Network Topology Project

Network Topology Project

Predrag Djapic and Goran Strbac

December 2019

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Executive Summary Penetration of Low Carbon Technologies (LCT) including electrification of transport and heat energy sectors, will play a major role in the development of future load in terms of peak load growth and shape of load profiles and will drive load related asset upgrades. In addition, ageing assets, reaching the end of their useful life, will drive increased volumes of condition-based asset replacement. These developments create an opportunity for the development of loss-inclusive long-term strategic design of distribution networks, which is the focus of this project. Specific objectives of the project are:

• To provide quantitative evidence to inform the development of long-term loss-minimisation strategies;

• Quantify and analyse the cost and efficiency gains related to the replacement of traditional transformers with low-loss units;

• Quantify and analyse the impact of voltage rationalisation and propose a prioritised schedule of potential upgrade projects;

• Quantify costs and benefits of upgrading HV assets to 11 kV or 20 kV, respectively; • Quantify the impact of deployment of LCTs on network losses, and • Inform the extent to which network losses could be influenced given the current indexed

valuation of £60 per MWh.

The holistic impact, consisting of different loss reduction strategies, is presented in this report. The summary of key observations is provided below. Provided benefit is based on £60/MWh but this could change depending on the future mix of generation.

Many grid and primary transformers currently in operation were installed in the 1960’s. We anticipate that these units will be replaced with new transformers conforming to the EU 2021 specification (or better), resulting in improved energy efficiency.

Our analysis of grid and primary transformers’ load profiles resulted in the discovery of a strong statistical relationship between load factors and load loss factors. This discovery enabled us to calculate annual losses without requiring a detailed load profile in each case. Many observed load loss factors for primary and grid transformers were between 27% and 44%. The average load loss factor is about 36% .

We have carried out a study to demonstrate how DNOs can minimise energy losses in transformers by selecting optimised transformer ratings during transformer replacement. This work required an understanding of load growth, load factors and the forecast number or years’ cyclic load growth (loading might reduce if a new substation is commissioned nearby). The observed range of peak utilisation for transformers is between 22-66% and widely speaking, greater peak utilisation in the year of commissioning is associated with:

- a lower load growth rate;

- a lower load loss factor;

- fewer years of cyclic load growth, and

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- linear load growth (as opposed to compound load growth).

It is observed for different scenarios of load growth that the average annual savings in grid and primary transformer losses is equivalent to about 1.3 GWh/a for each unit replaced. Replacement of 20 to 45 grid and primary transformers per year results in losses savings between £1.6-3.5m each year. The cost of bringing forward grid and primary transformer investment, at a WACC of 4.1%, for one year, is between £35 and £75k while the average savings from loss reduction, in this case, is about £78k. The business case for early replacement of transformers is hence very strong and should be conducted in more detail on a case-by-case basis. The residual value of transformers rendered redundant is not considered.

In the case of distribution transformers, similar to grid and primary transformers, a strong statistical relationship exists between load factors and load loss factors. Observed load loss factors range between 15% and 40%.

For the assumed load loss factor of 27%, distribution transformer losses will increase from about 1100 GWh/a in 2019 to between 1240 and 1370 GWh/a in 2032, dependent on the considered scenario. Due to the improved design of distribution transformers, the increase in losses will be lower than the relative load growth. The average energy loss improvement per replaced secondary transformer is about 15 MWh/a, assuming a load loss factor of 27%. Measured at £60/MWh, this improvement amounts to £900/a. Over 60 years, these savings add up to circa £23.6k per transformer. Considering that the cost of a one-year deferral of investment for distribution transformers is between £180 and £600; a business case for early investment could be very strong. The residual value of redundant transformers was not considered.

For ground mounted distribution transformers, the economically efficient initial-year peak utilisation ranges from 20% to 64%. For pole mounted distribution transformers, it is between 12% and 100% in the case of cold rolled grain oriented (CRGO) steel. This level changes to between 4% and 44% for amorphous steel units.

If all secondary transformers are replaced with new low-loss units, the overall distribution transformer losses could be reduced by about 50%.

We considered two propositions to quantify the benefit of shifting load peaks. In the first scenario, we assumed that daily load peaks could be reduced by 5% by shifting peak load to off peak periods. We increased this number to 10% in the second scenario. The observed increase in load loss factors, on average, is about 10% and 21% for peak reductions of 5% and 10% respectively. Given that peak is reduced, and hence peak losses are also reduced, the overall losses reduction will be about 1 and 2% for peak shifts of 5% and 10% respectively.

We found that these two scenarios led to loss reductions in LV & HV networks and distribution transformers of up to 45 and 105 GWh/a respectively in the 2019 in Centralised scenario. However, losses could increase by about 120 and 190 GWh/a respectively by 2032 in the Smart scenario given the same peak shifts. The increase in losses is expected given that asset utilisation is intensified, and savings might be achieved through investment deferrals. Any policy of incentivising losses reduction should consider that losses might increase due to application of low carbon technologies.

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We further estimated energy savings for all 33 kV conductors upgraded to 132 kV, assuming that conductors’ resistances remain unaltered in the process. The savings are between 220 and 395 GWh/a. The total length of existing 33 kV circuits is 10,750 km. Average savings per km is between 20 and 37 MWh/a.km, which is valued at £1,200-2,200/a.km at £60/MWh. Considering the removal of 132/33 kV transformation, the overall energy loss reduction associated with upgrading all 33kV circuits to 132 kV is between 520 and 820 GWh/a. The average monetary value of these savings is between £31 and £49m per annum.

Deferring 33kV to 132kV network upgrades by one year is valued between £35 and £47k. In addition, if all HV networks are upgraded to 20 kV, the overall loss reduction is between 900 and 1600 GWh/a, valued between £54 and £96m/a; assuming the cost of losses is £60/MWh. We ranked grid sites and networks by their potential for losses reduction. The Sall Grid 33kV site and its supplied 33 kV network have the greatest potential for losses reduction, which amounts to about 16.7 GWh/a. The monetary value of losses reduction is about £1m per annum. A detailed business case for each identified grid site is recommended to establish whether early conversion is economically justifiable.

Upgrading legacy 6.6 kV circuits to 11 kV could save up to 32/MWh/a per km of circuit, which is equivalent to £1,900/a.km. Upgrading all HV circuits to 20 kV could save between £23 and £44m/a when valued at £60/MWh. This equates to, on average, between £375 and 725/a per km for 6.6 and 11 kV circuits combined.

Table 1 shows the potential ranges of losses reduction for different strategies. These ranges were obtained through the use of different load growth scenarios. The first four approaches follow asset replacement due to load growth. For the last three approaches, we assumed that all relevant assets are replaced in year zero.

TABLE 1. POTENTIAL LOSSES REDUCTION OF DIFFERENT LOSS REDUCTION APPROACHES

Loss reduction approach Overall losses reduction from 2019-2032,

GWh Primary and grid transformer replacement 1,560 – 3,520 Distribution transformer replacement 270 – 501 Low carbon technologies 5% peak reduction (-725) – (-65) Low carbon technologies 10% peak reduction (-786) – 540 Voltage rationalisation 132/11/0.4 kV 8,560 – 9,530 Upgrade of legacy circuits to 11 kV 394 – 441 Upgrade of HV networks to 20 kV 6,209 – 7,678

Primary and grid transformer replacement shows the highest losses reduction potential amongst the first four interventions. If low carbon technologies to enable peak shifting are implemented, losses would potentially increase due to monetary savings achieved from deferring network upgrades. The resistance of assets that are not upgraded due to flexibility will be greater than the resistance of those upgraded amidst flexibility. The increase of losses in assets not upgraded counteract the losses decrease due to flexibility.

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Significant losses reduction could be achieved if networks are upgraded to direct 132/11 kV transformation and/or HV networks are upgraded to 20 kV. However, the enabling cost due to large numbers of assets involved could be prohibitive, and the approach could be beneficial only for some specific sections of the network.

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Contents Executive Summary ................................................................................................................... 2

1 Introduction ......................................................................................................................... 8

2 Data availability and data gap analysis ..............................................................................10

2.1 Network loading ..........................................................................................................10

2.2 Upgrade costs .............................................................................................................11

2.3 Asset parameters and network design paradigm ........................................................12

3 Energy savings obtainable from replacing grid and primary transformers with low-loss units 13

3.1 Primary and grid transformers statistics ......................................................................13

3.2 Case studies ...............................................................................................................16

3.3 Cost - benefit analysis .................................................................................................19

4 Energy savings obtainable from replacing distribution transformers with low-loss units......21

4.1 Distribution transformers statistics ..............................................................................21

4.2 Transformer peak utilisation and load loss factors ......................................................24

4.3 Case studies ...............................................................................................................26

4.4 Cost - Benefit Analysis ................................................................................................30

4.4.1 Ground mounted distribution transformers ...........................................................30

4.4.2 Pole mounted distribution transformers (CRGO) ..................................................31

4.4.3 Amorphous steel pole mounted distribution transformers .....................................33

4.5 Total replacement .......................................................................................................35

5 Potential impact of low carbon technologies on network losses .........................................36

6 Business case for voltage rationalisation driven by losses .................................................42

7 Cost - benefit analysis for upgrading legacy networks operating below 11kV to 11kV ........47

8 Cost-benefit analysis of upgrading HV networks to 20kV ...................................................52

9 Network losses per voltage level ........................................................................................55

10 Conclusions .......................................................................................................................59

10.1 Primary and grid substation transformers ....................................................................59

10.2 Distribution transformers .............................................................................................59

10.3 The impact of flexible loads .........................................................................................60

10.4 EHV voltage rationalisation .........................................................................................60

10.5 The value of upgrading legacy networks .....................................................................61

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11 Appendix A: ESRI Shapefiles .............................................................................................62

12 Appendix B: DINIS EDF files ..............................................................................................63

13 Appendix C: CIM files.........................................................................................................64

14 Appendix D: Microsoft Office Assess (.mdb) file .................................................................65

15 Appendix E: PowerFactory DSG files .................................................................................66

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1 Introduction The Losses Discretionary Reword (LDR) Tranche 1 project was aimed at understanding losses, benchmarking, best practice and reducing losses. The penetration of Low Carbon Technologies (LCTs), including the electrification of transport and heat energy sectors, will play a major role in the development of future load in terms of peak load growth and the shape of load profiles, and this will drive load related asset upgrades. In addition, ageing assets, reaching the end of their useful life, will drive increased volumes of condition-based asset replacements. These developments create an opportunity to shape loss-inclusive long-term strategic designs for distribution networks, which was the main focus of this project.

The potential benefits related to implementing some of the findings in UK Power Networks’ (UKPN) published benchmarking & best practice report for energy losses in electrical networks was considered. The results of this project will be used to support the preparation of UKPN’s LDR Tranche 3 submission and to inform the development of suitable loss-based strategies for ED2.

Our analysis was performed in two stages. The first stage considered the impact of end-of-life transformer replacements on losses. We used Eco2021 specifications for primary and grid transformers in all regions and amorphous steel distribution transformer specifications in EPN and SPN. In LPN, distribution transformers will be replaced with Eco2021 units due to concerns about spatial constraints.

In the second stage, the impact of LCT uptake was considered and scenarios defining the LCT uptake were agreed with UKPN. Using the Load Related Expenditure model, the schedule of minimum reinforcement upgrade was established.

The specific objectives of the project were:

• To provide quantitative evidence to inform the development of long-term loss-minimisation strategies;

• Quantify and analyse the cost and efficiency gains related to the replacement of traditional transformers with low-loss units;

• Quantify and analyse the impact of voltage rationalisation and propose a prioritised schedule of potential upgrade projects;

• Quantify costs and benefits related to upgrading HV assets to 11 kV or 20 kV, respectively; • Quantify the impact of LCT deployment on network losses • Inform the extent to which network losses could be influenced given the current indexed

valuation of £60 per MWh.

The rest of this report is organised in sections as follows:

• Section 2 describes the available data and results of data gap analysis; • Section 3 describes energy savings obtainable from grid and primary transformer

replacements. The economically efficient break-even peak utilisation in the year of transformer installation is established. This break-even analysis considers the cost of different transformer sizes and energy losses related to different load parameters;

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• Section 4 describes the energy savings obtainable from distribution transformer replacement using Eco2021 ground mounted units and amorphous steel pole mounted transformers. In the same fashion as grid and primary transformers, the economic break-even peak utilisation is established for different load related parameters;

• Section 5 shows the potential impact of low carbon technologies on network losses; • Section 6 describes the potential benefit of voltage level rationalisation and ranks 33 kV

networks; • In Section, 7 legacy HV networks are ranked by potential losses savings when upgraded to

11 kV; in section 8, HV networks are ranked by potential losses savings if upgraded to 20 kV;

• Section 9 provides an overview of losses in various voltage levels; • Section 10 contains our conclusions and section 11 provides references followed by

Appendices in subsequent Sections.

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2 Data availability and data gap analysis The Imperial team has been working on different projects with UK Power Networks (UKPN). From these previous projects, we had access to network connectivity, asset parameters and network loading. UK Power networks made further information available as needed. Data gap analysis was conducted to establish further requirements.

2.1 Network loading Present network loads have been derived from MPAN data, maximum demand indicator data, HV feeder loads and Planning Load Estimates (PLEs). Future loads were deduced from present load levels and load growth based on Element Energy (EE) scenarios.

From MPAN data, customers were classified into four types: domestic unrestricted, domestic multi-tariff, non-domestic unrestricted and non-domestic multi-tariff. Typical customer peak demands and coincidence factors were derived from maximum demand indicator data by minimising discrepancies between maximum demand indicators and the calculated maximum demand for each distribution transformer. Typical customer peak demands were used for secondary transformers where maximum demand indicator data were unavailable. Customer density was derived from MPAN data, see Figure 1. Customer densities were used to establish load types (rural to urban).

FIGURE 1. UKPN CUSTOMER DENSITY CALCULATED FROM MPAN DATA

Five recent Element Energy (EE) scenarios1, with different EV uptake rates, covering the time horizon to 2032 are shown in Table 2. The EV deployment rates in this table (low, medium and

1 From Recharge the Future project.

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high) correspond to the three levels of ambition set out in the Government’s Road to Zero2 strategy. The distribution across charging types determine the view on the horizontal axis in table 5 (i.e. centralised or decentralised). A centralised view assumes that a highly accessible public rapid charging network is available for electric vehicles (EVs).

Each scenario further accounts for domestic, industrial and commercial customers, EVs, heat pumps (HPs) and installed solar (PV) power. This information has been made available for successive years. In addition, winter and summer peak day profiles were specified for different types of customers and devices at distribution and primary substation levels for each year.

TABLE 2. SIMPLIFIED OVERVIEW OF THE FIVE EV SCENARIOS. SOURCE: RECHARGE THE FUTURE PROJECT

EV deployment rates Distribution across charging types Decentralised (default) Centralised charging

Low Business as Usual

Medium Medium Ambition

High High Ambition – Unmanaged High Ambition – Smart High Ambition - Centralised

The EV deployment rates, Low, Medium and High, correspond to the ambitions to see 30%, 50% and 70% of new car sales to be ultra-low emission cars by 2030, respectively.

PLEs provided by UKPN corresponded to EE scenarios, even though they covered the time horizon to 2030 only. These PLEs provide primary and grid substation firm capacity, maximum loading and load factors for future years.

Maximum demand indicator data were provided for some ground mounted distribution transformers. Annual profiles for some primary and grid substations were also provided and these were used to establish typical annual load duration curves, load factors and load loss factor ranges.

2.2 Upgrade costs Asset upgrade cost data were provided for overhead lines, underground cables, transformers and switchgear. The standard social preference time rate specified in the Green Book3 was used to obtain the capitalisation factor. The time horizon for the analysis was agreed with UKPN on a task-by-task basis. Given the assumed 604 years of transformer life, it is expected that the time horizon may be up to 2050 and beyond.

2 Department for Transport, The Road to Zero, 2018, https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/739460/road-to-zero.pdf 3 See page 104 in this location: https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/685903/The_Green_Book.pdf 4 See pp. 103 to 105 in this location: https://www.ofgem.gov.uk/system/files/docs/2017/05/dno_common_network_asset_indices_methodology_v1.1.pdf

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Energy losses were valued at £48.42 per MWh (in 2012-13 prices; source Ofgem) for the purposes of this study.

2.3 Asset parameters and network design paradigm The following key documents were made available by UKPN: • EDS 08-1105 Guidance for the Application of ENA EREC P2 Security of Supply • EDS 08-4000 EHV Network Design • EDS 08-0150 London 33kv Distribution Network Design and Customer Supplies • EDS 08-3000 HV Network Design • EDS 08-3001 HV Network Remote Control and Monitoring • EDS 08-2000 LV Network Design • EDS 08-1110 Fault Levels • EDS 08-5010 Energy Storage • EDS 08-0115 Loading of Secondary Distribution Transformers • EDS 04-8000 Grid Transformers • EDS 02-0034 33KV Single Core XLPE Cables • EDS 02-0033 LV Waveform Mains Cable Ratings • EDS 01-0045 Overhead Line Ratings • EDS 02-0027 11KV Triplex Cable Rating • EDS 02-0040 Current Ratings Guide of Distribution Cables • EDS 02-0027 11KV Triplex Cable

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3 Energy savings obtainable from replacing grid and primary transformers with low-loss units

This section examines the energy loss benefits obtainable from replacing primary and grid transformers with new low-loss units. Transformers’ commissioning dates were used to estimate replacement years for existing primary and grid transformers. We further assumed that primary and grid transformers will be replaced with Eco 2021 specification units in the future.

New transformers’ ratings were based on the assumption that new units should be adequately rated for at least 10 years’ service before additional network upgrades are needed. UKPN provided transformer loss characteristics for existing transformers to facilitate the study.

Present maximum demands for primary and grid sites were obtained from Planning Load Estimates (PLEs). Future loads for primary and GSP sites were based on PLE scenarios.

Available primary- and grid-transformer load profiles were used to derive load loss factors. Based on projected future load loss factors, the annual losses for each transformer were assessed. Loss improvements were based on the counterfactual, i.e. the losses that would occur if transformers are not replaced. We quantified the benefit of improved transformer specifications on the basis of the present valuation of energy losses.

3.1 Primary and grid transformers statistics Figure 2 shows on the year of manufacture for 2,264 grid and primary transformers. Most transformers were installed in 1960’s.

FIGURE 2. YEAR OR MANUFACTURE OF PRIMARY AND GRID TRANSFORMERS

UKPN provided a set of 53 annual half-hourly primary and grid transformer load profiles along with transformer loss specifications for the typical new units that they procure. The load profiles were recorded at 16 sites.

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Figure 3 shows a strong level of correlation between load factors and load loss factors for the load profiles that were provided to us. The regressed formula is as follows:

𝐿𝐿𝐿𝐿𝐿𝐿 = 0.94328727 ⋅ LF1.79100480. (1)

Load factors could be calculated from annual energy, E, and peak demand, Pm, as follows:

𝐿𝐿𝐿𝐿 = 𝐸𝐸8760⋅𝑃𝑃𝑚𝑚

(2)

The strong Pearson Coefficient (R2) in the graph below enabled us to use only a few well-known parameters to calculate LLFs.

FIGURE 3. CORRELATION BETWEEN LOAD LOSS FACTOR AND LOAD FACTOR FOR DIFFERENT PRIMARY (BLUE SQUARES) AND GRID (RED CIRCLES) DEMAND PROFILES

The majority of load factors for primary and grid transformers is between 0.5 and 0.65, and we generally observed larger load factors for grid transformers. For this range, the load loss factor is between 0.27 and 0.44. The stated strong correlation between load factors and load loss factors enables accurate estimation of losses from the annual energy transferred and the annual peak demand only.

The overall transformer losses could be calculated as:

𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿 = (𝑃𝑃0 + 𝑃𝑃𝑐𝑐0) ⋅ 𝑇𝑇 ⋅ 𝑌𝑌 + 𝑃𝑃𝑘𝑘 ⋅ �𝑆𝑆𝑚𝑚𝑚𝑚𝑚𝑚𝑆𝑆𝑟𝑟

�2⋅ 𝐿𝐿𝐿𝐿𝐿𝐿 ⋅ 𝑇𝑇 ⋅ ∑ 𝐿𝐿𝑦𝑦2𝑌𝑌

𝑦𝑦=1 (3)

Where 𝑃𝑃0 is no load losses, 𝑃𝑃𝑐𝑐0 is ventilation (cooling) losses, 𝐿𝐿𝐿𝐿𝐿𝐿 is load loss factor, 𝑇𝑇 is 8760 hours, 𝑌𝑌 is the number of years of load growth until the relevant network upgrade, LG is annual peak load growth rate, Y is the number of years of load growth, 𝑆𝑆𝑚𝑚𝑚𝑚𝑚𝑚 is apparent peak demand and 𝐿𝐿𝑦𝑦 is peak load multiplier in year 𝑦𝑦.

y = 0.9433x1.791

R² = 0.9977

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The four rightmost columns in Table 3 below show the recommended maximum peak utilisation for grid and primary transformers in the year of installation. Load loss factors, load growth rates and the number of years before upgrade are considered in this table. The term ‘constant demand, PEI’ represents demand for which the PEI is obtained i.e. demand for which no-load losses are equal to load losses.

TABLE 3. TRANSFORMER MAXIMUM PEAK UTILISATION DURING THE YEAR OF INSTALLATION ASSUMING LINEAR LOAD GROWTH

Linear load growth rate

Load loss factor

Number of years

Primary, 33/11 kV, 7.5 MVA

Primary, 33/11 kV, 12-20 MVA

Primary, 132/11 kV

Grid, 132/33 kV

Constant demand, PEI 46% 32%-36% 26%-28% 24%-27% 0% 27% 1 21% 62% 50% 66% 0% 44% 1 17% 48% 39% 52%

0.5% 27% 10 21% 60% 49% 64% 0.5% 27% 25 20% 58% 48% 62% 0.5% 27% 50 19% 55% 45% 59% 0.5% 44% 10 16% 47% 39% 50% 0.5% 44% 25 16% 45% 37% 49% 0.5% 44% 50 15% 43% 35% 46% 1% 27% 10 21% 59% 48% 63% 1% 27% 25 19% 55% 45% 59% 1% 27% 50 17% 49% 40% 52% 1% 44% 10 16% 46% 38% 49% 1% 44% 25 15% 43% 35% 46% 1% 44% 50 13% 38% 31% 41% 2% 27% 10 20% 57% 46% 60% 2% 27% 25 17% 49% 40% 53% 2% 27% 50 13% 40% 33% 43% 2% 44% 10 15% 44% 36% 47% 2% 44% 25 13% 38% 31% 41% 2% 44% 50 11% 31% 26% 34%

For grid transformers, the PEI is obtained at loading between 24 and 28%. For primary transformers, the figure is between 32 and 46%. These values are calculated using only particular transformer type parameters as received from UKPN. The Eco directive specifies the PEIs which transformer needs to achieve. This might be achieved through a different composition of load and no-load losses which could result in different loading at which PEI is achieved. The rest of values in this table were calculated by comparing overall losses to the next (bigger) transformer, see equation (3). Except for 7.5 MVA primary transformers, the economically efficient initial-year peak-loading, at which overall annual losses are minimal, is greater than constant load at which the PEI is achieved. For 7 MVA primary transformers it is the opposite, which indicates that a different balance of load and no-load losses exists that will minimise losses.

The initial peak utilisation is greater for lower load growth rates, lower load loss factors and lower number of years’ load growth, and vice versa.

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TABLE 4. TRANSFORMER MAXIMUM PEAK UTILISATION DURING THE YEAR OF INSTALLATION ASSUMING COMPOUND LOAD GROWTH

Compound load growth

rate Load loss

factor Number of years



Main, 132/11 kV

Grid, 132/33 kV


0.5% 27% 10 21% 60% 49% 64% 0.5% 27% 25 20% 58% 47% 62% 0.5% 27% 50 19% 54% 44% 58% 0.5% 44% 10 16% 47% 39% 50% 0.5% 44% 25 16% 45% 37% 48% 0.5% 44% 50 15% 43% 35% 45% 1% 27% 10 21% 59% 48% 63% 1% 27% 25 19% 54% 45% 58% 1% 27% 50 16% 47% 39% 51% 1% 44% 10 16% 46% 38% 49% 1% 44% 25 15% 43% 35% 45% 1% 44% 50 12% 37% 30% 40% 2% 27% 10 20% 56% 46% 60% 2% 27% 25 16% 48% 39% 51% 2% 27% 50 12% 34% 29% 37% 2% 44% 10 15% 43% 36% 47% 2% 44% 25 12% 37% 30% 40% 2% 44% 50 8% 27% 22% 29%

3.2 Case studies Figure 4 shows normalised PLEs for different load growth scenarios. PLEs for all years are summed and divided by sum of PLEs in the base year to obtain PLE growth rates. Five scenarios are considered: BaU, Medium Ambition and High Ambition (Centralised, Managed and Unmanaged). In addition, two trend lines depicting compounded growth rates of 1% and 2% are presented. For reference, the Core 3 scenario is provided which is the central scenario from 2012.

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FIGURE 4. SUM OF PLES GROWTH FOR DIFFERENT SCENARIOS FROM 2019 TO 2032

Figure 5 shows the energy loss savings obtainable from replacing grid and primary transformers with more efficient Eco specification units. The assumed load loss factors for primary and grid transformers are 35% and 40%, respectively. By 2032, predicted losses savings are between 330 and 760 GWh/a, dependent on the load growth scenario.

FIGURE 5. ANNUAL LOSSES SAVINGS DUE TO PRIMARY AND GRID TRANSFORMER REPLACEMENT IN DIFFERENT SCENARIOS ASSUMING LOAD LOSS FACTORS OF 35% AND 40% FOR PRIMARY AND GRID TRANSFORMERS RESPECTIVELY.

Figure 6 shows the cumulative number of primary and grid transformer replacements required to accommodate different load growth scenarios. By 2032, between 260 and 585 primary and grid transformers may require upgrading.

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FIGURE 6. NUMBER OF REPLACED PRIMARY AND GRID TRANSFORMERS FOR DIFFERENT SCENARIOS

Figure 7 shows the average annual energy loss improvements achievable from individual grid and primary transformer replacements. The average savings will be about 1.3 GWh/a for each unit by the year 2032. The average value energy saved in this manner amounts to £78k/a per transformer in the year of replacement when valued at £60 per MWh.

FIGURE 7. AVERAGE ANNUAL LOSSES SAVINGS PER REPLACED GRID AND PRIMARY TRANSFORMER

Replacing 20 to 45 transformers per year on average yields energy loss reductions of £1.6 to 3.5m per year due to improved specifications.

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3.3 Cost - benefit analysis Figure 8 illustrates the methodology used for cost – benefit analysis in this study. The figure shows the annual cost of losses for two differently rated grid transformers. The cost of losses (on the y-axis) is depicted as a function of peak demand in the initial year on the x-axis.

The compounded annual load growth is 1% in ten-year cycles in this instance, assuming that the load loss factor is 0.27. The combined costs of transformer replacement and energy losses over 50-years are presented by the two lines. The blue line represents the overall cost for a 40 MVA grid transformer, while red line depicts cost for a 60 MVA unit.

In summary, the graph shows that the 40 MVA unit is less expensive for lower initial load levels, while the 60 MVA unit costs less for larger initial loads. The break-even cost occurs where the peak load in the year of installation is 26.2 MVA. If the peak load in the year of installation is greater than 65% (i.e. 26 MVA), the installation of bigger transformer (of 60 MVA) is cost effective.

FIGURE 8. MAXIMUM ECONOMICALLY EFFICIENT PEAK OF GRID TRANSFORMER

We repeated this approach for different rates of load growth, load loss factors and number of years’ of cyclic load growth. After the stated period of time, we assume that a new substation is established to transfer load away. Table 5 shows the maximum recommended utilisation for primary and grid transformers in the year of commissioning. Above these points, we recommend that larger transformers be installed (assuming linear load growth).

TABLE 5. INITIAL PEAK UTILISATION OF PRIMARY AND GRID TRANSFORMERS FOR DIFFERENT LOAD GROWTH RATES, LOAD LOSS FACTORS AND NUMBER OF YEARS OF CYCLIC LOAD GROWTH, ASSUMING LINEAR LOAD GROWTH

Load growth rate

Load loss factor

Number of years



Main, 132/11 kV

Grid, 132/33 kV


0

20

40

60

80

100

120

140

0 10 20 30 40 50 60

Cos

t (£m

)

Peak in year of installation (MVA)

132/33kV 40MVA

132/33kV 60MVA

20

Load growth rate

Load loss factor

Number of years



Main, 132/11 kV

Grid, 132/33 kV

0.5% 27% 10 20% 61% 51% 66% 0.5% 27% 25 19% 59% 49% 64% 0.5% 27% 50 17% 56% 46% 60% 0.5% 44% 10 15% 48% 40% 52% 0.5% 44% 25 15% 46% 38% 50% 0.5% 44% 50 13% 43% 36% 47% 1% 27% 10 20% 60% 50% 65% 1% 27% 25 19% 56% 46% 60% 1% 27% 50 16% 50% 41% 54% 1% 44% 10 15% 47% 39% 51% 1% 44% 25 13% 43% 36% 47% 1% 44% 50 12% 38% 32% 42% 2% 27% 10 19% 58% 48% 62% 2% 27% 25 16% 50% 42% 54% 2% 27% 50 13% 41% 34% 44% 2% 44% 10 15% 44% 37% 49% 2% 44% 25 12% 38% 32% 42% 2% 44% 50 9% 32% 27% 35%

Table 10 is the same at table 9, except that we assumed composite load growth in this instance:

TABLE 6. INITIAL PEAK UTILISATION OF PRIMARY AND GRID TRANSFORMERS FOR DIFFERENT LOAD GROWTH RATE, LOAD LOSS FACTOR AND NUMBER OF YEARS OF CYCLIC LOAD GROWTH, ASSUMING COMPOUNDED LOAD GROWTH

Load growth rate

Load loss factor

Number of years



Main, 132/11 kV

Grid, 132/33 kV


0.5% 27% 10 20% 61% 51% 66% 0.5% 27% 25 19% 59% 49% 64% 0.5% 27% 50 17% 55% 46% 60% 0.5% 44% 10 15% 48% 40% 52% 0.5% 44% 25 15% 46% 38% 50% 0.5% 44% 50 13% 43% 36% 47% 1% 27% 10 20% 60% 50% 65% 1% 27% 25 17% 55% 46% 60% 1% 27% 50 15% 48% 40% 52% 1% 44% 10 15% 47% 39% 51% 1% 44% 25 13% 43% 36% 47% 1% 44% 50 12% 38% 31% 41% 2% 27% 10 19% 57% 47% 62% 2% 27% 25 16% 48% 40% 52% 2% 27% 50 11% 35% 29% 38% 2% 44% 10 15% 44% 37% 48% 2% 44% 25 12% 38% 31% 41% 2% 44% 50 8% 28% 23% 30%

The results above show that there are synergies between minimised losses and minimum overall costs. The lower recommended peak utilisation in the year of commissioning is driven by greater load growth rates, greater load loss factors, and longer load growth cycles.

21

4 Energy savings obtainable from replacing distribution transformers with low-loss units

In this task, we quantify the energy savings obtainable from replacing existing secondary transformers with more efficient units. The modelling is similar to the technique presented in section 3. The present maximum demand for each distribution site and the load growth were used to quantify peak load increases.

The annual load growth for distribution transformers was based on agreed EE scenarios. The transformers’ commissioning dates were used to determine replacement timing (once they reach 60 years of age). Due to amorphous steel units being larger, Eco 2021 specification losses were used in LPN, while amorphous steel units’ specifications were used in EPN & SPN.

We determined new transformers’ sizes by allowing sufficient spare capacity to accommodate ten years’ load growth. Known distribution transformer load profiles were used to calculate load loss factors. Based on projected future load loss factors, the annual losses for each transformer were assessed. We estimated losses improvements by comparing results to counterfactual results, i.e. if transformers were not replaced. Using the present value of losses5, the potential benefits of losses reduction is quantified.

4.1 Distribution transformers statistics Figure 9 shows distribution transformers’ year of manufacture. The graph is based on 117,584 distribution transformers. In the 1960’s, a lot of transformers were installed; these units are approaching (estimated) useful life.

FIGURE 9. YEAR OR MANUFACTURE OF DISTRIBUTION TRANSFORMERS

5 Present value of losses of £60/MWh is calculated by RPI indexing Ofgem’s value of £48.42/MWh.

0

0.005

0.01

0.015

0.02

0.025

0.03

0.035

0.04

1920 1940 1960 1980 2000 2020

Prob

abilit

y

22

Table 7 below shows a collection of distribution transformer loss parameters. These losses are dependent on the year of manufacture. Typically, rated load and especially no-load transformer losses are reduced over the time. This is illustrated in Figure 10 for two typical ground mounted transformer units rated 500 and 1000 kVA. Comparing the Pre-55 unit to the Eco 2021 unit reveals that their overall rated losses are reduced by about 45%. In the same period the rated no-load losses were reduced about 75%.

TABLE 7. DISTRIBUTION TRANSFORMER LOSS PARAMETERS

Phases Type Rating Pre-55 1971 1979 1984 ECO 2015 EU2021 Cu Fe Cu Fe Cu Fe Cu Fe Cu Fe Cu Fe

1 PMT 5 175 65 175 65 175 65 175 65 175 65 10 310 90 310 90 310 90 310 90 310 90 15 430 115 445 55 445 55 450 50 450 50 16 860 230 445 55 445 55 450 50 450 50 25 640 160 615 75 615 75 620 80 620 80 50 1,070 250 1,070 130 1,070 130 1,080 130 1,080 130 100 1,800 450 1,800 280 1,800 280 1,800 280 1,800 280 GMT 100 2,000 450 2,000 280 2,000 280 2,000 230 1,500 150

2 PMT 16 445 55 445 55 450 50 450 50 50 1,070 250 1,070 130 1,070 130 1,080 130 1,080 130

3 PMT 25 700 170 700 170 700 105 700 110 900 70 725 70 50 1,180 265 1,180 165 1,180 165 1,180 160 1,100 90 875 90 100 2,000 450 2,000 280 2,000 280 2,000 230 1,750 145 1,475 145 200 3,400 755 3,400 480 3,400 380 2,760 290 2,750 356 2,333 310 GMT 100 2,000 450 2,000 280 2,000 280 2,000 230 1,750 145 1,250 130 200 3,400 755 3,400 480 3,400 380 2,760 290 2,750 250 2,017 225 300 4,800 1,115 4,800 700 4,800 480 3,990 410 3,750 346 2,696 312 315 4,800 1,115 4,800 700 4,800 480 3,990 410 3,900 360 2,800 324 500 6,860 1,670 6,860 1,030 6,860 700 6,500 620 5,500 510 3,900 459 750 9,500 2,300 10,000 1,500 10,000 1,500 10,000 950 7,841 635 5,588 572 800 9,500 2,300 10,000 1,500 10,000 1,500 10,000 950 8,400 650 6,000 585 1,000 11,820 2,875 11,800 1,770 11,500 1,750 11,500 1,250 10,500 770 7,600 693

23

FIGURE 10. DISTRIBUTION TRANSFORMER LOSS PARAMETERS FOR 500 KVA (LEFT) AND 1000 KVA

Table 8 shows loss specifications for pole mounted amorphous steel units and Eco 2021 cold rolled steel grain oriented (CRGO) steel distribution transformers. Comparatively, the rated no-load losses are reduced by 60-80%.

TABLE 8. AMORPHOUS STEEL AND CRGO TRANSFORMER LOSSES; NLL: NO-LOAD LOSSES, LL: LOAD LOSSES

Rating, kVA

Phases count

Voltage, kV

Eco 2021 CRGO transformer

Amorphous Transformer

NLL LL NLL LL NLL reduction

Breakeven utilisation

25 1 11/0.25 70 725 15 900 -79% 56%

50 1 11/0.25 90 875 22 1100 -76% 55%

50 1 11/0.25-0-0.25

90 875 22 1100 -76% 55%

100 1 11/0.25-0-0.25

145 1475 38 1750 -74% 62%

100 3 11/0.43 145 1475 53 1750 -63% 58%

200 3 11/0.43 310 2333 90 2750 -71% 73%

Breakeven utilisation represents constant load at which point Eco 2021 CRGO and Amorphous steel pole mounted transformers have the same losses.

0

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Load losses No load losses

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)

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24

4.2 Transformer peak utilisation and load loss factors Figure 11 and Figure 12 below show the distribution of peak transformer loads in 2019, based on the EE scenarios used.

FIGURE 11. DISTRIBUTION OF 2019 PEAK UTILISATION OF DISTRIBUTION TRANSFORMERS, NUMBER

FIGURE 12. DISTRIBUTION OF 2019 PEAK UTILISATION OF DISTRIBUTION TRANSFORMERS, PERCENTAGE

The LPN region contains a smaller proportion of transformers utilised in the range between 5% and 50%. At the same time, more transformers in this region are utilised above 50% compared to EPN and SPN.

0

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12000

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16000

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0% 20% 40% 60% 80% 100% 120% 140% 160%

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f tra

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s

Peak utilisation, %

UKPN

EPN

LPN

SPN

0%

5%

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15%

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0% 20% 40% 60% 80% 100% 120% 140% 160%

Prop

ortio

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mer

s, %

Peak utilisation, %

UKPN

EPN

LPN

SPN

25

Figure 13 shows the regressed relationship between distribution transformers’ load factors and load loss factors. This relationship is based on 17 recorded profiles. The depicted load loss factors are between 15% and 40% with an average value of 27%. A high level of correlation is observed between load loss factor and load factors. The regression line is expressed in equation (4):

𝐿𝐿𝐿𝐿𝐿𝐿 = 0.814 ⋅ LF1.5428. (4)

FIGURE 13. CORRELATION BETWEEN LOAD LOSS FACTOR AND LOAD FACTOR

Figure 14 shows peak demand in relation to load factor.

FIGURE 14. PEAK DEMAND FOR DIFFERENT LOAD FACTOR; SITE REFERENCE IS SHOWN AS DATA LABEL

A weak correlation between transformers’ load factors and peak loads was observed.

y = 0.814x1.5428

R² = 0.9455

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

30% 35% 40% 45% 50% 55% 60% 65%

Load

loss

fact

or

Load factor

LLF

90044

90862

90638 8050

30257

6243

91045

6601

30027

6552

30055

8507

94192

90069

90043

8150

8151

0

100

200

300

400

500

600

30% 35% 40% 45% 50% 55% 60% 65%

Peak

, kVA

Load factor

Peak, kVA

26

4.3 Case studies Figure 15 shows the overall estimated distribution transformer load growth from 2019 to 2032. The load growth, dependent on the scenario selected, is between 30% and 60% by the year 2032.

FIGURE 15. OVERALL DISTRIBUTION SITE LOAD GROWTH

Load growth is the lowest for the BaU scenario; the Unmanaged scenario produces the highest. For the remaining three scenarios load growth is similar.

Figure 16 shows the estimated annual number of distribution transformer replacements required, dependent on the scenario selected. The trend indicates that the number of required replacements is expected to increase year-on-year. The BaU scenario resulted in the lowest number of transformers replacements, roughly 400 by 2030. In the Unmanaged scenario, the number of distribution transformer replacements reaches about 1,150 in 2032.

100%

110%

120%

130%

140%

150%

160%

2018 2020 2022 2024 2026 2028 2030 2032

Ove

rall

Dis

tribu

tion

Site

Loa

d G

row

th, p

.u.

BaU

Medium Ambition

Unmanaged

Smart

Centralised

27

FIGURE 16. NUMBER OF DISTRIBUTION TRANSFORMERS REPLACED DUE TO LOAD INCREASE ASSOCIATED WITH DIFFERENT LOAD GROWTH SCENARIOS

Figure 17 shows expected distribution transformer losses if existing transformers are not replaced by more efficient units. The assumed load loss factor was 27% in this instance. The graph shows that losses will increase from about 1100 GWh/a in 2019 to between 1300 and 1500 GWh/a in 2032, dependent on the scenario used.

FIGURE 17. DISTRIBUTION TRANSFORMER LOSSES DEVELOPMENT WITHOUT TRANSFORMER REPLACEMENT FOR DIFFERENT SCENARIOS, ASSUMING A LOAD LOSS FACTOR OF 27%

0

200

400

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1,000

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2018 2020 2022 2024 2026 2028 2030 2032

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ber o

f upg

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s pe

r yea

r

BaU

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2018 2020 2022 2024 2026 2028 2030 2032

Cou

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BaU

Medium Ambition

Unmanaged

Smart

Centralised

28

Figure 18 shows projected distribution transformer losses, assuming that old distribution transformers are replaced using newer specification units as per the schedule shown in Figure 16. The assumed load loss factor is 27%. The losses will increase from about 1100 GWh/a in 2019 to between 1240 and 1370 GWh/a in 2032, dependent on the scenario. Due to the improved design of distribution transformers, the increase in losses will be lower than the relative load growth.

FIGURE 18. DISTRIBUTION TRANSFORMER LOSSES DEVELOPMENT WITH TRANSFORMER REPLACEMENT FOR DIFFERENT SCENARIOS ASSUMING A LOAD LOSS FACTOR OF 27%

Figure 19 shows expected distribution transformer energy loss reductions for different scenarios assuming a load loss factor of 27%. The anticipated savings ranges between 50 and 150 GWh/a by 2032. Cumulative loss reductions over the analysed period are between 270 and 500 GWh.

1,100

1,150

1,200

1,250

1,300

1,350

1,400

1,450

1,500

1,550

2018 2020 2022 2024 2026 2028 2030 2032

Loss

es, G

Wh/

a

BaU

Medium Ambition

Unmanaged

Smart

Centralised

29

FIGURE 19. DISTRIBUTION TRANSFORMER LOSSES SAVINGS FOR DIFFERENT SCENARIOS ASSUMING LOAD LOSS FACTOR OF 27%

Figure 20 shows the average annual losses savings achieved per transformer replaced.

FIGURE 20. AVERAGE LOSSES SAVINGS PER REPLACED DISTRIBUTION TRANSFORMER ASSUMING LOAD LOSS FACTOR OF 27%

The average reduction in losses per replaced transformer is about 15 MWh/a, assuming that the load loss factor is 27%. At £60/MWh, the average annual value of reduced losses is £900. Over a 60-year period the potential savings reaches about £23.6k per transformer.

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BaU Medium Ambition

Unmanaged Smart

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30

4.4 Cost - Benefit Analysis 4.4.1 Ground mounted distribution transformers The approach illustrated in Section 3.3 is applied to ground mounted Eco 2021 specification CRGO distribution transformers in this section. Table 9 (below) shows the break-even initial peak utilisation for ground mounted transformers in the year of commissioning.

TABLE 9. INITIAL PEAK UTILISATION OF GROUND MOUNTED DISTRIBUTION TRANSFORMERS FOR DIFFERENT LOAD GROWTH RATES, LOAD LOSS FACTORS AND LOAD GROWTH PERIODS, ASSUMING LINEAR LOAD GROWTH

Load growth rate

Load loss factor

Number of years

Distribution transformer rating

100 kVA 200 kVA 315 kVA 500 kVA 800 kVA

0% 30% 1 64% 61% 60% 53% 57% 0% 50% 1 49% 47% 46% 41% 44%

0.5% 30% 10 63% 60% 59% 52% 56% 0.5% 30% 30 60% 57% 56% 49% 53% 0.5% 30% 60 56% 53% 52% 46% 50% 0.5% 50% 10 48% 46% 45% 40% 43% 0.5% 50% 30 46% 44% 43% 38% 41% 0.5% 50% 60 43% 41% 40% 35% 38% 1% 30% 10 61% 58% 57% 50% 55% 1% 30% 30 56% 53% 52% 46% 50% 1% 30% 60 49% 47% 46% 40% 44% 1% 50% 10 47% 45% 44% 39% 42% 1% 50% 30 43% 41% 40% 35% 38% 1% 50% 60 37% 36% 36% 31% 34% 2% 30% 10 59% 56% 55% 48% 52% 2% 30% 30 49% 47% 46% 40% 44% 2% 30% 60 39% 37% 37% 32% 35% 2% 50% 10 45% 43% 43% 37% 40% 2% 50% 30 37% 36% 36% 31% 34% 2% 50% 60 30% 29% 28% 25% 27%

Similarly, Table 10 shows initial peak utilisation of ground mounted Eco 2021 specification CRGO transformers assuming compounded load growth.

31

TABLE 10. INITIAL PEAK UTILISATION OF GROUND MOUNTED DISTRIBUTION TRANSFORMERS FOR DIFFERENT LOAD GROWTH RATE, LOAD LOSS FACTOR AND NUMBER OF YEARS OF CYCLIC LOAD GROWTH ASSUMING COMPOUNDED LOAD GROWTH

Load growth rate

Load loss factor

Number of years


100 kVA 200 kVA 315 kVA 500 kVA 800 kVA

0% 30% 1 64% 61% 60% 53% 57% 0% 50% 1 49% 47% 46% 41% 44%

0.5% 30% 10 63% 60% 59% 52% 56% 0.5% 30% 30 60% 57% 56% 49% 53% 0.5% 30% 60 55% 52% 51% 45% 49% 0.5% 50% 10 48% 46% 45% 40% 43% 0.5% 50% 30 46% 44% 43% 38% 41% 0.5% 50% 60 42% 40% 40% 35% 38% 1% 30% 10 61% 58% 57% 50% 55% 1% 30% 30 55% 52% 52% 45% 49% 1% 30% 60 46% 44% 43% 38% 41% 1% 50% 10 47% 45% 44% 39% 42% 1% 50% 30 42% 40% 40% 35% 38% 1% 50% 60 35% 34% 34% 29% 32% 2% 30% 10 58% 56% 55% 48% 52% 2% 30% 30 46% 44% 44% 38% 42% 2% 30% 60 31% 30% 30% 26% 28% 2% 50% 10 45% 43% 42% 37% 40% 2% 50% 30 36% 34% 34% 30% 32% 2% 50% 60 24% 23% 23% 20% 22%

The recommended initial peak utilisation ranges from 22% to 64%. The recommended initial peak utilisation is particularly efficient for loads characterised by significant load growth, substantial load loss factors and extended periods of load growth.

4.4.2 Pole mounted distribution transformers (CRGO) Table 12 shows the maximum recommended (break-even) initial peak utilisation for pole mounted distribution transformers, assuming linear load growth. The Eco 2021 CRGO specification is used in the calculation as shown in Table 11.

TABLE 11. ECO 2021 LOSSES PARAMETERS FOR CRGO POLE MOUNTED TRANSFORMERS

Parameter Distribution transformer rating

25 kVA 50 kVA 100 kVA 200 kVA

No-load losses 70 90 145 310 Load losses 725 875 1475 2333

32

TABLE 12. INITIAL PEAK UTILISATION OF POLE MOUNTED DISTRIBUTION TRANSFORMERS FOR DIFFERENT LOAD GROWTH RATE, LOAD LOSS FACTOR AND NUMBER OF YEARS OF CYCLIC LOAD GROWTH ASSUMING LINEAR LOAD GROWTH

Load growth rate

Load loss factor

Number of years


25 kVA 50 kVA 100 kVA

0% 10% 1 60% 100% 100% 0% 40% 1 28% 50% 67%

0.5% 10% 10 60% 100% 100% 0.5% 10% 30 56% 96% 100% 0.5% 10% 60 52% 90% 100% 0.5% 40% 10 28% 50% 65% 0.5% 40% 30 24% 46% 62% 0.5% 40% 60 24% 44% 58% 1% 10% 10 56% 100% 100% 1% 10% 30 52% 90% 100% 1% 10% 60 44% 78% 100% 1% 40% 10 24% 48% 64% 1% 40% 30 24% 44% 58% 1% 40% 60 20% 38% 51% 2% 10% 10 52% 94% 100% 2% 10% 30 44% 78% 100% 2% 10% 60 36% 62% 82% 2% 40% 10 24% 46% 61% 2% 40% 30 20% 38% 51% 2% 40% 60 16% 30% 40%

Table 13 shows the maximum recommended (i.e. break – even) initial peak loading of pole mounted distribution transformers considering compounded load growth.

TABLE 13. INITIAL PEAK UTILISATION OF POLE MOUNTED DISTRIBUTION TRANSFORMERS FOR DIFFERENT LOAD GROWTH RATE, LOAD LOSS FACTOR AND NUMBER OF YEARS OF CYCLIC LOAD GROWTH ASSUMING COMPOUND LOAD GROWTH

Load growth rate

Load loss factor

Number of years



0% 10% 1 60% 100% 100% 0% 40% 1 28% 50% 67%

0.5% 10% 10 60% 100% 100% 0.5% 10% 30 56% 96% 100% 0.5% 10% 60 52% 88% 100% 0.5% 40% 10 28% 50% 65% 0.5% 40% 30 24% 46% 62% 0.5% 40% 60 24% 42% 57%

33

Load growth rate

Load loss factor

Number of years


25 kVA 50 kVA 100 kVA 1% 10% 10 56% 100% 100% 1% 10% 30 52% 88% 100% 1% 10% 60 40% 74% 98% 1% 40% 10 24% 48% 64% 1% 40% 30 24% 42% 57% 1% 40% 60 16% 36% 48% 2% 10% 10 52% 94% 100% 2% 10% 30 40% 74% 98% 2% 10% 60 28% 50% 67% 2% 40% 10 24% 46% 61% 2% 40% 30 16% 36% 48% 2% 40% 60 12% 24% 33%

The observed initial peak utilisation ranges from 12% to 100%. Similar to previous results, the recommended initial peak utilisation is particularly efficient for loads characterised by significant load growth, substantial load loss factors and extended periods of load growth.

4.4.3 Amorphous steel pole mounted distribution transformers Table 14 shows the break - even initial peak utilisation of amorphous pole mounted distribution transformers assuming linear load growth.

TABLE 14. INITIAL PEAK UTILISATION OF AMORPHOUS POLE MOUNTED DISTRIBUTION TRANSFORMERS FOR DIFFERENT LOAD GROWTH RATES, LOAD LOSS FACTORS AND NUMBER OF YEARS’ CYCLIC LOAD GROWTH, ASSUMING LINEAR LOAD GROWTH

Load growth rate

Load loss factor

Number of years



0% 10% 1 16% 44% 37% 0% 40% 1 12% 34% 28%

0.5% 10% 10 16% 44% 36% 0.5% 10% 30 16% 40% 34% 0.5% 10% 60 16% 38% 32% 0.5% 40% 10 12% 32% 27% 0.5% 40% 30 12% 32% 26% 0.5% 40% 60 12% 28% 24% 1% 10% 10 16% 42% 35% 1% 10% 30 16% 38% 32% 1% 10% 60 12% 34% 28% 1% 40% 10 12% 32% 27% 1% 40% 30 12% 28% 24%

34

Load growth rate

Load loss factor

Number of years


25 kVA 50 kVA 100 kVA 1% 40% 60 8% 24% 21% 2% 10% 10 16% 40% 33% 2% 10% 30 12% 34% 28% 2% 10% 60 8% 26% 22% 2% 40% 10 12% 30% 25% 2% 40% 30 8% 24% 21% 2% 40% 60 4% 20% 17%

Table 15 shows the recommended maximum (break – even) initial peak loading of amorphous steel pole mounted distribution transformers assuming compounded load growth

TABLE 15. INITIAL PEAK UTILISATION OF AMORPHOUS POLE MOUNTED DISTRIBUTION TRANSFORMERS FOR DIFFERENT LOAD GROWTH RATES, LOAD LOSS FACTORS AND NUMBER OF YEARS’ CYCLIC LOAD GROWTH, ASSUMING COMPOUNDED LOAD GROWTH

Load growth rate

Load loss factor

Number of years



0% 10% 1 16% 44% 37% 0% 40% 1 12% 34% 28%

0.5% 10% 10 16% 44% 36% 0.5% 10% 30 16% 40% 34% 0.5% 10% 60 16% 38% 31% 0.5% 40% 10 12% 32% 27% 0.5% 40% 30 12% 30% 26% 0.5% 40% 60 8% 28% 24% 1% 10% 10 16% 42% 35% 1% 10% 30 16% 38% 31% 1% 10% 60 12% 32% 26% 1% 40% 10 12% 32% 27% 1% 40% 30 8% 28% 24% 1% 40% 60 8% 24% 20% 2% 10% 10 16% 40% 33% 2% 10% 30 12% 32% 26% 2% 10% 60 4% 20% 17% 2% 40% 10 12% 30% 25% 2% 40% 30 8% 24% 20% 2% 40% 60 4% 16% 13%

35

The recommended initial peak utilisation ranges from 4% to 44% in this instance. Due to lower no-load losses in amorphous core transformers, the economically efficient initial peak utilisation levels are significantly lowered to reduce transformer load losses (i.e. variable losses).

4.5 Total replacement In order to estimate the total potential for energy savings, we simulated a situation where all transformers were replaced at once at the start. Amorphous steel transformers are bigger and heavier than the CRGO transformers used to date. Due to this reason, we introduced the following assumptions to facilitate this study:

- UKPN can adopt amorphous steel pole mounted transformers in EPN and SPN;

- they can adopt amorphous steel ground mounted transformers in EPN and SPN, and

- due to spatial limitations, only Eco 2021 (CRGO) specification ground mounted transformers will be used in LPN.

We have determined that following this approach would reduce total transformer losses by about 50% compared to the counterfactual. This is illustrated in Figure 21, which shows savings in losses using a load loss factor of 27%. For clarity, losses savings are about 50% of the losses shown in Figure 17.

FIGURE 21. DEVELOPMENT OF DISTRIBUTION TRANSFORMER LOSSES IF ALL TRANSFORMERS ARE REPLACED IN 2019 WITH LOW LOSSES DESIGN ASSUMING LOAD LOSS FACTOR OF 27%

The potential losses savings ranges between 550 and 775 GWh/a. At £60/MWh, the value of savings is between £33 and 46.5m/a once all distribution transformers are replaced.

500

550

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800

2018 2020 2022 2024 2026 2028 2030 2032

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es s

avin

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Unmanaged Smart

Centralised

36

5 Potential impact of low carbon technologies on network losses

For the purposes of the analysis shown in this section, we made the following assumptions:

- All grid and primary transformers are replaced by Eco 2021 specification units, and

- all secondary transformers are either Eco 2021 specification or amorphous steel units as discussed in section 3.5 prior.

Next, we superimposed the expected LCT uptake onto this network. Using the LRE model, we quantified network losses for different LCT scenarios and compared results against the counterfactual scenario.

Our analysis of distribution site profiles shows that load loss factors will increase on average by 10% (9.1-10.5%) and 21% (16.8-22.6%) respectively, compared to values shown in Figure 13, if 5% and 10% of daily peak load is shifted to off peak periods.

Figure 22 shows LV losses in cables and overhead conductors only for different scenarios without flexibility applied. The range of losses, dependent on the year and chosen scenario, ranges between 1,200 and 1,880 GWh per annum.

Figure 22. UKPN LV network losses for different scenarios without flexibility applied

The unmanaged scenario will lead to more intense asset utilisation overall. Such an increase in asset utilisation, in turn, will drive more extensive network strengthening activities.

Energy losses will increase with increased EV penetration as depicted in the Unmanaged scenario. If EV charging is controlled, LV losses could be reduced to below the BaU scenario after 2029.

800

1,000

1,200

1,400

1,600

1,800

2,000

2018 2020 2022 2024 2026 2028 2030 2032

Loss

es, G

Wh/

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BaUMedium AmbitionUnmanagedSmartCentralised

37

Figure 23 shows the development of LV losses for different scenarios with 5% flexibility applied. In this scenario, we assumed that, for each day of the year, the peak load could be reduced by 5% through the use of network flexibility. The range of losses, dependent on year and scenario, is between 1,140 and 1,930 GWh per annum.

FIGURE 23. UKPN LV NETWORK LOSSES FOR DIFFERENT SCENARIOS WITH 5% FLEXIBILITY APPLIED

Figure 24 shows the development of LV losses for different scenarios with 10% flexibility applied. The range of losses, dependent on the year and scenario, is between 1,080 and1,900 GWh/a.

FIGURE 24. UKPN LV NETWORK LOSSES FOR DIFFERENT SCENARIOS WITH 10% FLEXIBILITY APPLIED

Figure 25 shows LV loss reduction for different scenarios assuming that 5% flexibility can be applied. The range of savings, dependent on the year and scenario, is up to 40 GWh/a across all

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three DNOs (i.e. EPN, LPN and SPN) and reduces over time. The potential value of savings is up to £2.4m/a. Reduction of losses savings is attributable to a lower cost of network upgrade.

We assume that network flexibility will enable DNOs to defer network upgrades. Deferring network upgrades means that smaller cross-sectional conductors will remain in service for longer. The continued use of these smaller conductors leads to losses increase when load increase due to LCT uptake. For increased EV uptake i.e. from 30% (in BaU scenario) to 70% (in Unmanaged scenario), the savings in losses will reduce and losses will increase to about 45 GWh/a in 2032, valued at £2.7m/a.

FIGURE 25. UKPN LV NETWORK LOSSES SAVINGS FOR DIFFERENT SCENARIOS WITH 5% FLEXIBILITY APPLIED

Figure 26 shows LV loss reduction for different scenarios assuming that 10% flexibility can be applied. The range of savings, dependent on the year and scenario, is up to 105 GWh/a valued at £6.3m/a. Similar to the case with 5% flexibility applied, losses savings decrease over time. In the Unmanaged scenario, this decrease could amount to -70 GWh/a in 2032.

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FIGURE 26. UKPN LV NETWORK LOSSES SAVINGS FOR DIFFERENT SCENARIOS WITH 10% FLEXIBILITY APPLIED

Driven by low carbon considerations, DNOs have begun to install more efficient equipment. The widespread adoption of more efficient equipment reduces loss improvements obtainable from the use of flexibility as shown in Figure 26 above.

Figure 27 shows potential energy savings in distribution transformers that could be achieved if daily peak, throughout the year, is reduced by 5 and 10% and energy shifted to off peak periods, respectively. All transformers are Eco 2021 specification units to avoid the potential for double counting.

FIGURE 27. UKPN DISTRIBUTION TRANSFORMERS (ECO DESIGN) LOSSES SAVINGS FOR DIFFERENT SCENARIOS AND FOR 5% (LEFT) AND 10% FLEXIBILITY

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It is expected that losses will increase by 10 to 19 GWh/a if flexibility is between 5 and10%. Due to the introduction of network flexiblity, DNOs will replace fewer transformers in the first year, which increases losses. The increase in losses will reduce over time, the reverse effect compared to the trend in LV networks. Observed losses reduction is the smallest in the Unmanaged scenario due to greater levels of asset upgrade.

Figure 28 shows the losses savings in HV networks for different scenarios and two levels of flexibility.

FIGURE 28. UKPN HV NETWORK LOSSES SAVINGS FOR DIFFERENT SCENARIOS AND FOR 5% (LEFT) AND 10% FLEXIBILITY

Due to the introduction of network flexibility, DNOs will replace fewer HV circuits in the first year, which increases losses. Losses savings are practically only observed in the Unmanaged scenario in the case of 10% flexibility being introduced. The value is about £40 MWh/a in 2032. It is observed in the Smart scenario that losses will increase due to deferral of network investment. Consideration should be taken when designing Smart schemes to minimise or reverse such effects.

Figure 29 shows the overall UKPN LV, Distribution Transformer and HV network savings.

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FIGURE 29. UKPN LV, DT AND HV NETWORK SAVINGS FOR DIFFERENT SCENARIOS AND FOR 5% (LEFT) AND 10% FLEXIBILITY

We found that our two scenarios yielded loss reductions in LV, HV networks and distribution transformers combined. This reduction is up to 45 and 105 GWh/a in 2019 in Centralised scenario, associated with peak reductions of 5% and 10% respectively. However, losses could increase by about 120 and 190 GWh/a in 2032 in Smart scenario for peak reductions of 5% and 10%, respectively. Due to the introduction of network flexibility, DNOs will defer more and more upgrades of network circuits from year-to-year. This increases losses, and at one point, the increase in losses due to network circuit upgrade deferral will outweigh the decrease in losses due to the introduction of flexibility.

Similar to network flexibility, it is expected that widespread smart meter adoption will reduce total energy consumption by circa 2.8%. This reduction in energy consumption could reduce technical losses by about 5.5%.

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6 Business case for voltage rationalisation driven by losses Network design strategies are evolving, and they are greatly influenced by customer distribution, economics, geographical layout and load density. Moreover, different countries adopted different network designs and planning philosophies, such as a four versus three voltage level design, and 11kV voltage levels versus 20kV etc.

The question arises as to what the optimal voltages and number of voltage transformation stages should be for specific load characteristics and future considerations. Apart from this question, the optimal number of substations, the types and ratings of circuits and transformers used, network losses and reliability performance are important considerations.

In this work, we consider the cost-benefit case for strategic change in the design of future distribution networks, taking specifically into account network losses rather than using a like-for-like asset replacement philosophy. This task, hence, focuses on the assessment of alternative distribution network design strategies to drive voltage level rationalisation where feasible.

For this part of the study, we analysed distribution networks from rural to urban, seeking to inform UKPN’s network reinforcement and replacements. We consider load growth driven by the penetration of different low carbon technologies, seeking to minimise energy losses.

Specifically, this analysis involves a comparison between four- and three-voltage level network designs such as, but not limited to, 132/33/11/0.4 kV and 132/11/0.4 kV approaches. In addition, we assessed the optimal number of transformers in substations as well as single to three-phase network upgrades. This modelling provides evidence to inform future network design that would help to reduce network losses from the present level of 7-9% to an ambitious level of 4-6%.

Utilising existing dual primary winding transformers and 11kV compatible cables on 6.6kV networks along with load related expenditure forecasts, we quantified the impact of like-for-like HV and EHV network upgrades. Next, we assessed opportunities to install higher voltage assets and investigated the impact that this would make on energy losses. We took into account incremental costs and carried out cost-benefit assessments to understand the value inherent to alternative voltage rationalisation propositions.

To assess the value of upgrading 33 kV circuits to 132 kV, 132/33 kV transformation stages were considered obsolete. Thus, to facilitate the study, 33/11 kV transformers were theoretically upgraded to three winding 132/11/11 kV or two winding 132/11 kV transformers.

Figure 30 shows variable losses occurring in 33 kV circuits. These losses amount to circa 235 GWh/a in 2019 and they increase to 325-420 GWh/a in 2032, assuming an average load loss factor of 36%.

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FIGURE 30. DEVELOPMENT OF LOSSES IN 33 KV CIRCUITS

Figure 31 shows energy savings if all of 33 kV conductors are upgraded to 132 kV, assuming that conductors’ resistance remains unaltered in the process. The savings represent a high proportion of the original losses, from 220 GWh/a in 2019 to 305-395 GWh/a in 2032. The total length of existing 33 kV circuits is 10,750 km. Savings per km is between 20 and 37 MWh/a.km. The value range is £1,200-2,200/a.km at £60/MWh.

FIGURE 31. DEVELOPMENT OF LOSSES SAVINGS IF 33 KV CIRCUITS ARE UPGRADED TO 132 KV CIRCUITS (LIKE FOR LIKE)

Figure 32 shows energy losses in 132/33 kV transformers. This, hence, represents potential energy savings once this voltage transformation stage becomes obsolete. The total savings range from 300 GWh/a in 2019 to 400-480 GWh/a in 2032. There are 340 such transformers. Savings

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per transformer is between 880 and 1,400 MWh/a. This equates to £52,800-84,000/a per transformer at £60/MWh.

FIGURE 32. DEVELOPMENT OF LOSSES IN 132/33 KV TRANSFORMERS

In summary, the overall energy loss reduction due to circuit upgrades from 33 to 132 kV is between 540 and 880 GWh/a due to voltage increase. This energy savings arises due to transformers becoming obsolete and voltage in conductors being increased to 132kV. The associated monetary value is between £32 and £53m per annum when valued at £60/MWh. The assumption in this instance is that losses in existing 33/11 kV transformers will be similar to losses in new 132/11/11 kV and 132/11 kV transformers due to 132/33 kV transformation stage being eradicated.

Table 16 shows the losses savings for the 30 top-ranked grid substations. For the purposes of this analysis, we assumed that Grid transformers are decommissioned, and all the losses in these grid transformers are saved. Primary transformers are replaced with direct transformation (i.e. 132/11 kV). Only one 132/11 kV transformer is used in situations where only one transformer exists at present. In primary sites with three or more existing transformers, only two direct transformation units were used. In the majority of cases, the replacement of primary transformers with 132/11 kV units will increase losses, but the overall approach will lead to savings in losses.

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TABLE 16. RANKING OF GRID SUBSTATIONS BY ANNUAL SAVINGS IN LOSSES IN 2023 IF DIRECT TRANSFORMATION IS IMPLEMENTED

DNO Substation Name Losses savings, MWh/a Grid transformers

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EPN Sall Grid 33kV 2,432 16,077 -1,783 16,726 EPN Trowse Grid 33kV 5,826 4,253 75 10,154 EPN Thaxted Grid 33kV 3,258 3,891 2,749 9,898 EPN Rye House Grid 33kV 3,529 8,053 -1,751 9,830 EPN Cliff Quay Grid 33kV 5,145 5,974 -2,401 8,719 EPN Thetford Grid 33kV 3,236 8,498 -3,564 8,170 EPN Huntingdon Grid 33kV 1,772 4,283 2,030 8,085 EPN Hatfield Grid 33kV 5,476 2,621 -869 7,228 EPN Little Barford 33kV 1,137 5,964 35 7,136 EPN Abberton Grid 33kV 4,846 3,136 -899 7,083 EPN Bury Grid 33kV 5,870 1,633 -516 6,988 SPN Sittingbourne Grid 33kV 3,227 3,852 -555 6,524 EPN Thorpe Grid 33kV 3,377 3,685 -801 6,261 SPN Chelsfield Grid 33kV 3,711 3,667 -1,190 6,189 LPN Eltham Grid 33kV 4,809 1,523 -203 6,129 EPN Finchley Grid 33kV 6,972 597 -1,495 6,074 EPN Burwell Local Grid 33kV 2,040 2,863 1,156 6,058 LPN Buckhurst Hill 33kV 6,407 659 -1,032 6,034 LPN Wimbledon Grid C 33kV 4,458 3,360 -2,013 5,805 EPN Kings Lynn Grid 33kV 3,791 1,969 -47 5,714 EPN Wickham Market Grid 33kV 1,849 3,524 339 5,712 EPN Houghton Regis Grid 33kV 3,613 1,874 222 5,710 EPN Brimsdown North Grid 33kV 4,314 1,510 -216 5,608 EPN March Grid 33kV 1,961 4,118 -836 5,242 SPN Ninfield Grid 33kV 1,901 5,532 -2,535 4,898 SPN West Weybridge Grid 33kV 761 2,655 1,460 4,876 SPN Three Bridges Local 33kV 3,891 1,102 -171 4,821 EPN Belchamp Grid 33kV 2,695 2,960 -866 4,789 EPN Stevenage Grid 33kV 2,336 5,269 -2,825 4,780 LPN Dartford Grid A 33kV 4,609 1,883 -1,793 4,700

If HV circuits are upgraded to 20 kV, the additional savings that could be achieved are shown in Figure 33 below:

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FIGURE 33. UPGRADE OF HV CIRCUITS TO 20 KV CIRCUITS, SEE SECTION 8 FOR MORE DETAILS.

The energy loss reduction available from upgrading 6.6 and 11 kV networks to 20 kV is between 380 and 740 GWh/a, assuming that conductors’ resistance remains unchanged in the process. The overall loss reduction, including grid and primary transformers, and lines, is between 900 and 1600 GWh/a, valued between £54 and 96m/a assuming that the cost of losses is £60/MWh. This assumes that the 132/33 kV transformation stage is eradicated, 33 kV circuits are upgraded to 132 kV and HV circuits are upgraded to 20 kV. An additional assumption is that losses in new primary 132/11 kV and distribution transformers will be similar to the original losses.

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7 Cost - benefit analysis for upgrading legacy networks operating below 11kV to 11kV

In this task we assess the potential benefit of strategically replacing all legacy networks operating below 11 kV (e.g. 2, 3.3, 6.6 kV) with 11 kV networks. In addition, the geographical location of such networks is considered to help estimate whether additional opportunities exist. The additional opportunities include reducing the number of primary sites and increasing 11kV feeder lengths to release valuable space while maintaining losses at similar levels.

Figure 34 shows the HV network in LPN. There are a few primary substations that supply the legacy 6.6 kV networks shown in green.

FIGURE 34. LPN HV NETWORK, 11 KV (RED) AND 6.6 KV (GREEN)

Figure 35 shows losses in all 6.6 kV network sections for different scenarios. Respectively, there are 485 and 1766 kilometres of 6.6 kV networks in LPN and SPN. Losses range from 25 GWh/a in 2019 to between 31 and 37 GWh/a in 2032, dependent on the chosen scenario.

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FIGURE 35. LOSSES IN 6.6 KV NETWORK

Figure 36 shows the energy savings attainable if all 6.6 kV networks are upgraded to 11 kV. The analysis assumes conductors’ cross-sectional areas remain unchanged. The total savings are between 16 and 23 GWh/a. The value of these savings are between £1m and 1.4m per year in 2019/20 monetary value. It equates to about £440-620 per km of 6.6 kV network each year. If larger cross-sectional conductors are installed, the savings could be even greater.

FIGURE 36. SAVINGS IN LOSSES IF 6.6 KV NETWORKS ARE UPGRADED TO 11 KV, ASSUMING UNCHANGED CONDUCTOR CROSS- SECTIONAL AREA

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Figure 37 highlights a section of HV network in LPN. The legacy 6.6 kV network is shown in green and adjacent 11 kV networks in red. Conversion from 6.6 kV to 11 kV is typically conducted in stages. Once a distribution transformer must be replaced, a new transformer with dual primary windings, 6.6 kV and 11 kV, is installed. In his manner, the network is prepared for the eventual switchover to 11 kV. Once a 6.6 kV cable section is due for upgrade/replacement, an 11 kV section is installed to facilitate eventual switchover to 11 kV.

FIGURE 37. INSET OF LPN HV NETWORK SHOWING LEGACY 6.6 KV NETWORK IN GREEN. THE ADJACENT 11 KV NETWORK IS SHOWN IN RED

Figure 38 shows an example of 6.6 kV network being replaced with 11 kV. Green lines denote 6.6 kV, while red lines symbolise 11 kV circuits.

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FIGURE 38. EXAMPLE OF REPLACED 6.6 KV NETWORK WITH 11 KV NETWORK. GREEN AND RED LINES REPRESENT 6.6 KV AND 11 KV CIRCUITS RESPECTIVELY

Each 6.6 kV network section supplied from a primary substation has been analysed and ranked by its potential to reduce energy losses. UK Power Networks will check the rated voltage of installed assets, and in due course upgrade them to 11 kV. Table 17 shows the ranking of legacy networks by their potential to reduce energy losses.

TABLE 17. LEGACY 6.6 KV NETWORK RANKED BY POTENTIAL FOR ANNUAL LOSSES SAVINGS PER CIRCUIT KM

Primary substation Length, km Savings, MWh/a Savings, MWh/a.km GUILDFORD 33/6.6KV 6.1 192.7 31.7 SHEERNESS 33/6.6KV 28.1 525.0 18.7 Imperial College 6.6kV 26.0 395.0 15.2 Bloomfield place 6.6kV 26.0 349.0 13.4 AYLESFORD 33/6.6KV 81.7 1067.8 13.1 Moscow Road 6.6kV 34.0 424.0 12.5 SPURGEONS BRIDGE 33/6.6KV 40.9 509.3 12.4 NORBURY 33/6.6KV 42.9 518.8 12.1 Barnes B 6.6kV 87.0 997.0 11.5 CROYDON A 6.6KV 69.7 792.7 11.4 TOWNSEND HOOK 33/6.6KV 9.4 100.1 10.6 MINSTER 33/6.6KV 31.2 313.8 10.1 BENSHAM GROVE 33/6.6KV 30.2 303.5 10.0 SELHURST 33/6.6KV 24.7 241.9 9.8 EAST CROYDON 33/6.6KV 27.3 261.0 9.5 LEYSDOWN 33/6.6KV 17.8 154.4 8.7 TONBRIDGE EAST 33/6.6KV 91.8 773.9 8.4

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Primary substation Length, km Savings, MWh/a Savings, MWh/a.km SUFFOLK ROAD 33/6.6KV 34.4 284.8 8.3 SINGLETON 33/6.6KV 37.6 301.2 8.0 Hackney C 6.6kV 148.0 1175.0 7.9 GRAVESEND TOWN 33/6.6KV 40.9 318.0 7.8 TUNBRIDGE WELLS TOWN 132/6.6kV 60.8 453.2 7.5 WADHURST 33/6.6KV 69.7 453.0 6.5 EASTCHURCH PRISON 33/6.6KV 37.0 240.4 6.5 CROWBOROUGH TOWN 33/6.6KV 69.9 389.7 5.6 TONBRIDGE TOWN 33/6.6KV 97.5 478.7 4.9 ROSHERVILLE 33/6.6KV 23.2 110.6 4.8 STEEL CROSS 33/6.6KV 32.5 146.7 4.5 TENTERDEN 33/6.6KV 118.4 529.4 4.5 LITTLE CHART 33/6.6KV 81.2 346.8 4.3 JARVIS BROOK 33/6.6KV 41.8 176.5 4.2 STAPLEHURST 33/6.6KV 50.5 211.9 4.2 QUEENBOROUGH 33/6.6KV 35.2 145.2 4.1 WITTERSHAM 33/6.6KV 53.6 197.8 3.7 HEADCORN 33/6.6KV 83.1 257.6 3.1 D.W.S. 33/6.6KV 10.3 30.2 2.9 KENARDINGTON 33/6.6KV 62.1 168.2 2.7 WEST ASHFORD 33/6.6KV 96.1 254.0 2.6 TIDWORTH 33/6.6KV 1.1 1.9 1.8 STRANGWAYS 33/6.6KV 29.3 10.5 0.4 BULFORD 6.6KV 25.8 1.2 0.0

Guilford 6.6 kV network shows the greatest potential to reduce losses. Measured at £60/MWh, the network’s potential amounts to £1,900/a.km.

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8 Cost-benefit analysis of upgrading HV networks to 20kV In this task, we assess the benefit of increasing HV distribution network voltages to 20 kV.

Figure 39, below, shows losses in 6.6 and 11 kV network sections associated with different scenarios. There are 485 and 1,766 kilometres of 6.6 kV networks in LPN and SPN regions respectively. LPN, SPN and EPN contain 9,850, 15,389 and 33,559 kilometres of 11 kV networks respectively.

FIGURE 39. LOSSES IN 6.6 AND 11 KV NETWORK

Figure 40 shows the savings in losses if 6.6 and 11 kV networks are upgraded to 20 kV. The analysis assumes that the conductors’ cross-sectional areas remains unaltered.

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FIGURE 40. SAVINGS IN LOSSES IF 6.6 AND 11 KV NETWORK IS UPGRADED TO 20 KV ASSUMING UNCHANGED CONDUCTOR CROSS-SECTIONAL AREA

The energy loss reduction due to upgrading 6.6 and 11 kV networks to 20 kV is between 380 and 740 GWh/a. These savings translate to a monetary value between £23m and £44m/a weighed at £60/MWh. It equates to, on average, between £375 and 725/a per km of 6.6 and 11 kV circuit.

HV networks are ranked by potential savings per circuit km and the top 30 HV networks are shown in Table 18.

TABLE 18. HV NETWORK RANKED BY POTENTIAL FOR 2019 LOSSES SAVINGS, IF CIRCUITS ARE UPGRADED TO 20 KV, PER CIRCUIT KM

DNO Primary substation Length, km Savings MWh/a Savings MWh/a.km LPN SHORTS GARDENS 46 2,134 46.4 LPN BEECH STREET B 46 2,134 46.4 LPN KINGSWAY 46 2,134 46.4 SPN GUILDFORD 33/6.6KV 6 241 39.8 SPN MARDEN 33/11KV 42 1,172 28.0 SPN SHEERNESS 33/6.6KV 28 658 23.4 SPN MEDWAY 33/11KV 73 1,634 22.3 SPN SUTTON B 33/11KV 48 864 18.0 LPN HYDE PARK B 44 763 17.5 SPN BANSTEAD 33/11KV 74 1,284 17.3 SPN CHERTSEY 33/11KV 94 1,576 16.7 SPN AYLESFORD 33/6.6KV 82 1,338 16.4 LPN CHURCHFIELDS 89 1,415 16.0 SPN MARGATE 33/11KV 38 607 15.8 SPN COULSDON 33/11KV 113 1,771 15.7

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DNO Primary substation Length, km Savings MWh/a Savings MWh/a.km SPN SPURGEONS BRIDGE 33/6.6KV 41 638 15.6 SPN NORBURY 33/6.6KV 43 650 15.2 SPN ASHFORD CENTRAL 49 738 15.1 LPN LEY ST B 105 1,581 15.1 LPN WOODGRANGE PARK 98 1,421 14.6 LPN BROMLEY SOUTH 94 1,347 14.4 LPN GLAUCUS ST 90 1,290 14.4 SPN CROYDON A 6.6KV 70 993 14.2 SPN EWELL 33/11KV 86 1,163 13.5 LPN DURNSFORD ROAD 78 1,045 13.5 SPN WEYBRIDGE 33/11KV 57 760 13.4 EPN NR ROXWELL QUARRY 25 329 13.3 SPN TOWNSEND HOOK 33/6.6KV 9 125 13.3 LPN NECKINGER MSS 70 933 13.3 LPN WATERLOO RD 133 1,756 13.2

A set of three interconnected LPN HV networks, Shorts Gardens, Beech Street B and Kingsway are ranked at the top with losses savings of 46.4 MWh/a.km in 2019. Loses savings could increase in the future if load increases.

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9 Network losses per voltage level The analysis in this section include asset replacement due to load growth only. For clarity, age related replacement is not included in this analysis.

The development of UKPN network losses per voltage level for the BaU scenario is shown in Figure 41. Total losses increase as load increases from about 4,100 in 2019 to about 5,200 GWh/a in 2032. The schedule of asset replacement/upgrade is thermal and voltage driven. Our approach for conductor upgrade or new cable installation is based on loss-inclusive design, while overloaded transformers are replaced with Eco 2021 specification units.

FIGURE 41. DEVELOPMENT OF UKPN NETWORK LOSSES FOR BAU SCENARIO

Figure 42 shows the annual losses in percentage of delivered annual energy. Losses in percentage is stable indicating that growth in losses is proportional to the load growth.

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FIGURE 42. DEVELOPMENT OF UKPN NETWORK LOSSES FOR BAU SCENARIO AS A PERCENTAGE OF DELIVERED ANNUAL ENERGY

The losses in LV networks and distribution transformers account for about 55% of the overall amount. This is a conservative view, given that losses in customers’ service cables were not considered in this instance.

The greatest increase in losses was observed in the Unmanaged scenario. Figure 43 shows the development of losses for the Unmanaged scenario. The overall losses reach about 6,300 GWh/a in 2032, which is about 20% more than for BaU scenario. The scenarios are considered without flexible technologies applied.

FIGURE 43. DEVELOPMENT OF UKPN NETWORK LOSSES FOR UNMANAGED SCENARIO

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Given the increase in demand, the development of the overall percentage losses is very similar in both the BaU and Unmanaged scenarios. Figure 44 shows the development of UKPN network losses for the Unmanaged scenario as percentage of delivered annual energy. Losses, in percentage terms, increase linearly on assets that remain in service, and decrease where assets are upgraded or replaced. Only a small increase in losses in percentage terms is observed.

FIGURE 44. DEVELOPMENT OF UKPN NETWORK LOSSES FOR UNMANAGED SCENARIO AS A PERCENTAGE OF DELIVERED ANNUAL ENERGY

Table 19 summarises energy loss reductions associated with different interventions.

TABLE 19. PERCENTAGE OF LOSSES REDUCTION FOR DIFFERENT LOSSES REDUCTION APPROACHES

Loss reduction approach Value, GWh/a

Percentage of losses

Replacement of primary and grid transformers 330-760 6.5-12.6% Replacement of distribution transformers 50-150 1.3-2.5%

Flexibility 5-10% LV 35-170 0.9-2.8% DT 15-60 0.4-1% HV -120-120 (-2)-2%

Voltage rationalisation

Upgrade of 33 kV circuit to 132 kV

220-400

5.7-6.6%

Decommission Tr 132/33 kV 320-480 8-8.3% Legacy network upgrade to 11 kV 16-23 0.4% HV network upgrade to 20 kV 380-740 9.8-12.3%

The greatest observed potential for losses reduction is replacement of primary and grid transformers with units conforming to Eco2021 design, voltage rationalisation and upgrade of HV networks to operate on 20 kV. Given the potentially wide range of enabling costs for different

0%

1%

2%

3%

4%

5%

6%

2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Loss

es, %

LV DT HV P&GT EHV

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approaches, we recommend that business cases be developed for each of the investigated approaches to establish feasibility.

Table 20 shows ranges for potential loss reduction associated with different interventions. The ranges arise from the use of different load growth scenarios. The first four approaches follow asset replacement due to load growth. In the last three approaches, all relevant assets are assumed replaced in the year zero.

TABLE 20. POTENTIAL LOSSES REDUCTION OF DIFFERENT LOSS REDUCTION APPROACHES

Loss reduction approach Overall losses reduction from 2019-2032,

GWh Primary and grid transformer replacement 1,560 – 3,520 Distribution transformer replacement 270 – 501 Low carbon technologies 5% peak reduction (-725) – (-65) Low carbon technologies 10% peak reduction (-786) – 540 Voltage rationalisation 132/11/0.4 kV 8,560 – 9,530 Upgrade of legacy circuits to 11 kV 394 – 441 Upgrade of HV networks to 20 kV 6,209 – 7,678

From the first four approaches, primary and grid transformer replacement have the highest overall energy loss reduction potential. If peak shifting is implemented, losses could potentially increase due to network upgrades deferral. Due to the introduction of network flexibility, DNOs will defer network upgrades from year-to-year. This increases losses and at one point, the increase in losses due to network upgrade deferral will outweigh the decrease in losses available from flexibility.

Significant losses reduction could be achieved if networks are upgraded to direct 132/11 kV transformation and/or HV networks are upgraded to 20 kV. However, the enabling cost due to high numbers of assets involved could be prohibitive, and the approach could be beneficial only for parts of the network.

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10 Conclusions 10.1 Primary and grid substation transformers Many grid and primary transformers currently in operation were installed in the 1960’s. We anticipate that these units will be replaced with new transformers conforming to the EU 2021 specification (or better), resulting in improved energy efficiency.

Our analysis of grid and primary transformers’ load profiles resulted in the discovery of a strong statistical relationship between load factors and load loss factors. This discovery enabled us to calculate annual losses without requiring a detailed load profile in each case. Many observed load loss factors for primary and grid transformers were between 27% and 44%. The average load loss factor is about 36%.

We have carried out a study to demonstrate how DNOs can minimise energy losses in transformers by selecting adequate transformer ratings during transformer replacement. For this work, the understanding of load growth, load factors, and the forecast number or years’ of cyclic load growth are required (loading might reduce if a new substation is commissioned nearby). The recommended range of peak utilisation for transformers is between 22-66% and widely speaking, greater peak utilisation in the year of commissioning is associated with:

- a lower load growth rate;

- a lower load loss factor;

- fewer years of cyclic load growth, and

- linear load growth (as opposed to compound load growth).

It is observed for different load growth scenarios that the average annual savings in grid and primary transformer losses is equivalent to about 1.3 GWh/a. Replacement of 20 to 45 grid and primary transformers per year results in losses savings between £1.6 and 3.5m each year. The cost of bringing forward grid and primary transformer investment, at a WACC of 4.1%, for one year, is between £35 and 75k. The average savings from loss reduction in this case is about 78k. The business case for early replacement of transformers is hence very strong and should be conducted in more detail on a case-by-case basis. The residual value of transformers rendered redundant is not considered.

10.2 Distribution transformers In the case of distribution transformers, similar to grid and primary transformers, a strong statistical relationship exists between load factors and load loss factors. Observed load loss factors range between 15% and 40%.

For the assumed load loss factor is 27% distribution transformer losses will increase from about 1100 GWh/a in 2019 to between 1240 and 1370 GWh/a in 2032, dependent on the considered scenario. Due to the improved design of distribution transformers, the increase in losses will be lower than the relative load growth. The average energy loss improvement per replaced secondary transformer is about 15 MWh/a, assuming a load loss factor of 27%. Measured at £60/MWh, this improvement amounts to £900/a. Over 60 years, these savings add up to circa

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£23.6k per transformer. Considering that the cost of a one-year deferral in distribution transformer replacement is between £180-600, a business case for early investment could be very strong. The residual value of redundant transformers was not considered.

For ground mounted distribution transformers, the economically efficient initial-year peak utilisation ranges from 20% to 64%. For pole mounted distribution transformers, it is between 12% and 100% in the case of cold rolled grain oriented (CRGO) steel. This level changes to between 4% and 44% for amorphous steel units.

If all secondary transformers are replaced with new low-loss units, the overall distribution transformer losses could be reduced by about 50%.

10.3 The impact of flexible loads We considered two propositions to quantify the benefit of shifting load peaks. In the first scenario, we assumed that daily load peaks could be reduced by 5% through shifting peak load to off peak periods. We increased this number to 10% in the second scenario. The observed increase in load loss factor, on average, is about 10% and 21% for peak reductions of 5% and 10% respectively. Given that peak is reduced, and hence peak losses are also reduced, the overall losses reduction will be about 1 and 2% for peak shifting of 5% and 10% respectively.

We established that these two scenarios led to loss reductions in LV, HV networks and distribution transformers combined. These savings range from 45 to 105 GWh/a in the 2019 Centralised scenario. However, losses could increase by about 120 and 190 GWh/a respectively in the 2032 Smart scenario. The increase in losses is expected, given that the asset utilisation would increase, and monetary savings might be achieved through investment deferrals. Any policy of incentivising losses reduction should consider that losses might increase due to application of low carbon technologies.

10.4 EHV voltage rationalisation We calculated energy savings for a scenario which assumed that all 33 kV conductors are upgraded to 132 kV. This scenario further worked from the premise that conductors’ resistances remain unaltered. The savings in this instance are between 220 and 395 GWh/a. The total length of existing 33 kV circuits is 10,750 km. Average savings per km is between 20 and 37 MWh/a.km. This yields a valuation of £1,200-2,200/a.km at £60/MWh.

Considering the removal of 132/33 kV transformation, the overall energy loss reduction associated with upgrading all 33kV conductors and cables to 132 kV is between 520 and 820 GWh/a. The average monetary value of these savings is between £31 and £49m per annum.

Deferring the upgrade of 33kV network to 132kV by one year is valued between £35 and 47k/a.km. In addition, if all HV networks are upgraded to 20 kV, the overall loss reduction is between 900 and 1600 GWh/a, valued between £54 and 96m/a; assuming the cost of losses is £60/MWh.

Grid sites and supplied networks were ranked by potential for losses reduction. The Sall Grid 33kV site and supplied 33 kV network have the greatest potential for losses reduction, which amounts to about 16.7 GWh/a. The monetary value of losses reduction is about £1m per annum.

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A detailed business case for each identified grid site is recommended to establish whether early conversion is economically justifiable.

10.5 The value of upgrading legacy networks Upgrading legacy 6.6 kV circuits to 11 kV could save up to £32/MWh/a per km of circuit, which is equivalent to £1,900/a.km. Upgrading all HV circuits to 20 kV could save between £23 and £44m/a when valued at £60/MWh. This equates to, on average, between £375 and 725/a per km for 6.6 and 11 kV circuits combined.

Table 20 summarised the value inherent to different interventions. The use of load growth scenarios resulted in ranges amongst our findings. The first four approaches in Table 19 follow asset replacement due to load growth, while in the last three approaches, all relevant assets are assumed to be replaced in year zero.

From the first four approaches, primary and grid transformer replacement have the highest overall losses reduction potential. If low carbon technologies for peak shifting are implemented, losses could potentially increase due to monetary savings achieved from network upgrade deferral. The resistances of unupgraded assets in the presence of flexibility will be greater than those upgraded in the case without flexibility. The increase of losses on unupgraded assets will counteract the losses decrease arising from flexibility.

Using direct 132/11 kV transformation and upgrading HV networks to 20 kV could reduce energy losses significantly. However, the enabling cost due due to high numbers of assets involved could be prohibitive, and the approach could be beneficial for parts of the network only.

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11 Appendix A: ESRI Shapefiles Received ESRI Shapefiles for SPN LV networks contains tables for: • Underground cables: state, length, conductor type, geographical route • Overhead lines: state, length, conductor type, geographical route • Link boxes: reference, link box type (2 to 8 way), geographical location • Open points: geographical location • Joints: state, type (branch, straight, tee joint, sleeve repair, pot end, capped end),

geographical location • Service cables: state, length, conductor type, geographical route • Overhead services: state, length, conductor type, geographical route • Distribution sites: state, type (substation, switching station, vacant site, NMS node),

reference, name, label location, area (SPN only) • Distribution transformers: state, site reference, site name, rating, geographical location • Poles: reference, geographical location • LV feeder node (EPN GMT only): state, geographical location

State: In use, Out of Use, Abandoned, Reserve, Planned, Unknown, [blank].

FIGURE 45. PART OF SPN LV NETWORKS. RED CIRCLE IS LOCATION OF DISTRIBUTION SITE, WHITE CIRCLE IS LOCATION OF OPEN POINT, BLUE LINE IS UNDERGROUND CABLE AND GREEN LINE UNDERGROUND SERVICES. SHADED AREA ARE BUILDINGS (SOURCE ORDNANCE SURVEY).

Connection between transformers and LV feeders was not provided and for SPN LV feeder nodes had to be identified. For EPN, the majority of GMT feeder nodes were provided and for the rest, including PMTs, they have been identified. Connectivity between link boxes and lines was identified based on type of link box and geometrical spread of line ends. Given the number of link boxes, a big data algorithm had to be implemented in order to speed up discovery to a reasonable duration. Some open point locations were away from lines or nodes and a proximity algorithm was devised to match them with relevant assets. Some open points were not matched due to relatively higher distances to nodes. For each distribution transformer, total overhead and underground conductor length is calculated. Where LV feeders are interconnected between multiple distribution transformers, its overhead and underground conductor length is equally split between distribution transformers. In this way double counting is avoided.

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12 Appendix B: DINIS EDF files The received DINIS EDF file for LPN contains thefollowing tables for which key records are specified: • Site records: Unique identifier (ID), type (main substation, secondary substation, link box,

other), reference, name, label coordinate • Node records: ID, symbol, site reference, site coordinate, panel number, geographical and

schematic coordinates; depending on symbol the following data associated with the node exists

• Load records: ID, transformer rating, status (on, off), actual load, power factor • Transformer records: ID, type (auto, basic, two-winding, three-winding and unit

transformer), winding nameplate voltages and ratings, impedances and tap related data, connected to ‘infinite busbar’ flag

• Sectionalizer records: ID, nominal, load and short circuit ratings • Auto-recloser records: ID, rating, short circuit rating • Switch records: ID, status (on, off), rating, short circuit rating

• Line records: ID, Node IDs, number of segments, segment IDs, segment symbols, segment lengths, status on each line end, geographical and schematic route coordinates

The DINIS EDF file contains data for LPN LV and HV networks. For LV networks, total overhead and underground conductor length per each distribution transformer were calculated. For HV networks, all network connectivity model data were used.

FIGURE 46. GEOGRAPHICAL LPN HV NETWORKS DRAWN FROM DINIS EDF FILE DATA

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13 Appendix C: CIM files Figure 47 shows a block diagram of the received Common Information Model (CIM) file for SPN. CIM file for EPN is similar, but data for HV networks are not yet ready for use and hence, its explanation is omitted from this report. CIM files contain other voltage levels i.e. LV and EHV but those data are not used given new data for LV and EHV networks were received just before receiving CIM files.

FIGURE 47. UNIFIED MODELLING LANGUAGE (UML) BLOCK DIAGRAM OF SPN CIM TABLES SHOWING KEY DATA RELATIONSHIPS; NUMBER OF RECORDS FOR KEY TABLES ARE SHOWN

+ID : StringIDClass

+name : StringNameClass

+aliasName : StringIdentifiedObject

+AssetDatasheet+BaseVoltage+EquipmentContainer+PerLengthImpedance-length, r, r0, x, x0, bch, b0ch

ACLineSegment

+PowerSystemResource+Terminal-measurementType-unitSymbol-unitMultiplier

Analog

-MeasurementQuality-MeasurementSource-Analog-value

AnalogValue

-PowerSystemResource-AssetInfo

Asset

-nominalVoltageBaseVoltage

+EquipmentContainer+BaseVoltage+Location-ratedCurrent-breakingCapacity-normalOpen

Breaker

+EquipmentContainer+Location

BusbarSection

-radius-ratedCurrent-nominalTemperature

CableInfo

-ControlType-Discrete

Command

ConnectivityNode

ControlType

-crsUrnCoordinateSystem

-orientation-x1InitialView-x2InitialView-y1InitialView-y2InitialView

Diagram-IdentifiedOjbect-Diagram-VisibilityLayers-rotation

DiagramObject-DiagramObject-sequenceNumber-xPosition-yPosition

DiagramObjectPoint

+EquipmentContainer : Object+BaseVoltage : Object+Location : Object-ratedCurrent-normalOpen

Disconnector-PowerSystemResource-VAlueAliasSet-measurementType

Discrete

-MeasurementValueSource-Discrete-MeasurementValueQuality-value-timeStamp

DiscreteValue

-EquipmentContainer-BaseVoltage-Location-customerCount

EnergyConsumer

-EquipmentContainer-BaseVoltage-nominalVoltage-activePower

EnergySource

Line

-coordinateSystemLocation

-failure-validity-suspect-oldData-operatorBlocked

MeasurementValueQuality MeasurementValueSource

-radius-ratedCurrent

OverheadWireInfo

-r, r0, x, x0, bch, b0chPerLengthSequenceImpedance

-TransformerEnd-highStep-lowStep-ltcFlag-neutralStep-stepPhaseShiftIncrement

PhaseTapChangerLinear

-Location-sequenceNumber-xPosition-yPosition

PositionPoint

-EquipmentContainer-Location-vectorGroup

PowerTransformer

-BaseVoltage-Terminal-PowerTransformer-endNumber-grounded-connectionKind-phaseAngleClock-ratedS-r, r0, x, x0, b-rground, xground

PowerTransformerEnd

-TransformerEnd-highStep-ltcFlag-neutralStep-stepVoltageIncrement

RatioTapChanger

-EquipmentContainer-BaseVoltage-normalSection-maximumSection-phaseConnection-bPerSection

ShuntCompensator

-LocationSubstation

-ConductingEquipment-ConnectivityNode-sequenceNumber-phases

Terminal

ValueAliasSet-ValueAliasSet-value

ValueToAlias

-drawingOrderVisibilityLayer

-radius-ratedCurrent

WireInfo

190692

67835

816295

299753

3700474008

162605

33981

46693

36831

104

15

15623

61999

18

1544

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14 Appendix D: Microsoft Office Assess (.mdb) file For EPN HV networks, data from the .mdb database were used. The following tables are encoded within the file:

• Primary sites: contains site reference • HV feeders: contains feeder reference • Branches: contains section length and type, start and end coordinates, voltage level and

status on each end • Nodes: contains node coordinate and type; the switchgear and distribution transformer loads

are modelled as node • Switchgear (circuit breakers, reclosers and switches are defined in separate tables):

contains location and status of switchgear • Load: contains site reference, distribution transformer rating

Distribution site references were updated to match the new site reference encoding style.

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15 Appendix E: PowerFactory DSG files PowerFactory DGS file contains EHV and 132 kV networks including primary and grid transformers for all three UKPN regions. Data are split into the following key tables:

• ChaVec: contains asset ratings for different seasons • ElmFeeder: contains data for feeders • ElmGenstat: contains data for generators • ElmLne: contains data for single-section overhead lines and cables • ElmLnesec: contains data for multi-section overhead lines and cables • ElmLod: contains data for network loading • ElmSubstat: lists substations • ElmTerm: contains data for nodes including busbars, junctions and internal nodes • ElmSym: contains data about synchronous generators • ElmTr2: contains data about two-winding transformers • ElmTr3: contains data about three-winding transformers • IntMat: contains rating data for overhead lines and cables depending on previous loading • IntThrating: contains rating data for transformers • StaCubic: contains connectivity data between nodes and assets • TypLne: data for conductor type • TypLod: data per load type • TypSym: data for synchronous generator type • TypTr2: data for two-winding transformer type • TypTr3: data for three-winding transformer type

The file contains some other lesser relevant tables which are not mentioned above, but some of them are used when LRE EHV network models are created.

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