primary considerations behind the omission of embedded civils was driven by:
• Ambiguity and inconsistency in their treatment in the current GSCs
19 | P a g e• Bespoke nature of every site and the associated risks that greatly influence final civil costs.
These were comprehensively presented at the recent open industry consultation forum and
acknowledge by CRU at the time.
• Under-recovery in the current PTC charges thus leading to unnecessary UoS liability
• Civils costs are not just limited to the plant, materials and labour associated with a civil
activity. They must also encompass a portion of any design, supervision, contract
administration and project management cost associated with the activity.
The proposed model of omitting civils and recovering via pass through charges has the following
advantages
• Generators will only pay the civils associated with their connection at their connecting
station.
• Generators with benign sites will pay civils reflective of the low risk. Only those with more
challenging site will pay the associated civils representative of the risks of their node station.
This is deemed equitable.
• Embedded civils will need to be at a level that all potential risks as previously highlighted are
blended into the individual charge items. This will result in unnecessarily higher charges to
ensure that the UoS customer is adequately protected from any liability.
• Embedded civils may disadvantage the smaller generator as they are required to pay higher
charges that will benefit the larger generators. This may well result in a disincentive to
smaller customers.
The exercise used in the Cohort study utilised costs based on frameworks rates that excluded
many of the risk items discussed previously. This proposal will only be of benefit to the
generators and again leave UoS liable for any under-recovery. Again, the alternative would be to
increase the embedded civils by such a level that protects the UoS customer. If it were deemed
appropriate by CRU to include the civils (with the associated UoS cost risk) then civil costs would
have to be developed/reviewed for each of the items that CRU wished to include them in.
Query 23 – Pass Through Costs - Greater transparency on pass through costs
Please respond to the joint association call for greater transparency on how pass-through costs
figures are arrived at and agreed between ESB Networks and connection parties and the steps that
are suggested.
Response: ESB Networks acknowledges and understands Industry’s requirement for greater
transparency in the provision of PTCs.
Firstly, is should be noted that ESB Networks changed its process when preparing and issuing offers
as part of ECP-1 to include provisional PTCs. This involves extra upfront work and consideration
from a cross function of teams/experts but we appreciate that in doing this at offer stage allows the
generators to have a greater understanding of the potential costs upfront for consideration when for
example they are engaging in the RESS auction. The PTCs were based on a high-level connection
studies based on known information at the time and do not for example include full site
investigations etc. The PTC information provided is very useful to the generator when considering
their offer and this has been widely appreciated by the industry as a positive development. We
intend to continue to provide PTC estimates in ECP2.1 which gives the generator this upfront
transparency on costs.
20 | P a g eMore detailed construction budgets at offer stage would require greater upfront design. This has to
be balanced with the need to expedite offers, minimise application fees and reduce sunk costs/UoS
liability from customers who may not proceed further with a project on receipt of their offer.
As the project moves through the various stages and the associated payment milestones the costs
become clearer. ESB Networks has been actively improving transparency and communications in
this area in the last number of years through the provision of Pass Though Cost Reports. These
reports have been used as a separate tool to inform customers of the details pertaining to PTCs that
are included in third and fourth stage invoices and customer meetings take place as required to
discuss same in greater detail. Many customers have complimented the level of detail and
assurance that it has provided to their financiers.
As noted above it is clearly understood by all that connection works are defined as the connection
moves from offer through scoping, detailed design and construction. Likewise, costs move from
order of magnitude to indicative to final reconciliation in tandem with the project lifecycle. The
pass-through cost reports as referred to above provide the information on the associated costs to
the generator as the project progresses through the different phases and stage payments. ESB
Networks is continuously seeking to improve engagement with generators on this process and is
open to looking at, for example, the frequency and manner of reports and engagement, which
would be dictated by the complexity of the individual projects.
One point to note in relation to the above is that the sharing of commercially sensitive information
such as for example ESB Network’s frameworks tenders and contractors’ rates with the generator
would be in breach of the confidentiality agreements contained within these contracts. These
agreements are required to protect commercially sensitive information that if made public could
serve to undermines the continued operation of these companies. Whilst industry may perceive this
as a lack of transparency on ESB Network’s part, they can be assured that ESB Network’s
procurement policies are held against and governed by EU Utilities Directive to ensure openness and
competitiveness in the procurement of goods and services.
Query 24 – Cost recovery –Higher costs due to delays with contestable works
Please respond to the consultation response that asserted that “In some cases, higher pass-through
costs may be due to a combination of project delays with contested works or other reasons outside
of ESB Network’s control.”
Response: The pass-through costs on a customer contestable connection can be impacted due to
delays to the customers work programme, the opposite is also true where a customer’s contestable
work programme is completed faster than planned, ESB Networks supervision costs will be less and
that is reflected in the reconciliation of the pass-through supervision costs.
21 | P a g eQuery 25 – Pass Through Costs – Outage constraints
Please respond to the consultation response calling for further information on understanding how
outage costs could be deemed as costs to generators how outage constraints are deemed as pass
through.
Response: ESB Networks is quite often constrained by outage limitations, with connection works
having to be undertaken outside normal working hours i.e. weekend or nighttime. GSCs are based
on completing works within normal working hours. Therefore, where outages determine that
connection works must take place outside of these normal working hours, the additional cost of
which can be passed through to the generator. e.g. Rossaveal, nighttime outages were only
permitted to maintain supply to the Aran Islands.
Query 26 - Pass Through Costs –Flexible Working Hours
Please respond to the consultation response that asserted that “Currently there is no transparent
process of how and when developers can engage and request ESB Networks to work outside normal
hours to achieve connection dates.”
Response: ESB Networks must work within the Working Time Act and may not be able to accept
accelerated work programmes from customers who require outside normal hours to facilitate their
connection timelines. ESB Networks is always open to engaging with developers to achieve
connection dates but is constrained by the Working Time Act.
Query 27 - General - Applicability of charges to projects on hold/mods
What are ESB Networks comments around requirement for greater communication and clarity of
being put on hold as described by the associations?
Response: Projects awaiting planning permission or waiting for a route to market e.g. through a
RESS Auction were the primary reasons for projects going on hold. The ECP rule requiring projects to
have planning and more frequent RESS auctions go a long way to mitigating projects choosing to
delay their grid connection. ESB Networks will be strictly enforcing long stop dates so to avoid
projects tying up network capacity for long periods of time. It is ESB Networks view that projects
applying for modifications should have the approved GSCs applied at the time of modification offer
processing.
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