UK Power Networks. Overall Cost Benefit Analysis

Transcription

1 UK Power Networks Overall Cost Benefit Analysis

2 Contents 1 Executive Summary Analysis Conclusions Summary Table 4 2 Introduction Scope Input Parameters Asset Replacement/Refurbishment Low Carbon Generation Low Loss Equipment Smart Grid Solutions Quality of Supply High Value Projects Limitations 7 3 Methodology Asset Replacement/Refurbishment Probability of Failure and Impact Low Carbon Generation Reinforcement Smart Grid Solutions Losses Quality of Supply High Value Projects 15 4 CBA Results Introduction Asset Replacement EHV and 132kV Transformers EHV Switchgear kV Switchgear Distribution Switchgear Low Carbon Generation Losses Smart Grid Solutions Quality of Supply High Value Projects 45 5 Conclusions Asset Replacement Reinforcement for low carbon generation Loss Reduction Smart Grid Solutions Quality of Supply High Value Projects Summary 47 Contents Page 2

3 1 Executive Summary This document sets out UK Power Networks approach to using Cost Benefit Analysis to evaluate and justify a number of our key investment areas, in order to ensure a robust and justifiable expenditure plan. Extensive Cost Benefit Analysis (CBA) has been undertaken, based on Ofgem s guidance, to measure and quantify the benefits associated with key areas of our investment plan. Analysis has been focused on the major areas where we are proposing changes from the investment profile in DPCR5. This document describes the process we undertook, setting out the parameters and methodology we used in calculating the benefits, and our approach to treatment of these benefits within the CBAs. 1.1 Analysis Conclusions Asset Replacement In carrying out assessments of the actual projects that our asset replacement intervention strategies have identified, we have demonstrated that our intervention strategies produce robust investment plans which provide positive benefits for customers and maintain the condition of the distribution networks. The results of the sensitivities around duration of interruption strongly support investing to avoid the potentially long outages that can occur should there be the failure of multiple items of equipment at higher voltages. The assessments have then been summarised and presented in with RIGs costs in Section 4. We have carried out assessments aimed at identifiable projects covering fluid filled cables, 132kV, 66kV and 33kV transformers, 132kV, 66kV, 33kV and 11kV Primary switchgear Reinforcement for low carbon generation We have used CBA to justify investment in EPN of 15.4m of reinforcement which will increase network capacity by 187MVA Loss Reduction We have used CBA to value the impact of our loss reduction initiative and identify the tipping point for investing in low loss transformers ahead of any limits being imposed by EU directives Smart Grid Solutions We have used CBA to test the parameters we have used to assess the implementation smart technologies will have on our investment plans. These support using Demand side response to defer investment. Separate parameters have been define around 2MVA in deferring reinforcement for at least 3 years in EPN and SPN and 5MVA of DSR deferring reinforcement for 4 years in LPN. Partial Discharge testing provides benefits in deferring switchgear replacement Smart adaptation of overhead ratings will allow reinforcement to be managed more effectively Equipment to allow real time transformer rating provides benefits in allowing capacity increases to be deferred. Executive Summary Page 3

4 These technologies will allow our investment plans to be better optimised and uncertainties better managed Quality of Supply We have demonstrated that our proposed additional investments in quality of supply provide substantial benefits to customers High Value Projects We have demonstrated that the replacement of gas filled cables between Sydenham and Eltham in south east London should be carried out in RIIO-ED1 rather than being deferred until RIIO-ED2 1.2 Summary Table The table below summarises the results where CBA assessment has been used to justify specific investment kv EPN LPN SPN FFC Replacement Transformer Replacement Transformer Refurbish Switchgear Replacement Switchgear Refurbish QoS High Value Projects Key CBA results positive Partial support No projects Executive Summary Page 4

5 2 Introduction A Cost Benefit Analysis (CBA) is a systematic way of calculating and comparing benefits and costs of a project. A CBA has two purposes: 1. To determine if a project is a sound investment decision 2. To provide a basis for comparing projects or project options considering both the costs and benefits. For the purposes of assessing our investment plans, and in with Ofgem s guidance, CBA assessments have been used to consider the costs against the benefits of changes to timing of investments. All costs and benefits assessments are presented in millions of pounds at 12/13 prices. 2.1 Scope Cost benefit analysis has been completed on the following areas of spend: Asset Replacement/refurbishment: Replacing/refurbishing these assets facilitates a reduction in the probability of failure, which ensures fewer customers will experience a loss of supply. Low Carbon Generation Reinforcement: Investing in reinforcement to allow more low carbon generation to connect and displace higher carbon generation creating benefits from reduced carbon emissions. Low Loss Equipment: Newer, more efficient equipment with lower losses ratings not only provides a financial benefit of the reduced cost of generating the lost energy, but also an environmental benefit, in the associated reduced carbon emissions. Smart Grid Solutions: Employing innovative techniques to help manage our network can help us defer investment to a point where we have more information about the future and what is needed. High Value Projects: Discretionary replacement projects with abnormally high investment costs require more justification as to why they need to be completed now, rather than deferred until a later date. Introduction Page 5

6 2.2 Input Parameters The key parameters that were used for the CBA are shown in Table 1: Table 1 CBA Parameters Parameter Value Comments Cost of Capital 4.2% RIIO ED1 UKPN Value Discount rate 3.5% Treasury Green Book/Ofgem guidance CI Ofgem s recommended values CML 0.38 Ofgem s recommended values Losses /MWh Ofgem s recommended values Oil Leakage /Litre ARP Model/ Ofgem guidance Capitalization rate (split between fast & slow money) 70% RIIO ED1 UKPN Value Asset Life 45 Years Ofgem Guidance 2.3 Asset Replacement/Refurbishment The CBAs are focused on the most significant categories of expenditure in which CBAs could be effectively applied; Fluid Filled Cables, 11kV Switchgear, EHV and 132kV Switchgears and EHV and 132kV transformers. CBAs for these investments were undertaken at an individual project level and subsequently summarised by combining all costs and benefits, as this aligns all relevant costs with the associated benefits. Project costs are mapped to multiple associated RIGs s to reflect all the works necessary to carry out that project; a simple RIGs level analysis would result in not all costs being considered for the benefits being included. The CBAs were grouped by voltage and activity, so that the costs covered by the CBAs could be directly matched to the relevant RIGs s. We have also conducted a policy level CBA on our Distribution Switchgear replacement programme, comparing the benefits of the average Probability of Failure of one of our assets against our target unit cost of an RMU replacement, The key costs and benefits that have been compared are as follows: Table 2 Asset Replacement Inputs Price Control Costs/Benefits Investment Costs Costs Avoided Society Costs/Benefits Carbon Emissions Unsupplied Energy (Loss of supply) Oil Leakage Network Losses 2.4 Low Carbon Generation We have used cost benefit assessment of a number of potential projects to enable additional distributed generation connection to assess which would be included in our RIIO-ED1 business plan. The benefits included were the reduced emissions associated with low carbon generation displacing more traditional generation. Ofgem s recommended traded carbon values were used to quantify this. In order to estimate the amount of low carbon generation each project would enable, the following parameters were used: Introduction Page 6

7 Table 3 Low Carbon Generation Inputs Parameter Capacity of the site Load Factor -0.4 Power Factor- 1 (At/near unity) Comments Measured in MVA Used to estimate an average loading To convert the MVA into MWh 2.5 Low Loss Equipment UK Power Networks has a strategy for managing technical losses as set out in the Losses Strategy Annex. A range of opportunistic measures have been planned within our proposed costs, and the CBA model has been used in order to determine the economic benefits. In addition, a new possible EU directive may lead to new, tougher standards for electrical losses in our distribution transformers. A CBA assessment has been carried out and sensitivities were run to establish a threshold for the price of a new low loss transformer that would produce a positive CBA result. This is essentially a tipping point price, where if these new transformers are below a certain price, installation of them can be considered justifiable, whereas if they turn out to be more expensive, it will not. 2.6 Smart Grid Solutions A number of Smart technologies have been tested through Ofgem s CBA model, looking at whether the use of these technologies to defer conventional investment, provides sufficient justification for their utilisation. The technologies that were considered were: Demand Side Response Partial Discharge Testing (switchgear) OHL Ratings Real Time Transformer Ratings 2.7 Quality of Supply Our proposed investment in Quality of Supply related projects have been against the improvements in forecast CIs & CMLs. The QoS schemes that were considered are: Algorithmic Automation ASL Programme Auto Recloser Programme Switchgear Change Programme Improved Operational Response A detailed discussion of the benefits is included in the Quality of Supply Annex. 2.8 High Value Projects A CBA has been carried out for the High Value Project at Eltham/Sydenham, where replacement of gas cables is planned. The value of deferring the investment for five years has been tested against the potential impact of failure, considering the impact of the increased probability of failure on the 16,000 customers affected, with the aim to show that deferring investment would not be advisable (i.e. a negative NPV), as gas cable are significantly more prone to failure under abnormal running conditions. 2.9 Limitations CBAs have not been applied where specific, measurable benefits were not determinable. EHV solid cables and Tower s are a significant category of expenditure, but there were no specific schemes for EHV cables and it was difficult to quantify the benefits of Tower refurbishment in such a way that would be useful in a CBA. It was therefore decided not to pursue Cost Benefit Analysis for these categories. Introduction Page 7

8 A number of schemes which have been selected for asset replacement/refurbishment were customer specific sites. Because of this, these projects have been removed from the CBA assessment. The CBAs consider only significant costs and benefits. We have excluded a number of costs/benefits that were because they would have an insignificant effect on the overall outcome. After assessing costs per asset unit we have excluded costs and benefits were Fault Opex, Repair Opex, Maintenance costs and Inspections costs. Minor repair costs per item on major plant items are currently low compared to scheme replacement costs and benefits. Introduction Page 8

9 3 Methodology 3.1 Asset Replacement/Refurbishment Project Costs Projects for each asset type were identified from the UK Power Networks Network Asset Management Plan (NAMP), which identifies total forecast expenditure for each of the projects. All of the benefits and costs were collated for each asset, as well as secondary data such as health indexes, failure rates, leakage rates, degradation rates, and other values related to the assets that would allow the calculation of a financial value for benefits. All the data was analysed using the CBA model to give an absolute Net Present Value for the projects. All projects within the selected categories in the NAMP were reviewed and only selected if the majority of the project costs occurred in RIIO ED1 period ( ). Where there was an overlap with DPCR5 ( ) or ED2 periods ( ), the deciding factor was which period the majority of the costs were incurred in. If majority of the costs were incurred in the ED1 period, the project was included into the process, and the costs that fall into the other periods were included in the RIIO ED1 CBA Base scenarios The base scenario option has been taken as a defer investment scenario, until intervention is absolutely necessary. We have defined this as the point that the asset gets to an ARP score of 10 out of a maximum of 15. For reference, an ARP score of 7.5 equates to an Ofgem HI score of HI5. Bearing in mind the condition of an asset degrades non-arly, an ARP score of 10 is a reasonable point at which intervention would become necessary, as the risk of failure would become unsatisfactorily high. Option 1 is a replace/refurbish during ED1 option, where the benefits of replacement/refurbishment are accrued only from the year after investment, up until the asset gets an ARP score of HI10 (i.e. it will have to be replaced anyway), at which point there is an avoided cost of investment. Where the NPV of Option 1 is positive, the asset should be replaced or refurbished during ED1, whereas if it is negative, the benefits are not substantial enough to outweigh the discounted value of deferral. 3.2 Probability of Failure and Impact Probability of Failure Initially we applied a ar degradation to the Probability of Failure (PoF) so as to increase the chance of failure as an asset ages in a straightforward way. ar degradation rates proved either to produce too low a potential future failure rate i.e. too long an asset life before failure became likely, or a very aggressive likelihood of failure, as shown in Figure 1 below. We therefore decided to replicate the complex ARP failure rate calculation was in the models to reflect a more accurate probability of failure as an asset reaches the end of its life. This is consistent with the industry accepted bathtub failure degradation models. Methodology Page 9

10 Figure 1 Failure Rate Assumptions and Asset Life Probabilityof Failure Excess benefits if ar rate used to EoL Low benefits if ar rate based on initial degradation Asset Age ARP Model Original ar Degradation ar Degradation to match EoL failure rate The PoF was used for 11kV Switchgear, EHV Switchgear and 132kV and 33kV Transformers, whilst the Oil Leakage Rate was used for the Fluid Filled Cables. We have used Health Index data from the ARP model (which uses a 1-15 scale) which takes into account different factors such as the age of equipment, the make, the model, location etc. The implications are that the higher the Health Index value or the older the asset gets, the higher the Probability of Failure or leakage rate. The Probability of Failure has been calculated using the same approach as used in the ARP model (as this is an industry standard model). This is calculated as follows: PoF Where: k 1 HI c i HI c HI c HI c 2! PoF = probability of failure per annum HI = health index k & c = constants (c=1.35) The following allows the calculation of k: 3! k i 0 i! 2 HI c HI c n 3 i i k 1 HIi c Average no. i 1 2! 3! of failures per annum I Where: n = the number of assets in asset group The above calculations allow the use of 25 years of forecast Health Index (HI) data to calculate the PoF for a given asset. A typical relationship between the HI score and the PoF can be seen below, showing how the failure rate kicks up towards the end of its life. Methodology Page 10

11 Probability of Failure Figure 2 Failure rate relationship to asset condition ARP HI Score Where required we use the GROWTH function in Excel to extend the PoF values out to 45 years, by estimating a growth rate based on the previous 25 years HI numbers. The PoF was calculated on an asset by asset basis, and then an overall site PoF is calculated from the sum of the component assets. This ensures that we have not overestimates the probability of failure from, for example, choosing the highest asset failure rate for a site. It should be noted that the CBAs are negatively affected where a poor condition asset is in parallel with a good condition asset; one asset could be very likely to fail but the likelihood this would result in supply loss is low kV and EHV Switchgear For 132kV and EHV Switchgear, should one asset on a site fail, the whole site would not experience a loss of supply. A probability of failure was therefore developed considering the failure of a second asset whilst the first was out of service. For switchgear a return to service duration on 4 weeks was assumed for EPN and SPN and 8 weeks for LPN reflecting the additional complexity of replacing indoor assets in an urban environment. Outage durations of 2 hours and 12 hours have been modelled for 132kV and EHV switchgear kV and EHV Transformers For 132kV and EHV transformers, should one asset on a site fail, the whole site would not experience a loss of supply. A probability of failure was therefore developed considering the failure of a second asset whilst the first was out of service. For transformers a return to service duration of 8 weeks was assumed for EPN and SPN and 16 weeks for LPN, reflecting the additional complexity of replacing indoor or enclosed assets in an urban environment. Outage durations of 12, 24 and 48 hours have been modelled for 132kV and EHV transformers kV Switchgear For 11kV switchgear, the failure of an asset would directly affect supplies to customers, but only for a proportion of the customers supplied from the substation. As a general rule the number of customers affected would be the number of customers on the site divided by the number of transformers supplying the site. We have carried out an example CBA to assess refurbishing switchgear rather than replacing based on a known site with 26 circuit breakers Distribution switchgear Ring Main Units For distribution switchgear, we took an average PoF from all of our Ofgem HI4&5 assets Oil Leakage For Fluid Filled cables, as oil leakage does not necessarily follow the probability of electrical failure (which is captured in the PoF data), a different method was used. It was assumed that the HI of a cable was directly linked to the amount of oil it would leak, so as the HI increased, so did the leakage rate accordingly. Leakage rate for each year = (6 year leakage average) x (leakage multiple for desired year) Methodology Page 11

12 Leakage Multiple = (HI*e (Logest -1)x(year) )/HI Project specific rates were then scaled up to match the Asset Management calculated oil leakage at a total level. Fluid filled cables can be maintained in service by continuing to top up cable fluid. electrical failure and loss of supply very low likelihood events. This makes Fluid filled cable replacement has considered only the value of loss of oil, however allowing excessive leakage could result in prosecution for beach of environmental regulations Loss of Supply Calculations and Assumptions The probability of failure of an asset was multiplied by the number of customers connected to a site, to get an annual average customers off supply. Depending on which time off supply sensitivity was run, customer minutes lost were obtained from the product of the customers interrupted and the length of time off supply. For Distribution Switchgear, an average number of customers connected to each switchgear was obtained by dividing the total number of customers on each of our networks, by the total number of distribution switchgear. This was then multiplied by the PoF, as above, to obtain the impacts Transformer Losses Calculation Transformer replacements have an additional benefit from the reduced losses they get as a result of a newer, often more efficient asset replacing it. A total annual electrical losses number, in MWh, was calculated for both the existing asset, and the new one replacing it, to enable the calculation of an overall reduced losses amount. A typical average value for new transformer losses was taken from the UK Power Networks transformer specification documents, depending on the MVA rating of the transformer Safety Assumptions Safety benefits have only been included in our analysis of Distribution Switchgear, given the large number of these assets that are in public areas. We have used a probability of injury of 5%, and a probability of fatality of 1%. These are then multiplied by the probability of failure of the asset to get an overall risk of injury/fatality Sensitivities We have run a number of sensitivities on each asset type to be sure we have a robust set of data, in order to make a well-justified decision. The sensitivities were run as follows: FFC: 11kV Switchgear: EHV Switchgear: EHV Transformers: Sensitivities were run on the leakage rate, producing scenarios where it is 50% higher, and 50% lower than our standard scenario. (These are shown in the CBA files by the designation High and Low, respectively). Sensitivities were run on the probability of failure, producing outcomes where the PoF is 10% higher or lower than the standard scenario. Additional sensitivities have been undertaken on the time off supply, using 2 hours, reflecting faster restoration times following a non-damage event such as stuck breakers, 6 hours and 12 hours for longer restoration due to equipment damage. As with 11kV Switchgear, sensitivities of 10% around the original PoF have been run. The time off supply sensitivities of 2 hours and 12 hours have been run, again reflecting scenarios for both damage and non-damage failure events. Methodology Page 12

13 Again, a 10% sensitivity around the PoF has been run as with Switchgear assets. Reflecting a longer estimated restoration time due to the fact only the probability of two or more transformers failing is used, sensitivities on the time off supply have been run for 12 hours, 24 hours and 48 hours. 3.3 Low Carbon Generation Reinforcement Carbon Emissions In order to calculate the amount of Low Carbon Generation each project would produce, the capacity of the site was multiplied by a loading factor of 0.4, to get an average loading. A power factor of 1 is used to convert the MVA capacity into MW, and then a subsequent annual MWh of generation can be calculated. This is then put through Ofgem s model to convert into tco2e, so the value of the benefits can be calculated Base The reinforcement of our network is a necessity, and it is only the technology we use to achieve this that we can decide. Therefore, the base scenario has been defined as a high carbon scenario, where the reinforcement is completed through other means, not utilising low carbon technologies. This creates large environmental benefits in the other options, which are compared against the additional costs of employing these newer technologies Sensitivities Sensitivities were run on the amount of capacity utilised, introducing a phased utilisation period, where only a certain proportion of the capacity was employed at first, ramping up to the full amount over several years. The exact sensitivities can be seen in the results section. Sensitivities have also been modelled around the amount of planned low carbon generation. Whilst it is expected all of the planned capacity will come from Low Carbon generation, scenarios have been modelled where only 50% or 75% of the capacity comes from low carbon sources Project Selection As not all of the potential low carbon generation schemes would have been likely to go ahead, there was a need to select only the most beneficial projects. As the resulting CO2 benefits are very high, a benefit to cost ratio for each project was calculated, and only the schemes with the highest ratios were chosen to be included in our investment plan. We chose the cut off as the upper quartile, in order to ensure we gain the most beneficial outcome for the expenditure. 3.4 Smart Grid Solutions Base & Sensitivities For all Smart Grid solution schemes except Partial Discharge Monitoring, the base scenario is set as network reinforcement during RIIO-ED1, with the options examining the effects of employing these Smart Grid Solutions in order to defer investment by a number of years, depending on the technology. The deferral lengths are shown below. Table 4 CBA Parameters Smart Grid Solution Demand Side Response- EPN & SPN Demand Side Response- LPN 33kV OHL Ratings 132kV OHL Ratings Real Time Transformer Rating Deferral Length 3 years/6 years, depending on sensitivity 4 years 3 years 2/4/6 years, depending on sensitivity 3 years Methodology Page 13

14 For Partial Discharge Monitoring, as installation of this equipment does not guarantee the ability to defer reinforcement, the base scenario has been set as 35% of sites equipped with monitoring devices are able to defer further investment by 5 years, with sensitivities run around this of 20%, 50% and 60%. For more information on the Smart Grid Solutions Cost Benefit Assessments, please refer to Annex 9: Smart Grid Strategy. 3.5 Losses Losses and Costs Calculations The CBA model has been used to calculate a benefit for all the loss reduction initiatives we have identified for RIIO-ED1. For all of the measures set out in the Losses Strategy, an overall reduced losses amount was calculated for each year of RIIO-ED1, and then flat-d beyond this. This was then run through the CBA model, and a financial value for the reduced losses attained. The costs of these projects are estimated to be minimal, since they are planned to be in conjunction with other investment works. When running the CBA for the new EU losses standards, standard losses ratings for our current transformers were compared against the losses ratings for the new, proposed transformers. An annual MWh was then calculated for each, and the two compared to get a reduction in losses benefit. Various hypothetical investment costs were then input into the model, in order to find out the point at which the CBA turned from negative to positive. This was then taken as the tipping point price in which it was justifiable to invest in the lower-loss transformers Base & Sensitivities As our Losses strategy is very much an opportunistic approach, where reduced losses investment is often in conjunction with other investment drivers, only the incremental costs of these initiatives are taken into account in the options. Therefore, the base scenario is a business as usual approach, assuming these other investment drivers are undertaken anyway, without the added costs of the loss reduction projects. When calculating the benefits of moving to the low EU losses standard, the base scenario is where more traditional, higher loss transformers continue to be installed. The multiple options are modelled around various ratings and types of low loss transformers (315kVA transformer, 500kVA transformer, 800kVA transformer, 1000kVA transformer, 25kVA Pole Mounted Transformer (PMT), 50kVA PMT and 100kVA PMT), looking at the additional cost of a low loss transformer, against the benefits of reduced losses. 3.6 Quality of Supply CI and CML benefits Forecasted CI and CML benefits resulting from investments which will result in quality of supply improvements taken from the RIGs table CV106, and then multiplied by the number of customers on the network, to get a total number of customers interrupted and customer minutes lost. The benefits were assumed to continue only through RIIO-ED1 and RIIO-ED Costs The costs were taken from CV106 with an additional 10% of the switchgear change costs added to represent the additional value from additional remote control which will be installed as standard. This is representative of the historic costs booked to quality of supply for the addition of secondary remote control to distribution switchgear Base The base we have selected is, again, a business as usual option, where none of the Quality of Supply initiatives are undertaken, and therefore, no investment, and no CI/CML benefits. The base assumes no degradation in service. Methodology Page 14

15 3.7 High Value Projects Probability of Failure Replacement of the gas cables at Eltham/Sydenham brings with it a reduced probability of failure. Because of the nature of gas cables, there is a significantly higher risk of failure once one circuit already fails, and this is reflected in the model with an increase risk multiplier of 6 (i.e. the circuit is 6 times more likely to fail than previously). Recent experience with the replacement of gas cables in SPN indicates that this is a reasonable assumption. In this instance a gas cable was taken out of service for replacement and the second circuit failed almost immediately; supply loss being averted only because alternative supply arrangements have been put in place before the first circuit was taken out of service Base The base scenario in this case is to replace the cables during RIIO-ED1, with the options testing whether a deferral of 5 years into RIIO-ED2 is justifiable, given an increased probability of failure from delaying. Methodology Page 15

16 4 CBA Results 4.1 Introduction The CBA assessments consider the costs of bringing works forward over deferral. In the CBA assessments the costs of any scheme are represented as the return and depreciation over 45 years. The CBA results over 45 years therefore best represent the comparison of total costs and benefits; we have therefore chosen to present the CBA model output over 32 and 45 years. 4.2 Asset Replacement In the following section we present the results of the CBA assessments for Fluid Filled Cables, 11kV Switchgear, EHV and 132kV Switchgear and EHV and 132kV transformers. For each of the assessments we have carried out we have summarised the costs against covered by the projects included in the assessment and the resulting overall CBA outputs Assessments carried out Table 5 Number of projects Total Schemes considered Schemes without sufficient data Total schemes Fluid Filled Cables EHV and 132kV Transformer kV Switchgear EHV Switchgear Overall there were 392 projects considered in four different asset categories. However 6 projects addressed customer specific sites and were excluded from the assessment. These schemes were grouped by voltage (132kV, 66kV, 33kV or 11kV) and activity (replacement or refurbishment) in order to test how justifiable they are at an activity level that aligned closely to the RIGs categories. The costs of each project are allocated to multiple s in the RIGs, but the benefits from each project cannot be split by RIGs. Therefore, the CBAs have been carried out at a project level, with a breakdown of the costs by RIGs shown before the CBA results. The total amount of expenditure that has been from each RIGs table is shown in Table 6 below. Results of the CBA assessments for each category are presented by voltage, replacement and refurbishment. A total CBA has been carried out for each category and is included in the results. CBA Results Page 16

17 Table 6 CBA Assessments by % value of key RIGs tables EPN LPN SPN CV3 Asset Replacement 35.16% 48.90% 27.54% CV5 Refurbishment 10.58% 17.45% 24.69% CV6 Civil Works 42.22% 10.78% 31.57% CV8 Legal & Safety 13.68% 12.14% 10.06% CV101 Reinforcements & DSM 0.31% 0.95% 0.60% CV105 Op. IT & Telecoms 4.24% 1.06% 2.00% EPN Fluid Filled Cables Fluid filled cables are replaced by solid cables with costs attributed to oil pressurised cables for the decommissioning of these assets. Table 7 EPN 132kV Replacement CV kV UG Cable (Non Pressurised) 132kV % CV kV UG Cable (Oil) 132kV % Table 8 EPN 33kV Replacement CV kV UG Cable (Non Pressurised) EHV % CV kV UG Cable (Oil) EHV % Table 9 EPN Fluid Filled Cable Summary Total 132kV ( 0.54) ( 0.38) Total 33kV ( 0.06) ( 0.05) Total ( 0.66) ( 0.46) Projects returning + ve CBAs 3/6 5/6 5/6 4/6 5/6 5/6 There is a single scheme in EPN that gives a negative result. Overall investment in fluid filled cable replacement shows a positive benefit and we consider that this demonstrates that our proposed investments represent value for money LPN Fluid Filled Cables Fluid filled cables are replaced by solid cables with costs attributed to oil pressurised cables for the decommissioning of these assets. CBA Results Page 17

18 Table 10 LPN 132kV Replacement CV kV UG Cable (Non Pressurised) 132kV % CV kV UG Cable (Oil) 132kV % Table 11 LPN 66kV Replacement CV kV UG Cable (Non Pressurised) EHV % CV kV UG Cable (Oil) EHV % Table 12 LPN 33kV Replacement CV kV UG Cable (Non Pressurised) EHV % CV kV UG Cable (Oil) EHV % Table 13 LPN Fluid Filled Cable Summary Total 132kV Total 66kV ( 0.73) ( 0.56) Total 33kV Total Projects returning +ve CBAs 15/21 17/21 18/21 16/21 17/21 19/21 Over 45 years the CBA results are strongly positive for our proposed investments under all sensitivities. We have included a small number of projects in our programme that do not return positive CBAs on an individual basis as these have a sound engineering basis for replacement given their age and condition, but where the amount of oil leakage would have to be unacceptably high to give benefits higher than the costs of the projects SPN Fluid Filled Cables Fluid filled cables are replaced by solid cables with costs attributed to oil pressurised cables for the decommissioning of these assets. Table 14 SPN 132kV Replacement CV kV UG Cable (Non Pressurised) 132kV % CV kV UG Cable (Oil) 132kV % CBA Results Page 18

19 Table 15 SPN 33kV Replacement CV kV UG Cable (Non Pressurised) EHV % CV kV UG Cable (Oil) EHV % Table 16 SPN Fluid Filled Cable Summary Total 132kV ( 2.74) ( 2.27) ( 1.81) ( 2.45) ( 1.98) ( 1.52) Total 33kV ( 0.28) ( 0.17) Total ( 3.02) ( 1.74) ( 0.47) ( 2.62) ( 1.34) ( 0.07) Projects returning + ve CBAs 6/10 7/10 8/10 6/10 7/10 8/10 There is one high cost scheme that is causing the both the 132kV replacement and the overall activity level CBA to go negative. We consider that this scheme is technically justified but is sufficiently expensive that the amount of oil leakage would have to be unacceptably high for the CBA to become positive. 4.3 EHV and 132kV Transformers EPN Transformer replacement projects include costs across a number of RIGs s as such works include the replacement of associated switchgear costs and auxiliaries. Table 17 below sets out the costs covered by these assessments. Table 17 EPN 132kV Transformers Replace Total RIGs CV /11kV Transformer (GM) HV % CV kV CB (Air Insulated Busbars)(OD) (GM) EHV % CV kV Transformer (GM) EHV % CV kV OHL (Tower ) Conductor 132kV % CV kV CB (Air Insulated Busbars)(OD) (GM) 132kV % CV kV Switchgear - Other 132kV % CV kV Transformer 132kV % CV6 33 Plinths and Groundworks 132kV % CV6 34 Building 132kV % CV6 35 Enclosures and Surrounds 132kV % CV8 8 Site Security % CV8 13 Earthing Upgrades % CBA Results Page 19

20 Table 18 EPN 33kV Transformers Replace Total RIGs CV /11kV UG Cable HV % CV /11kV Transformer (GM) HV % CV kV UG Cable (Non Pressurised) EHV % CV kV Transformer (GM) EHV % CV6 30 Plinths and Groundworks EHV % CV6 32 Enclosures and Surrounds EHV % CV8 7 Site Security % CV101 7 Secondary network HV to LV CV Primary network (n-1) 132kV to EHV % % Table 19 EPN 132kV Transformers Refurbish Total RIGs CV kV Transformer 132kV % Table 20 EPN 33kV Transformers Refurbish Total RIGs CV kV Transformer (GM) EHV % CBA Outputs Table 21 EPN Transformers CBA Results 12 hours Total 132kV Replacement Total 33kV Replacement ( 2.04) ( 1.19) ( 0.33) Total 132kV Refurbishment Total 33kV Refurbishment Total Projects returning + ve CBAs 25/55 26/55 26/55 28/55 28/55 28/55 Table 22 EPN Transformers CBA Results 24 hours Total 132kV Replacement Total 33kV Replacement Total 132kV Refurbishment CBA Results Page 20

21 Total 33kV Refurbishment Total Projects returning + ve CBAs 31/55 32/55 32/55 32/55 32/55 32/55 Table 23 EPN Transformers CBA Results 48 hours Total 132kV Replacement Total 33kV Replacement Total 132kV Refurbishment Total 33kV Refurbishment Total Projects returning + ve CBAs 35/55 37/55 39/55 37/55 39/55 39/55 The EPN CBA results for our programme are all positive in the 24 and 48 hour scenarios. The strongly positive movements shown in the outage duration sensitivities demonstrate that there is good justification for replacing transformers before the risk of prolonged outages develops. There are still projects that give a negative CBA but these are considered technically justifiable based on the condition of the assets. Our EHV Transformer replacement and refurbishment plan returns a positive benefit to customers and we consider the CBA supports our investment plans LPN Table 24 LPN 132kV Transformers Replace Total RIGs CV /11kV UG Cable HV % CV /11kV Transformer (GM) HV % CV kV Transformer (GM) EHV % CV kV CB (Air Insulated Busbars)(ID) (GM) 132kV % CV kV CB (Air Insulated Busbars)(OD) (GM) 132kV % CV kV Switchgear - Other 132kV % CV kV Transformer 132kV % CV6 33 Plinths and Groundworks 132kV % CV6 34 Building 132kV % CV6 35 Enclosures and Surrounds 132kV % CV kV Substations % CV8 13 Locations % CBA Results Page 21

22 Table 25 LPN 66kV Transformers Replace CV /11kV UG Cable HV % CV /11kV Transformer (GM) HV % CV kV UG Cable (Non Pressurised) EHV % CV kV CB (Air Insulated Busbars)(OD) (GM) EHV % CV kV Transformer (GM) EHV % CV kV Transformer EHV % CV kV CB (Air Insulated Busbars)(OD) (GM) 132kV % CV6 30 Plinths and Groundworks EHV % CV6 31 Building EHV % CV6 32 Enclosures and Surrounds EHV % CV8 7 Site security EHV % CV8 13 Earthing upgrades % CV Primary network (n-1) EHV to EHV CV105 6 Substation RTUs, marshalling kiosks, receivers % % Table 26 LPN 33kV Transformers Replace CV /11kV UG Cable HV % CV /11kV Transformer (GM) HV % CV kV UG Cable (Non Pressurised) EHV % CV kV CB (Air Insulated Busbars)(OD) (GM) EHV % CV kV Transformer (GM) EHV % CV kV UG Cable (Non Pressurised) 132kV % CV kV CB (Air Insulated Busbars)(ID) (GM) 132kV % CV kV CB (Air Insulated Busbars)(OD) (GM) 132kV % CV kV Switchgear - Other 132kV % CV kV Transformer 132kV % CV6 30 Plinths and Groundworks EHV % CV6 32 Enclosures and Surrounds EHV % CV6 33 Plinths and Groundworks 132kV % CV6 34 Building 132kV % CV6 35 Enclosures and Surrounds 132kV % CV8 7 Site security EHV % CV8 8 Site security 132kV % CBA Results Page 22

23 CV8 13 Earthing upgrades % CV Primary network (n-1) 132kV to HV % Table 27 LPN 132kV Transformers Refurbish CV kV Transformer 132kV % Table 28 LPN 66kV Transformers Refurbish CV kV Transformer EHV % CBA Output Table 29 LPN Transformers CBA Results 12 hours Total 132kV Replacement ( 5.94) ( 5.71) ( 5.47) ( 0.43) Total 66kV Replacement ( 4.92) ( 4.79) ( 4.65) ( 4.10) ( 3.92) ( 3.73) Total 33kV Replacement Total 132kV Refurbishment Total 66kV Refurbishment Total Projects returning + ve CBAs 6/22 6/22 6/22 8/22 8/22 9/22 Table 30 LPN Transformers CBA Results 24 hours Total 132kV Replacement ( 3.95) ( 3.49) ( 6.04) Total 66kV Replacement ( 3.78) ( 3.51) ( 3.03) ( 2.53) ( 2.17) ( 1.81) Total 33kV Replacement Total 132kV Refurbishment Total 66kV Refurbishment Total Projects returning + ve CBAs 9/22 9/22 10/22 10/22 11/22 11/22 CBA Results Page 23

24 Table 31 LPN Transformers CBA Results 48 hours Total 132kV Replacement Total 66kV Replacement ( 1.49) ( 0.97) ( 0.45) Total 33kV Replacement Total 132kV Refurbishment Total 66kV Refurbishment Total Projects returning + ve CBAs 12/22 12/22 12/22 12/22 12/22 12/22 The CBA results are positive for our programme over 45 years under all sensitivities. The strongly positive movements shown in the outage duration sensitivities demonstrate that there is good justification for replacing transformers before the risk of prolonged outages develops, even though a number of projects remain slightly negative in this assessment. The individual projects that do not produce a positive CBA are still considered to be valid for asset condition driven replacement based on the condition of the assets with high costs and lower customer numbers driving lower outputs than would be expected given the loading of the assets SPN Table 32 SPN 132kV Transformers Replace CV /11kV UG Cable HV % CV /11kV Transformer (GM) HV % CV kV CB (Air Insulated Busbars)(OD) (GM) EHV % CV kV Transformer (GM) EHV % CV kV OHL (Tower ) Conductor 132kV % CV kV CB (Air Insulated Busbars)(OD) (GM) 132kV % CV kV Switchgear - Other 132kV % CV kV Transformer 132kV % CV6 30 Plinths and Groundworks EHV % CV6 33 Plinths and Groundworks 132kV % CV6 34 Building 132kV % CV6 35 Enclosures and Surrounds 132kV % CV8 7 Site security EHV % CV8 8 Site security 132kV % CV8 13 Earthing upgrades % CBA Results Page 24

25 Table 33 SPN 33kV Transformers Replace CV /11kV UG Cable HV % CV /11kV Transformer (GM) HV % CV kV UG Cable (Non Pressurised) EHV % CV kV Transformer (GM) EHV % CV6 29 Enclosures and Surrounds HV % CV6 30 Plinths and Groundworks EHV % CV6 32 Enclosures and Surrounds EHV % CV8 7 Site security EHV % CV Primary network (n-1) EHV to HV % Table 34 SPN 132kV Transformers Refurbish CV kV Transformer 132kV % Table 35 SPN 33kV Transformers Refurbish CV kV Transformer EHV % CBA Output Table 36 SPN Transformers CBA Results 12 hours Total 132kV Replacement Total 33kV Replacement Total 132kV Refurbishment Total 33kV Refurbishment Total Projects returning + ve CBAs 29/48 29/48 31/48 31/48 31/48 32/48 CBA Results Page 25

26 Table 37 SPN Transformers CBA Results 24 hours Total 132kV Replacement Total 33kV Replacement Total 132kV Refurbishment Total 33kV Refurbishment Total Projects returning + ve CBAs 35/48 35/48 37/48 36/48 37/48 38/48 Table 38 SPN Transformers CBA Results 48 hours Total 132kV Replacement Total 33kV Replacement Total 132kV Refurbishment Total 33kV Refurbishment Total Projects returning + ve CBAs 39/48 39/48 39/48 39/48 39/48 39/48 SPN s transformer replacement/refurbishment programme produces positive CBA results over all sensitivities and all assessment periods. The individual projects that do not produce a positive CBA are still considered to be valid for asset condition driven replacement based on the condition of the assets. The strongly positive movements shown in the outage duration sensitivities demonstrate that there is good justification for replacing transformers before the risk of prolonged outages develops 4.4 EHV Switchgear EPN Table 39 EPN 132kV Switchgear Replace CV kV Transformer (GM) EHV % CV kV UG Cable (Non Pressurised) 132kV % CV kV CB (Air Insulated Busbars)(ID) (GM) CV kV CB (Air Insulated Busbars)(OD) (GM) CV kV CB (Gas Insulated Busbars)(ID) (GM) CV kV CB (Gas Insulated Busbars)(OD) (GM) 132kV % 132kV % 132kV % 132kV % CV kV Switchgear - Other 132kV % CV3 102 Batteries at 132kV Substations 132kV % CBA Results Page 26

27 CV6 33 Plinths and Groundworks 132kV % CV6 34 Building 132kV % CV6 35 Enclosures and Surrounds 132kV % CV8 13 Earthing upgrades % CV105 6 Substation RTUs, marshalling kiosks, receivers % Table 40 EPN 33kV Switchgear Replace CV3 51 Batteries at GM HV Substations HV % CV kV UG Cable (Non Pressurised) EHV % CV kV CB (Air Insulated Busbars)(ID) (GM) CV kV CB (Air Insulated Busbars)(OD) (GM) CV kV CB (Gas Insulated Busbars)(ID) (GM) EHV EHV EHV % % % CV kV Switch (GM) EHV % CV kV Transformer (GM) EHV % CV3 85 Batteries at 33kV Substations EHV % CV3 102 Batteries at 132kV Substations 132kV % CV3 104 Pilot Wire Underground Other % CV6 30 Plinths and Groundworks EHV % CV6 31 Building EHV % CV6 32 Enclosures and Surrounds EHV % CV6 34 Building 132kV % CV6 35 Enclosures and Surrounds 132kV % CV105 6 Substation RTUs, marshalling kiosks, receivers % CBA Results Page 27

28 CBA Output Table 41 EPN EHV Switchgear CBA Results 2 hours Total 132kV Replacement Total 33kV Replacement Total Projects returning + ve CBAs 26/37 27/37 27/37 27/37 27/37 27/37 Table 42 EPN EHV Switchgear CBA Results 12 hours Total 132kV Replacement Total 33kV Replacement Total Projects returning + ve CBAs 31/37 33/37 33/37 32/37 33/37 34/37 The cost benefit assessment for our EPN EHV switchgear replacement provides is highly positive result, providing strong support for our proposed programme of work. The interruption duration sensitivity indicates that this investment should be made to avoid the risk of prolonged outages over 12 hours LPN Table 43 LPN 132kV Switchgear Replace Total RIGs CV kV Transformer (GM) EHV % CV kV UG Cable (Non Pressurised) 132kV % CV kV CB (Air Insulated Busbars)(ID) (GM) 132kV % CV kV CB (Air Insulated Busbars)(OD) (GM) 132kV % CV kV CB (Gas Insulated Busbars)(ID) (GM) 132kV % CV kV Switchgear - Other 132kV % CV3 102 Batteries at 132kV Substations 132kV % CV6 33 Plinths and Groundworks 132kV % CV6 34 Building 132kV % CV6 35 Enclosures and Surrounds 132kV % CV8 13 Earthing upgrades Locations % CBA Results Page 28

29 Table 44 LPN 66kV Switchgear Replace Total RIGs CV kV CB (Air Insulated Busbars)(OD) (GM) EHV % CV kV CB (Gas Insulated Busbars)(ID) (GM) EHV % CV kV Transformer (GM) EHV % CV kV UG Cable (Non Pressurised) 132kV % CV kV CB (Air Insulated Busbars)(OD) (GM) 132kV % CV kV CB (Gas Insulated Busbars)(OD) (GM) 132kV % CV kV Switchgear - Other 132kV % CV3 102 Batteries at 132kV Substations 132kV % CV6 33 Plinths and Groundworks 132kV % CV6 34 Building 132kV % CV6 35 Enclosures and Surrounds 132kV % CV8 13 Earthing upgrades Locations % Table 45 LPN 33kV Switchgear Replace Total RIGs CV kV UG Cable (Non Pressurised) EHV % CV kV CB (Air Insulated Busbars)(OD) (GM) EHV % CV kV Switch (GM) EHV % CV kV Transformer (GM) EHV % CV6 30 Plinths and Groundworks EHV % CBA Output Table 46 LPN EHV Switchgear CBA Results 2 hours Total 132kV Replacement Total 66kV Replacement Total 33kV Replacement Total Projects returning + ve CBAs 6/8 6/8 6/8 6/8 6/8 6/8 CBA Results Page 29

30 Table 47 LPN EHV Switchgear CBA Results 12 hours Total 132kV Replacement Total 66kV Replacement Total 33kV Replacement Total Projects returning + ve CBAs 8/8 8/8 8/8 8/8 8/8 8/8 The cost benefit assessment for LPN EHV switchgear change is positive for all identified projects. Again the interruption duration sensitivities show that the economic benefits of investing to avoid prolonged interruptions to supply are high. CBA Results Page 30

31 4.4.3 SPN Table 48 SPN 132kV Switchgear Replace Total RIGs CV kV Transformer (GM) EHV % CV kV OHL (Tower ) Conductor 132kV % CV kV UG Cable (Non Pressurised) 132kV % CV kV CB (Air Insulated Busbars)(OD) 132kV % CV kV CB (Gas Insulated Busbars)(ID) 132kV % CV kV CB(Gas Insulated Busbars)(OD) 132kV % CV kV Switchgear - Other 132kV % CV3 102 Batteries at 132kV Substations 132kV % CV6 33 Plinths and Groundworks 132kV % CV6 34 Building 132kV % CV6 35 Enclosures and Surrounds 132kV % CV8 13 Earthing upgrades Locations % CV105 6 Substation RTUs, marshalling kiosks,receivers % Table 49 SPN 33kV Switchgear Replace Total RIGs CV kV UG Cable (Non Pressurised) EHV % CV kV CB (Air Insulated Busbars)(ID) (GM) EHV % CV kV CB (Gas Insulated Busbars)(ID) (GM) EHV % CV kV Transformer (GM) EHV % CV3 85 Batteries at 33kV Substations EHV % CV3 104 Pilot Wire Underground Other % CV6 30 Plinths and Groundworks EHV % CV6 31 Building EHV % CV6 32 Enclosures and Surrounds EHV % CV8 7 Site security EHV % CV105 6 Substation RTUs, marshalling kiosks, receivers % Table 50 SPN 33kV Switchgear Refurbish CV kV Transformer (GM) EHV % CV kV CB (GM) EHV % CBA Results Page 31

32 CBA Output Table 51 SPN EHV Switchgear CBA Results 2 hours Total 132kV Replacement Total 33kV Replacement ( 0.11) Total 33kV Refurbishment Total Projects returning + ve CBAs 6/7 7/7 7/7 7/7 7/7 7/7 Table 52 SPN EHV Switchgear CBA Results 12 hours Total 132kV Replacement Total 33kV Replacement Total 33kV Refurbishment Total Projects returning + ve CBAs 7/7 7/7 7/7 7/7 7/7 7/7 The cost benefit analysis for SPN EHV switchgear programme is positive for all identified projects kV Switchgear Replace v Refurbish A replace v refurbish cost benefit assessment has been undertaken considering a known site with 26 11kV circuit breakers. An indicative replacement cost of 0.1m per breaker was assumed against the known cost of refurbishment and ongoing maintenance contract. The CBA considered replacement against a refurbish base and showed that replacement instead of refurbishment would be over 1m negative. Refurbishment is therefore undertaken where technically possible and the fixed portion of the switchgear is in good condition EPN Table 53 EPN 11kV Switchgear Replace CV /11kV UG Cable HV % CV /11kV CB (GM) Primary HV % CV /11kV RMU HV % CV kV Transformer (GM) EHV % CV3 85 Batteries at 33kV Substations EHV % CV6 16 Civil Works At 33kV & 66kV Substations EHV % CBA Results Page 32

33 CV6 30 Plinths and Groundworks EHV % CV6 31 Building EHV % CV8 7 Site security EHV Substations % CV8 13 Earthing upgrades Locations % CV105 6 Substation RTUs, marshalling kiosks, receivers % Table 54 EPN 11kV Switchgear Refurbish CV /11kV CB (GM) Primary HV % CBA Output Table 55 EPN 11kV Switchgear CBA Results 2 hours Total Replacement Total Refurbishment Total Projects returning + ve CBAs 69/91 71/91 71/91 71/91 71/91 79/91 Table 56 EPN 11kV Switchgear CBA Results 6 hours Total Replacement Total Refurbishment Total Projects returning + ve CBAs 86/91 87/91 87/91 86/91 87/91 87/91 Table 57 EPN 11kV Switchgear CBA Results 12 hours Total Replacement Total Refurbishment Total Projects returning + ve CBAs 89/91 89/91 89/91 89/91 89/91 89/91 CBA Results Page 33

34 Both replacement and refurbishment of 11kV switchgear produce positive CBA results under all sensitivities. The sensitivity assessment shows that with longer outage durations more of the projects in the proposed programme of work produce positive results which supports replacement to avoid the risk of prolonged outages over 12 hours resulting from switchgear failure at primary substations LPN Table 58 LPN 11kV Switchgear Replace CV % CV /11kV CB (GM) Primary HV % CV /11kV RMU HV % CV3 51 Batteries at GM HV Substations HV % CV kV Transformer (GM) EHV % CV3 85 Batteries at 33kV Substations EHV % CV6 27 Plinths and Groundworks HV % CV6 28 Building HV % CV6 30 Plinths and Groundworks EHV % CV6 31 Building EHV % CV8 6 Site security HV Substations CV8 7 Site security EHV Substations % % CV8 13 Earthing upgrades Locations % CV105 6 Substation RTUs, marshalling kiosks, receivers % Table 59 LPN 11kV Switchgear Refurbish CV /11kV CB (GM) Primary HV % CBA Results Page 34

35 CBA Output Table 60 LPN 11kV Switchgear CBA Results 2 hours Total Replacement Total Refurbishment Total Projects returning + ve CBAs 17/18 17/18 17/18 17/18 17/18 17/18 Table 61 LPN 11kV Switchgear CBA Results 6 hours Total Replacement Total Refurbishment Total Projects returning + ve CBAs 18/18 18/18 18/18 18/18 18/18 18/18 Table 62 LPN 11kV Switchgear CBA Results 12 hours Total Replacement Total Refurbishment Total Projects returning + ve CBAs 18/18 18/18 18/18 18/18 18/18 18/18 The CBA assessment gives positive results for the 11kV switchgear programme for LPN both for the overall programme and for all projects individually SPN Table 63 SPN 11kV Switchgear Replace CV /11kV UG Cable HV % CV /11kV CB (GM) Primary HV % CV /11kV RMU HV % CV3 51 Batteries at GM HV Substations HV % CV kV Transformer (GM) EHV % CV3 85 Batteries at 33kV Substations EHV % CV6 27 Plinths and Groundworks HV % CBA Results Page 35

36 CV6 28 Building HV % CV6 30 Plinths and Groundworks EHV % CV6 31 Building EHV % CV6 33 Plinths and Groundworks 132kV % CV8 6 Site security HV % CV8 7 Site security EHV % CV8 13 Earthing upgrades Locations % CV101 8 Secondary network HV to HV % CV105 6 Substation RTUs, marshalling kiosks, receivers % Table 64 SPN 11kV Switchgear Refurbish CV /11kV CB (GM) Primary HV % CBA Output Table 65 SPN 11kV Switchgear CBA Results 2 hours Total Replacement Total Refurbishment Total Projects returning + ve CBAs 59/62 59/62 59/62 59/62 59/62 60/62 Table 66 SPN 11kV Switchgear CBA Results 6 hours Total Replacement Total Refurbishment Total Projects returning + ve CBAs 60/62 60/62 61/62 60/62 60/62 61/62 CBA Results Page 36

37 Table 67 SPN 11kV Switchgear CBA Results 12 hours Total Replacement Total Refurbishment Total Projects returning + ve CBAs 62/62 62/62 62/62 62/62 62/62 62/62 The CBA assessment gives strongly positive results for the SPN 11kV switchgear replacement and refurbishment programmes all individual projects provide positive results when considering the impact of longer outages that could result from catastrophic failure. 4.6 Distribution Switchgear The CBA assessment for distribution switchgear implies that replacement should be undertaken as close to the end of the asset life as possible. The 45 year CBA result was considered with a 5 year maximum deferral to ensure costs were fully captured. The CBA results show that with average customers per site the CBA results are more positive the smaller the time between replacement and the end of life. Higher customer number sensitivities indicate that more critical assets are more justifiable to be replaced ahead of failure, as is shown by the increasing (more positive) results with longer deferral. Table 68 Distribution switchgear CBA results 45year CBA Result EPN LPN SPN Option 1 1 year deferral ( ) ( ) ( ) Option 1 (2) 3 year deferral ( ) ( ) ( ) Option 1 (3) 5 year deferral ( ) ( ) ( ) Option 2 (1) Option 2 (2) Option 2 (3) Option 3 (LPN only 1 year deferral (400 customers connected 3 year deferral (400 customers connected) 5 year deferral (400 customers connected) 5 year deferral (900 customers connected) ( ) ( ) ( ) ( ) ( ) These results support the health and criticality model used to select assets for replacement. Replacing poor health assets and focusing on the highest criticality assets, typically those with the highest numbers of customers, provides the most beneficial result to customers. Our investment plans which aim to roughly maintain the current asset condition profile in conjunction with a long term sustainable replacement, will maintain the performance of the network and the safety risk to our staff and the public. We consider that this assessment also supports a similar conclusion for other distribution equipment such as linkboxes and distribution transformers. CBA Results Page 37

38 4.7 Low Carbon Generation The following projects were looked at as potential low carbon generation schemes Table 69 Low carbon generation schemes Scheme Name Estimated Cost ( m) Additional MVA provided (Winter) Annual Low Carbon MWh Trowse Grid 132kV Kings Lynn- Snettisham Kings Lynn- Hempton Kings Lynn South- Dowham Market Walsoken- Downham Market Kings Lynn South- Walsoken Snettisham - Hunstanton Burnham Thorpe Swaffham Hempton Funtham s Lane Chatteris tee point Sall Stody West Beckham Wroxham North Walsham No Wroxham Scottow - North Walsham No Sall Sprowston March Grid New Grid Substation between March and Peterborough Peterborough East The results of the CBAs are shown below, split by sensitivities. The schemes we selected using the upper quartile benefit to cost ratio, as discussed earlier, are highlighted orange above. Table 70 Low Carbon Generation Reinforcement Immediate Utilisation Scheme Name m (16 m (24 m (32 m (45 Benefit /Cost ratio 45 Yrs Trowse Grid 132kV Kings Lynn- Snettisham Kings Lynn- Hempton Kings Lynn South- Dowham Market Walsoken- Downham Market Kings Lynn South- Walsoken Snettisham - Hunstanton Burnham Thorpe Swaffham Hempton Funtham s Lane Chatteris tee point Sall Stody West Beckham CBA Results Page 38

39 Scheme Name m (16 m (24 m (32 m (45 Benefit /Cost ratio 45 Yrs Wroxham North Walsham No Wroxham Scottow - North Walsham No Sall Sprowston March Grid New Grid Substation between March and Peterborough Peterborough East The capacity is not guaranteed to be taken up in one year. We carried out a number of sensitivities looking at different take up rates Scenario 1 Phased Utilisation of Capacity as follows: Year 1 Year 2 Year 3 Year 4 Year % 80.00% % % % Table 71 Low Carbon Generation Reinforcement Phased Utilisation 1 Scheme Name m (16 m (24 m (32 m (45 Benefit /Cost ratio 45 Yrs Trowse Grid 132kV Kings Lynn- Snettisham Kings Lynn- Hempton Kings Lynn South- Dowham Market Walsoken- Downham Market Kings Lynn South- Walsoken Snettisham - Hunstanton Burnham Thorpe Swaffham Hempton Funtham s Lane Chatteris tee point Sall Stody West Beckham Wroxham North Walsham No Wroxham Scottow - North Walsham No Sall Sprowston March Grid New Grid Substation between March and Peterborough Peterborough East CBA Results Page 39

40 Scenario 2 Phased Utilisation of Capacity as follows: Year 1 Year 2 Year 3 Year 4 Year % 50.00% 90.00% % % Table 72 Low Carbon Generation Reinforcement Phased Utilisation 2 Scheme Name m (16 m (24 m (32 m (45 Benefit /Cost ratio 45 Yrs Trowse Grid 132kV Kings Lynn- Snettisham Kings Lynn- Hempton Kings Lynn South- Dowham Market Walsoken- Downham Market Kings Lynn South- Walsoken Snettisham - Hunstanton Burnham Thorpe Swaffham Hempton Funtham s Lane Chatteris tee point Sall Stody West Beckham Wroxham North Walsham No Wroxham Scottow - North Walsham No Sall Sprowston March Grid New Grid Substation between March and Peterborough Peterborough East Scenario 3 Phased Utilisation of Capacity as follows: Year 1 Year 2 Year 3 Year 4 Year % 20.00% 40.00% 60.00% % Table 73 Low Carbon Generation Reinforcement Phased Utilisation 3 Scheme Name m (16 m (24 m (32 m (45 Benefit /Cost ratio 45 Yrs Trowse Grid 132kV Kings Lynn- Snettisham Kings Lynn- Hempton Kings Lynn South- Dowham Market CBA Results Page 40

41 Scheme Name m (16 m (24 m (32 m (45 Benefit /Cost ratio 45 Yrs Walsoken- Downham Market Kings Lynn South- Walsoken Snettisham - Hunstanton Burnham Thorpe Swaffham Hempton Funtham s Lane Chatteris tee point Sall Stody West Beckham Wroxham North Walsham No Wroxham Scottow - North Walsham No Sall Sprowston March Grid New Grid Substation between March and Peterborough Peterborough East Additionally we tested the immediate utilisation against differing amounts of low carbon generation taking up the capacity. Table 74 Low Carbon Generation Reinforcement No Phasing 75% Low Carbon Scheme Name m (16 m (24 m (32 m (45 Benefit /Cost ratio 45 Yrs Trowse Grid 132kV Kings Lynn- Snettisham Kings Lynn- Hempton Kings Lynn South- Dowham Market Walsoken- Downham Market Kings Lynn South- Walsoken Snettisham - Hunstanton Burnham Thorpe Swaffham Hempton Funtham s Lane Chatteris tee point Sall Stody West Beckham Wroxham North Walsham No Wroxham Scottow - North Walsham No Sall Sprowston March Grid New Grid Substation between March and Peterborough Peterborough East CBA Results Page 41

42 Table 75 Low Carbon Generation Reinforcement No Phasing 50% Low Carbon Scheme Name m (16 m (24 m (32 m (45 Benefit /Cost ratio 45 Yrs Trowse Grid 132kV Kings Lynn- Snettisham Kings Lynn- Hempton Kings Lynn South- Dowham Market Walsoken- Downham Market Kings Lynn South- Walsoken Snettisham - Hunstanton Burnham Thorpe Swaffham Hempton Funtham s Lane Chatteris tee point Sall Stody West Beckham Wroxham North Walsham No Wroxham Scottow - North Walsham No Sall Sprowston March Grid New Grid Substation between March and Peterborough Peterborough East All the scenarios produced positive costs benefit assessments. As we do not expect all generation projects to progress we have used the benefit to cost ratio to select the projects included in our proposals. Projects above the upper quartile benefit/cost ratio have been included in our proposals. The four schemes represent 56% of potential identified capacity, and 34% of identified potential expenditure. 4.8 Losses Table 76 Loss Reduction Strategy Loss Reduction 8 years 16 years 24 years 32 years 45 years Documented losses strategy Our proposed loss reduction measures are forecast to bring benefits of over 45m during the RIIO- ED1 period. The CBA testing the effects of the new EU directive, requiring new standards for losses in distribution transformers, found that, for 1000kVA transformers to be considered a justifiable expenditure, they need to be within 25% (based on 100kVA transformer) of the current cost of a new transformer. Our current 500kVA transformer specification already provides for low losses until the more stringent EU standards are available at reasonable costs. 4.9 Smart Grid Solutions Below are all of the results for each of the proposed Smart Grid solutions Demand Side Response The same assumptions have been tested for EPN and SPN considering the deferral of reinforcement by 2MVA of demand side response (DSR). CBA Results Page 42

43 Table 77 EPN and SPN Demand Side Response Option/Sensitivity m (16 m (24 m (32 m (45 Base Scenario- 3m reinforcement MVA of DSR allow deferment of 3m reinforcement for 3 years MVA of DSR allow deferment of 1m reinforcement for 3 years MVA of DSR allow deferment of 0.5m reinforcement for 6 years Demand side response can be seen to be beneficial 2MVA of DSR defers more than 1 million of reinforcement investment for 3 or more years. Table 78 LPN Demand Side Response Option/Sensitivity m (16 m (24 m (32 m (45 Base Scenario- 5m reinforcement MVA of DSR allow deferment of 5m reinforcement for 4 years MVA of DSR allow deferment of 13.1 reinforcement for 4 years In LPN our DSR assessment has considered that a larger amount of DSR would have to be procured to defer investment, but that this would defer a higher value of investment. This indicated that 5MVA of DSR deferring 5m for 4 years would provide a positive cost benefit Partial Discharge testing Table 79 Smart Solutions Partial Discharge Testing Option/Sensitivity m (16 m (24 m (32 m (45 Base Scenario-30 sites equipped defers investment of 35% of sites (11 sites / 11m) by 5 years 11m cost split equally between the last 5 years of the ED1 period OPEX Incurred up to the last replacement (beyond ED1) 30 sites equipped defers investment of 50% of sites (15 sites / 18m) by 5 years 15m cost split equally between the last 5 years of the ED1 period OPEX Incurred up to the last replacement (beyond ED1) 30 sites equipped defers investment of 60% of sites (18 sites / 18m) by 5 years 18m cost split equally between the last 5 years of the ED1 period OPEX Incurred up to the last replacement (beyond ED1) The analysis shows that the additional installation and opex costs are outweighed by the benefits of deferring the replacement of switchgear. CBA Results Page 43

44 4.9.3 OHL Ratings Table 80 Smart Solutions 132kV Overhead Ratings Option/Sensitivity m (16 m (24 m (32 m (45 Base Scenario- 6.36m Reinforcement Defer reinforcement for 8 years Defer reinforcement for 4 years Defer reinforcement for 2 years Table 81 Smart Solutions 33kV Overhead Ratings Option/Sensitivity m (16 m (24 m (32 m (45 Base Scenario- 2.7m Reinforcement Defer reinforcement for 3 years The scenarios indicate that providing deferral is greater than 3 years, the employment of OHL rating equipment is justified Real Time Transformer Ratings Table 82 Smart Solutions Real Time Transformer Ratings Option/Sensitivity m (16 m (24 m (32 m (45 Base Scenario- 1.5m Reinforcement RTTR on two transformers at 70k per transformer allow 1.5m deferment for 3 years Installing equipment to allow real time transformer ratings is beneficial if reinforcement can be deferred for 3 years Quality of Supply Table 83 Quality of Supply Option/Sensitivity m (16 m (24 m (32 m (45 EPN Improvement Schemes LPN Improvement Schemes SPN Improvement Schemes All QoS related schemes provide positive benefits. CBA Results Page 44

45 4.11 High Value Projects Table 84 Eltham Sydenham Gas Cable Replacement High value Project Option/Sensitivity m (16 m (24 m (32 m (45 Base Scenario-Reinforce in ED1 at cost 26.36m Defer 5 years - impact of failure rota disconnections for repair time Defer 5 years - restoration in 4 days using generation - on for 6 week repair time at 3.1m Deferral of the High Value Project at Eltham/Sydenham into the RIIO-ED2 period generates a negative CBA result, demonstrating the project should go ahead within ED1. CBA Results Page 45

46 5 Conclusions At an activity-level, we are confident that the cost benefit assessments we have conducted support that our current investment plans provide value for money to our customers. 5.1 Asset Replacement In carrying out assessments of the actual projects that our asset replacement intervention strategies have identified, we have demonstrated that our intervention strategies produce robust investment plans which provide positive benefits for customers and maintain the condition of the distribution networks. The results of the sensitivities around duration of interruption strongly support investing to avoid the potentially long outages that can occur should there be the failure of multiple items of equipment at higher voltages. We have demonstrated that refurbishment offers benefits over replacement where it is technically feasible. 5.2 Reinforcement for low carbon generation We have used CBA to justify investment in EPN of 15.4m which will increase network capacity by 187MVA. 5.3 Loss Reduction We have used CBA to value the impact of our loss reduction initiative and identify the tipping point for investing in low loss transformers ahead of any limits being imposed by EU directives. 5.4 Smart Grid Solutions We have used CBA to test the parameters we have used to assess the impact smart technologies will have on our investment plans. These support using Demand side response to defer investment. Separate parameters have been defined around 2MVA in deferring reinforcement for at least 3 years in EPN and SPN and 5MVA of DSR deferring reinforcement for 4 years in LPN. Partial Discharge testing provides benefits in deferring switchgear replacement Smart adaptation of overhead ratings will allow reinforcement to be managed more effectively Equipment to allow real time transformer rating provides benefits in allowing capacity increases to be deferred. These technologies will allow our investment plans to be better optimised and uncertainties better managed. 5.5 Quality of Supply We have demonstrated that our proposed additional investments in quality of supply provide substantial benefits to customers. 5.6 High Value Projects We have demonstrated that the replacement of gas filled cables between Sydenham and Eltham in south east London should be carried out in RIIO-ED1 rather than being deferred until RIIO-ED2. Conclusions Page 46

47 5.7 Summary The table below summarises the results where CBA assessment has been used to justify specific investment kv EPN LPN SPN FFC Replacement Transformer Replacement Transformer Refurbish Switchgear Replacement Switchgear Refurbish QoS High Value Projects Key CBA results positive Partial support No projects Conclusions Page 47

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