submarine electricity cables cost benefit analysis methodology...

Submarine Electricity CablesCost Benefit Analysis Methodology StatementStakeholder Consultation Final Report July 2016

Submarine Electricity Cables ConsultationWhat you need to know

Contents

We would like to thank those who contributed their views on our December 2015 Submarine Electricity Cables Cost Benefit Analysis Methodology Statement.

We have been addressing the 189 pieces of feedback we received and are pleased to be able to share our July 2016 Submarine Electricity Cables Cost Benefit Analysis Methodology Statement which will underpin our marine licence applications for the following electricity submarine cables: • Mainland – Shapinsay• Shapinsay – Stronsay• Rousay – Westray• Mossbank – Yell• Yell – Unst 1• Yell – Unst 2• Harris – Scalpay• Kintyre – Gigha

02 Introduction

05 Methodology Overview:

Stage 1: Identifying if impacts have any significant implications for any living organism, natural resource or habitat

Stage 2: Quantifying the link between submarine electricity cable installations and the impact on any living organism, natural resource or habitat

Stage 3: Assigning a monetary value to the impact that submarine electricity cable installations have on any living organism, natural resource or habitat

Stage 4: Data used to quantify the impact that submarine electricity cable installations have on any living organism, natural resource or habitat

29 Next Steps

Submarine Electricity CablesCost Benefit Analysis Methodology Statement

What you need to know

Fifty-nine Scottish islands are currently connected to the electricity network that serves mainland Great Britain by the Scottish Hydro Electric Power Distribution network. They are connected by submarine cables which supply electricity to homes and businesses on the islands.

The cost of supplying electricity to the Scottish islands is supported by electricity consumers across the north of Scotland as part of their energy bills.

Scotland’s National Marine Plan, adopted in March 2015, requires us to consider how submarine electricity cables are laid and protected on the seabed.

During September and October 2015, we asked stakeholders to help us shape the cost benefit analysis model. The model will be used to help us determine which method of submarine electricity cable installation delivers best value by satisfying all current legislation and providing a sustainable balance of economic, safety and wider social and economic impacts.

Your responses to the first phase of our consultation have been valuable in helping inform:

• the submarine cable installation methods we consider in the cost benefit analysis;

• the benefits and drawbacks of protecting submarine electricity cables;

• the key impacts associated with installing submarine electricity cables;

• the methodology we will use to identify and evaluate potential impacts.

We summarised your responses in our December 2015 publication ‘Cost Benefit Analysis Methodology Statement’ and made this available on our website http://news.ssepd.co.uk/submarinecables

We undertook a second round of consultation comprising four workshops in December 2015, January and February 2016 to:

• allow stakeholders to see how their comments had been considered in the final methodology;

• demonstrate how the cost benefit analysis tool models different cable installation methods on one of our existing cable routes; and

• provide any further feedback on our identified impacts and method(s) for quantifying them.

This final report details how the second round of consultation has further refined the methodology.

We hope to deploy eight electricity submarine cables in 2017 and the cost benefit analysis tool will be used as supporting evidence within our marine licence applications. The tool will help us define the best value installation method.

We define best value as the method(s) of installation which satisfy all current legislation and provide(s) a sustainable balance of health and safety; socio-economic; environment; and wider economic and engineering impacts. In turn, this will help demonstrate why we believe our applications represent best value for our customers, our regulators and our business.


Page 01

The cost of maintaining the electricity distribution network involves investment by us. When customers in our network area receive an electricity bill from their supplier, our costs are included.

Within our current business plan we propose spending £44 million over the next eight years to replace 112km of submarine electricity cables. This cost was based on our existing engineering practice of laying these cables on the seabed.

The policies within Scotland’s National Marine Plan may require us to change this practice. If we are required to protect the whole 112km, our initial high-level analysis suggests the cost of doing so could be in the region of £300 million.

We want to find the best value method of cable installation which satisfies all current legislation and provides a sustainable balance of health and safety, socio-economic, environmental and wider engineering and economic impacts.

To help us do this, we propose to use a cost benefit analysis model which will demonstrate (to ourselves, our customers, our regulators – Ofgem and Marine Scotland – and all users of the marine environment) that the method(s) we propose to deploy in the future for laying and protecting cables around the coast of Scotland justify the additional expenditure and provide best value.

This report sets out the final methodology which we will apply to identify the best value installation method for each submarine electricity cable route. We will provide this as supporting evidence in future marine licence applications.

Introduction


Page 02

November 2014Ofgem published its views on the allowances that Scottish Hydro Electric Power Distribution could spend on submarine electricity cables over the next eight years.

March 2015Scotland’s National Marine Plan was adopted on 25 March 2015 and laid before Parliament on 27 March 2015. The plan includes policies on how submarine cables are laid and protected on the seabed to achieve seabed user co-existence. This means we may have to change our engineering practices.

Timeline

Dec

Jan

Feb

Apr

May

Jun

Jul

Aug

May

June

Oct

Nov

Dec

April

Jan

Feb

Sept 2015 to March 2016We are undertaking a significant piece of work to fully understand the case for changing our engineering practices to meet the requirements of Scotland’s National Marine Plan in terms of how submarine electricity cables are laid and protected on, or under, the seabed.

May 2018Based on the outcome of the recent Ofgem consultation, SHEPD will in May 2018 work with Ofgem to see if provisions can be made to recover additional costs associated with changes in engineering practice.

July 2016 to March 2017 We will provide cost benefit analysis tool output as supporting evidence for the eight marine licence applications we will make to Marine Scotland. This will help demonstrate our applications represent best value. The cost benefit analysis process and methodology during this period will also continue to be refined with feedback from each cable application process.


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Installation Methods

The cable installation methods that the cost benefit analysis will consider are:

• Surface laying: submarine cable is laid directly on the seabed with no additional protection.• Ploughing: a narrow trench is cut in the seabed in which to lay the cable.• Jetting: high pressure water jets ‘fluidise’ the seabed allowing the cable to ‘sink’ into the seabed.• Mass flow excavation: a method of burial that clears sediment from underneath the cable.• Mattressing: a concrete ‘mattress’, usually 3m x 6m, is used to protect the cable at key points.• Rock dumping: covering the cable with rock.• Horizontal directional drilling: land-based solution of drilling under short passages of water.

No additional installation methods were suggested at workshops during our second phase of consultation.

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Methodology Overview

The majority of respondents expressing an opinion on the proposed methodology, shown in Figure 1, agreed it enables adequate assessment of whether or not to include an impact within the cost benefit analysis model.

Analysis Methodology Statement

For example, is there a risk of:• loss of human life or injury (safety impact)• loss of earnings (socio-economic)

• financial impact on marine users (economic impact)

• habitat damage (environmental impact)

Does the identified impact have any significant implications for any living organism, natural resource or habitat?

1

• y units of health and safety impact• y units of socio-economic impact

• y units of environmental impact• £y of wider economic and engineering impact

Is there a quantifiable link between submarine cable installations and whatever they impact upon? For instance, x units of surface lay or protection will result in:

2Can this link be valued in a way that fits with the cost benefit analysis model?3Is there pre-existing data to allow impacts to be quantified without significant primary data collection?4

Figure 1: Cost benefit analysis methodology overview


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1 Identifying if impacts have any significant implications for any living organism, natural resource or habitat

We carried out an initial literature review of impacts relevant to submarine electricity cable installation methods. This identified 34 impacts which we grouped into four broad impact categories. Respondents broadly agreed with these but requested further clarification of what we meant. Therefore we have redefined the broad impact categories as:

• Health and safety: refers to the health and safety of humans within the vicinity of our submarine electricity cables, during installation, operation, and removal.

• Socio-economic: describes how submarine electricity cables impact on human activities, including fuel poverty, commercial fishing, and future renewable generation.

• Environmental: relates to the impact of our submarine electricity cables on the natural environment during their installation, operation and removal.

• Wider economic and engineering impacts: the cost impacts associated with installation, operation, and removal of submarine electricity cables, which may be directly or indirectly incurred by SHEPD’s customers.

We asked stakeholders about the key impacts associated with submarine electricity cables installation methods and for evidence to support their view.

During the first phase of the consultation, we heard from 120 stakeholders who helped us reduce the focus of the cost benefit analysis from 34 to 13 impact areas where a quantifiable link between the submarine cable installation method and the impact could be established from existing evidence bases.

Our second consultation phase, we received a further 32 responses which resulted in:

• classification of whether or not impacts are considered to be an overall costs or benefit to society

• clarification and separation of impacts which sees the number of impacts we will model increase to 16

Table 1 sets out the impacts that will be quantified in our submarine electricity cables cost benefit analysis methodology.

Stage 1


Page 06

Table 1: Key impacts quantified in the submarine electricity cables cost benefit analysis methodology

Category No Type Detail of impact

Health and safety impacts

1 Benefit Decreased health and safety risk to marine vessel operators from cable snagging

2 Net benefit/cost

Change in health and safety risk to cable laying vessel operators

Note, this is based on trade-off between: (i) lower fault rates leading to less time at sea; and (ii) longer installation, repair, and decommissioning time requiring longer time at sea

Socio-economic impacts

3 Benefit Decreased damage costs to marine vessel operators from cable snagging

4 Benefit Decreased risk of energy outages for island communities due to lower fault rates

5 Cost Increased distribution costs leading to lower renewable generation on islands and lower Gross Value Added (GVA)

6 Cost Increased cost of fuel poverty eradication programme due to higher fuel bills

7 Cost Increased cost to fishing operators due to loss of access to fishing grounds during cable installation

8 NEW

Benefit Decreased risk of energy outages for renewable generators due to lower fault rates

Environmental impacts

9 Cost Increased distribution costs leading to lower renewable generation on islands and higher greenhouse gas emissions

10 Net benefit/cost

Change in greenhouse gas emissions from use of backup diesel generators.

Note, this is based on trade-off between: (i) lower fault rates resulting in a reduction in diesel usage; and (ii) longer repair time resulting in an increase in diesel usage

Wider economic and engineering

11 Cost Increased installation costs associated with protection

12 Net benefit/cost

Impacts due to change in repair costs

Note this is based on trade-off between: (i) lower fault rates resulting in fewer repairs; and (ii) longer repair time because cables are protected

13 Cost Increased cost of decommissioning associated with protection

14NEW

Benefit Decreased risk of outage charges due to lower fault rates

15 Cost Increased cost of maintenance surveys associated with protection

16NEW

Net benefit/cost

Change in use costs of using backup diesel generators

Note this is based on trade-off between: (i) lower fault rates resulting in a reduction in diesel usage; and (ii) longer repair time resulting in an increase in diesel usage


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2 Quantifying the link between submarine electricity cable installations and the impact on any living organism, natural resource or habitat

We have decided to use the following evidence-based selection criteria to identify those studies that best help to identify and evaluate potential impacts. The selection criteria we used in this process are:

• Date: given the large volume of available studies, the evidence will be limited to more recent studies from 2000 onwards. It is worth noting that with advances in non-market valuation techniques over the past decade, there is a greater likelihood of obtaining results which are more robust for the purposes of value transfer by focusing on more recent studies.

• Language: only evidence provided in English will be considered.

• Geography: the search will prioritise studies based in similar contexts to the Greater North Sea region, focusing on studies in the UK, and only including studies from other regions where there is a particularly clear case to do so.

• Technique: priority will be given to the results of peer-reviewed empirical studies rather than studies based on theoretical models, value transfer, or literature review.

In conclusion, the quantifying of the links was agreed by stakeholders as an appropriate proxy of real life to model the possible impacts. However, stakeholders believed that further work would be beneficial in support of quantifying the links between submarine electricity cable installations and the impact on the natural environment.

This was a consistent finding to the Renewables Grid Initiative’s expert review and recommendations report, ‘Subsea Cable Interactions with the Marine Environment’1.

As a result of this we are seeking further opportunities to support the development of research in this area in addition to the mandatory Environmental Impact Assessments (EIAs) which will be carried out prior to a marine licences application.

1 The Renewables Grid Initiative expert review and recommendation report can be downloaded (http://renewables-grid.eu/publications/offshore-report.html)

Stage 2


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3 Assigning a monetary value to the impact that submarine electricity cable installations have on any living organism, natural resource or habitat

For each of the broad impact categories (health and safety; socio-economic; environmental; and wider economic and engineering) we have developed pathways to illustrate how we will quantify each impact. This will allow us to define

the activity that gives rise to the impact on a receptor and what we believe will be the effect of that impact and the data we have used to produce the cost benefit analysis output.

Stage 3

Impact pathway – Health and Safety

Activity: Installation of submarine electricity cable Input Variable: Method of cable installation

a. The baseline length of cable installed using each technique (e.g. 15km surface laid).b. The proposed length of cable installed using each technique (e.g. 10km surface laid and 5km ploughed).

c. Whether the cable (or section of the cable) lies within an area used by fishing vessels (e.g. yes or no).

Impact 1

Decreased health and safety risk to marine vessel operators from cable snagging

Output

Total cost of health and safety risks over operational lifetime of electricity submarine cable

Impact 2


Output

Total cost of health and safety risks for each installation technique

Receptor

Marine vessel operators and their families

Scottish Hydro Electric Power Distribution Business

Wider economy

Effect

Pain and suffering, medical costs, lost consumption

Lower efficiency, administration costs

NHS costs, administration costs, HSE investigations

Loss of output, resources spent on insurance

Figure 2: Impact pathway to output – Health and Safety


Page 09

We asked:

Would you like to see any changes to the Health and Safety Impact Pathway?

We heard:Impact 1: The scope of this impact should be widened to consider operators in and users of the marine environment.

Our response: We have updated the descriptor of Impact 1 from ‘Risks to health and safety of those working in the fishing industry’ to ‘Decreased health and safety risk to marine vessels operators from cable snagging’.

We heard:For all impacts Scottish Government, UK Government and Marine Scotland should be included as receptors.

Our response:The Scottish Government, UK Government and Marine Scotland are stakeholders to the process of understanding the impacts of subsea cable protection. However, within the context of assessing the impacts of subsea cable protection, these entities are not directly impacted and are therefore not considered receptors.

We heard:To confirm the amount of time it takes the UK Hydrographic Office to publish updated maps and reflect this within the cost benefit analysis.

Our response:Within the model we have extended the risk premium to reflect the increased risk to marine users during installation and until cables appear on ADMIRALTY charts (when risk reduces) so that this does not skew the model. This was informed by the official response received from the UK Hydrographic Office on the publication deadlines for ADMIRALTY charts.

We heard:Develop a sensitivity analysis of the likelihood of increased incident rates associated with any changes in marine usage over a 10 year period. This will reflect changes in marine, fishing and leisure patterns over the 45-year life of the cable.

Our response:The Marine Accident Investigation Branch data that is currently incorporated within the model is based on a 10-year average and will be updated for future price control periods. It is challenging to establish a basis for the changing health and safety data to reflect long-term changes in the fisheries industry. To do this would require an estimation of the change in incidents/fatalities for the specified period of time. It would also require an estimation of the change in the extent of the subsea cable network over the same period. Therefore the best estimate of the future is the long-term average of previous incidents.

Areas to be addressed on a cable-specific basis within the cost benefit analysis• We have contacted the UK Harbour Masters and

are waiting to receive information with regarding non-fishing incidents so that they can be included in the cost benefit analysis model. Due to the possible unique nature of these reports these will be included on a case-by-case basis.


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Impact pathway – Socio-Economic



c. Whether the cable (or section of the cable) lies within an area used by fishing vessels (e.g. yes or no).d. Possible failure rate and time taken to energise a replacement cable.

Impact 3Decreased damage costs to marine vessel operators from cable snagging

OutputTotal cost of damage of snagging incidents over the operational lifetime of the submarine electricity cable

Impact 4Decreased risk of energy outages for island communities due to lower fault rates

Impact 5Increased distribution costs leading to lower renewable generation on islands and lower GVA

Impact 6Increased cost of fuel poverty eradication programme due to higher fuel bills

Impact 7Increased cost to fishing operators due to loss of access to fishing grounds during cable installation

Impact 8Decreased risk of energy outages for renewable generators due to lower fault rates

OutputTotal cost to electricity users over operational life of the submarine electricity cable

OutputTotal cost of changes in energy production over operational life of submarine electricity cable

OutputTotal cost of changes in fuel poverty for each installation technique

OutputTotal cost due to fishery closure over installation of submarine electricity cable

OutputTotal estimated cost of energy outages for renewable generators per cable failure event over operational life of the cable

ReceptorMarine vessel operators and their families

SHEPD customers

Scottish Hydro Electric Power Distribution Business

Scottish renewables industry

Wider economy

Fish and other benthic species

Effect Loss of catch in entangled nets

Damage to machinery or vessels

Down time during which fishing cannot occur

Inconvenience

Damage to goods requiring refrigeration

Reduced ability to provide electricity-dependent services

Loss of employment and income in the renewable industry

Higher bills for customers leading to greater rates of fuel poverty

Loss of habitat

Loss of stationary species

Reduced income for fishery operators

Figure 3: Impact pathway to output – Socio-Economic


Page 11

We asked:

Would you like to see any changes to the socio-economic impact pathway?

We heard:Stakeholders believed that there were some changes needed to Figure 3 to better reflect the detailed modelling being undertaken. For example, socio-economic impacts on the fishing industry at a sub-sector level.

Our response:We have updated the impact pathway titles to better reflect the scope of the analysis. The following changes have been made to Figure 3:• The title of Impact 3 has been updated from

‘Damage to fishing equipment and vessels’ to ‘Decreased damage costs to marine vessel operators from cable snagging’

• The receptor descriptor ‘Operators and their families’ has been amended to ‘Marine operators and their families’

• The receptor descriptor ‘Island communities’ has been removed as they are already represented by the category ‘SHEPD customers’

We heard:The impact of submarine electricity cables on marine environment users varies. How will this be quantified in the model?

Our response:Through our engagement with stakeholders, the different risk profiles for the fishing subsectors and other marine users will be included in the quantification data used for Impact 3. This process will be route specific and will be gathered in greater detail once it has been identified where a cable may be installed.

We are currently reviewing all our submarine electricity cable routes and associated wayleaves. As part of the process, we are identifying marine users in the vicinity of our model in an effort to realistically model the impact of our cables on their activities.

We heard:Do the socio-economic and wider economic impacts associated with Impact 6 capture the economic impact of a potential increase in bills?

Our response:The current methodology assumes that the estimated increase in the distribution element of end user bills (Impact 6) is reflected as an increase in the rate of fuel poverty. The methodology requires an estimation of the change in the proportion of Scottish households in fuel poverty coupled with an estimation of the change in end user bills.

Any increase in end user bills is calculated across Scotland (rather than being specific to the community most affected by the protection of a subsea cable). In this way, the methodology incorporates consideration of the effect of subsea cable protection at local and broader economy levels.

We heard:We were asked to look at whether the way in which we consider wider health impacts of fuel poverty is captured in the model.

Our response:According to the Scottish Government Fuel Poverty Evidence Review: “The evidence of a direct link between fuel poverty and physical health appears to be inconclusive,” and “There does not appear to be a coherent evidence base to support a link between fuel poverty and excess winter deaths in Scotland, based on the statistical data currently available. This is not to say that such a correlation does not exist or cannot be proven but that an evidence gap exists.” Given this finding, this impact at present cannot be included in the model due to the lack of a direct relationship on which to measure.


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We heard:We were also asked to consider including the following receptors: public sector services (including NHS); and business (small, medium and large and high energy users).

Our response:Public sector services, including the NHS, are stakeholders to the process of understanding the impacts of subsea cable protection. However, within the context of assessing the impacts of subsea cable protection, these entities are not directly impacted and are therefore not considered receptors.

Small, medium, large and high energy users that are SHEPD customers are included within the estimation of the temporary impact upon island community economies due to energy insecurity in the event of cable failure (Impact 4) and the estimation of the increase in distribution element of end user bills (Impact 6).

We heard:The model did not fully consider the impact of cable faults on the income streams of renewable generators.

Our response:We have added impact 8 ‘Decreased risk of energy outages for renewable generators due to lower fault rates’ to model the impact loss distribution system capacity during outages.

Areas to be addressed on a cable-specific basis within the cost benefit analysis• We are working with the Shetland Energy

Solutions Team to identify cross overs and economic impacts that should be considered as part of our cable installation project on the Shetland Islands. Therefore, at present, the model does not consider changes in generation patterns on Shetland as this is a unique situation on our network.


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Figure 4: Impact pathway to output – Environmental

Impact pathway – Environmental



c. Possible failure rate and time taken to energise a replacement cable.

Impact 9Increased distribution costs leading to lower renewable generation on islands and higher greenhouse gas emissions

OutputTotal cost of greenhouse gas emissions from the reduction in renewables

Impact 10Change in greenhouse gas emissions from use of backup diesel generators

OutputTotal cost of greenhouse gas emissions over period of cable fault

Receptor Global Climate System

Local Climate System

Effect Increase in greenhouse gas emissions

Increase in air pollution and respiratory disease


Page 14

We asked:

Would you like to see any changes to the Environmental Impact Pathway?

We heard:Do the environmental impacts currently included in the cost benefit analysis model accurately reflect the level of impact that your cable installation processes would have on the wider marine environment? Would it be appropriate to include a weighting to adjust for impacts not currently captured?

Our response:We have conducted a wide review of the literature to identify links between our installation processes and the marine environment and have included the ones we are comfortable have a tangible relationship.

We feel using a generic weighting to estimate the possible level of environmental impact would not be appropriate at present as it would not be consistent with the other methodologies which currently use a measurable link.

We will also be conducting extensive sensitivity analyses for inclusion in the marine licences supporting evidence to ensure that any variables which are driving the analysis are clearly identified.

To address the lower number of environmental impact links we continue to seek further research evidence during the marine licences process and will report back in 12 months any further evidence we have identified.

Our marine licences will therefore continue to follow the standard EIA process and we have engaged with the Renewables Grid Initiative2 which has recently completed an additional analysis on the environmental impacts of electricity submarine cables to further analyse where tangible links can be quantified and included in subsequent analysis.

We are working with partners3 to better understand the environmental impact of rock placement as a submarine electricity cable protection method and have applied for Natural Environment Research Council funding4.

Areas to be addressed on a cable-specific basis within the cost benefit analysis• The methodology for including the

environmental impacts on benthic habitats and how we include them will be informed by the detailed EIA work carried out for each cable installation. How the model has been updated for this aspect will be reported back in 12 months after our next round of marine licences. Any update will also consider how the cable protection methods have addressed potential risks to species in the immediate environment.

2 The Renewables Grid Initiative is a Berlin based collaboration of Transmission System Operators 3 Our partners are Scottish Association of Marine Scientists, Scottish Hydro Electric Transmission plc, Scottish Fishing Federation,

Renewables Grid Initiative, Marine Scotland, Clyde Fishermen’s Association4 The Environmental Risks to Infrastructure Innovation Programme (ERIIP) is collaboration between NERC and infrastructure

owners and operators to enable them to access research and use environmental sciences to identify, quantify and manage environmental risks to UK infrastructure: http://www.nerc.ac.uk/innovation/activities/infrastructure/envrisks/environrisk/


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Figure 5: Impact pathway to output – Wider Economic and Engineering

Impact pathway – Wider Economic and Engineering



c. Possible failure rate and time taken to energise a replacement cable.

Impact 11Increased installation costs associated with protection

OutputTotal engineering cost incurred during the installation of a submarine electricity cable

OutputTotal engineering cost incurred during recovery of a decommissioned submarine electricity cable

OutputTotal estimated economic cost of diesel used during a fault of submarine electricity cables

Impact 12Change in repair costs

Impact 13Increased cost of decommissioning associated with protection

Impact 14Decreased risk of outage charges due to lower fault rates

Impact 15Increased cost of maintenance surveys associated with protection

Impact 16Change in use costs of using backup diesel generators

OutputTotal engineering cost incurred during the repair of a submarine electricity cable

OutputTotal estimated engineering costs from operation and maintenance of submarine electricity cables

OutputTotal economic cost of customer interruption and customer minutes lost during the repair of a submarine electricity cable

ReceptorScottish Hydro Electric Power Distribution Business

SHEPD customers

Local economy

Scottish economy

Effect Permanent increase in costs

Removal of protection before fault can be repaired

Hire of specialist equipment and vessels

Further vessels for restatement of protection

Reduced risk of third party faults

Increased mean time between failures

Increased maintenances and related survey costs


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We asked:

Would you like to see any changes to the Wider Economic and Engineering Impact Pathway?

We heard:Does the cable type change with each installation method and how does this affect the cost benefit analysis model?

Our response:We are seeking to standardise our cable type as a cost-reduction mechanism and to improve security of supply by having on hand all the strategic spares we need for faster repairs.

We heard: If the engineering costs are going to be paid for by SHEPD customers, there is a real need to show this as part of the overall outcome.

Our response:The whole cost benefit analysis process has been designed to draw out the costs of different cable installation methods on the noted receptors and in particular this is explored in Impact 6.

We heard:That the economic costs of a failure were not being captured in the overall design costs of installing the new electricity submarine cable and as a result the possible benefits of using a protection installation method were being underestimated.

Our response:As a result we have now added an additional impact, ‘Impact 14 – Decreased risk of outage charges due to lower fault rates’ which will be used to estimate the potential benefit of having a lower fault rate.

We heard: The economic cost of using diesel generation or alternative localised supply of electricity during submarine cables failures was not being captured and thus the potential net benefit or costs were not being captured.

Our response:As a result we have now added an additional impact, ‘Impact 16 – Change in use costs of using backup diesel generators’ which will be used to estimate the potential net benefit or costs of have a lower fault rate.


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4 Data used to quantify the impact that submarine electricity cable installations have on any living organism, natural resource or habitat

We have included tables for each of the broad categories to show how we will build the cost benefit analysis model. For each impact area we have defined the following:

Inputs – these are the submarine electricity cable factors which will vary the magnitude of the output depending on the specific type or types of installation methodology.

Data – these are the defined values based on evidence which will be used to quantify the impact.

Output – the positive or negative value of the quantified impact.

We will use the total of all impact outputs to determine which installation method offers the best value.

The December 2015, January and February workshops enabled us to show stakeholders how we build the cost benefit analysis model using the evidence base, and how we applied it to one of our submarine electricity cable routes. The purpose of these workshops was to gather stakeholder views – and the evidence they have access to – to inform the development of the cost benefit analysis tool which we will use to demonstrate to Ofgem, Marine Scotland, and users of the marine environment whether or not the additional cost of protecting or burying submarine electricity cables represents value to SHEPD customers and wider stakeholders.

We have now updated the data within Tables 2 to 5 to reflect what we have heard from stakeholders. This information will now form the baseline which has been externally verified by an independent third party DNVGL. This review has been carried out prior to our first marine application to provide an additional level of comfort to the ultimate users of the cost benefit information for risk assessment of key marine licence decisions.

Another methodology statement update will be provided in April 2017 after a competitive tender for the submarine electricity cable installation contract has been completed so that we include accurate market prices.

Stage 4

We asked:

Would you like to see any changes to the data used to support health and safety estimates?

We heard:Can you explain further what the Value of Statistical Life (VSL) is and the need to use a value for human life in economic terms?

Our response:We have added a simple definition below the table for reference which explains the need to attribute an economic value to life to illustrate the value that changes in policy have on different receptors.

“In economic terms the VSL is the amount of money a person (or society) is willing to spend to save a life. Understanding the value of life is important for government policies where lives are at risk or where the goal is to save lives.”


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Impact 1 2

Decreased health and safety risk to marine vessel operators from cable snagging


Input For the proposed cable route the user chooses:a. The baseline length of cable installed using each

technique (e.g. 15km surface laid)b. The proposed length of cable installed using

each technique (e.g. 10km surface laid and 5km ploughed)

c. Whether any organisations use the area in which the cable lies for fishing (e.g. SFF, Clyde Fishermen’s Association, or None)

For the proposed cable route the user chooses:a. The proposed length of cable installed with each

technique (e.g. 10km HDD)

Data Databases in the CBA model contain information on:A. Statistical rate of accidental lives lost for cable

snagging incidents for each cable type (e.g. 0.000015 fatal accidents per km per year for unprotected cables)

B. Value of a statistical life (e.g. £1.9 million per life)C. Statistical rate of reportable injuries from cable

snagging incidents for each cable type (e.g. 0.0000086 reportable injuries per km per year for unprotected cables)

D. Cost of a reportable injury (e.g. £29,155 per injury)E. The length of time for the assessment period

(e.g. 45 years)F. Health and safety discount rate (e.g. Ofgem

guidance suggests using a discount rate for health and safety impacts of 1.5%†)

Databases in the CBA model contain information on:A. Time taken for vessel operation for each cable

installation technique (e.g. 10 days per km)B. Statistical rate of accidental lives lost for vessel

use (e.g. 0.0001 accidents per day)C. Value of a statistical life (e.g. £1.9 million per life)D. Statistical rate of reportable injuries for vessel use

(e.g. 0.0002 accidents per day)E. Cost of a reportable injury (e.g. £29,155 per injury)F. The length of time for the assessment period (e.g.

45 years)G. Health and safety discount rate (e.g. 1.5%†)

Calculation CBA model programmed to calculate:1. Baseline health and safety costs

for each installation technique i.e. IF(c=“None”,0,PV(F,(a*A*B)+(a*C*D),E))

2. Proposed health and safety costs for each installation technique (protected) i.e. IF(c=“None”,0,PV(F,(b*A*B)+(b*C*D),E))

3. Proposed health and safety costs for each installation technique (unprotected) i.e. IF(c=“None”,0,PV(F,(b*A*B)+(b*C*D),E))

4. Net health and safety costs i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline health and safety costs assumed to be

zero as no installation required2. Proposed health and safety costs for each

installation technique per vessel callout (protected) i.e. PV((G,((a*A*B*C)+(b*A*D*E)),F)

3. Proposed health and safety costs for each installation technique per vessel callout (unprotected) i.e. PV((G,((a*A*B*C)+(b*A*D*E)),F)

4. Net health and safety costs i.e. 2–1 and 2–3

Output Output presented in terms of total estimated cost of health and safety risks over operational lifetime of cables.

Output presented in terms of total estimated cost of health and safety risks for each installation technique per vessel callout over life of cables.

Table 2: Data used to support health and safety estimates

† Ofgem (2014), Template CBA RIIO ED1 v4.xls


Page 19

Impact 3 4 5 6

Decreased damage costs to marine vessel operators from cable snagging

Decreased risk of energy outages for island communities due to lower fault rates

Increased distribution costs leading to lower renewable generation on islands and lower GVA

Increased cost of fuel poverty eradication programme due to higher fuel bills

Input For the proposed cable route the user chooses:a. The baseline length of cable installed with

each technique (e.g. 15km surface laid)b. The proposed length of cable installed with


c. Type of fishing organisation operating within area (e.g. SFF, CFA, or none)

For the proposed cable route the user chooses:a. The NRN number of the circuit (e.g. 0331021)b. Life expectancy of cable and expected number

of years to fault (e.g. 25 years)


technique (e.g. 10km surface laid and 5km ploughed)b. The NRN number of the circuit (e.g. 0331021) or, if a new

circuit, the future projected amount of renewable energy to be connected (e.g. 50MW)


technique (e.g. 10km surface laid and 5km ploughed)

Data Databases in the CBA model contain information on:A. Damage cost to fisheries if cable

unprotected (e.g. £127.83 per km per year for SFF fisheries, £396.46 per km per year for CFA fisheries, £0 per km per year if no fishing present)

B. The length of time for the assessment period (e.g. 45 years)

C. Discount rate (e.g. the Ofgem discount rate for non-health and safety impacts is 3.5% for years 0–30 and 3.0% for years 31–45)

Databases in the CBA model contain information on:A. Average length of outage during faults

(e.g. 2 hours per fault)B. Number of domestic, SME, and C&I users on

the circuit (e.g. 845 domestic, 10 SME, 5 C&I)C. Costs of outages to domestic, SME, and C&I

users (e.g. £4.73 per hour for domestic users)D. The length of time for the assessment period

(e.g. 45 years)E. Discount rate (e.g. 3.5% for years 0–30 and

3.0% for years 31–45)

Databases in the CBA model contain information on:A. Projected demand for renewable generation distribution

access on island (e.g. 100MW)B. Percentage of applications likely to go ahead (e.g. 40%)C. Distribution costs passed on to renewable generators

(e.g. £1 million)D. Existing renewable energy generation costs

(e.g. £1.5 million per MW)E. Impact of costs on output (e.g. 1% increase in costs leads

to 1% decrease in output)F. GVA reduction per unit of renewable energy generated

due to reduced demand from construction costs (e.g. £212,000 per MW per year)

G. GVA reduction per unit of renewable energy generated due to reduced demand from operation and maintenance costs (e.g. £212,000 per MW per year)

H. Expected lifetime of wind farm following construction (e.g. 19 years)

I. The length of time for the assessment period (e.g. 20 years)

J. Discount rate (e.g. 3.5% for years 0–30 and 3.0% for years 31–45)

Databases in the CBA model contain information on:A. Total installation costs (e.g. £1 million per km)B. Proportion of costs passed on to domestic user distribution

bills in Year 1 (e.g. 10.25%)C. Proportion of costs passed on to domestic user distribution

bills in Years 2–6 (e.g. 4.46%)D. Number of domestic SHEPD customers (e.g. 683,831)E. Average existing electricity bill (e.g. £1,058.94)F. Ratio of change in fuel prices to fuel poverty (e.g. 1:0.4)G. Existing number of households in fuel poverty amongst

SHEPD customers (e.g. 267,378)H. Costs to eradicate fuel poverty from households

(e.g. £8,273)I. First period in which costs are passed on to consumers

(e.g. Year 1)J. Second period in which costs are passed on to consumers

(e.g. Years 2–6)K. The length of time for the assessment period

(e.g. 45 years)L. Discount rate (e.g. 3.5% for Years 1–30 and 3.0% for

Years 31–45)

Calculation CBA model programmed to calculate:1. Baseline damage costs i.e. PV(C,a*A(c),B)2. Proposed damage costs (protected)

i.e. PV(C,b*A(c),B)3. Proposed damage costs (unprotected)

i.e. PV(C,b*A(c),B)4. Net costs i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline costs per cable failure

i.e. PV(E,A*B(a)*C*(1/b),D)2. Proposed costs per cable failure (protected)

i.e. PV(E,A*B(a)*C*(1/b),D)3. Proposed costs per cable failure (unprotected)

i.e. PV(E,A*B(a)*C*(1/b),D)4. Net costs i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline costs assumed to be zero as no installation

required2. Proposed change in GVA (protected) i.e.

PV(J,((A(b)*B)*((∑C(a)/D)*E)*F)+((A(b)*B)*((∑C(a)/D)*E)*G)*H)),I)

3. Proposed change in GVA (unprotected) i.e. PV(J,((A(b)*B)*((∑C(a)/D)*E)*F)+((A(b)*B)*((∑C(a)/D)*E)*G)*H)),I)

4. Net change in GVA from change in renewable energy production i.e. 2–1 and 2–3


required2. Proposed costs (protected) i.e. PV(L,((((((a*A*B)/D)/

E)*F*G*H*I)-(a*A*B))+((((((a*A*C)/D)/E)*F*G*H*J)-(a*A*C)),K)3. Proposed costs (unprotected) i.e. PV(L,((((((a*A*B)/D)/

E)*F*G*H*I)-(a*A*B))+((((((a*A*C)/D)/E)*F*G*H*J)-(a*A*C)),K)4. Net costs i.e. 2–1 and 2–3

Output Output presented in terms of total estimated damage cost of snagging incidents over operational lifetime of cables.

Output presented in terms of total estimated cost to electricity users per cable failure event over operational life of the cable.

Output presented in terms of estimated total cost of changes in renewable energy production over 20-year period.

Output presented in terms of total cost of changes in fuel poverty for each installation technique over a six-year period.

Table 3: Data used to support socio-economic estimates


Page 20

Impact 3 4 5 6

Decreased damage costs to marine vessel operators from cable snagging

Decreased risk of energy outages for island communities due to lower fault rates

Increased distribution costs leading to lower renewable generation on islands and lower GVA

Increased cost of fuel poverty eradication programme due to higher fuel bills

Input For the proposed cable route the user chooses:a. The baseline length of cable installed with

each technique (e.g. 15km surface laid)b. The proposed length of cable installed with


c. Type of fishing organisation operating within area (e.g. SFF, CFA, or none)

For the proposed cable route the user chooses:a. The NRN number of the circuit (e.g. 0331021)b. Life expectancy of cable and expected number

of years to fault (e.g. 25 years)


technique (e.g. 10km surface laid and 5km ploughed)b. The NRN number of the circuit (e.g. 0331021) or, if a new

circuit, the future projected amount of renewable energy to be connected (e.g. 50MW)



Data Databases in the CBA model contain information on:A. Damage cost to fisheries if cable

unprotected (e.g. £127.83 per km per year for SFF fisheries, £396.46 per km per year for CFA fisheries, £0 per km per year if no fishing present)

B. The length of time for the assessment period (e.g. 45 years)

C. Discount rate (e.g. the Ofgem discount rate for non-health and safety impacts is 3.5% for years 0–30 and 3.0% for years 31–45)

Databases in the CBA model contain information on:A. Average length of outage during faults

(e.g. 2 hours per fault)B. Number of domestic, SME, and C&I users on

the circuit (e.g. 845 domestic, 10 SME, 5 C&I)C. Costs of outages to domestic, SME, and C&I

users (e.g. £4.73 per hour for domestic users)D. The length of time for the assessment period

(e.g. 45 years)E. Discount rate (e.g. 3.5% for years 0–30 and

3.0% for years 31–45)

Databases in the CBA model contain information on:A. Projected demand for renewable generation distribution

access on island (e.g. 100MW)B. Percentage of applications likely to go ahead (e.g. 40%)C. Distribution costs passed on to renewable generators

(e.g. £1 million)D. Existing renewable energy generation costs

(e.g. £1.5 million per MW)E. Impact of costs on output (e.g. 1% increase in costs leads

to 1% decrease in output)F. GVA reduction per unit of renewable energy generated

due to reduced demand from construction costs (e.g. £212,000 per MW per year)

G. GVA reduction per unit of renewable energy generated due to reduced demand from operation and maintenance costs (e.g. £212,000 per MW per year)

H. Expected lifetime of wind farm following construction (e.g. 19 years)

I. The length of time for the assessment period (e.g. 20 years)

J. Discount rate (e.g. 3.5% for years 0–30 and 3.0% for years 31–45)

Databases in the CBA model contain information on:A. Total installation costs (e.g. £1 million per km)B. Proportion of costs passed on to domestic user distribution

bills in Year 1 (e.g. 10.25%)C. Proportion of costs passed on to domestic user distribution

bills in Years 2–6 (e.g. 4.46%)D. Number of domestic SHEPD customers (e.g. 683,831)E. Average existing electricity bill (e.g. £1,058.94)F. Ratio of change in fuel prices to fuel poverty (e.g. 1:0.4)G. Existing number of households in fuel poverty amongst

SHEPD customers (e.g. 267,378)H. Costs to eradicate fuel poverty from households

(e.g. £8,273)I. First period in which costs are passed on to consumers

(e.g. Year 1)J. Second period in which costs are passed on to consumers

(e.g. Years 2–6)K. The length of time for the assessment period

(e.g. 45 years)L. Discount rate (e.g. 3.5% for Years 1–30 and 3.0% for

Years 31–45)

Calculation CBA model programmed to calculate:1. Baseline damage costs i.e. PV(C,a*A(c),B)2. Proposed damage costs (protected)

i.e. PV(C,b*A(c),B)3. Proposed damage costs (unprotected)

i.e. PV(C,b*A(c),B)4. Net costs i.e. 2–1 and 2–3


i.e. PV(E,A*B(a)*C*(1/b),D)2. Proposed costs per cable failure (protected)

i.e. PV(E,A*B(a)*C*(1/b),D)3. Proposed costs per cable failure (unprotected)

i.e. PV(E,A*B(a)*C*(1/b),D)4. Net costs i.e. 2–1 and 2–3


required2. Proposed change in GVA (protected) i.e.

PV(J,((A(b)*B)*((∑C(a)/D)*E)*F)+((A(b)*B)*((∑C(a)/D)*E)*G)*H)),I)

3. Proposed change in GVA (unprotected) i.e. PV(J,((A(b)*B)*((∑C(a)/D)*E)*F)+((A(b)*B)*((∑C(a)/D)*E)*G)*H)),I)

4. Net change in GVA from change in renewable energy production i.e. 2–1 and 2–3


required2. Proposed costs (protected) i.e. PV(L,((((((a*A*B)/D)/

E)*F*G*H*I)-(a*A*B))+((((((a*A*C)/D)/E)*F*G*H*J)-(a*A*C)),K)3. Proposed costs (unprotected) i.e. PV(L,((((((a*A*B)/D)/

E)*F*G*H*I)-(a*A*B))+((((((a*A*C)/D)/E)*F*G*H*J)-(a*A*C)),K)4. Net costs i.e. 2–1 and 2–3

Output Output presented in terms of total estimated damage cost of snagging incidents over operational lifetime of cables.

Output presented in terms of total estimated cost to electricity users per cable failure event over operational life of the cable.

Output presented in terms of estimated total cost of changes in renewable energy production over 20-year period.

Output presented in terms of total cost of changes in fuel poverty for each installation technique over a six-year period.


Page 21

Impact 7 8

Increased cost to fishing operators due to loss of access during cable installation

Decreased risk of energy outages for renewable generators due to lower fault rates

Input For the proposed cable route the user chooses:a. The proposed length of cable installed with


b. Economic value of fisheries crossing each section of the cable route (e.g. £150,00 per year)

For the proposed cable route the user chooses:a. The NRN number of the circuit (e.g. 0331021)b. Life expectancy of cable and expected

number of years to fault (e.g. 25 years)

Data Databases in the CBA model contain information on:A. Time taken for cable installation for each

technique (e.g. 5 days per km)B. Time taken for cable location to be added to

ADMIRALTY charts (e.g. 10 days)C. The length of time for the assessment period

(e.g. 45 years)D. Discount rate (e.g. 3.5% for Years 1–30 and

3.0% for Years 31–45)

Databases in the CBA model contain information on:A. Projected demand for distribution access on

island (e.g. 100MW)B. Percentage of applications likely to go ahead

(e.g. 40%)C. Average onshore wind capacity factor

(e.g. 30%)D. Average length of outage during faults

(e.g. 2 hours per fault)E. The length of time for the assessment period

(e.g. 45 years)F. Discount rate (e.g. 3.5% for years 0–30 and

3.0% for years 31–45)

Calculation CBA model programmed to calculate:1. Baseline fishery costs assumed to be zero as

no additional disturbance 2. Proposed fishery costs for each

installation technique (protected) i.e. PV(D,((a*A)+B)*(b/365)),C)

3. Proposed fishery costs for each installation technique (unprotected) i.e. PV(D,((a*A)+B)*(b/365)),C)

4. Net fishery costs i.e. 2–1 and 2–3


i.e. PV(F,A(a)*B*C*D*(1/b),E)2. Proposed costs per cable failure (protected)

i.e. PV(F,A(a)*B*C*D*(1/b),E)3. Proposed costs per cable failure (unprotected)

i.e. PV(F,A(a)*B*C*D*(1/b),E)4. Net costs i.e. 2–1 and 2–3

Output Output presented in terms of total estimated cost due to fishery closure due to installation of cables.

Output presented in terms of total estimated cost of energy outages for renewable generators per cable failure event over operational life of the cable.

Table 3: Data used to support socio-economic estimates (continued)


Page 22

We asked:

Would you like to see any changes to the data used to support socio-economic estimates?

We heard:There is need to better reflect the island poverty figures within the model. The extent of the problem is significantly higher than the figures used in the model.

Our response:We will seek to use the most appropriate fuel poverty figures for the electricity submarine cable cost benefit analysis. In some instances it maybe more appropriate to use the Scottish Government study and on other occasions use the more localised reports which are being produced. This will also be addressed through regular updates and we propose publishing another report in 12 months to further highlight these changes.

We heard:There was a growing need to establish industry standard compensation rates for marine users due to the level of activity which is planned in the marine environment in the future. Marine users would find it useful to have a clearer understanding of electricity submarine cable policies, for example project development timetables and rates for possible compensation for damage to vessels.

Our response:Our preference would be to have an agreed industry position around compensation to marine users for items such as loss of fishing equipment by sector, or temporary loss of access to fishing grounds and we have begun discussions with Scottish fishing representatives to establish these.

We will also seek to give marine users as much notice of projects as possible to help them plan their activities during the project installation.

We are also seeking the best method to communicate any key policies or policy updates to the wider marine stakeholders.

We asked:

Would you like to see any changes to the data used to support environmental estimates?

Stakeholders did not express a view on the data to support environmental estimates.


Page 23

Impact 9 10

Increased distribution costs leading to lower renewable generation on islands and increased greenhouse gases emissions

Change in greenhouse gas emissions from use of backup diesel generators

Input For the proposed cable route the user chooses:a. The proposed length of cable installed with


b. The NRN number of the circuit (e.g. 0331021)

For the proposed cable route the user chooses:a. The baseline length of cable installed with each

technique (e.g. 15km surface laid)b. The proposed length of cable installed with


c. Life expectancy of cable and expected number of years to fault (e.g. 25 years)

Data Databases in the CBA model contain information on:A. Projected energy distribution demand on island

from future renewable supply (e.g. 100MW)B. Percentage of renewable generation applications

likely to go ahead (e.g. 40%)C. Distribution costs passed on to renewable

generators (e.g. £1 million)D. Existing renewable energy generation costs

(e.g. £1.5 million per MW)E. Impact of distribution costs on renewable output

(e.g. 1% increase in costs leads to 1% decrease in output)

F. Wind energy capacity factor (e.g. 30%)G. Greenhouse gas emissions factor for reduction in

renewable generation (e.g. 0.237 tCO2e per MWh)

H. Abatement cost of CO2 emissions (e.g. £5.14)

I. Expected life of wind farm development (e.g. 20 years)

J. The length of time for the assessment period (e.g. 20 years)

K. Discount rate (e.g. 3.5% for years 0–30 and 3.0% for years 31–45)

Databases in the CBA model contain information on:A. Repair time for each cable type per year

(e.g. 24 days)B. Rate of fuel use in backup generators and repair

vessels (e.g. 4,800 litres per day)C. Carbon intensity of generators

(e.g. 0.0028 tonnes CO2e per litre of fuel)

D. DECC carbon price (e.g. £50 per tonne of CO2)

E. The length of time for the assessment period (e.g. 45 years)

F. Discount rate (e.g. 3.5% for years 0–30 and 3.0% for years 30–45)

Calculation CBA model programmed to calculate:1. Baseline costs assumed to be zero as no

installation required2. Proposed change in GVA (protected)

i.e. PV(K,(((A(b)*B)*(∑C(a)/D))*E)*F*G*H*I),J)3. Proposed change in GVA (unprotected)

i.e. PV(K,(((A(b)*B)*(∑C(a)/D))*E)*F*G*H*I),J)4. Net change in GVA from change in energy

production i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline emission costs for each installation

technique per fault i.e. PV(F,a*A*B*C*D*(1/c),E) 2. Proposed emission costs for each installation

technique per fault (protected) i.e. PV(F,b*A*B*C*D*(1/c),E)

3. Proposed emission costs for each installation technique per fault (unprotected) i.e. PV(F,b*A*B*C*D*(1/c),E)

4. Net emission costs i.e. 2–1 and 2–3

Output Output presented in terms of total estimated cost of changes in Greenhouse gas emissions over a 20-year period.

Output presented in terms of total estimated cost of emissions per fault over 45-years.

Table 4: Data used to support environmental estimates


Page 24

Impact 11 12

Increased installation costs associated with protection

Impacts due to the change in repair costs

Input For the proposed cable route the user chooses:a. The proposed length of cable laid with


For the proposed cable route the user chooses:a. The baseline length of cable laid with


b. The proposed length of cable laid with each technique (e.g. 10km surface laid and 5km ploughed)

Data Databases in the CBA model contain information on:A. Cost of decommissioning the existing cable,

if applicableB. Cable laying rates for each technique

(e.g. 5km per hour)C. Day rates for cable laying vessels (e.g. £1,000

per day, assuming a 6 or 12 hour working day)D. Day rates for additional vessels for protection

installation (e.g. £1,000 per day)E. Mobilisation, demobilisation and travel costs for

vessel operators (e.g. £390,000 per job)F. Cost of different cable types

(e.g. £1,000 per km of 33kV)G. The length of time for the assessment period

(e.g. 45 years)H. Discount rate (e.g. 3.5% for years 0–30 and 3.0%

for years 31–45)

Databases in the CBA model contain information on:A. Cable recovering rates for each technique

(e.g. 5km per hour)B. Day rates for recovering the cable

(e.g. £1,000 per day)C. Cable laying rates including reinstallation of any

protection (e.g. 5km per hour)D. Dates rates for relaying cable including any

protection (e.g. £1,000 per day)E. Cost of different cable types

(e.g. £1,000 per km of 33kV)F. Mobilisation, demobilisation and travel costs for

vessel operators (e.g. £390,000 per job)G. Assessment period (e.g. 45 years)H. Discount rate (e.g. 3.5% for years 0–30 and 3.0%

for years 31–45)

Calculation CBA model programmed to calculate:1. Baseline costs assumed to be zero as no

installation required2. Proposed installation costs for cable (protected)

i.e. PV(H,(A+(a*C/B)+(a*D/B)+E+(a*F),G) 3. Proposed installation costs for cable (unprotected)

i.e. PV(H,(A+(a*C/B)+E+(a*F),G)4. Net costs of installation i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline cost of recovering and replacing

the cable per repair, i.e. PV(H,(a*B/A)+(a*D/C)+(a*E)+F,G)

2. Proposed cost of recovering and replacing the cable per repair (protected), i.e. PV(H,(b*B/A)+(b*D/C)+(b*E)+F,G)

3. Proposed cost of recovering and replacing the cable per repair (unprotected), i.e. PV(H,(b*B/A)+(b*C/D)+(b*E)+F,G)

4. Net change in repair costs i.e. 2–1 and 2–3

Output Output presented in terms of total estimated engineering cost incurred during cable installation over 45-year assessment period.

Output presented in terms of total estimated engineering cost incurred to repair cables over the 45-year assessment period.

Table 5: Data used to support wider economic and engineering estimates


Page 25

Impact 13 14 15 16

Increased cost of decommissioning associated with protection

Decreased risk of outage charges due to lower fault rates

Increased cost of maintenance surveys associated with protection


Input For the proposed cable route the user chooses:a. The baseline length of cable installed with each



For the proposed cable route the user chooses:a. NRN Number

For the proposed cable route the user chooses:a. The baseline length of cable installed with each technique

(e.g. 15km surface laid)b. The proposed length of cable installed with each




technique (e.g. 10km surface laid and 5km ploughed)c. Life expectancy of cable and expected number of years to

fault (e.g. 25 years)

Data Databases in the CBA model contain information on:A. Cable recovery rates for each technique

(e.g. 5km per day)B. Day rates for vessels recovering the cable

(e.g. £1,000 per day)C. Mobilisation, demobilisation and travel costs for

vessel operators (e.g. £390,000 per job)D. Assessment period (e.g. 45 years)E. Discount rate (e.g. 3.5% for years 0–30 and 3.0%

for years 31–45)

Databases in the CBA model contain information on:A. Number of customers (e.g. 1,000)B. Time to reconnect customers after a fault

(e.g. two hours)C. Cost per CI (e.g. £16.38)D. Cost per CML (e.g. £0.40)E. Assessment period e.g. 45 yearsF. Discount rate (e.g. 3.5% for years 0–30 and 3.0%

for years 31–45)

Databases in the CBA model contain information on:A. Survey costs (e.g. £1,000 per day)B. Survey productivity (e.g. 5km per day)C. Survey setup costs (e.g. £30,000 per survey)D. Current survey procedure (e.g. every 5 years)E. Future survey procedure (e.g. every 3 years)F. Assessment period e.g. 45 yearsG. Discount rate (e.g. 3.5% for years 0–30 and

3.0% for years 31–45)

Databases in the CBA model contain information on:A. Repair time for each cable type per year (e.g. 24 days per

km per year)B. Rate of fuel use in backup generators and repair vessels

(e.g. 1 tonne per day)C. Cost of diesel (e.g. £/ML)D. The length of time for the assessment period

(e.g. 45 years)E. Discount rate (e.g. 3.5% for years 0–30 and 3.0%

for years 30–45)

Calculation CBA model programmed to calculate:1. Baseline cost of recovering the cable,

i.e. PV(E,(a*B/A)+C,D) 2. Proposed cost of recovering the cable (protected),

i.e. PV(E,(b*B/A)+C,D)3. Proposed cost of recovering the cable

(unprotected), i.e. PV(E,(b*B/A)+C,D) 4. Net costs of decommissioning i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline costs of CI and CML per fault i.e.

PV(F,(A(a)*C)+(A(a)*B*D),E)2. Proposed costs of CI and CML per fault

(unprotected) i.e. PV(F,(A(a)*C)+(A(a)*B*D),E)3. Proposed costs of CI and CML per fault

(protected) i.e. PV(F,(A(a)*C)+(A(a)*B*D),E)4. Net costs of CI and CML i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline operation and maintenance costs per survey, i.e.

PV(G,D((a*A/B)+C)),F)2. Proposed operation and maintenance costs per survey

(protected), i.e. PV(G,E((b*A/B)+C)),F)3. Proposed operation and maintenance costs per survey

(unprotected), i.e. PV(G,E((b*A/B)+C)),F)4. Net costs of surveys, i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline diesel costs for each installation technique per

fault i.e. PV(E,A(a)*B*C*(1/c),D) 2. Proposed diesel costs for each installation technique per

fault (protected) i.e. PV(E,A(b)*B*C*(1/c),D) 3. Proposed diesel costs for each installation technique per

fault (unprotected) i.e. PV(E,A(b)*B*C*(1/c),D) 4. Net diesel costs i.e. 2–1 and 2–3

Output Output presented in terms of total estimated engineering cost incurred during recovery of the cables over the assessment period.

Output presented in terms of total estimated economic costs from Customer Interruption (CL) and Customer Minutes Lost (CML) charges over the 45-year assessment period.

Output presented in terms of total estimated engineering costs for operation and maintenance of the cables over the 45 year assessment period.

Output presented in terms of total estimated cost of diesel used per fault over 45 years.

Table 5: Data used to support wider economic and engineering estimates (continued)


Page 26

Impact 13 14 15 16

Increased cost of decommissioning associated with protection

Decreased risk of outage charges due to lower fault rates

Increased cost of maintenance surveys associated with protection


Input For the proposed cable route the user chooses:a. The baseline length of cable installed with each



For the proposed cable route the user chooses:a. NRN Number






technique (e.g. 10km surface laid and 5km ploughed)c. Life expectancy of cable and expected number of years to

fault (e.g. 25 years)

Data Databases in the CBA model contain information on:A. Cable recovery rates for each technique

(e.g. 5km per day)B. Day rates for vessels recovering the cable

(e.g. £1,000 per day)C. Mobilisation, demobilisation and travel costs for

vessel operators (e.g. £390,000 per job)D. Assessment period (e.g. 45 years)E. Discount rate (e.g. 3.5% for years 0–30 and 3.0%

for years 31–45)

Databases in the CBA model contain information on:A. Number of customers (e.g. 1,000)B. Time to reconnect customers after a fault

(e.g. two hours)C. Cost per CI (e.g. £16.38)D. Cost per CML (e.g. £0.40)E. Assessment period e.g. 45 yearsF. Discount rate (e.g. 3.5% for years 0–30 and 3.0%

for years 31–45)

Databases in the CBA model contain information on:A. Survey costs (e.g. £1,000 per day)B. Survey productivity (e.g. 5km per day)C. Survey setup costs (e.g. £30,000 per survey)D. Current survey procedure (e.g. every 5 years)E. Future survey procedure (e.g. every 3 years)F. Assessment period e.g. 45 yearsG. Discount rate (e.g. 3.5% for years 0–30 and

3.0% for years 31–45)

Databases in the CBA model contain information on:A. Repair time for each cable type per year (e.g. 24 days per

km per year)B. Rate of fuel use in backup generators and repair vessels

(e.g. 1 tonne per day)C. Cost of diesel (e.g. £/ML)D. The length of time for the assessment period

(e.g. 45 years)E. Discount rate (e.g. 3.5% for years 0–30 and 3.0%

for years 30–45)

Calculation CBA model programmed to calculate:1. Baseline cost of recovering the cable,

i.e. PV(E,(a*B/A)+C,D) 2. Proposed cost of recovering the cable (protected),

i.e. PV(E,(b*B/A)+C,D)3. Proposed cost of recovering the cable

(unprotected), i.e. PV(E,(b*B/A)+C,D) 4. Net costs of decommissioning i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline costs of CI and CML per fault i.e.

PV(F,(A(a)*C)+(A(a)*B*D),E)2. Proposed costs of CI and CML per fault

(unprotected) i.e. PV(F,(A(a)*C)+(A(a)*B*D),E)3. Proposed costs of CI and CML per fault

(protected) i.e. PV(F,(A(a)*C)+(A(a)*B*D),E)4. Net costs of CI and CML i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline operation and maintenance costs per survey, i.e.

PV(G,D((a*A/B)+C)),F)2. Proposed operation and maintenance costs per survey

(protected), i.e. PV(G,E((b*A/B)+C)),F)3. Proposed operation and maintenance costs per survey

(unprotected), i.e. PV(G,E((b*A/B)+C)),F)4. Net costs of surveys, i.e. 2–1 and 2–3

CBA model programmed to calculate:1. Baseline diesel costs for each installation technique per

fault i.e. PV(E,A(a)*B*C*(1/c),D) 2. Proposed diesel costs for each installation technique per

fault (protected) i.e. PV(E,A(b)*B*C*(1/c),D) 3. Proposed diesel costs for each installation technique per

fault (unprotected) i.e. PV(E,A(b)*B*C*(1/c),D) 4. Net diesel costs i.e. 2–1 and 2–3

Output Output presented in terms of total estimated engineering cost incurred during recovery of the cables over the assessment period.

Output presented in terms of total estimated economic costs from Customer Interruption (CL) and Customer Minutes Lost (CML) charges over the 45-year assessment period.

Output presented in terms of total estimated engineering costs for operation and maintenance of the cables over the 45 year assessment period.

Output presented in terms of total estimated cost of diesel used per fault over 45 years.


Page 27

We asked:

Would you like to see any changes to the data used to support wider economic and engineering estimates?

We heard:Through detailed testing of our model 27 changes were required to the cost benefit analysis model.

Our response:We have completed the 27 changes identified and have now had the cost benefit analysis model independently assessed by technical experts DNVGL. Their conclusion was that the methodology statement and cost benefit analysis tool provided a good overview of the process that SHEPD had carried out to date and that the cost benefit analysis output would be a fair reflection of the impacts highlighted in Table 1 to quantify the impact of installing electricity submarine cables.

We will continue to update these data points as we procure, through a competitive tender, the services of third-party companies to install our electricity submarine cables.


Page 28

Next StepsNext Steps

Page 29


This model will be used to inform our engineering practices and future marine licences during the RIIO-ED1 period and beyond.

We will commit to providing an update in 12 months to show how it has informed our business decisions during 2016/17. We will also highlight any further refinements to the model.

We will commit to provide a further update on the key data points contained in Tables 2 to 5 in 2018/19 to ensure the model remains relevant and reflective of the current thinking of our material impacts.

During the consultation we received a total of 189 comments on the methodology statement and the cost benefit analysis model. We have done our best to address each one of these in this July 2016 update, to ensure that the stakeholders who we spoke to can see how we have incorporated their views.

17 comments that could not be addressed at this stage have been put on hold until further information could be obtained from more stakeholder consultation, academic research or a competitive tender of electricity submarine cable installation companies.

Examples of these questions are: • At which point do different electricity

submarine cable installations methods become best values solutions?

• How representative of your portfolio are the eight cables you are going to install next year?

• When you are carrying out ploughing as a protection method would you require one or two vessels, and what are the implications for installation costs?

We will, therefore, provide a further update on the progress of these comments in our next publication in March 2017.

Finally, we would like to thank all those stakeholder who have provided their views so far and continue to encourage you and other stakeholders to engage with us further throughout our marine licensing applications in 2016.

For further information please contact:

Submarine Cable Cost Benefit Analysis Project Team Scottish Hydro Electric Power Distribution Inveralmond House 200 Dunkeld Road PerthPH1 3AQ

www.news.ssepd.co.uk/submarinecablesor by email at [email protected]

This document is the follow up to Cost Benefit Analysis Methodology Statement – our December consultation publication, which can be downloaded atwww.news.ssepd.co.uk/submarinecables/information


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