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Offshore Transmission Benchmarking and
Cost Monitoring
Final Report
10 June 2016
ORE Catapult
Document History
Revision Date Prepared by Checked by Approved
by
Revision
History
V01.00 25/04/2016 Gavin Smart
Hytham Emam
Owen Murphy
Ander Madariaga
V02.00 16/05/2016 Gavin Smart Hytham Emam
Peter MacDonald Chris Hill
V02.01 10/06/2016 Gavin Smart Hytham Emam Chris Hill
ORE Catapult
Contents
1 Executive Summary ............................................................................................... 6
1.1 Background ...................................................................................................... 6
1.2 Key Findings .................................................................................................... 6
1.3 Recommendation ............................................................................................. 8
1.4 Further Considerations – Cost Reduction Monitoring Framework .................. 10
1.5 Conclusions ................................................................................................... 11
2 Introduction........................................................................................................... 12
2.1 Background .................................................................................................... 12
2.2 Transmission Costs ....................................................................................... 12
2.3 Potential Approaches to Offshore Transmission Cost Benchmarking &
Monitoring ............................................................................................................... 13
3 Publicly Available Transmission Cost Data ....................................................... 14
3.1 Overview ........................................................................................................ 14
3.2 Available Data Sources .................................................................................. 14
3.3 Capex Estimation Methodology ..................................................................... 17
3.4 Metrics Summary ........................................................................................... 18
3.5 Summary of Publicly Available Offshore Transmission Cost Data ................. 22
4 Action 1 - Cost Benchmarking based on OFTO Data ........................................ 23
4.1 Background .................................................................................................... 23
4.2 Current GB Offshore Wind Transmission Benchmarking ............................... 24
4.3 Examples of Benchmarking in Other Industries ............................................. 25
4.4 Estimate of Benefits ....................................................................................... 26
4.5 Implementation .............................................................................................. 27
4.6 Data Confidentiality ........................................................................................ 30
4.7 Anonymity of Results ..................................................................................... 30
ORE Catapult
4.8 One-off exercise to prepare current benchmarks ........................................... 31
4.9 Cost of conducting the exercise ..................................................................... 32
4.10 Recommendations ...................................................................................... 32
5 CRMF Background ............................................................................................... 33
5.1 CRMF Overview ............................................................................................. 33
5.2 CRMF Key Challenges .................................................................................. 33
6 Action 2 – Amend Existing CRMF LCOE Calculator .......................................... 35
6.1 Amendments to the LCOE Calculator ............................................................ 35
6.2 Key Considerations ........................................................................................ 35
6.3 Recommendations ......................................................................................... 35
7 Action 3 – Update CRMF Qualitative Indicators ................................................. 36
7.1 Qualitative Workstream – Existing Offshore Transmission Indicators ............ 36
7.2 Proposed Offshore Transmission Indicators .................................................. 36
7.3 Recommendations ......................................................................................... 37
8 Recommendations ............................................................................................... 38
8.1 Implement an ongoing transmission cost benchmarking exercise ................. 38
8.2 CRMF Quantitative Workstream .................................................................... 40
Appendix 1 CRMF Qualitative Stream Detailed Design ....................................... 42
Appendix 2 CRMF Quantitative Stream Detailed Design ..................................... 43
Appendix 3 Existing Transmission CRMF Indicators .......................................... 45
Appendix 4 OFTO Transfer Metrics in 2011 Terms .............................................. 46
Appendix 5 OFTO Transfer Metrics by Windfarm................................................. 47
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List of Tables
Table 1 Key project-specific data required for cost monitoring ...................................................................................... 7
Table 2 Proposed Direct Cost benchmarks ................................................................................................................. 10
Table 3 Proposed CRMF transmission indicators ....................................................................................................... 11
Table 4 Proposed quantitative transmission benchmark metrics ................................................................................ 14
Table 5 Ofgem OFTO Cost Assessment capex summary by windfarm ...................................................................... 15
Table 6 Calculation data sources ................................................................................................................................ 18
Table 7 Metrics summary for OFTO transfers to date ................................................................................................. 19
Table 8 Illustrative potential savings from benchmarking against best in class by windfarm ...................................... 26
Table 9 Combined illustrative savings from benchmarking ......................................................................................... 27
Table 10 Proposed Direct Cost benchmarks ............................................................................................................... 29
Table 11 Initial analysis of OFTO transfers to date ..................................................................................................... 32
Table 12 Existing transmission-related CRMF indicators ............................................................................................ 36
Table 13 Proposed transmission-related CRMF indicators ......................................................................................... 37
Table 14 CRMF qualitative indicator tracking example ............................................................................................... 37
Table 15 Proposed Direct Cost benchmarks ............................................................................................................... 39
Table 16 Proposed CRMF transmission indicators ..................................................................................................... 40
Table A1 - 1 CRMF Qualitative Indicators Design ....................................................................................................... 42
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List of Figures
Figure 1 Offshore Substation Capex Metrics 2011 - 2015 ............................................................................................ 6
Figure 2 Offshore TNUoS charge worked example ..................................................................................................... 17
Figure 3 TRS as a % of FTV shown against number of OFTO transfers by year 2011 - 2015 .................................... 19
Figure 4 Offshore Substation capex metrics by year 2011 – 2015 .............................................................................. 20
Figure 5 Offshore Circuit capex metrics by year 2011 - 2015 ..................................................................................... 21
Figure 6 Onshore Substation Capex per MW by year 2011 - 2015 ............................................................................. 22
Figure A4 - 1 Offshore Substation capex metrics in 2011 terms ................................................................................. 46
Figure A4 - 2 Offshore Circuit capex metrics in 2011 terms ........................................................................................ 46
Figure A4 - 3 Onshore Substation capex metrics in 2011 terms ................................................................................. 46
Figure A5 - 1 TRS % of FTV by windfarm 2011 - 2015 ............................................................................................... 47
Figure A5 - 2 Offshore Substation capex metrics (nominal) by windfarm 2011 - 2015 ................................................ 47
Figure A5 - 3 Offshore Circuit capex metrics (nominal) by windfarm 2011 - 2015 ...................................................... 47
Figure A5 - 4 Onshore Substation capex metrics (nominal) by windfarm 2011 - 2015 ................................................ 48
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1 Executive Summary
1.1 Background
Transmission costs represent approximately 10% - 15% of the Levelised Cost of Energy (LCOE)
for offshore wind. However, the current level of costs and cost reduction potential of offshore wind
transmission have not been subject to the same level of widely-published industry-level analysis
as the generation assets. There has been a tendency in offshore wind industry studies to deal
with transmission at a high level (in the UK, this has been partly driven by the background of study
sponsors or a changing regime; in Europe more due to state provision of transmission assets).
As offshore wind generation technology develops and sites are developed further from shore, the
demands on the transmission system are changing. There are also developments which require
improved industry and regulatory co-ordination. The ongoing CRMF tracks progress in specific
innovations and quantifies current LCOE on an industry-aggregated level. However, of the 40
technology innovations monitored in CRMF, only 5 relate directly to transmission so there is
currently limited visibility of the progress of cost reduction and innovation in this area.
The OWPB Grid Group has commissioned this initial feasibility study into the potential for
implementing a benchmarking and cost monitoring process for offshore wind transmission costs.
1.2 Key Findings
1.2.1 Offshore Wind Transmission Costs Publicly Available Data
There is a reasonable amount of Offshore wind transmission data already publicly available,
in Ofgem OFTO Cost Assessment reports and published National Grid tariffs, from which asset
costs of Offshore Substation, Offshore Circuit and Onshore Substation can be approximated
at a high level (see Section 3 of this report).
The cost metrics derived from these high-level capex estimations show that there is no
consistent trend of cost reduction by project or by year (see Section 3.4 of this report). In fact,
it appears that a number of key cost metrics are increasing. The example of increasing offshore
substation costs is shown in Figure 1, below. Further analysis is included in Section 3.4.
Figure 1 Offshore Substation Capex Metrics 2011 - 2015
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In order to facilitate the required levels of cost reduction the reasons for apparent cost
increases require further detail on market and project-specific cost drivers. A summary of the
key additional details required is shown in Table 1, below.
Offshore Substation Local Circuit
Cost of transformers Offshore cable supply cost; Offshore cable
installation cost; number and size of offshore
cable sections
Cost of platform Onshore cable supply cost; Onshore cable
installation cost; number and size of onshore
cable sections
Offshore Substation foundations supply cost Landfall cost and method used
Foundations and topside installation cost Cost and properties of onshore reactive
equipment
Cost of any spare equipment included Cost of any spare equipment included
Table 1 Key project-specific data required for cost monitoring
From a disclosure point of view, release of the detailed information provided to Ofgem as part
of the OFTO Cost Assessment process is an additional level of detail compared to the data
already publicly available, but is essential in order to monitor and benchmark these costs more
accurately, to understand cost drivers and to inform and prioritise actions for transmission
system designers and procurement teams and for innovators.
1.2.2 The Case for Cost Monitoring and Benchmarking in Offshore Wind Transmission
Cost benchmarking is already used successfully by Ofgem in assessing economic and efficient
expenditure for OFTO assets, but the published metrics do not provide explanations for the
cost trends highlighted in Section 1.2.1, above, and in more detail in Section 3.4 of this report.
Cost monitoring and benchmarking is widely used internationally across different industries in
order to enable cost reduction and performance improvement. Section 4.3 of this report
outlines the examples of Energy Networks in multiple countries, Energy regulation in Europe,
GB Water Utilities and Offshore Oil & Gas.
The Cost Reduction Monitoring Framework, sponsored by the Offshore Wind Industry Council
(OWIC), is actively being used to inform priorities in innovation, research and joint industry
programmes within government and in organisations within industry.
The SPARTA (System performance, Availability and Reliability Trend Analysis) collaborative
project between ORE Catapult, The Crown Estate and offshore wind farm owner/operators is
used on an ongoing basis by owner/operators to benchmark their performance against the
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wider industry, in order to understand their strengths and weaknesses against peers rather
than against internal benchmarks only.
SPARTA is designed to capture and report on operating performance metrics and, as such,
does not include details on capital or operating costs. It is therefore not a potential source of
data for the cost monitoring proposed here. However, a number of the operating metrics (eg.
offshore substation failures, export cable failures and onshore substation failures) would be a
valuable complement, should permission be granted in future to use SPARTA data.
Cost monitoring and benchmarking of direct costs in offshore wind transmission could
contribute to cost reduction, with initial illustrative savings up to 14% of transmission asset
capex based on enabling future OFTO assets to be constructed for the same cost as the lowest
capex seen to date (see Section 4.4 of this report).
Analysis of actual costs against budget will provide lessons on areas for improved contract
and risk management.
Analysis of “soft” costs such as project management and contract wraps will provide
understanding of the cost-benefit of different procurement approaches.
Data anonymity can be preserved using similar principles as employed in the CRMF.
1.3 Recommendation
Implement an ongoing transmission cost benchmarking exercise
A proposal could be made to OWPB for its members to authorise release to ORE Catapult of the
data provided to Ofgem as part of the OFTO Cost Assessment process. This will provide the basis
for an industry-wide understanding of common and design-specific offshore wind transmission
cost drivers, which can inform innovation and procurement decisions. ORE Catapult currently
manages the CRMF and SPARTA projects, giving a proven track record in fulfilling data handling
and confidentiality requirements as well as establishing and maintaining cost monitoring and
benchmarking systems.
The benchmarking process should have two elements: Direct Cost metrics; and Indirect Cost
metrics.
Recommended Direct Cost metrics are consistent with the Cost Comparators used by Ofgem’s
advisers in the OFTO Cost Assessment process, as shown in Table 2, below.
Asset Metric Rationale
Offshore substation
Offshore substation (platform structure,
topside and electrical equipment) supply
cost per MW of secure capacity
Minimises the effect of design choices by
simplifying the electrical infrastructure to the
function of secure export capability (the
power that can be exported with the loss of
a single transformer)
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Asset Metric Rationale
Offshore substation electrical (electrical
assets on the platform) cost per MW of total
capacity
Takes into account the cost of total
generation capacity installed
Transformer cost per MVA
Provides like for like comparison between
transformers for windfarms of different
generating capacity
Topside installation cost per substation
Provides insight into whether, for example,
lower topside supply cost is being offset by
more complex installation methods
Foundation supply cost
Provides insight into whether, for example,
lower topside supply cost is being offset by
more complex foundation solutions
Foundation installation cost
Provides insight into whether, for example,
lower foundation supply cost is being offset
by more complex installation methods
Offshore Export
Cable
Offshore cable supply cost per km offshore
cable
Splitting cable supply into offshore and
onshore allows a better like for like
comparison between windfarms
Offshore cable supply cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Offshore cable installation cost per km
offshore cable
Tracking installation as well as supply costs
allows insight into whether, for example,
cheaper cable supply is being offset by
more expensive installation
Offshore cable installation cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Onshore Export
Cable
Onshore cable supply cost per km offshore
cable
Splitting cable supply into offshore and
onshore allows a better like for like
comparison between windfarms
Onshore cable supply cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Onshore cable installation cost per km
offshore cable
Tracking installation as well as supply costs
allows insight into whether, for example,
cheaper cable supply is being offset by
more expensive installation
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Asset Metric Rationale
Onshore cable installation cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Reactive
compensation
Cost of offshore reactive power
compensation per km of cable Taking distance into account allows for a
like for like comparison between windfarms Cost of onshore reactive power
compensation per km of cable
Development Capitalised development costs as a
percentage of asset cost
Provides insight to the relative magnitude of
capitalised development costs
Table 2 Proposed Direct Cost benchmarks
Recommended Indirect Cost metrics are: Actual costs vs budgeted costs; and Relative costs of
multi-contract vs greater use of EPC arrangements.
The benchmarking exercise could be implemented as a two-stage process – an initial exercise to
produce benchmark metrics for all fourteen OFTO transfers completed to date in order to establish
the current level of capex and to identify common issues and lessons learned; and an ongoing
exercise based on further completed transfers.
Release of data would be subject to Non-Disclosure Agreements (NDA) between the disclosing
and receiving parties. OWPB members should also consider the anonymity issues detailed in
Section 4.7 of this report, in order to determine the exact requirements (eg. include Direct Cost
metrics only or also include Indirect Cost metrics) and frequency of benchmarking (after each
OFTO transfer is completed, or after a minimum of 3 transfers in order to preserve complete
anonymity within aggregated results).
The recommendation here is that the exercise should be conducted following each OFTO transfer
with the Direct Cost metrics being produced. The Indirect Cost metrics would not be published,
but would inform ORE Catapult’s (or another receiving party) understanding of project issues in
order to identify common issues and best practice to be rolled out across the industry.
1.4 Further Considerations – Cost Reduction Monitoring Framework
1.4.1 CRMF Quantitative Study
A proposal should be made to the OWPB and OWIC in 2016 for the existing CRMF quantitative
LCOE calculator to be amended for future years to separate the LCOE results into LCOE for
generation and LCOE for transmission.
It is possible that next year’s study (CRMF 2017) will not include sufficient projects reaching FID
or Works Completion to conduct the quantitative assessment. One approach therefore may be
for OWIC to request permission from those who have responded to previous CRMF for the
Transmission LCOE to be extracted from the previous submissions (by the consultants who have
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already reviewed the submissions) in order to establish a baseline Transmission LCOE consistent
with that already reported for UK Offshore Wind as a whole.
1.4.2 CRMF Qualitative Workstream
The additional transmission-specific indicators shown in Table 3 will be added to the qualitative
study in 2016. This does not require a recommendation to OWIC, as it will be carried out as part
of the CRMF annual review.
Proposed Indicator Rationale Next Steps
Lightweight Substations
First orders are expected in 2016.
The proportion of projects using
lightweight substations or radically
novel design concepts would be
expected to steadily increase,
approaching 100% by or before FID
2020.
Review 2020 cost reduction potential
and establish annual milestones based
on the OWPB report “Lightweight
Offshore Substation Designs”,
completed in January 2016
Increased Capacity Export
Cables
Cables at the “state of the art” capacity
level (400MW) expected in 2016.
The size of cable used by (sufficiently
large) projects would be expected to
rise steadily, reaching the 550MW
suggested by OWPB’s work on at least
one FID 2020 project
Estimate 2020 cost reduction potential
and establish annual milestones based
on work currently contracted by the
Grid Group to EDIF ERA, with results
expected to be available by June 2016.
Tender Revenue Stream
(TRS) % of OFTO Transfer
Value (see Section 3.4.1)
This should be added to the CRMF
Finance indicators to track the level of
return being required by OFTO’s
Estimate 2020 cost reduction potential
and establish annual milestones in
conjunction with OWPB Finance Group
Table 3 Proposed CRMF transmission indicators
This requires further work to be done to establish appropriate annual milestones and a 2020 target
against which to track progress.
1.5 Conclusions
Taken together, implementing the above measures will provide a basis for tracking the actual
costs of offshore wind transmission and assessing areas where progress is not being made at
the rate expected to be necessary to achieve the 2020 LCOE target of £100/MWh and further
ongoing cost reductions. This will provide a robust basis for transmission system designers,
procurement teams and innovators to learn lessons from previous projects and prioritise actions.
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2 Introduction
2.1 Background
There is a growing body of evidence showing the reductions being achieved in Levelised Cost of
Energy (“LCOE”) for Offshore Wind. The Cost Reduction Monitoring Framework (“CRMF”) 2014-
151 showed LCOE for projects taking FID in 2012 – 2014 is estimated at £121/MWh in 2011 real
terms. The two offshore wind contracts for difference (CfD) awarded in the UK’s first CfD auction
round in January 2015 were at Strike Prices of £120 and £115, providing evidence that the CfD
recipients forecast LCOE for these projects lower than these figures. Of the two projects, East
Anglia One achieved FID in February 2016, while the outlook for Neart na Gaoithe is currently
unclear with the project entering judicial review over withdrawal of the CfD after missing key
milestones due to legal challenge.
Due to the commercial sensitivities around specific costs and contractual arrangements, the key
components of LCOE within these totals can only be estimated, rather than quantified with
certainty, based on known factors of site conditions and technology used.
The transmission cost elements, however, can be approximated from publicly available data (see
Section 3 of this report). Further disclosure of the detailed information provided to Ofgem is
required in order to understand these costs more accurately and to draw conclusions and prioritise
actions.
2.2 Transmission Costs
Transmission costs as a percentage of total LCOE vary depending on a number of factors,
including distance from shore (driving export cable length to be supplied and installed and reactive
compensation equipment requirements), windfarm capacity, onshore distance to grid connection
point, civil works required onshore and onshore grid connection and compatibility issues. Taking
into account the assets from the offshore substation to onshore substation, transmission would
typically represent 10% - 15% of total LCOE2. As turbine, balance of plant and installation
technology develops to be able to take advantage of higher wind speeds further from shore and
as windfarms become larger, the demands on the transmission system are changing.
As well as the changing demands, there are other factors which require focus on the area of
transmission cost and innovation. For example, there are a number of consented and in-planning
far from shore sites, which will only be cost-competitive if there is an acceleration in the
development of solutions. There are also developments which require industry and regulatory co-
ordination, such as use of dynamic rating and distributed transformer systems.
The ongoing CRMF tracks progress in specific innovations and quantifies current LCOE on an
industry-aggregated level. However, of the 40 technology innovations monitored in CRMF, only 5
relate directly to transmission so there is currently an opportunity to establish a better
understanding of the progress of innovation in this area.
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2.3 Potential Approaches to Offshore Transmission Cost Benchmarking & Monitoring
There is a strong case for implementing a framework for benchmarking and monitoring the costs
of offshore transmission in order to allow those responsible for transmission system design and
procurement to learn lessons from previous projects, to ensure technical and commercial
innovations address the evolving needs of the industry and to identify areas where action is
required to kick-start or accelerate faltering progress, whether through R&D initiatives or other
means.
This report will present options for such a framework:
1. Release of the data provided to Ofgem for the cost assessment of each OFTO transaction in
order to compile and maintain key benchmark metrics;
1. An extension of the existing CRMF Qualitative Workstream to increase the number of
innovations tracked in the area of transmission; and
2. An amendment to the existing CRMF Quantitative Workstream, requiring modification of the
LCOE calculator to show LCOE for generation assets and transmission assets separately.
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3 Publicly Available Transmission Cost Data
3.1 Overview
There is already sufficient publicly available data relating to OFTO transfers and tariffs to allow
high-level estimates to be made of the capital costs of the key elements of transmission assets.
However, the available data is not sufficient to explain the resulting trends in key metrics and is
therefore insufficient to inform decision making for system designers or innovation priorities.
Estimates can be made for the following cost metrics shown in Table 4.
Workstream Element Indicator
Finance OFTO Return Tender Revenue Stream % of Transfer Value
Capex Offshore substation £m per substation
Capex Offshore substation £ per MVA
Capex Offshore circuit £m per km installed
Capex Offshore circuit £m per MWkm
Capex Onshore substation £m per MW installed
Table 4 Proposed quantitative transmission benchmark metrics
As the same sets of data are published for each OFTO transfer, these metrics can be estimated
for each windfarm once the transfer has been completed, using the data sources and
methodology outlined in the following sections of this report. Note that it is not sufficient to simply
track the absolute values of the published substation and circuit tariffs, since these are driven by
the level of OFTO return in the Tender Revenue Stream as well as the underlying capex.
3.2 Available Data Sources
There are four key sources of publicly available information which, taken together, can be used
to estimate at a high level the actual capex of offshore wind transmission assets:
1. OFTO transfer Cost Assessment reports published by Ofgem3
2. OFTO TRS published by National Grid 4
3. Local substation and offshore circuit tariffs published by National Grid5
4. Offshore Transmission Network Use of System (TNUoS) charging methodology published
by National Grid6
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3.2.1 OFTO Transfer Cost Assessment reports published by Ofgem
Ofgem publishes a Cost Assessment report for each OFTO transfer once the licence has been
granted. While the tender process is ongoing, a draft Cost Assessment report is made available
and once the transfer has been concluded a final Cost Assessment report is published. In addition
to the main report, several back-up documents are generally also made available in redacted
form, including the auditor’s report and the technical assessment. A high level summary of the
costs included in the Cost Assessment reports is shown in Table 5, below.
Year Windfarm Capacity Capex Devex Other FTV
MW £m £m/MW £m £m £m
2011 Robin Rigg East & West 180 50 0.28 4 12 66
2011 Barrow 90 26 0.29 4 4 34
2011 Gunfleet Sands 1 & 2 173 38 0.22 6 6 50
2011 Walney 1 184 88 0.48 8 10 105
2012 Walney 2 184 94 0.51 8 8 110
2012 Ormonde 150 80 0.54 14 10 104
2013 Greater Gabbard 504 241 0.48 34 41 317
2013 Sheringham Shoal 317 159 0.50 27 7 193
2013 London Array 630 344 0.55 49 66 459
2014 Thanet 300 120 0.40 27 17 164
2014 Lincs 270 234 0.87 36 38 308
2015 Gwynt y Môr 576 253 0.44 52 48 352
2015 West of Duddon Sands 389 215 0.55 31 23 269
2016 Westermost Rough 210 122 0.58 23 11 157
Table 5 Ofgem OFTO Cost Assessment capex summary by windfarm
It should be noted that the Final Transfer Value (FTV) represents the amount which Ofgem deems
to have been economically and efficiently incurred, based on the financial audit and technical
assessment reports. This is not necessarily the total amount of cost incurred, which is likely to be
greater than the amount allowed. However, for estimation purposes, the allowed value can be
used as a proxy for actual capex as it is not possible in most cases to track from Initial Transfer
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Value, through Indicative Transfer Value, to the FTV in order to understand where costs have
been disallowed (and, in any case, even the Initial Transfer value may already be net of some
disallowed costs). It is also important to use the FTV in order to be consistent with the TRS and
tariff data outlined in the following sections.
3.2.2 OFTO Tender Revenue Streams (TRS) published by National Grid
National Grid publishes a 5-year forecast of TNUoS charges, which includes detail of the current
and forecast TRS for each offshore windfarm, expressed in £m per year in nominal terms. This is
the amount being paid to the OFTO to operate the transmission assets and will depend, among
other things, on the FTV paid to acquire the OFTO assets, the forecast ongoing O&M costs and
the level of return the OFTO requires to operate the assets (which will in turn depend on the
OFTO’s appetite and the level of competition between potential OFTO’s in the market).
3.2.3 Local substation and offshore circuit tariffs published by National Grid
The National Grid TNUoS forecast referred to previously also includes current and forecast values
for the local substation and offshore circuit tariffs charged to offshore windfarm generators for use
of the OFTO assets.
The local substation tariff relates to the assets at the offshore substation, specific to the generator.
The costs taken into account in calculating the tariff are Transformer, Switchgear and Offshore
Platform.
The offshore circuit tariff relates to the cost of the OFTO circuit, specific to the generator. The
costs taken into account in calculating the tariff are Offshore cable, Harmonic filtering equipment
and Reactive plant.
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3.2.4 Offshore TNUoS charging methodology published by National Grid
This document sets out the basis for the charges levied on the generator for use of the
transmission assets. It provides a worked example for calculating the local substation and
offshore circuit tariffs from the cost of the capital elements and the agreed TRS. This worked
example for a 400MW offshore windfarm is reproduced in Figure 2.
In summary, the transmission assets capex items are allocated to Circuit, Offshore Substation or
Other (Onshore works). The capex for each category is calculated as a percentage of the total
transmission assets capex and this percentage is applied to the TRS. In this example, the Circuit
and Substation capex account for 38% and 45% of capex respectively, a total of 83% of capex.
The Circuit and Substation tariffs are then converted into 38% and 45% of the TRS, which will be
paid by the generator. The remaining 16.5%, relating to the Onshore substation is socialised into
the wider tariff element of TNUoS.
3.3 Capex Estimation Methodology
The data sources outlined in Section 3.2, above, provide the windfarm-specific information
outlined in Table 6, while the TNUoS charging methodology statement provides a way of
calculating each of the tariffs from the FTV and TRS. The same methodology can therefore be
applied in reverse to estimate the capex cost of the groups of components included in each tariff.
Figure 2 Offshore TNUoS charge worked example
Capex % of total TRS share Rating LSF Tariff
£m £ MVA £ / kW
Circuit
Export Cable Supply & Install 100.00 32.9%
Harmonic Filtering Equipment 1.00 0.3%
Reactive Plant 15.00 4.9%
Subtotal Circuit 116.00 38.2% 9.56 420 1.00 22.75
Substation
Transformer 10.00 3.3% 0.82 640 1.29
Switchgear 2.50 0.8% 0.21 680 0.30
Platform 125.00 41.2% 10.30 640 16.09
Onshore Civils cost adjustment - (0.40)
Subtotal Substation 137.50 45.3% 11.33 17.27
Other
Onshore Substation 50.00 16.5% 4.12 -
Subtotal Other 50.00 16.5% 4.12 -
Total 303.50 100.0% 25.00 40.02
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Required information Source
Transmission assets capex Cost Assessment reports
Tender Revenue Stream National Grid TNUoS forecast
Local substation tariff National Grid TNUoS forecast
Offshore circuit tariff National Grid TNUoS forecast
Platform Rating Case-by-case basis
Cicuit Rating Case-by-case basis
Table 6 Calculation data sources
3.4 Metrics Summary
Applying the relevant calculations to the data for OFTO transfers to date, the capex for each of
the transmission asset elements can then be shown against relevant factors in order to quantify
specific metrics as shown in Table 7. The proposal here is to focus on Offshore Substation and
Circuit capex as Onshore Substation capex tends to be very site-specific. However, it would also
be worthwhile to track capex per MW for Onshore Substation in order to better understand the
cost drivers.
Windfarm MW Transfer
Year
FTV
£m
Capex
£m
TRS/FTV
%
Offshore
Substation
£m/platform
Offshore
Substation
£/MVA
Circuit
£m/km
Circuit
£k/MWkm
Barrow 90 2011 34 26 16.8% 3.0 25,370 0.5 6.1
Robin Rigg E&W 180 2011 66 50 12.2% (0.2) (2,375) 1.1 6.3
Gunfleet Sands 173 2011 50 38 14.3% 14.9 62,100 1.1 6.6
Walney 1 184 2011 105 88 12.2% 24.8 103,289 1.1 5.8
Walney 2 184 2012 110 94 11.6% 26.7 111,089 1.1 6.2
Ormonde 150 2012 104 80 11.5% 23.2 136,610 1.0 6.4
Greater Gabbard 504 2013 317 241 8.5% 31.6 175,567 1.0 2.0
Sheringham
Shoal 317 2013 193 159
10.2% 28.5 158,116 0.9 2.9
London Array 630 2013 459 344 8.6% 26.0 72,121 0.8 1.3
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Windfarm MW Transfer
Year
FTV
£m
Capex
£m
TRS/FTV
%
Offshore
Substation
£m/platform
Offshore
Substation
£/MVA
Circuit
£m/km
Circuit
£k/MWkm
Thanet 300 2014 164 120 9.9% 37.8 104,879 1.3 4.3
Lincs 270 2014 308 234 8.6% 33.3 92,419 1.2 4.3
Gwynt y Môr 576 2015 352 253 6.9% 50.8 158,702 0.9 1.5
WoDS 389 2015 269 215 7.9% 30.1 62,664 1.8 4.7
Table 7 Metrics summary for OFTO transfers to date
The metrics can then be viewed on a timeline on an annual MW-weighted basis, consistent with
a CRMF-style approach, as shown in the following Sections 3.4.1 to 3.4.4. These sections
illustrate the level of analysis possible from publicly available data, but also highlight the key
shortcomings.
Note that these figures and analysis are shown in nominal terms. It may be desirable to deflate
all costs to a 2011 base (see Appendix 4 ) in order to be consistent with the basis of the £100/MWh
LCOE target and the current base year for monitoring under the CRMF. Appendix 5 shows that
the trends can be shown on a project-by-project basis and illustrates the point that the trends can
only be explained and acted upon with further data disclosure.
3.4.1 TRS as a % of FTV
This metric provides a guide to the level of return required by OFTO’s and is a major driver of the
charges to be levied on windfarm operators. As shown in Figure 3, this has been steadily
decreasing from a MW-weighted average of 13.4% in 2011 to 7.3% in 2015. It is a simple ratio,
which can be derived for all future OFTO transfers.
Further data: Estimates of OFTO asset opex to understand the overall level of OFTO return.
Figure 3 TRS as a % of FTV shown against number of OFTO transfers by year 2011 - 2015
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3.4.2 Offshore Substation Capex
The metrics estimated for Offshore Substation capex are:
Cost per Substation; and
Cost per MVA of capacity
The historic data included in Figure 4 shows capex having risen from a MW-weighted average of
£12m per offshore substation in 2011 to £42m in 2015. At the same time, capex per MVA of
capacity has risen from a MW-weighted average of £50k per MVA in 2011 to £120k per MVA in
2015. Naturally, capex per MW follows these 2 trends, rising from a MW-weighted average of
£67k per MW in 2011 to £136k per MW in 2015.7 Overall it appears that the cost of constructing
and installing an offshore substation is increasing quite significantly. This trend can only be
understood with a number of additional data.
Further data:
Cost of transformers
Cost of platform
Offshore Substation foundations supply cost
Foundations and topside installation cost
Cost of any spare equipment included
3.4.3 Offshore Circuit Capex
The metrics estimated for Offshore Circuit capex are:
Cost per km; and
Figure 4 Offshore Substation capex metrics by year 2011 – 2015
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Cost per MWkm to capture the effects of installing different capacities over distance
The historic data included in Figure 5 shows capex having risen from a MW-weighted average of
£1.0m per km of circuit in 2011 to £1.3m per km in 2015. At the same time, capex per MWkm has
reduced from a MW-weighted average of £6.2k per MWkm to £2.8k per MWkm in 2015. Capex
per MW follows the slightly increasing trend of capex per km, rising from a MW-weighted average
of £180k per MW in 2011 to £260k per MW in 2015.
It should be noted that circuit capex derived from the offshore circuit tariff includes onshore
harmonic filtering and reactive plant in addition to offshore and onshore cable. Therefore the
metrics derived using this method will be higher than a straightforward cost per km or per MWkm
of cable supplied and installed. This may account for some of the increase in capex per km as
the need for reactive plant increases with distance from shore, even if the cable cost per km is
not increasing.
Further data:
Offshore cable supply cost; Offshore cable installation cost; number and size of offshore
cable sections
Onshore cable supply cost; Onshore cable installation cost; number and size of onshore
cable sections
Landfall cost and method used
Cost and properties of onshore reactive equipment
Cost and properties of offshore reactive equipment
Figure 5 Offshore Circuit capex metrics by year 2011 - 2015
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3.4.4 Onshore Substation Capex
The metric estimated for Onshore Substation is:
Capex £m per MW
The project by project movements shown in Appendix 5 illustrate how site-specific this metric is
likely to be. Continued tracking will, however, provide better understanding of the cost drivers.
3.5 Summary of Publicly Available Offshore Transmission Cost Data
Quantitative finance and capex indicators can be tracked using publicly available data
Data required are contained in Ofgem published OFTO transfer reports and National Grid
published tariffs
Analysis of historic OFTO transfer data shows that some elements of capex appear to be
reducing while others appear to be increasing
The public data needs to be supplemented with project-specific information in order to draw
conclusions on cost drivers and learn lessons for future system design and procurement
Further considerations
Expressing capex metrics in 2011 terms to be consistent with existing CRMF
quantitative analysis (see Appendix 4 ), though in order to be robust this may require
additional transparency in terms of the timing of capex spend.
Analysing metrics on a project-by-project basis (see Appendix 5 )
Figure 6 Onshore Substation Capex per MW by year 2011 - 2015
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4 Action 1 - Cost Benchmarking based on OFTO Data
4.1 Background
As part of the GB OFTO regime, detailed cost data is provided by each developer8 to Ofgem. This
is provided in the form of cost reporting templates, contract values, asset cost schedules and
cash flows. Developers also provide supporting evidence to substantiate their cost submissions
including, amongst other things, contract documentation, supplier payment lists and invoices and
receipts. In order to assess the cost efficiency of the constructed assets, Ofgem and its advisers
benchmark a range of cost metrics against previous OFTO transactions, taking into account site-
specific factors and market variables, such as commodity prices and exchange rates.
As outlined in Section 3 of this report, there is valuable information contained in publicly available
sources. It is possible to generate approximate cost metrics by windfarm and by year; groupings
could also be made based on other properties, for example, windfarm size or distance from shore.
However, disclosure of the detailed data provided to Ofgem as part of the OFTO Cost Assessment
process would add a great amount of value to the analysis in terms of project-specific or
approach-specific cost drivers and allowing the trends identified to be explained and acted upon.
It is proposed here that the OFTO data disclosed to Ofgem should be made available for an
ongoing benchmarking study. The ORE Catapult could potentially conduct the benchmarking
study using similar principles as those applied to the CRMF. The expected benefits of undertaking
such a study would be as follows:
Allow developers to understand the current best in class across the industry, rather than purely
against internal benchmarks or their own supply chain inputs;
Provide consistent metrics for developers to compare between supply chain quotes;
Provide developers with more comprehensive benchmarks against which to challenge the
supply chain;
Provide insight into the cost impact of design trade-offs made in previous projects;
Provide developers with this information before they make procurement decisions (rather than
this information only being available to Ofgem and its advisers for use during the OFTO cost
assessment process once the money has already been spent);
Identification of common areas of cost and performance issues to enable industry participants
to take joint action;
Estimating the impact on costs of different contracting approaches;
Identifying the best methods of dealing with project issues (eg. supply chain delays or
performance levels)
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4.2 Current GB Offshore Wind Transmission Benchmarking
Ofgem already undertakes comprehensive benchmarking of OFTO costs. This is required in order
to be able to assess economic and efficient expenditure. Key examples of publications in this field
are described here only very briefly:
Cost Efficiency Report 10010731, KEMA Ltd, June 20099
KEMA created a comparator valuation for each transmission project assessed, based on six
comparator metrics:
Offshore substation cost per megawatt of secure capacity
Offshore substation electrical cost per megawatt of generation installed
Cable cost per kilometre supplied
Cost per MVA for transformers
Capitalised development costs as a percentage of asset cost
Cost of reactive power compensation per kilometre of cable
All monetary values are redacted in the published version of this report.
Offshore Transmission Cost Assessment Development Update, Ofgem, June 201510
Published following industry consultation and detailed modelling by CEPA and SKM (see below),
including updated benchmarks for six metrics:
Land cable supply and installation (less than 15km) £m/km
Land cable supply and installation (greater than 15km) £m/km
Onshore substation £m/MW
Offshore substation £m/MW
Submarine cable supply £m/km
Submarine cable installation £m/km
The updated benchmark figures are included, as is a brief explanation of the movement from
the previous benchmark values.
OFTO Benchmarking, CEPA Ltd in association with SKM, December 201411
Detailed review of information from OFTO Tender Rounds 1 and 2 in support of the above
Ofgem report [10], including detailed examination and comparison of various statistical models
for validating relationships between cost drivers and costs.
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While these publications are extremely valuable as tools in cost assessment and show that
comprehensive benchmarking has been undertaken, the published results do not provide
explanations of the trends in offshore transmission costs presented in Sections 3.4.2 – 3.4.4 of
this report.
4.3 Examples of Benchmarking in Other Industries
UK Offshore Wind
o The Cost Reduction Monitoring Framework, sponsored by the Offshore Wind Industry
Council (OWIC), is actively being used to inform priorities in innovation, research and
joint industry programmes within government and in organisations within industry.
o The SPARTA (System performance, Availability and Reliability Trend Analysis)
collaborative project between ORE Catapult, The Crown Estate and offshore wind farm
owner/operators is used on an ongoing basis by owner/operators to benchmark their
performance against the wider industry, in order to understand their strengths and
weaknesses against peers rather than against internal benchmarks only.
Government Construction Strategy - The UK government began publishing construction cost
benchmark data in 2012. All government departments are required to use a common
procurement strategy for construction projects and to share construction benchmarks. Cost
reductions declared of 13% to 20% per year in years 2012 to 2014.12
Energy Networks – Benchmarking is used widely to assess the reasonableness of
transmission costs in a number of countries and territories including the GB13, Australia14 and
Alberta (Canada)15.
Energy Regulation – Cost benchmarking is used throughout Europe, including Austria,
Denmark, Finland, Germany, Norway, Spain and Sweden to assess the reasonableness and
set targets for costs and performance levels16.
GB Water utilities – Scottish, English and Welsh water utilities share benchmark data on capital
maintenance and operating costs. This has assisted Scottish Water in targeting 13% cost
reduction from efficiency benefits in its 2015-2021 Business Plan17
Offshore Oil & Gas (two examples from multiple arrangements)
o Dodson Drilling Performance Benchmark Database System18 - a database system
consisting of benchmarking application software and information on wells drilled in the
Gulf of Mexico, including public and operator-submitted data.
o Solomon's Worldwide Offshore Production Operations Performance Analysis (Offshore
Study)19 - a platform for assessing the performance of offshore assets at the company
level and for comparing the performance of similar types of operations either globally
or within a given region
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4.4 Estimate of Benefits
The average Final Transfer Value (FTV) of the fourteen completed OFTO transfers is £0.6m per
MW. For a 500MW windfarm, this equates to £300m. Analysis of published FTV’s and offshore
transmission tariffs allows an approximation to be made of key metrics for transfers completed to
date. The relevant costs and properties of each OFTO transfer are shown in Table 5 in Section
3.2.1 of this report. Comparing the estimated metrics for each transfer from 2012 onwards against
the lowest metrics achieved in previous years is taken here as an approximation of potential
savings. The analysis takes 2012 as the start year as the first OFTO transfers were completed in
2011. The estimated savings by windfarm are shown in Table 8.
Year Windfarm Capacity Illustrative Potential Savings (£m)
MW Based on
Transformer rating
Based on Substation
capex
Based on Cable
length and capacity
Based on Cable length
2012 Walney 2 184 1 1 3 3
2012 Ormonde 150 9 0 9 -
2013 Greater Gabbard 504 38 23 - 14
2013 Sheringham Shoal 317 24 9 19 -
2013 London Array 630 - 10 - -
2014 Thanet 300 17 22 67 36
2014 Lincs 270 9 14 119 50
2015 Gwynt y Môr 576 80 82 25 15
2015 West of Duddon Sands 389 - 8 130 96
2016 Westermost Rough 210 72 64 23 15
Total (£m)
3,529 251 234 396 228
Median (£m)
13 12 21 14
Median (£/MW)
36,405 33,418 59,461 40,117
Table 8 Illustrative potential savings from benchmarking against best in class by windfarm
Taking the average of illustrative savings from the Offshore Substation and Circuit capex metrics,
provides an estimate of potential benefit from being able to reduce key metrics to the lowest
achieved in previous transactions of 14% cost savings as shown in Table 9. Note that Onshore
Substation is not included in the potential savings as analysis of the publicly available data
suggests cost drivers are too site-specific. These savings should be taken as purely illustrative
ORE Catapult Page 27 of 50
since, if nothing else, the length of the planning and design phase of transmission projects means
that it will not always be possible to incorporate the most recent learnings into the process.
Metric Values
Average Saving based on Substation metrics (£/MW) 34,912
Average Saving for 500MW windfarm based on
Substation metrics (£m) 17.5
Average Saving based on Circuit metrics (£/MW) 49,789
Average Saving for 500MW windfarm based on
Circuit metrics (£m) 24
Average Saving based on both Substation and Circuit
metrics (£/MW) 84,700
Average Saving for 500MW windfarm based on both
Substation and Circuit metrics (£m) 42
Average OFTO Capex based on transactions to date
(£/MW) 600,000
Average OFTO Capex based on transactions to date
for 500MW windfarm (£m) 300
Saving % 14%
Table 9 Combined illustrative savings from benchmarking
4.5 Implementation
The benchmarking process can be split into two key elements:
Direct cost benchmarks (eg. costs per MWkm, derived directly from data provided)
Indirect benchmarks (eg. project management or procurement-related, which would require
more detailed analysis of contractual arrangements, variance analysis between budget and
actual costs and potentially direct engagement with developers and the supply chain)
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If this approach were to be followed, it may be desirable to implement the Direct Cost Benchmarks
as the initial process in order to establish the feasibility of conducting further, more detailed
analysis on the more contractual elements.
4.5.1 Direct Cost Benchmarks
The proposed cost benchmark metrics are consistent with the Cost Comparators used by Ofgem
and their advisers in assessing the cost efficiency of OFTO capex.
Table 10, below, shows the proposed cost benchmark metrics. Those used in the Ofgem cost
efficiency testing are shaded grey. Note that the Ofgem comparators include a single cable metric
of cable supply cost per km and do not separate offshore from onshore cable, but it is considered
necessary here in order to provide a like for like comparison between projects which all have
different proportions of offshore vs onshore cable.
Asset Metric Rationale
Offshore substation
Offshore substation (platform structure,
topside and electrical equipment) supply
cost per MW of secure capacity
Minimises the effect of design choices by
simplifying the electrical infrastructure to the
function of secure export capability (the
power that can be exported with the loss of
a single transformer)
Offshore substation electrical (electrical
assets on the platform) cost per MW of total
capacity
Takes into account the cost of total
generation capacity installed
Transformer cost per MVA
Provides like for like comparison between
transformers for windfarms of different
generating capacity
Topside installation cost per substation
Provides insight into whether, for example,
lower topside supply cost is being offset by
more complex installation methods
Foundation supply cost
Provides insight into whether, for example,
lower topside supply cost is being offset by
more complex foundation solutions
Foundation installation cost
Provides insight into whether, for example,
lower foundation supply cost is being offset
by more complex installation methods
Offshore Export
Cable
Offshore cable supply cost per km offshore
cable
Splitting cable supply into offshore and
onshore allows a better like for like
comparison between windfarms
Offshore cable supply cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
ORE Catapult Page 29 of 50
Asset Metric Rationale
Offshore cable installation cost per km
offshore cable
Tracking installation as well as supply costs
allows insight into whether, for example,
cheaper cable supply is being offset by
more expensive installation
Offshore cable installation cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Onshore Export
Cable
Onshore cable supply cost per km offshore
cable
Splitting cable supply into offshore and
onshore allows a better like for like
comparison between windfarms
Onshore cable supply cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Onshore cable installation cost per km
offshore cable
Tracking installation as well as supply costs
allows insight into whether, for example,
cheaper cable supply is being offset by
more expensive installation
Onshore cable installation cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Reactive
compensation
Cost of offshore reactive power
compensation per km of cable Taking distance into account allows for a
like for like comparison between windfarms Cost of onshore reactive power
compensation per km of cable
Development Capitalised development costs as a
percentage of asset cost
Provides insight to the relative magnitude of
capitalised development costs
Table 10 Proposed Direct Cost benchmarks
4.5.2 Indirect Benchmarks
Potential indirect benchmark metrics could be as follows:
Actual costs vs budgeted costs – Identify and analyse the causes of cost over-runs. As far
as possible, group the causes into generic categories, eg. weather delays, supplier
defects/errors, developer errors, change in requirements in order to identify common issues
and quantify their impacts.
Relative costs of multi-contract vs greater use of EPC arrangements – Conduct cost-
benefit analysis between project management costs and contractors’ risk pricing. (This may
require an even greater level of detail than is available in the Ofgem submissions.)
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4.5.3 Implementation Phases
The cost benchmarking would be performed in two distinct phases
One-off exercise to prepare current benchmarks
An initial exercise would be required to collate and analyse the data for all OFTO transactions
completed to date (fourteen at the time of writing). This would establish the current cost base and
provide insight into site-specific and market cost drivers.
Ongoing exercise for completed OFTO transfers in a given period
The exercise would be updated for each completed OFTO transfer or periodically once a minimum
of three OFTO transactions have completed (see below on confidentiality and anonymity).
4.6 Data Confidentiality
In order to preserve the confidentiality of data provided, non-disclosure agreements (NDA’s)
would be required between the disclosing and receiving parties. The exact terms of the NDA may
need to be agreed individually with each disclosing party, but the expected general condition
would be that no confidential information should be disclosed to a third party without the prior
written consent of the disclosing party unless required by law. The receiving party may be ORE
Catapult or may be another third party (in CRMF, a limited disclosure of quantitative data is made
to an appointed consultant – in 2014 this was Deloitte LLP). This process has already successfully
been completed for LCOE data required for the CRMF work and could be replicated here.
The submitted data would be held and analysed within a secure location, eg. a restricted server
area with suitable password protection and named users.
4.7 Anonymity of Results
4.7.1 Option 1a – Produce Direct Cost benchmark metrics for each completed OFTO
transaction
The analysis of potential savings shown in Section 4.4, above, is based on estimating capex for
Offshore Substation, Offshore Circuit and Onshore Substation from the published FTV, the
published local circuit and substation tariffs and National Grid’s TNUoS charging methodology
statement. That is, the capex elements can be estimated by applying the TNUoS charging
methodology to the FTV (net of non-capex elements of Interest During Construction,
Development Expenditure and Transaction Costs) and the published tariffs. While the accuracy
of the estimate depends on the assumption that the non-capex elements are spread pro-rata over
the capital assets and cannot disaggregate the cost of the circuit into cable and onshore reactive
equipment, it does provide an approximate view.
One could argue that disclosing the OFTO data provided to Ofgem is not a significant step from
the estimates which can be made based on publicly available information and should pose no
commercial threat to disclosing parties.
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If OWIC members are of this view, then it would be possible to produce the proposed Direct Cost
benchmark metrics for each OFTO transaction once completed. However, the deeper analysis
required to conduct the proposed Indirect Cost benchmarking of actual costs vs budget and the
costs and benefits of procurement strategies (the Indirect Cost metrics) may be more sensitive
and so should not be produced following each transaction.
4.7.2 Option 1b - Produce Direct and Indirect Cost benchmark metrics on similar basis to
CRMF
Under this option, the methodology would, as far as possible, mirror that applied in the CRMF.
One of the fundamental principles is that the data for each project should remain confidential to
the respective project developer(s). All data would be provided into the benchmarking process
under NDA’s. In order to ensure that no third party can backward-engineer the cost metrics of a
single project, three key tests would have to be satisfied:
1. Three project rule – a minimum of three OFTO transactions must be included in the dataset;
2. Ownership history – past ownership of projects will be considered in order to identify any
projects where parties other than the current owners have access to the project data; and
3. Relative size of projects – as a general rule, the combined contribution of any two projects
should not be greater than 80% of that year’s total capacity subject to OFTO transaction (the
80% hurdle will be considered on a year-by-year basis)
As a result of these requirements, it is highly unlikely that the transmission cost benchmarking
exercise could be conducted each year. Similar to the CRMF approach, a minimum of three OFTO
transactions would need to be completed before a further benchmarking could be undertaken.
This is likely to lead to single or multiple year gaps in benchmark publication.
4.8 One-off exercise to prepare current benchmarks
In order to provide meaningful benchmarks, it is likely that the fourteen already-completed OFTO
transactions to be included in the initial one-off exercise would be grouped by year. To preserve
anonymity in line with the principles outlined in Section 4.7.2, some multi-year groupings would
be required, possibly as in Table 11, below:
Year OFTO transactions completed Capacity
2011
Barrow Robin Rigg E&W Gunfleet Sands Walney 1
626MW
2012 - 2013
Walney 2 Ormonde Greater Gabbard Sheringham Shoal London Array
1,784MW
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Year OFTO transactions completed Capacity
2014 - 2016
Thanet Lincs Gwynt y Mor West of Duddon Sands Westermost Rough
1,745MW
Table 11 Initial analysis of OFTO transfers to date
4.9 Cost of conducting the exercise
The costs of initial set-up and ongoing management of the process are not envisaged to be
significant, but would need to be assessed if there would be an appetite to pursue this proposal.
4.10 Recommendations
A proposal should be made to OWPB & OWIC for its members to authorise release to ORE
Catapult of the data provided to Ofgem as part of the OFTO Cost Assessment process. This will
provide the basis for an industry-wide understanding of common and design-specific cost drivers,
which can inform innovation and procurement decisions.
OWIC members should consider the anonymity issues detailed in Section 4.7, above, in order to
determine the exact requirements (eg. include Direct Cost metrics only or also include Indirect
Cost metrics) and frequency of benchmarking.
The recommendation here is that the exercise should be conducted following each OFTO transfer
with the Direct Cost metrics being produced. The Indirect Cost metrics would not be published,
but would inform ORE Catapult (or another receiving party) understanding of project issues in
order to identify common issues and best practice to be rolled out across the industry.
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5 CRMF Background
5.1 CRMF Overview
The CRMF was developed by the ORE Catapult and The Crown Estate and has been approved
by the Offshore Wind Industry Council (OWIC). The framework has been implemented in order to
track the Offshore Wind industry’s progress towards achieving LCOE of £100/MWh for 2020
FID’s. The CRMF comprises two separate, but related, workstreams:
a) A qualitative forecasting approach to track industry progress against a framework of pre-
agreed milestones based on innovations identified in the Crown Estate’s Pathways Study
(“the Pathways Study”)20;
b) A quantitative tracking approach using standardised project data declared at FID and
works completion to calculate an industry average LCOE weighted by yield across as
many projects as is necessary to guarantee individual project anonymity in each year.
The output is a series of annual reports for the Offshore Wind Programme Board (OWPB) to
assess how the industry is progressing and where focus is required to make further progress in
delivering a lower LCOE.
The designs of the Qualitative and Quantitative Workstreams are provided in Appendix 1 and
Appendix 2 respectively.
5.2 CRMF Key Challenges
The results of the CRMF are used to mobilise industry, government and R&D organisations
around areas with cost reduction potential, particularly where progress is identified as falling
behind target. It is therefore seen by OWIC members as of crucial importance as an objective
method for measuring industry cost reduction progress. In spite of this, there were a number of
challenges to be overcome in order to design a process which could achieve the objectives, while
being capable of implementing in practice. It is vital to take this into account when implementing
any modification to the existing CRMF process.
5.2.1 Confidentiality
The need to maintain data confidentiality is a prime concern for all involved in the CRMF. Wind
farm developers and owners are required to complete a pro forma LCOE calculator for each
relevant project, in order to provide a project LCOE which would be aggregated up to an industry
weighted LCOE. In order to preserve data anonymity, a number of steps have been put in place.
Without these measures, the Quantitative Workstream could not proceed:
1. 3-project rule – each sample must include a minimum of 3 projects in order to prevent back-
calculation of individual LCOE’s.
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2. Non-Disclosure Agreements (NDA’s) – an NDA was entered into with each respondent to the
Quantitative Workstream. This was a time and resource-consuming process as bespoke
wording had to be agreed with each respondent.
3. Independent consultant – a consultant (Deloitte LLP in 2014-15) was appointed to work
directly with the wind farm developers and owners in order to provide an additional layer
between wind farm data and ORE Catapult and The Crown Estate.
4. LCOE Model confidentiality – while Deloitte personnel were able to seek clarifications on how
the Excel model had been populated and, in some cases permitted to review the Excel models
in the participants’ offices accompanied by staff, only the ‘Results’ sheet, showing the wind
farm size, FID or Works Completion year, total capex, total annual opex, total annual electricity
generation and resulting LCOE, from the Excel model was provided to Deloitte.
5.2.2 Resource availability from respondents
Completion of both the Qualitative questionnaires and the Quantitative Excel LCOE calculator is
time-consuming. The CRMF is designed with this in mind in order to minimise the additional work
from respondents and maintain buy-in to the process.
5.2.3 Sample Size and Response times
In order to compile meaningful results, the CRMF includes as many participants from the
development, operating, supply chain and finance communities as possible. However, this
requires a significant level of project management resource in order to ensure responses are
received in a timely manner in order to deliver results to required deadlines.
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6 Action 2 – Amend Existing CRMF LCOE Calculator
6.1 Amendments to the LCOE Calculator
The existing LCOE Calculator which is completed by CRMF respondents provides LCOE for each
project at total level (ie. generating assets plus transmission assets). The level of detail included
in the LCOE Calculator inputs enables generating and transmission LCOE to be shown
separately. The existing LCOE Calculator could be amended to show the LCOE for generating
and transmission assets separately on the ‘Results’ sheet. This would allow separate generation
and transmission LCOE to be included in the CRMF report going forward.
6.2 Key Considerations
The issues which had to be overcome when implementing the existing CRMF process are likely
to be evident and so it is worth considering how each of these can be addressed.
6.2.1 Confidentiality
The main consideration will be buy-in from respondents that showing the LCOE broken down into
these 2 elements does not pose any commercial or confidentiality issues. It will be vital to
emphasise that the results will still be reported at an industry aggregate level and so there should
be the same level of comfort as with the existing arrangements for preserving anonymity.
6.2.2 Resource availability from respondents
The level of detail required in populating the LCOE Calculator will not change from the existing
process and so no additional time or effort is anticipated in completing an amended Excel sheet
(the amendments would be made to the calculation and ‘Results’ sheets, rather than the inputs).
6.2.3 Sample Size and Response times
As above, respondents should not be required to spend any more time than under the existing
CRMF arrangements.
6.3 Recommendations
A proposal should be made to the OWPB and OWIC in 2016 for amendment of the existing CRMF
quantitative LCOE calculator to separate the LCOE results into LCOE for generation and LCOE
for transmission. However, the substantial potential obstacles detailed in Section 6.2 of this report
may prevent this option from being implemented in the current year.
It is possible that CRMF 2017 will not include sufficient projects reaching FID or Works Completion
to conduct the quantitative assessment. One approach therefore may for OWIC to request
permission from those who have responded to previous CRMF for the Transmission LCOE to be
extracted from the previous submissions (by the consultants who have already reviewed the
submissions) in order to establish a baseline Transmission LCOE consistent with that already
reported for UK Offshore Wind as a whole.
ORE Catapult Page 36 of 50
7 Action 3 – Update CRMF Qualitative Indicators
7.1 Qualitative Workstream – Existing Offshore Transmission Indicators
The Pathways Study focused on innovation and cost reduction potential up to the offshore
substation (ie. generating assets only). The CRMF indicators shown in Table 12 built on the
complementary piece of work “Potential for offshore transmission cost reductions”21 published by
The Crown Estate and RenewableUK in February 2012 and on areas being highlighted to DNV
GL (who designed the Qualitative Workstream) and to ORE Catapult.
Full detail for the 5 offshore transmission-related qualitative indicators currently included in the
CRMF are included in Appendix 3
Existing Indicator 2020 Vision
Standardisation of Offshore AC
Substation
All substations have standard rating and voltage, substantial standardisation
of other features
Overplanting and/or use of
dynamic rating Substantial use of overplanting and/or dynamic rating of cables
Booster stations Deployed on one offshore project
Compact HVDC systems HVDC equipment competitive with other options at 70km.
OFTO O&M OFTOs utilise condition monitoring on majority of assets, with some sharing
of vessels and spares, leading to cost savings of 10%
Table 12 Existing transmission-related CRMF indicators
7.2 Proposed Offshore Transmission Indicators
ORE Catapult, in conjunction with Transmission Excel, has undertaken a review of the existing
indicators and of OWPB Grid Group priorities, in order to assess the appropriateness of existing
indicators and to identify additional indicators relevant to offshore transmission. This review
reinforced the existing practice of reviewing the indicators each year to ensure their ongoing
relevance (eg. considering the cost reduction potential of standardised substations before there
is agreement that an optimised design has been achieved).
The review identified new indicators are shown in Table 13.
ORE Catapult Page 37 of 50
Proposed Indicator Rationale Next Steps
Lightweight Substations
First orders are expected in 2016.
The proportion of projects using
lightweight substations or radically
novel design concepts expected to
steadily increase, approaching 100%
by or before FID 2020.
Review 2020 cost reduction potential
and establish annual milestones based
on the OWPB report “Lightweight
Offshore Substation Designs”,
completed in January 2016
Increased Capacity Export
Cables
Cables at the “state of the art” capacity
level (400MW) expected in 2016.
The size of cable used by (sufficiently
large) projects would be expected to
rise steadily, reaching the 550MW
suggested by OWPB’s work on at least
one FID 2020 project
Estimate 2020 cost reduction potential
and establish annual milestones based
on work currently contracted by the
Grid Group to EDIF ERA, with results
expected to be available by June 2016
Tender Revenue Stream
(TRS) % of OFTO Transfer
Value (see Section 3.4.1)
This should be added to the CRMF
Finance indicators to track the level of
return being required by OFTO’s
Estimate 2020 cost reduction potential
and establish annual milestones in
conjunction with OWPB Finance Group
Table 13 Proposed transmission-related CRMF indicators
7.3 Recommendations
As shown in Table 13, the next steps (to be undertaken as part of the existing CRMF process)
for including new indicators in the CRMF will be to:
Estimate 2020 cost reduction potential for each new indicator
Establish annual milestones and a measurable 2020 target in order to compile a table as
shown in Table 14
Proposed
Indicator
Cost Reduction
figure for weighting
2020 Vision (to
hit £100/MWh)
Milestone
scorecard
FID
2016
FID
2017
FID
2018
FID
2019
FID
2020
Indicator X xx% Xxxxxxxxxx
Ahead of target
On target
Behind target
Missed target
Table 14 CRMF qualitative indicator tracking example
ORE Catapult Page 38 of 50
8 Recommendations
This report recommends 3 actions for the ongoing monitoring and benchmarking of offshore wind
transmission costs. The first two require a proposal to be made to OWIC, while the third is included
here for information only.
8.1 Implement an ongoing transmission cost benchmarking exercise
A proposal should be made to OWIC for its members to authorise release to ORE Catapult of the
data provided to Ofgem as part of the OFTO Cost Assessment process. This will provide the basis
for an industry-wide understanding of common and design-specific offshore wind transmission
cost drivers, which can inform innovation and procurement decisions.
The benchmarking process should have two elements: Direct Cost metrics; and Indirect Cost
metrics.
Recommended Direct Cost metrics are consistent with the Cost Comparators used by Ofgem’s
advisers in the OFTO Cost Assessment process, as shown in Table 15, below.
Asset Metric Rationale
Offshore substation
Offshore substation (platform structure,
topside and electrical equipment) supply
cost per MW of secure capacity
Minimises the effect of design choices by
simplifying the electrical infrastructure to the
function of secure export capability (the
power that can be exported with the loss of
a single transformer)
Offshore substation electrical (electrical
assets on the platform) cost per MW of total
capacity
Takes into account the cost of total
generation capacity installed
Transformer cost per MVA
Provides like for like comparison between
transformers for windfarms of different
generating capacity
Topside installation cost per substation
Provides insight into whether, for example,
lower topside supply cost is being offset by
more complex installation methods
Foundation supply cost
Provides insight into whether, for example,
lower topside supply cost is being offset by
more complex foundation solutions
Foundation installation cost
Provides insight into whether, for example,
lower foundation supply cost is being offset
by more complex installation methods
Offshore Export
Cable
Offshore cable supply cost per km offshore
cable
Splitting cable supply into offshore and
onshore allows a better like for like
comparison between windfarms
ORE Catapult Page 39 of 50
Asset Metric Rationale
Offshore cable supply cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Offshore cable installation cost per km
offshore cable
Tracking installation as well as supply costs
allows insight into whether, for example,
cheaper cable supply is being offset by
more expensive installation
Offshore cable installation cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Onshore Export
Cable
Onshore cable supply cost per km offshore
cable
Splitting cable supply into offshore and
onshore allows a better like for like
comparison between windfarms
Onshore cable supply cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Onshore cable installation cost per km
offshore cable
Tracking installation as well as supply costs
allows insight into whether, for example,
cheaper cable supply is being offset by
more expensive installation
Onshore cable installation cost per MWkm
offshore cable
Taking distance and capacity into account
allows for an even better like for like
comparison between windfarms
Reactive
compensation
Cost of reactive power compensation per
km of cable
Taking distance into account allows for a
like for like comparison between windfarms
Development Capitalised development costs as a
percentage of asset cost
Provides insight to the relative magnitude of
capitalised development costs
Table 15 Proposed Direct Cost benchmarks
Recommended Indirect Cost metrics are: Actual costs vs budgeted costs; and Relative costs of
multi-contract vs greater use of EPC arrangements.
The benchmarking exercise would be implemented as a two-stage process – an initial exercise
to produce benchmark metrics for all fourteen OFTO transfers completed to date; and an ongoing
exercise based on further completed transfers.
Release of data would be subject to Non-Disclosure Agreements (NDA) between the disclosing
and receiving parties. OWIC members should also consider the anonymity issues detailed in
Section 4.7 of this report, in order to determine the exact requirements (eg. include Direct Cost
metrics only or also include Indirect Cost metrics) and frequency of benchmarking.
ORE Catapult Page 40 of 50
8.2 CRMF Quantitative Workstream
A proposal should be made to the OWPB and OWIC in 2016 for amendment of the existing CRMF
quantitative LCOE calculator to separate the LCOE results into LCOE for generation and LCOE
for transmission. However, the potential obstacles detailed in Section 6.2 of this report may
prevent this option from being implemented in the current year.
It is possible that CRMF 2017 will not include sufficient projects reaching FID or Works Completion
to conduct the quantitative assessment. One approach therefore may for OWIC to request
permission from those who have responded to previous CRMF for the Transmission LCOE to be
extracted from the previous submissions (by the consultants who have already reviewed the
submissions) in order to establish a baseline Transmission LCOE consistent with that already
reported for UK Offshore Wind as a whole.
8.2.1 CRMF Qualitative Workstream
The additional transmission-specific indicators shown in Table 16 should be added to the
qualitative study. This does not require a recommendation to OWIC, as it should be carried out
as part of the CRMF annual review. This would require further work to be done to identify further
indicators and to establish annual milestones and a 2020 target against which to track progress.
Proposed Indicator Rationale Next Steps
Lightweight Substations
First orders are expected in 2016.
The proportion of projects using lightweight
substations or radically novel design
concepts would be expected to steadily
increase, approaching 100% by or before
FID 2020.
Review 2020 cost reduction potential and
establish annual milestones based on the
OWPB report “Lightweight Offshore
Substation Designs”, completed in January
2016
Increased Capacity Export
Cables
Cables at the “state of the art” capacity level
(400MW) expected in 2016.
The size of cable used by (sufficiently large)
projects would be expected to rise steadily,
reaching the 550MW suggested by OWPB’s
work on at least one FID 2020 project
Estimate 2020 cost reduction potential and
establish annual milestones based on work
currently contracted by the Grid Group to
EDIF ERA, with results expected to be
available by June 2016.
Tender Revenue Stream
(TRS) % of OFTO Transfer
Value (see Section 3.4.1)
This should be added to the CRMF Finance
indicators to track the level of return being
required by OFTO’s
Estimate 2020 cost reduction potential and
establish annual milestones in conjunction
with OWPB Finance Group
Table 16 Proposed CRMF transmission indicators
ORE Catapult Page 41 of 50
1 https://ore.catapult.org.uk/documents/10619/168655/pdf/a8c73f4e-ba84-493c-8562-acc87b0c2d76
2 ORE Catapult financial modelling
3 https://www.ofgem.gov.uk/electricity/transmission-networks/offshore-transmission/offshore-transmission-tenders
4 http://www2.nationalgrid.com/UK/Industry-information/System-charges/Electricity-transmission/Approval-conditions/Condition-5/
5 ibid
6 http://www2.nationalgrid.com/UK/Industry-information/System-charges/Electricity-transmission/Transmission-Network-Use-of-
System-Charges/Tools-and-Data/
7 Note that 2011 includes Barrow and Robin Rigg, with very low Offshore substation capex. Excluding these, 2011 weighted
averages are £20m per Substation, £83k per MVA and £110k per MW.
8 Under the current practice of Generator-build, transmission assets are constructed by developers/generators before being
transferred to an OFTO. The Generator-build model is assumed throughout this paper and so “developer” is used to refer to the
builders of transmission assets, but this is also intended to refer to any builder of transmission assets in the future
9 https://www.ofgem.gov.uk/ofgem-publications/50898/appendix-5-kema-technical-benchmarking-report.pdf
10 https://www.ofgem.gov.uk/sites/default/files/docs/2015/06/150312_cost_assessment_decision_documentt.pdf
11
https://www.ofgem.gov.uk/sites/default/files/docs/2015/06/final_cambridge_economic_policy_associates_ofto_benchmarking_report
_1.pdf
12
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/325919/Departmental_Cost_Benchmarks_Cost_Redu
ction_Trajectories_and_Cost_Reductions_02_July_2014.pdf
13 Ofgem study for RIIO II implementation: https://www.ofgem.gov.uk/sites/default/files/docs/2013/05/rpt-
total_cost_benchmarking_at_riio-ed1_-_volume_1_-_final_-_stc_-_revised_25042013_1.pdf
14 https://www.accc.gov.au/system/files/Working%20paper%20no.%206%20%20-%20Benchmarking%20energy%20networks.pdf
15
http://www.aeso.ca/downloads/Reasonableness_Assessment_of_Transmission_Cost_Using_Benchmarking_Methodology_June_3.
16 http://www.wik.org/fileadmin/Studien/2011/Cost_benchmarking_in_energy_regulation_in_European_countries.pdf
17 http://www.scottishwater.co.uk/about-us/publications/strategic-projections
18 https://www.dodsondatasystems.com/Public/Default.aspx?sssid=84
19 https://www.solomononline.com/benchmarking/upstream/worldwide-offshore-study
20 http://www.thecrownestate.co.uk/media/5493/ei-offshore-wind-cost-reduction-pathways-study.pdf
21
http://www.thecrownestate.co.uk/media/5709/RenewableUK%20Potential%20for%20offshore%20transmission%20cost%20reductio
ns.pdf
ORE Catapult Page 42 of 50
Appendix 1 CRMF Qualitative Stream Detailed Design
The aim of the qualitative workstream is to assess progress of specific areas against the pathways
that were defined in the Offshore Wind Cost Reduction Pathways report.
The design phase of the workstream identified 66 indicators that would be tracked and a set of
milestones was agreed for each of these indicators. The milestones are designed to demonstrate
whether progress is on track for the related cost reduction to be achieved by projects reaching
FID in 2020.
The indicators are grouped into three areas (technology, supply chain and finance) and the
indicators are weighted in terms of estimated cost reduction potential before being combined to
present an overall assessment of progress towards the LCOE target of £100/MWh.
The first and second level indicators are:
Level One Indicator Level Two Indicator
Technology
PM and Development
Turbine
Balance of Plant
OFTO Capex
Installation
O&M
Design Life
Supply Chain
Growth and Scale
Competition
Collaboration
Finance
Cost of Equity
Cost of Debt
Insurance
Table A1 - 1 CRMF Qualitative Indicators Design
The full design methodology was approved by the CRMF Steering Group and the Offshore Wind
Programme Board Risk Committee and is available in the Final Design Report.
Assessment of progress towards the milestones was carried out during the implementation
phase. Primary evidence was gathered from consultation with companies actively engaged in the
sector. This was further supported by a literature review and the experience of the assessment
teams from DNV GL and PWC.
A final review of the assessment was carried out in conjunction with ORE Catapult and the CRMF
steering group.
ORE Catapult Page 43 of 50
Appendix 2 CRMF Quantitative Stream Detailed Design
Design Overview
The final process agreed is as follows:
1. Documentation (LCOE Calculator, User Guide, Questionnaire) provided by the Consultant
(in this case Deloitte) to participating developers
2. Developers complete LCOE Calculator and Questionnaire and return outputs to
Consultant
3. Consultant reviews outputs of completed LCOE Calculators and Questionnaires
4. Consultant conducts face-to-face interviews in order to clarify any issues with inputs or
outputs and to gain insight into project-specific drivers of LCOE
5. Consultant prepares final report for ORE Catapult of findings from Quantitative
workstream
LCOE Calculator
The main data gathering and analysis tool developed by, and used in, the Quantitative
workstream was the LCOE Calculator, an Excel workbook provided to all developers providing
project data to the CRMF. The LCOE Calculator includes data entry sections for all inputs required
for LCOE calculations, with the calculation and outputs sections password-protected to ensure
that LCOE calculations for all projects are conducted on the same basis. The Calculator also
includes built-in checks to identify any inputted or calculated parameters which fall outside of
expected ranges and any input sections not completed.
LCOE Calculator User Guide
The Excel workbook was accompanied by the LCOE Calculator User Guide, provided to all
participating developers in order to ensure that data for each project were inputted to the
Calculator on a like-for-like basis.
Questionnaire
The Questionnaire focuses on the qualitative factors which have been material for the quantitative
assessment of LCOE. Narrative information is requested, which provides insight to the drivers of
LCOE.
Assessors Handbook
The Assessors Handbook was compiled to document the methodology and process employed.
The Handbook is designed as a guide to allow any qualified party to implement the Quantitative
worak of the CRMF in future years.
Data Sets
For the 2014 CRMF process, projects reaching either FID or Works Completion in any of the
years 2011-2014 (inclusive) have been included. In future years, projects reaching FID or Works
Completion in the relevant year will be included.
ORE Catapult Page 44 of 50
Rules for Preserving Anonymity
One of the fundamental principles of the methodology employed is that the data for each project
should remain confidential to the respective project developer(s). All data has been provided to
the CRMF under Non-Disclosure Agreements (NDA’s). In order to ensure that no third party can
backward-engineer the LCOE of a single project, three key tests must be satisfied:
1. Three project rule – a minimum of three projects must be included in the dataset;
2. Ownership history – past ownership of projects will be considered in order to identify any
projects where parties other than the current owners have access to the project data; and
3. Relative size of projects – as a general rule, the combined contribution of any two projects
should not be greater than 80% of that year’s LCOE (the 80% hurdle will be considered
on a year-by-year basis)
As a result of these requirements, it may not be possible to conduct the Quantitative work each
year and it is likely that this report will instead be compiled bi-annually.
ORE Catapult Page 45 of 50
Appendix 3 Existing Transmission CRMF Indicators
Indi
cato
r
Cost
Red
ucti
on
figu
re c
hose
n fo
r
wei
ghti
ng
2020
Vis
ion
(whe
re w
e
need
to b
e to
hit
£100
/MW
h)
Mile
ston
e
scor
ecar
dFI
D 2
016
FID
201
7FI
D 2
018
FID
201
9FI
D 2
020
Ahe
ad o
f tar
get
Hal
f of p
roje
cts
use
stan
dard
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stry
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avai
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mar
ket.
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st p
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ct d
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e.
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se s
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ard
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ndar
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t
leas
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ther
pro
ject
con
trac
ts u
sing
the
appr
oach
over
25%
of p
roje
cts
use
the
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oach
Ove
r 50%
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roje
cts
cont
ract
usi
ng th
e
appr
oach
Ove
r 50%
of p
roje
cts
reac
hing
FID
ove
rpla
nt
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se d
ynam
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able
s
Behi
nd ta
rget
Firs
t pro
ject
con
trac
ts u
sing
ove
rpla
ntin
g
and/
or d
ynam
ic ra
ting
. IEC
cab
le ra
ting
for
win
d ge
nera
tion
bei
ng d
evel
oped
Firs
t pro
ject
und
er c
onst
ruct
ion
Firs
t pro
ject
ope
rati
onal
usi
ng o
verp
lant
ing
and/
or d
ynam
ic c
able
s ra
ting
. IEC
pub
lishe
s
'win
d ge
nera
tin'
cab
le ra
ting
sta
ndar
d. A
t
leas
t ano
ther
pro
ject
con
trac
ts u
sing
the
appr
oach
over
25%
of p
roje
cts
use
the
appr
oach
Ove
r 25%
of p
roje
cts
cont
ract
usi
ng th
e
appr
oahc
Mis
sed
targ
etSo
me
use
of o
verp
lant
ing
and/
or d
ynam
ic
rati
ng o
n at
leas
t one
pro
ject
.
Som
e us
e of
ove
rpla
ntin
g an
d/or
dyn
amic
rati
ng o
n at
leas
t one
pro
ject
.
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e us
e of
ove
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ntin
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d/or
dyn
amic
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leas
t tw
o pr
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ts.
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e us
e of
ove
rpla
ntin
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d/or
dyn
amic
rati
ng o
n at
leas
t tw
o pr
ojec
ts.
Som
e us
e of
ove
rpla
ntin
g an
d/or
dyn
amic
rati
ng o
n 50
% o
f pro
ject
s.
Ahe
ad o
f tar
get
Firs
t pro
ject
und
er c
onst
ucti
onFi
rst p
roje
ct u
nder
con
stru
ctio
nFi
rst p
roje
ct o
pera
tion
al u
sing
boo
ster
stat
ions
Firs
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ject
bui
lt u
sing
boo
ster
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tion
sA
dopt
ed in
>1
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ect.
On
targ
etFi
rst p
roje
ct c
ontr
acts
usi
ng b
oost
er s
tati
ons
Firs
t pro
ject
und
er c
onst
ucti
onFi
rst p
roje
ct u
nder
con
stru
ctio
nFi
rst p
roje
ct o
pera
tion
al u
sing
boo
ster
stat
ions
Firs
t pro
ject
bui
lt u
sing
boo
ster
sta
tion
s
Behi
nd ta
rget
Cons
ider
ed in
det
ail i
n FE
ED s
tudi
esCo
nsid
ered
in d
etai
l in
FEED
stu
dies
Cons
ider
ed in
det
ail i
n FE
ED s
tudi
esCo
nsid
ered
in d
etai
l in
FEED
stu
dies
Firs
t pro
ject
con
trac
ts u
sing
boo
ster
sta
tion
s
Mis
sed
targ
etR&
D ta
skR&
D ta
skR&
D ta
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D ta
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ered
in d
etai
l in
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stu
dies
Ahe
ad o
f tar
get
At l
east
one
non
Ger
man
pro
ject
con
trac
ts
usin
g H
VD
C ex
port
sys
tem
HV
DC
deliv
ered
on
tim
e an
d on
bud
get w
ith
cost
s st
arti
ng to
fall.
Com
peti
tive
at 7
0km
At l
east
sec
ond
non-
Ger
man
pro
ject
cont
ract
s us
ing
HV
DC
Redu
ctio
n in
cos
ts to
allo
w H
VD
C to
be
com
peti
tive
at 6
0km
Redu
ctio
n in
cos
ts to
allo
w H
VD
C to
be
com
peti
tive
at 4
0km
On
targ
et>1
non
Ger
man
pro
ject
con
trac
ts u
sing
HV
DC
expo
rt s
yste
m
> 1
non
Ger
man
pro
ject
con
trac
ts u
sing
HV
DC
expo
rt s
yste
m
HV
DC
deliv
ered
on
tim
e an
d on
bud
get w
ith
cost
s st
arti
ng to
fall.
Com
peti
tive
at 7
0km
At l
east
sec
ond
non-
Ger
man
pro
ject
cont
ract
s us
ing
HV
DC
Redu
ctio
n in
cos
ts to
allo
w H
VD
C to
be
com
peti
tive
at 7
0km
Behi
nd ta
rget
Firs
t non
-Ger
man
pro
ject
con
trac
ts H
VD
CFi
rst n
on-G
erm
an p
roje
ct c
ontr
acts
HV
DC
> 1
non
Ger
man
pro
ject
con
trac
ts u
sing
HV
DC
expo
rt s
yste
m. C
osts
falli
ng
> 1
non
Ger
man
pro
ject
con
trac
ts u
sing
HV
DC
expo
rt s
yste
m. C
osts
falli
ng
HV
DC
deliv
ered
on
tim
e an
d on
bud
get w
ith
cost
s st
arti
ng to
fall.
Com
peti
tive
at 7
0km
Mis
sed
targ
etN
o no
n-G
erm
an (h
ub a
nd s
poke
) pro
ject
use
s
HV
DC
No
non-
Ger
man
(hub
and
spo
ke) p
roje
ct u
ses
HV
DC
No
non-
Ger
man
(hub
and
spo
ke) p
roje
ct u
ses
HV
DC
Firs
t non
-Ger
man
pro
ject
con
trac
ts H
VD
CFi
rst n
on-G
erm
an p
roje
ct c
ontr
acts
HV
DC
Ahe
ad o
f tar
get
Furt
her i
mpr
ovem
ents
are
impl
emen
ted
on
proj
ects
, par
ticu
lalr
y in
con
diti
on m
onit
orin
g.
Ves
sels
sta
rtin
g to
be
shar
ed
OFT
Os
able
to d
emon
stra
te c
ost s
avin
gs.
Ves
sels
and
spa
res
star
ting
to b
e sh
ared
.
Enha
nced
sha
ring
of v
esse
ls a
nd s
pare
s.
Cond
itio
n m
onit
orin
g be
ing
used
on
over
30%
of O
FTO
ass
ets.
OFT
Os
utili
se c
ondi
tion
mon
itor
ing
on
maj
orit
y of
ass
ets,
wit
h so
me
shar
ing
of
vess
els
and
spar
es, l
eadi
ng to
cos
t sav
ings
of
10%
Dem
onst
rate
d co
st s
avin
gs o
f 10%
of O
FTO
O&
M c
ost o
n av
erag
e ac
ross
all
proj
ects
.
On
targ
et
Firs
t im
prov
emen
ts im
plem
ente
d le
adin
g to
cost
redu
ctio
ns. P
lans
for s
hari
ng o
f ves
sels
disc
usse
d
Furt
her i
mpr
ovem
ents
are
impl
emen
ted
on
proj
ects
, par
ticu
lalr
y in
con
diti
on m
onit
orin
g.
Ves
sels
sta
rtin
g to
be
shar
ed
OFT
Os
able
to d
emon
stra
te c
ost s
avin
gs.
Ves
sels
and
spa
res
star
ting
to b
e sh
ared
.
Enha
nced
sha
ring
of v
esse
ls a
nd s
pare
s.
Cond
itio
n m
onit
orin
g be
ing
used
on
over
30%
of O
FTO
ass
ets.
OFT
Os
utili
se c
ondi
tion
mon
itor
ing
on
maj
orit
y of
ass
ets,
wit
h so
me
shar
ing
of
vess
els
and
spar
es, l
eadi
ng to
cos
t sav
ings
of
10%
Behi
nd ta
rget
Firs
t inc
rem
enta
l im
prov
emen
ts s
tart
ing
to
be im
plem
ente
d, in
clud
ing
enha
nced
cond
itio
n m
onit
orin
g of
ass
ets.
Firs
t im
prov
emen
ts im
plem
ente
d le
adin
g to
cost
redu
ctio
ns. P
lans
for s
hari
ng o
f ves
sels
disc
usse
d
Furt
her i
mpr
ovem
ents
are
impl
emen
ted
on
proj
ects
, par
ticu
lalr
y in
con
diti
on m
onit
orin
g.
Ves
sels
sta
rtin
g to
be
shar
ed
OFT
Os
able
to d
emon
stra
te c
ost s
avin
gs.
Ves
sels
and
spa
res
star
ting
to b
e sh
ared
.
Enha
nced
sha
ring
of v
esse
ls a
nd s
pare
s.
Cond
itio
n m
onit
orin
g be
ing
used
on
over
30%
of O
FTO
ass
ets.
Mis
sed
targ
etN
o co
st re
duci
ng o
ptio
ns id
enti
fied
No
inve
stig
atio
n by
OFT
Os
into
sav
ings
No
impr
ovem
ents
impl
emen
ted
Firs
t im
prov
emen
ts im
plem
ente
dM
inim
al c
ost s
avin
g id
enti
fied
Stan
dard
isat
ion
of
Off
shor
e A
C
Subs
tati
on
All
subs
tati
ons
have
stan
dard
rati
ng a
nd v
olta
ge,
subs
tant
ial s
tand
ardi
sati
on
of o
ther
feat
ures
1.10
%
Ove
rpla
ntin
g an
d/or
use
of d
ynam
ic ra
ting
0.80
%
Subs
tant
ial u
se o
f
over
plan
ting
and
/or
dyna
mic
rati
ng o
f cab
les
Boos
ter s
tati
ons
(add
itio
nal p
latf
orm
s
mid
way
to s
hore
, to
redu
ce re
acti
ve
pow
er p
robl
em fo
r AC
tran
smis
sion
)
0.30
%D
eplo
yed
on o
ne o
ffsh
ore
proj
ect
Com
pact
HV
DC
syst
ems
0.20
%
HV
DC
equi
pmen
t
com
peti
tive
wit
h ot
her
opti
ons
at 7
0km
.
OFT
O O
&M
0.10
%
OFT
Os
utili
se c
ondi
tion
mon
itor
ing
on m
ajor
ity
of
asse
ts, w
ith
som
e sh
arin
g
of v
esse
ls a
nd s
pare
s,
lead
ing
to c
ost s
avin
gs o
f
10%
ORE Catapult Page 46 of 50
Appendix 4 OFTO Transfer Metrics in 2011 Terms
Figure A4 - 1 Offshore Substation capex metrics in 2011 terms
Figure A4 - 2 Offshore Circuit capex metrics in 2011 terms
Figure A4 - 3 Onshore Substation capex metrics in 2011 terms
ORE Catapult Page 47 of 50
Appendix 5 OFTO Transfer Metrics by Windfarm
Figure A5 - 2 Offshore Substation capex metrics (nominal) by windfarm 2011 - 2015
Figure A5 - 3 Offshore Circuit capex metrics (nominal) by windfarm 2011 - 2015
Figure A5 - 1 TRS % of FTV by windfarm 2011 - 2015
ORE Catapult Page 48 of 50
Figure A5 - 4 Onshore Substation capex metrics (nominal) by windfarm 2011 - 2015
ORE Catapult Page 49 of 50
Contact
ORE Catapult
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