Use of System Charging Statement

USE OF SYSTEM CHARGING STATEMENT

Notice of Charges

Effective from 1st April 2017

Version 1.1

THIS STATEMENT IS IN A FORM APPROVED BY THE GAS AND ELECTRICITY MARKETS AUTHORITY (OFGEM) Toll Bar Road, Marston, Grantham, Lincolnshire, NG32 2HT Harlaxton Energy Networks Limited APR 2017 – V1.1

V e r s i o n C o n t r o l

A change-marked version of this statement can be provided upon request. Toll Bar Road, Marston, Grantham, Lincolnshire, NG32 2HT Harlaxton Energy Networks Limited APR 2017 – V1.1

C o n t e n t s

1. Introduction

5 Validity period

6 Contact details

6 2. Charge application and definitions

7 Supercustomer billing and payment

7 Supercustomer charges

7 Site-specific billing and payment

9 Site-specific billed charges

9 Time periods for half-hourly metered properties

10 Time periods for pseudo half-hourly unmetered properties

11 Application of capacity charges

11 Chargeable capacity

11 Exceeded capacity

12 Demand exceeded capacity

12 Generation exceeded capacity

12 Standby capacity for additional security on site

13 Minimum capacity levels

13 Application of charges for excess reactive power

13 Demand chargeable reactive power

13 Generation chargeable reactive power

14 Incorrectly allocated charges

14 Generation charges for pre-2005 designated EHV properties

16 Methodology to determine export tariffs for domestic and small-scale generation

16 Methodology to determine export tariffs for generation with a maximum export capacity

17 Methodology to determine generic import tariffs

18 Methodology to determine site-specific import tariffs

19 Provision of billing data

20 Out of area use of system charges

21 Licensed distribution network operator charges

21 Licence exempt distribution networks

21 Full settlement metering

22 Difference metering

22 Gross Settlement

22 Net Settlement

23 3. Schedule of charges for use of the distribution system

24 4. Schedule of line loss factors

25 Role of line loss factors in the supply of electricity

25 Calculation of line loss factors

25 Publication of Line Loss Factor

26 5. Notes for Designated EHV Properties

27 EDCM network group costs

27 Charges for new Designated EHV Properties

27 Charges for amended Designated EHV Properties

27 Demand-side management

27 6. Electricity distribution rebates

28 7. Accounting and administration services

28 8. Charges for electrical plant provided ancillary to the grant of use of system

28 Appendix 1 - Glossary

29 Appendix 2 - Guidance notes

35 Background

35 Meter point administration

35 Your charges

37 Reducing your charges

37 Reactive power and reactive power charges

38 Site-specific EDCM charges

OF 4 1 Harlaxton Energy Networks Limited APR 2017 – V1.1

Annex 1 - Schedule of charges for use of the distribution system by LV and HV Designated Properties

37 Annex 2 - Schedule of charges for use of the distribution system by Designated EHV Properties (including LDNOs with Designated EHV Properties/end-users)

37 Annex 3 - Schedule of charges for use of the distribution system by preserved/additio nal LLF classes

37 Annex 4 - Charges applied to LDNOs with LV and HV end-users

37 Annex 5 - Schedule of line loss factors

37 Annex 6 - Addendum to charging statement detailing charges for new Designated EH V Properties

37 PAGE 4 OF 4 1 Harlaxton Energy Networks Limited APR 2017 – V1.1

1 . I n t r o d u c t i o n

1.1. This statement tells you about our charges and the reasons behind them. It has been prepared consistent with Standard Licence Condition 14 of our Electricity Distribution Licence. The main purpose of this statement is to provide our schedule of charges1 for the use of our Distribution System and to pr ovide the schedule of adjustment factors2 that should be applied in Settlement to acc ount for losses from the Distribution System. We have also included guidanc e notes in Appendix 2 to help improve your understanding of the charges we apply.

1.2. Within this statement we use terms such as ‘Users’ and ‘Customers’ as well as other terms which are identified with initial capitalisation. These te rms are defined in the glossary.

1.3. The charges in this statement are calculated using the Common Distri bution Charging Methodology (CDCM) for Low Voltage and High Voltage (LV and HV) Designated Properties and the Extra-high Voltage (EHV) Distribution C harging Methodology (EDCM) for Designated EHV Properties.

1.4. Separate charges are calculated depending on the characteristics of the connection and whether the use of the Distribution System is for dem and or generation purposes.

1.5. The application of charges to premises can usually be referenced usi ng the Line Loss Factor Class (LLFC) contained in the charge tables. Further information on how to identify and calculate the charge that will apply for your premise is provided in the guidance notes in Appendix 2.

1.6. All charges in this statement are shown e x c l u s i v e of VAT. Invoices will incl ude VAT at the applicable rate.

1.7. The annexes that form part of this statement are also available in spreadsh eet format. This spreadsheet contains supplementary information used for cha rging purposes and a simple model to assist you to calculate charges. This spreadsheet can be downloaded from www.harlaxtonenergynetworks.co.uk

1 Charges can be positive or negative. 2 Also known as Loss Adjustment Factors or Line Loss Factors

OF 41 Harlaxton Energy Networks Limited APR 2017 – V1.1

V a l i d i t y p e r i o d 1.8. This charging statement is valid for services provided between the eff ective from date and the effective to date stated on the front of the stateme nt.

The statement remains valid between those dates until updated by a revised version.

1.9. When using this charging statement care should be taken to ensure t hat the statement or statements covering the period that is of interest are used.

1.10. Notice of any revision to the statement will be provided to Us ers of our Distribution System. The latest statements can be downloaded from www.harlaxtonenergynetworks.co.uk

C o n t a c t d e t a i l s 1.11. If you have any questions about this statement please contact u s at this address:

Business Operations Manager Toll Bar Road Marston Grantham Lincolnshire NG32 2HT

Tel: 0844 800 1813 Fax: 0800 055 6288 Email: [email protected]

1.12. All enquiries regarding connection agreements and changes to ma ximum capacities should be addressed to:

Buiness Operations Manager Toll Bar Road Marston Grantham Lincolnshire NG32 2HT

Tel: 0844 800 1813 Fax: 0800 055 6288 Email: [email protected]

For all other queries please contact our general enquiries telephone servi ce on 0844 800 1813, lines are open 08:00 to 18:00 Monday to Friday.

2 . C h a r g e a p p l i c a t i o n a n d d e f i n i t i o n s

2.1. The following section details how the charges in this statement are applie d and billed to Users of our Distribution System.

2.2. We utilise two billing approaches depending on the type of meteri ng data received. The ‘Supercustomer’ approach is used for Non-Half-Hourly (NHH) metered, NHH unmetered or aggregated Half-Hourly (HH) metered pre mises and the ‘Site-specific’ approach is used for HH metered or pseudo HH unmetered premises.

2.3. Typically NHH metered are domestic and small businesses, HH meter ed are larger businesses and unmetered premises are normally streetlights.

S u p e r c u s t o m e r b i l l i n g a n d p a y m e n t 2.4. Supercustomer billing and payment applies to metering points registe red as NHH metered, NHH unmetered or aggregated HH metered. The Supercustomer approach makes use of aggregated data obtained from Suppliers using the ‘Non Half Hourly Distribution Use of System (DUoS) Re port’ data flow.

2.5. Invoices are calculated on a periodic basis and sent to each User for whom we transport electricity through our distribution system. Invoices are reco nciled over a period of approximately 14 months to reflect later and more ac curate consumption figures.

2.6. The charges are applied on the basis of the LLFC assigned to a Met er Point Administration Number (MPAN), and the units consumed within th e time periods specified in this statement. These time periods may not necessaril y be the same as those indicated by the Time Pattern Regimes (TPRs) ass igned to the Standard Settlement Configuration (SSC). All LLFCs are assigned at our sole discretion.

S u p e r c u s t o m e r c h a r g e s 2.7. Supercustomer charges include the following components:

 a fixed charge - pence/MPAN/day; there will be only one fixe d charge applied to each MPAN; and

 unit charges, pence/kWh; more than one unit charge may apply depending on the type of tariff for which the MPAN is registered.

2.8. Users who supply electricity to a Customer whose metering system is:

 Measurement Class A or B, and settled on Profile Classes (PC) 1 throu gh to 8;

 Measurement Class F or G;

will be allocated the relevant charge structure set out in Annex 1.

2.9. Measurement Class A charges apply to Exit/Entry Points where NHH metering is used for Settlement.

2.10. Measurement Class B charges apply to Exit Points deemed to be suit able as Unmetered Supplies as permitted in the Electricity (Unmetered Supply) Regulations 20013 and where operated in accordance with Balanci ng and Settlement Code (BSC) procedure 5204.

2.11. Measurement Class F and G charges apply to Exit/Entry Points where HH aggregated metering data is used for Settlement.

2.12. Identification of the appropriate charge can be made by cross- reference to the LLFC. 2.13. Valid Settlement PC/SSC/Meter Timeswitch Code (MTC) combinatio ns for LLFCs where the Metering System is Measurement Class A and B are detailed in Market Domain Data (MDD).

2.14. Where an MPAN has an invalid Settlement combination, the ‘Domestic Unrestricted’ fixed and unit charges will be applied as default until the invalid combination is corrected. Where there are multiple SSC/TPR combin ations, the default ‘Domestic Unrestricted’ fixed and unit charges will be appli ed for each invalid TPR combination.

2.15. The time periods for unit charges where the Metering System is Meas urement Class A and B are as specified by the SSC. To determine the a ppropriate

3 The Electricity (Unmetered Supply) Regulations 2001 available from http://www.legislation.gov.uk/uksi/2001/3263/ma de 4 Balancing and Settlement Code Procedures on unmetered supplies are available from https://www.elexon.co.uk/bsc- related-documents/related-documents/bscps/

charge rate for each SSC/TPR a lookup table is provided in the spre ad sheet that accompanies this statement5.

2.16. The time periods for unit charges where the Metering System is Meas urement Class F and G are set out in the table ‘Time Bands for Half Hourly Metered Properties’ in Annex 1.

2.17. The ‘Domestic Off-Peak’ and ‘Small Non-Domestic Off-Peak’ charg es are additional to either an unrestricted or a two-rate charge.

S i t e - s p e c i f i c b i l l i n g a n d p a y m e n t 2.18. Site-specific billing and payment applies to Measurement Class C, D and E metering points settled as HH metered. The site-specific billing and pa yment approach to Use of System (UoS) billing makes use of HH metering d ata at premise level received through Settlement.

2.19. Invoices are calculated on a periodic basis and sent to each User for whom we transport electricity through our Distribution System. Where an acc ount is based on estimated data, the account shall be subject to any adjustm ent that may be necessary following the receipt of actual data from the User.

2.20. The charges are applied on the basis of the LLFCs assigned to the MPAN (or the Meter System Identifier (MSID) for Central Volume Allocation (CVA ) sites), and the units consumed within the time periods specified in this statement.

2.21. All LLFCs are assigned at our sole discretion. Where an incorrectly a pplied LLFC is identified, we may at our sole discretion apply the correct LLF C and/or charges.

S i t e - s p e c i f i c b i l l e d c h a r g e s 2.22. Site-specific billed charges may include the following components:

 a fixed charge pence/MPAN/day or pence/MSID/day;

 a capacity charge, pence/kVA/day, for Maximum Import Capacit y (MIC) and/or Maximum Export Capacity (MEC);

 an exceeded capacity charge, pence/kVA/day, if a site exceeds its MIC and/or MEC;

 unit charges, pence/kWh, more than one unit charge may be applied;

 an excess reactive power charge, pence/kVArh, for each unit in ex cess of the reactive charge threshold.

2.23. Users who wish to supply electricity to customers whose metering syst em is Measurement Class C, D or E or CVA will be allocated the relevant c harge structure dependent upon the voltage and location of the metering point.

2.24. Measurement Class C, E or CVA charges apply to Exit/Entry Points where HH metering, or an equivalent meter, is used for Settlement purposes.

2.25. Measurement Class D charges apply to Exit points deemed to be suit able as Unmetered Supplies as permitted in the Electricity (Unmetered Supply) Regulations 20016 and where operated in accordance with BSC pr ocedure 5207.

2.26. Fixed charges are generally levied on a pence per MPAN/MSID basis. Where two or more HH MPANs/MSIDs are located at the same point of connection (as identified in the connection agreement), with the same LLFC, and regi stered to the same supplier, only one daily fixed charge will be applied. 2.27. LV and HV Designated Properties will be charged in accordance with the CDCM and allocated the relevant charge structure set out in Annex 1.

2.28. Designated EHV Properties will be charged in accordance with the EDCM and allocated the relevant charge structure set out in Annex 2.

2.29. Where LV and HV Designated Properties or Designated EHV Properti es have more than one point of connection (as identified in the Connection Agr eement) then separate charges will be applied to each point of connection.

T i m e p e r i o d s f o r h a l f - h o u r l y m e t e r e d p r o p e r t i e s 2.30. The time periods for the application of unit charges to LV and HV De signated Properties that are HH metered are detailed in Annex 1. We have not issued a notice to change the time bands.

6 The Electricity (Unmetered Supply) Regulations 2001 available from http://www.legislation.gov.uk/uksi/2001/3263/ma de 7 Balancing and Settlement Code Procedures on unmetered supplies and available from http://www.elexon.co.uk/pages/bscps.aspx

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2.31. The time periods for the application of unit charges to Designate d EHV Properties are detailed in Annex 2. We have not issued a notice to change the time bands.

T i m e p e r i o d s f o r p s e u d o h a l f - h o u r l y u n m e t e r e d p r o p e r t i e s 2.32. The time periods for the application of unit charges to connections th at are pseudo HH metered are detailed in Annex 1. We have not issued a notice to change the time bands.

A p p l i c a t i o n o f c a p a c i t y c h a r g e s 2.33. The following sections explain the application of capacity charges and exceeded capacity charges.

C h a r g e a b l e c a p a c i t y 2.34. The chargeable capacity is, for each billing period, the MIC/MEC, as detailed below.

2.35. The MIC/MEC will be agreed with us at the time of connection or pursuant to a later change in requirements. Following such an agreement (be it at the ti me of connection or later) no reduction in MIC/MEC will be allowed for a 12 month period.

2.36. Reductions to the MIC/MEC may only be permitted once in a 12 month period. Where MIC/MEC is reduced the new lower level will be agreed with r eference to the level of the customer’s maximum demand. The new MIC/MEC will be applied from the start of the next billing period after the date that the request was received. It should be noted that, where a new lower level is agr eed, the original capacity may not be available in the future without the need for net work reinforcement and associated charges.

2.37. In the absence of an agreement, the chargeable capacity, save for err or or omission, will be based on the last MIC and/or MEC previously agree d by the distributor for the relevant premise’s connection. A customer can seek to a gree or vary the MIC and/or MEC by contacting us using the contact details in section 1.

E x c e e d e d c a p a c i t y 2.38. Where a customer takes additional unauthorised capacity over and ab ove the MIC/MEC, the excess will be classed as exceeded capacity. The exc eeded portion of the capacity will be charged at the excess capacity charge p/kVA/ day rate, based on the difference between the MIC/MEC and the actual c apacity used. This will be charged for the full duration of the month in which the br each occurs.

D e m a n d e x c e e d e d c a p a c i t y

Demand exceeded capacity  max( 2 x 2 2 0 AI  max( RI,RE )  MIC, )

Where:

AI = Active Import (kWh)

RI = Reactive import (kVArh)

RE = Reactive export (kVArh)

MIC = Maximum import capacity (kVA)

2.39. Only reactive import and reactive export values occurring at times of active import are used in the calculation.

2.40. This calculation is completed for every half hour and the maximum va lue from the billing period is applied.

G e n e r a t i o n e x c e e d e d c a p a c i t y

Generation exceeded capacity  max( 2 x 2 2 0 AE  max( RI,RE )  MEC, )

Where:

AE = Active Export (kWh)

RI = Reactive import (kVArh)

RE = Reactive export (kVArh)

MEC = Maximum export capacity (kVA)

2.41. Only reactive import and reactive export values occurring at times of active export are used in the calculation.

2.42. This calculation is completed for every half hour and the maximum va lue from the billing period is applied.

S t a n d b y c a p a c i t y f o r a d d i t i o n a l s e c u r i t y o n s i t e 2 . 4 3 . W h e r e s t a n d b y c a p a c i t y c h a r g e s a r e a p p l i e d , t h e c h a r g e w i l l b e s e t a t t h e s a m e r a t e a s t h a t a p p l i e d t o n o r m a l M I C . W h e r e , a t t h e c u s t o m e r ’ s r e q u e s t , f o r a d d i t i o n a l s e c u r i t y o f s u p p l i e s r e q u i r i n g s t e r i l i s a t i o n o f c a p a c i t y a t t w o d i f f e r e n t s o u r c e s o f s u p p l y , w e r e s e r v e t h e r i g h t t o c h a r g e f o r t h e c a p a c i t y h e l d a t e a c h s o u r c e . M i n i m u m c a p a c i t y l e v e l s 2 . 4 4 . T h e r e i s n o m i n i m u m c a p a c i t y t h r e s h o l d .

A p p l i c a t i o n o f c h a r g e s f o r e x c e s s r e a c t i v e p o w e r 2 . 4 5 . W h e n a n i n d i v i d u a l H H m e t e r e d M P A N ’ s r e a c t i v e p o w e r ( m e a s u r e d i n k V A r h ) a t L V a n d H V D e s i g n a t e d P r o p e r t i e s e x c e e d s 3 3 % o f t o t a l a c t i v e p o w e r ( m e a s u r e d i n k W h ) , e x c e s s r e a c t i v e p o w e r c h a r g e s w i l l a p p l y . T h i s t h r e s h o l d i s e q u i v a l e n t t o a n a v e r a g e p o w e r f a c t o r o f 0 . 9 5 d u r i n g t h e p e r i o d . A n y r e a c t i v e u n i t s i n e x c e s s o f t h e 3 3 % t h r e s h o l d a r e c h a r g e d a t t h e r a t e a p p r o p r i a t e t o t h e p a r t i c u l a r c h a r g e .

2 . 4 6 . P o w e r F a c t o r i s c a l c u l a t e d a s f o l l o w s :

C o s θ = P o w e r F a c t o r

k V A r h

θ k W h

2 . 4 7 . T h e c h a r g e a b l e r e a c t i v e p o w e r i s c a l c u l a t e d a s f o l l o w s :

D e m a n d c h a r g e a b l e r e a c t i v e p o w e r

W h e r e :

A I = A c t i v e i m p o r t ( k W h )

R I = R e a c t i v e i m p o r t ( k V A r h )

R E = R e a c t i v e e x p o r t ( k V A r h )

P A G E 1 3 O F 41 Harlaxton Energy Networks Limited A P R 2 0 1 7 – V 1 . 1

2 . 4 8 . O n l y r e a c t i v e i m p o r t a n d r e a c t i v e e x p o r t v a l u e s o c c u r r i n g a t t i m e s o f a c t i v e i m p o r t a r e u s e d i n t h e c a l c u l a t i o n .

2 . 4 9 . T h e s q u a r e r o o t c a l c u l a t i o n w i l l b e t o t w o d e c i m a l p l a c e s .

2 . 5 0 . T h i s c a l c u l a t i o n i s c o m p l e t e d f o r e v e r y h a l f h o u r a n d t h e v a l u e s s u m m a t e d o v e r t h e b i l l i n g p e r i o d .

G e n e r a t i o n c h a r g e a b l e r e a c t i v e p o w e r 

W h e r e :

A E = A c t i v e E x p o r t ( k W h )

R I = R e a c t i v e I m p o r t ( k V A r h )

R E = R e a c t i v e E x p o r t ( k V A r h )

2 . 5 1 . O n l y r e a c t i v e i m p o r t a n d r e a c t i v e e x p o r t v a l u e s o c c u r r i n g a t t i m e s o f a c t i v e e x p o r t a r e u s e d i n t h e c a l c u l a t i o n .

2 . 5 2 . T h e s q u a r e r o o t c a l c u l a t i o n w i l l b e t o t w o d e c i m a l p l a c e s .

2 . 5 3 . T h i s c a l c u l a t i o n i s c o m p l e t e d f o r e v e r y h a l f h o u r a n d t h e v a l u e s s u m m a t e d o v e r t h e b i l l i n g p e r i o d .

I n c o r r e c t l y a l l o c a t e d c h a r g e s 2 . 5 4 . I t i s o u r r e s p o n s i b i l i t y t o a p p l y t h e c o r r e c t c h a r g e s t o e a c h M P A N / M S I D . T h e a l l o c a t i o n o f c h a r g e s i s b a s e d o n t h e v o l t a g e o f c o n n e c t i o n a n d m e t e r i n g i n f o r m a t i o n . W e a r e r e s p o n s i b l e f o r d e c i d i n g t h e v o l t a g e o f c o n n e c t i o n w h i l e t h e S u p p l i e r d e t e r m i n e s a n d p r o v i d e s t h e m e t e r i n g i n f o r m a t i o n . 2 . 5 5 . G e n e r a l l y , t h e v o l t a g e o f c o n n e c t i o n i s d e t e r m i n e d b y w h e r e t h e m e t e r i n g i s l o c a t e d a n d w h e r e r e s p o n s i b i l i t y f o r t h e e l e c t r i c a l e q u i p m e n t t r a n s f e r s f r o m u s t o t h e c o n n e c t e d c u s t o m e r . T h i s i s n o r m a l l y e s t a b l i s h e d w h e n t h e M P A N / M S I D i s c r e a t e d a n d w i l l i n c l u d e i n f o r m a t i o n a b o u t w h e t h e r t h e M P A N / M S I D i s f o r i m p o r t o r e x p o r t p u r p o s e s . W h e r e a n M P A N / M S I D i s u s e d f o r e x p o r t p u r p o s e s t h e t y p e o f g e n e r a t i o n ( i n t e r m i t t e n t o r n o n - i n t e r m i t t e n t ) w i l l a l s o b e d e t e r m i n e d .

2 . 5 6 . T h e S u p p l i e r p r o v i d e s u s w i t h m e t e r i n g i n f o r m a t i o n w h i c h e n a b l e s u s t o a l l o c a t e c h a r g e s w h e r e t h e r e i s m o r e t h a n o n e c h a r g e p e r v o l t a g e l e v e l . T h i s m e t e r i n g d a t a i s l i k e l y t o c h a n g e o v e r t i m e i f , f o r e x a m p l e , a S u p p l i e r c h a n g e s f r o m a t w o

P A G E 1 4 O F 41 Harlaxton Energy Networks Limited A P R 2 0 1 7 – V 1 . 1

rate meter to a single rate meter.When this happens we will change the allocation of charges accordingly.

2.57. Where it has been identified that a LLFC/charge is likely to be i ncorrectly allocated due to the wrong voltage of connection, (incorrect impor t/export details or an incorrectly noted metering location) then a correction request must be made to us. Requests from persons other than the current Supplie r should be accompanied by a Letter of Authority from the Customer; the existing Supplier must also acknowledge that they are aware that a correction request has been made. Any request must be supported by an explanation of why it is believed that the current charge is wrongly applied along with su pporting information, including, where appropriate photographs of metering posit ions or system diagrams. Any request to correct the current LLFC/charge that also includes a request to backdate the correction must include justification as to why it is considered appropriate to backdate the change.

2.58. If it has been identified that a charge has been incorrectly allocated due to the metering data then a correction request should be made to the Supplier.

2.59. Where we agree that an MPAN/MSID has been assigned incorrectly to the wrong voltage level then we will correct it by allocating the corre ct set of charges for that voltage level. Any adjustment for incorrectly applied c harges will be as follows:

 Any credit or additional charge will be issued to the Supplier/s wh o were effective during the period of the change.

 The correction will be applied from the date of the request, back to the date of the incorrect allocation or, up to the maximum period specified by; the Limitation Act (1980), in England and Wales, which covers a six year p eriod and the Prescription and Limitation (Scotland) Act 1973, which covers a five year period; whichever is the shorter.

2.60. Should we reject the request a justification will be provided to the req uesting Party. 2.61. We shall not unreasonably withhold or delay any agreement to correct the charges applied and would expect to reach agreement within three months from the date of request.

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G e n e r a t i o n c h a r g e s f o r p r e - 2 0 0 5 d e s i g n a t e d E H V p r o p e r t i e s 2.62. Designated EHV Properties that were connected to the distribution system under a pre-2005 connection charging policy are eligible for exemption from UoS charges for generation unless one of the following criteria has been m et:

 25 years have passed since their first energisation/connection date (i.e. Designated EHV Properties with connection agreements dated prio r to 1st April 2005, and for which 25 years has passed since their first energisation/connection date will receive use of system charges for generation from the next charging year following the expiry of their 25 y ears exemption, (starting 1st April), or

 the person responsible for the Designated EHV Property has provided notice to us that they wish to opt in to UoS charges for generation.

If a notice to opt in has been provided there will be no further opportunity to opt out. 2.63. Furthermore, if an exempt customer makes an alteration to its export requirement then the customer may be eligible to be charged for the additional capacity required or energy imported or exported. For example, w here a generator increases its export capacity the incremental increase in export capacity will attract UoS charges as with other non-exempt generators.

Methodology to determine export tariffs for domestic

and small-scale generation

2.64 For small-scale non half hourly metered or aggregated half

hourly metered generation, we apply the same tariff as the

Distribution Services Provider in the Host DNO Area. This

usually includes use of system credits payable by us to the

supplier

Methodology to determine export tariffs for generation

with a maximum export capacity 2.65 For half hourly metered generation that is billed on a site-

specific basis, our tariff has a single component, which is a

p/kVA/day export capacity charge.

2.66 Our methodology to calculate the export capacity charge is

based on the costs of operating an illustrative generation-led

network based on the kind of networks we are developing to

connect generators.

2.67 We estimate the annual cost associated with the illustrative

generation-led network by aggregating:

A) The cost of routine inspections, maintenance and

transformer oil testing;

B) The expectation value of the cost of component

repair and replacement, based on our experience of

failure rates and typical repair/replacement costs.

2.68 The expected costs of scheduled or end-of-life equipment

replacement are not included in this analysis.

2.69 We then estimate the export capacity likely to be serviced by

the illustrative generation-led network. In doing so, we take

account of the possibility of spare capacity arising from the

commissioning of network capacity ahead of the completion

of the construction of some generators served by the

network, and/or the risk of early closure of some generators.

2.70 Dividing the annual cost associated with the illustrative

generation-led network by the export capacity likely to be serviced by the illustrative generation-led network gives us a

£/kVA/year charging rate.

2.71 Our export capacity charge is calculated by converting the

£/kVA/year determined above to p/kVA/day, by dividing it by

3.6525 and rounding to two decimal places.

2.72 We do not pay any use of system credits to half hourly

metered generation that is billed on a site-specific basis. This

reflects the fact that, on our networks, larger-scale

generation is normally connected to a generation-dominated

section of network whose primary purpose is to collect power

from generators, and therefore the logic underpinning CDCM

generation credits is not applicable.

2.73 We do not charge any fixed charge to half hourly metered

generation that is billed on a site-specific basis. The relevant

operation and maintenance costs are covered by our

capacity charge. In the context of a network which is

assumed to be generation-led, we consider that it is fairer

and more cost-reflective to charge for these costs on the

basis of export capacity than on the basis of individual

MPANs or metering points.

2.74 We charge for excess reactive power at the same rate as the

Distribution Services Provider in the Host DNO Area for each

type of generator. Methodology to determine generic import tariffs

2.75 For demand customers supplied through our network at

voltages below 22kV and which fall within the scope of a

generic tariff published by the Distribution Services Provider

in the Host DNO Area, our applicable use of system tariff is

the same as the published tariff that would apply to an

equivalent customer supplied by the Distribution Services

Provider in the Host DNO Area.

2.76 At the time of preparing this statement, the method used by

Distribution Services Providers to determine the relevant use

of system tariffs is called the CDCM, and it applies to all

customers supplied at voltages below 22kV except supplied

at 1kV or more and metered at a transformation substation

with a primary voltage of 22kV or more.

Methodology to determine site-specific import tariffs

2.77 For non-domestic customers supplied through our network at

22kV or more, or where the supply is at 1kV or more at a

substation with a primary voltage of 22kV or more, with the

metering point (or asset boundary in the case of a customer

which is a LDNO network) at the same substation, then our

applicable use of system tariff will be determined on a site-

specific basis. 2.78 To determine this site-specific tariff, we will compute the

following:

A) The tariff that would have applied to the site if the Host

DNO owned the relevant section of our system and used it to

supply the site.

B) The charges (if any) applied to us by other networks

(distribution or transmission) in respect of the supply to the

2.79 Where appropriate, we will set our site-specific tariff to be the

notional tariff that would have applied to the site if the Host

DNO owned the relevant section of our system. This would

be consistent with our methodology for setting generic

demand tariffs.

2.80 However, this notional tariff approach might not be always

appropriate, because:

A) We might not always be able to estimate the tariff that

would have applied to the site if the Host DNO owned the

relevant section of our system, because making such

estimates is dependent on the provision of information by the

Host DNO, which is out of our control.

B) The design and implementation of the Host DNO’s

charging methodology is also out of our control, there is a

risk that the notional tariff might not cover the charges

applied to us by any other networks, or might give an

inadequate margin over these charges. 2.81 If we determine that the notional tariff approach is not

appropriate for a site, then we will set the tariff for the site as

the sum of:

OF 4 1 Harlaxton Energy Networks Limited APR 2016 – V1.1 A) The pass-through of the charges applied to us by any

other networks.

B) The costs associated with the fulfillment of our

obligation to provide a safe and secure distribution system to

supply the site. Where assets are used in the supply, we will

set cost to reflect depreciation plus a return of 7.6 per cent a

year on the modern equivalent value of these assets. Where

costs or assets are used for supplies to more than one site,

we will apportion the costs to determine the share to be

borne by the use of system tariff for the site. We will review

the 7.6 per cent rate of return as part of our annual review of

this methodology. The current figure is based on the rate of

return determined by Ofgem for independent gas

transporters.

P r o v i s i o n o f b i l l i n g d a t a 2.64. Where HH metering data is required for UoS charging and this is not provided in accordance with the BSC or the Distribution Connection and Use of System Agreement (DCUSA), such metering data shall be provided to us by the Us er of the system in respect of each calendar month within five working day s of the end of that calendar month.

2.65. The metering data shall identify the amount consumed and/or produced in each half hour of each day and shall separately identify active and reactive import and export. Metering data provided to us shall be consistent with that received through the metering equipment installed.

2.66. Metering data shall be provided in an electronic format specified by u s from time to time and, in the absence of such specification, metering data shall be provided in a comma-separated text file in the format of Master Regis tration Agreement (MRA) data flow D0036 (as agreed with us). The data m ust be transmitted via the industry standard Data Transfer Network (http://www.electralink.co.uk/DTS/overview).

2.67. We require details of reactive power imported or exported to be provide d for all Measurement Class C and E sites. It is also required for CVA sites and Exe mpt Distribution Network boundaries with difference metering. We reserve t he right to levy a charge on Users who fail to provide such reactive data. In o rder to estimate missing reactive data, a power factor of 0.9 lag will be applie d to the active consumption in any half hour.

O u t o f a r e a u s e o f s y s t e m c h a r g e s 2.68. HARL does not have a Distribution Service Area

L i c e n s e d d i s t r i b u t i o n n e t w o r k o p e r a t o r c h a r g e s 2.69. Licensed Distribution Network Operator (LDNO) charges are applied to LDNOs who operate Embedded Networks within our Distribution Service Area.

2.70. The charge structure for LV and HV Designated Properties embe dded in networks operated by LDNOs will mirror the structure of the All-the-way Ch arge and is dependent upon the voltage of connection of each embedded netwo rk to the host DNO’s network. The same charge elements will apply as tho se that match the LDNO’s end customer charges. The relevant charge structu res are set out in Annex 4.

2.71. Where an MPAN has an invalid Settlement combination, the ‘LDN O HV: Domestic Unrestricted’ fixed and unit charges will be applied as default unti l the invalid combination is corrected. Where there are multiple SSC/TPR combinations, the default ‘LDNO HV: Domestic Unrestricted’ fixed and unit charges will be applied for each invalid TPR combination.

2.72. The charge structure for Designated EHV Properties embedded in net works operated by LDNOs will be calculated individually using the EDC M. The relevant charge structures are set out in Annex 2.

2.73. For Nested Networks the relevant charging principles set out in DCUSA Schedule 21 will apply. http://www.dcusa.co.uk/SitePages/Documents/Documents.aspx,

L i c e n c e e x e m p t d i s t r i b u t i o n n e t w o r k s 2.74. The Electricity and Gas (Internal Market) Regulations 2011 introdu ced new obligations on owners of licence exempt distribution networks (so metimes

called private networks) including a duty to facilitate access to electrici ty and gas suppliers for customers within those networks.

2.75. When customers (both domestic and commercial) are located within a licence exempt distribution network and require the ability to choose their own supplier this is called ‘third party access’. These embedded customers will req uire an MPAN so that they can have their electricity supplied by a Supplier of their choice.

2.76. Licence exempt distribution networks owners can provide third party a ccess using either full settlement metering or the difference metering approach.

F u l l s e t t l e m e n t m e t e r i n g 2.77. This is where a licence exempt distribution network is set up so that each embedded installation has an MPAN and Metering System and therefo re all customers purchase electricity from their chosen Supplier. In this case ther e are no Settlement Metering Systems at the boundary between the licensed Distribution System and the exempt distribution network.

2.78. In this approach our UoS charges will be applied to each MPAN.

D i f f e r e n c e m e t e r i n g 2.79. This is where one or more, but not all, customers on a licence exempt distribution network choose their own Supplier for electricity supply to their premise. Under this approach the customers requiring third party access o n the exempt distribution network will have their own MPAN and must have a HH Metering System.

2.80. Unless agreed otherwise, our UoS charges will be applied using gross settlement/net settlement or both.

G r o s s s e t t l e m e n t

2.81. Where one of our MPANs (prefix 29) is embedded within a licence exempt distribution network connected to our Distribution System, and difference metering is in place for Settlement purposes and we receive gross measurement data for the boundary MPAN, we will continue to c harge the boundary MPAN Supplier for use of our Distribution System. No charges wi ll be levied by us directly to the Customer or Supplier of the embedded M PAN(s) connected within the licence exempt distribution network .

2.82. We require that gross metered data for the boundary of the con nection is provided to us. Until a new industry data flow is introduced for the sending of such gross data, gross metered data shall:

 be provided in a text file in the format of the D0036 MRA data flow;

 the text file shall be emailed to [email protected]

 the title of the email should also contain the phrase “gross d ata for difference metered private network”.

 the text file and the title of the email shall contain the metering ref erence specified by us in place of the Settlement MPAN, i.e. a dummy alphanumeric reference to enable the relating of the gross metere d data to a given boundary MPAN;

 the text filename shall be formed of the metering reference specified by us followed by a hyphen and followed by a timestamp in the format YYYYMMDDHHMMSS and followed by “.txt”; and

2.83. For the avoidance of doubt, the reduced difference metered measurement data for the boundary connection that is to enter Settlement should continu e to be sent using the Settlement MPAN.

N e t S e t t l e m e n t

2.84. Where one of our MPANs (prefix 29) is embedded within an licence e xempt distribution network connected to one of our distribution systems, and difference metering is in place for Settlement purposes, and we do n o t receive gross measurement data for the boundary MPAN, we will charge the boundary MPAN Supplier based on the net measurement for use of our Di stribution System. Charges will also be levied directly to the Supplier of the em bedded MPAN(s) connected within the licence exempt distribution network based o n the actual data received.

2.85. The charges applicable for an embedded MPAN are unit charges only . These will be the same values as those at the voltage of connection to the l icence exempt distribution network and are shown in Annex 1. The fixed char ge and capacity charge, at the agreed MIC/MEC of the boundary MPAN, will be charged to the boundary MPAN supplier.

3 . S c h e d u l e o f c h a r g e s f o r u s e o f t h e d i s t r i b u t i o n s y s t e m

3.1. Tables listing the charges for the distribution of electricity for UoS are publi shed in the annexes to this document.

3.2. These charges are also listed in a spreadsheet which is published with this statement and can be downloaded from www.harlaxtonenergynetworks.co.uk

3.3. Annex 1 contains charges applied to LV and HV Designated Properties.

3.4. Annex 2 contains the charges applied to our Designated EHV Properti es and charges applied to LDNOs for Designated EHV Properties connected within their embedded Distribution System.

3.5. Annex 3 contains details of any preserved and additional charges that are valid at this time. Preserved charges are mapped to an appropriate charge and are closed to new customers.

3.6. Annex 4 contains the charges applied to LDNOs in respect of L V and HV Designated Properties connected in their embedded Distribution System.

4 . S c h e d u l e o f l i n e l o s s f a c t o r s

R o l e o f l i n e l o s s f a c t o r s i n t h e s u p p l y o f e l e c t r i c i t y 4.1. Electricity entering or exiting our Distribution System is adjusted to take ac count of energy that is lost8 as it is distributed through the network. This adj ustment does not affect distribution charges but is used in energy settlement t o take metered consumption to a notional grid supply point so that suppliers’ purchases take account of the energy lost on the Distribution System.

4.2. We are responsible for calculating the Line Loss Factors9 (LLFs) and providing these to Elexon. Elexon is the company that manages the BSC. This code covers the governance and rules for the balancing and settlement arrangements.

4.3. LLFs are used to adjust the metering system volumes to take account of lo sses on the distribution network.

C a l c u l a t i o n o f l i n e l o s s f a c t o r s 4.4. LLFs are calculated in accordance with BSC procedure 128. BSCP 12 8 sets out the procedures and principles by which our LLF methodology must comply. It also defines the procedure and timetable by which LLFs are review ed and submitted.

4.5. LLFs are calculated for a set number of time periods during the year using either a generic method or a site-specific method. The generic method is used for sites connected at LV or HV and the site-specific method is used for sites connected at EHV or where a request for site- specific LLFs has bee n agreed. Generic LLFs will be applied as a default to all new EHV sites until s ufficient data is available for a site-specific calculation.

4.6. The definition of EHV used for LLF purposes differs from the definition use d for defining Designated EHV Properties used in the EDCM. The definition used for LLF purposes can be found in our LLF methodology. 8 Energy can be lost for technical and non-technical reasons and losses normally occur by heat dissipation through po wer flowing in conductors and transformers. Losses can also reduce if a customer’s action reduces power flowing in the distribution network. This might happen when a customer generates electricity and the produced energy is consumed locally. 9 Also referred to as Loss Adjustment Factors.

4.7. The Elexon website (http://www.elexon.co.uk/reference/technical- operations/losses/) contains more information on LLFs. This page also has links to BSCP 128 and to our LLF methodology.

P u b l i c a t i o n o f L i n e L o s s F a c t o r 4.8. The LLFs used in Settlement are published on the Elexon portal website, www.elexonportal.co.uk. The website contains the LLFs in standard in dustry data formats and in a summary form. A user guide with details on regi stering and using the portal is also available.

4.9. The BSCP128 sets out the timetable by which LLFs are submitted and audi ted. The submission and audit occurs between September and December i n the year prior to the LLFs becoming effective. Only after the completion of the audit at the end of December and BSC approval are the final LLFs published.

4.10. Illustrative LLFs based on the latest LLFs are provided in Annex 5 of this statement. These illustrative LLFs are provided with reference to the metered voltage or associated LLFC for generic LLFs and by reference to the LLFC s for site specific LLFs. Each LLF is applicable to a defined time period.

5 . N o t e s f o r D e s i g n a t e d E H V P r o p e r t i e s

E D C M n e t w o r k g r o u p c o s t s 5.1. HARL does not currently have any designated EHV properties.

5.2. These are illustrative of the modelled costs at the time that this statement was published. A new connection will result in changes to current network utilisations, which will then form the basis of future prices: the charge determined in this statement will not necessarily be the charge in sub sequent years because of the interaction between new and existing network connections and any other changes made to our Distribution System which may affect charges.

C h a r g e s f o r n e w D e s i g n a t e d E H V P r o p e r t i e s 5.3. Charges for any new Designated EHV Properties calculated after publicati on of the current statement will be published in an addendum to that state ment as and when necessary.

5.4. The form of the addendum is detailed in Annex 6 to this statement.

5.5. The addendum will be sent to relevant DCUSA parties and published as a revised ‘Schedule of Charges and Other Tables’ spreadsheet on our website. The addendum will include charge information that under endurin g circumstances would be found in Annex 2 and line loss factors t hat would normally be found in Annex 5.

5.6. The new Designated EHV Properties charges will be added to Annex 2 in the next full statement released.

C h a r g e s f o r a m e n d e d D e s i g n a t e d E H V P r o p e r t i e s 5.7. Where an existing Designated EHV Property is modified and energise d in the charging year, we may revise the EDCM charges for the modified De signated EHV Property. If revised charges are appropriate, an addendum will b e sent to relevant DCUSA parties and published as a revised ‘Schedule of Char ges and Other Tables' spreadsheet on our website. The modified Designate d EHV Property charges will be added to Annex 2 in the next full statement releas ed.

D e m a n d - s i d e m a n a g e m e n t 5.8. HARL does not offer ‘demand side management’.

6 . E l e c t r i c i t y d i s t r i b u t i o n r e b a t e s

6.1. We have neither given nor announced any DUoS rebates to Users in the 12 months preceding the date of publication of this revision of the statement.

7 . A c c o u n t i n g a n d a d m i n i s t r a t i o n s e r v i c e s

7.1. We reserve the right to impose payment default remedies. The remedies ar e as set out in DCUSA where applicable or else as detailed in the fo llowing paragraph.

7.2. If any invoices that are not subject to a valid dispute remain unpaid on the due date, late payment interest (calculated at base rate plus 8%) and administr ation charges may be imposed.

7.3. Our administration charges are detailed in the following table. These c harges are set at a level which is in line with the Late Payment of Commerci al Debts Act; 8 . C h a r g e s f o r e l e c t r i c a l p l a n t p r o v i d e d a n c i l l a r y t o t h e g r a n t o f u s e o f s y s t e m

8.1. None

A p p e n d i x 1 - G l o s s a r y

1.1. The following definitions, which can extend to grammatical variations and cognate expressions, are included to aid understanding: PAGE 2 9 OF 41 Harlaxton Energy Networks Limited APR 2017 – V1.1 PAGE 30 OF 41 Harlaxton Energy Networks Limited APR 2017 – V1.1 PAGE 31 OF 4 1 Harlaxton Energy Networks Limited APR 2017 – V1.1 PAGE 32 OF 4 1 Harlaxton Energy Networks Limited APR 2017 – V1.1

OF 41 Harlaxton Energy Networks Limited APR 2017 – V1.1 10 Balancing and Settlement Code Procedures are available from http://www.elexon.co.uk/pages/bscps.aspx

A p p e n d i x 2 - G u i d a n c e n o t e s 1 1

B a c k g r o u n d 1.1. The electricity bill from your Supplier contains an element of charge t o cover electricity distribution costs. This distribution charge covers the cost of operating and maintaining a safe and reliable Distribution System that form s the ‘wires’ that transport electricity between the national transmission sys tem and end users such as homes and businesses. Our Distribution System in cludes overhead lines, underground cables, as well as substations and transforme rs.

1.2. In most cases, your Supplier is invoiced for the distribution charge an d this is normally part of your total bill. In some cases, for example business u sers, the supplier may pass through the distribution charge as an identifiable line ite m on the electricity bill.

1.3. Where electricity is generated at a property your Supplier may receive a credit for energy that is exported on to the Distribution System. These credi ts are intended to reflect that the exported generation may reduce the need for traditional demand led reinforcement of the Distribution System.

1.4. Understanding your distribution charges could help you reduce your c osts and increase your credits. This is achieved by understanding the components o f the charge to help you identify whether there may be opportunities to cha nge the way you use the Distribution System.

M e t e r p o i n t a d m i n i s t r a t i o n 1.5. We are responsible for managing the electricity supply points that are connected to our Distribution System. Typically every supply point is i dentified by a Meter Point Administration Number (MPAN). A few supply points may have more than one MPAN depending on the metering configuration (e.g. a school which may have an MPAN for the main supply and a MPAN for catering).

1.6. The full MPAN is a 21 digit number, preceded by an ‘S’. The MPAN applicable to a supply point is found on the electricity bill from your Supplier. Thi s number enables you to establish who your electricity distributor is, details of the characteristics of the supply and importantly the distribution charges t hat are applicable to your premise.

11 These guidance notes are provided for additional information and do not form part of the application of charges.

5 OF 41 Harlaxton Energy Networks Limited APR 2017 – V1.1 1 . 7 . T h e 2 1 - d i g i t n u m b e r i s n o r m a l l y p r e s e n t e d i n t w o s e c t i o n s a s s h o w n i n t h e f o l l o w i n g d i a g r a m . T h e t o p s e c t i o n i s s u p p l e m e n t a r y d a t a w h i c h g i v e s i n f o r m a t i o n a b o u t t h e c h a r a c t e r i s t i c s o f s u p p l y , w h i l e t h e b o t t o m ‘ c o r e ’ i s t h e u n i q u e i d e n t i f i e r .

F u l l M P A N d i a g r a m

1 . 8 . G e n e r a l l y , y o u w i l l o n l y n e e d t o k n o w t h e D i s t r i b u t o r I D a n d l i n e l o s s f a c t o r c l a s s t o i d e n t i f y t h e d i s t r i b u t i o n c h a r g e s f o r y o u r p r e m i s e . H o w e v e r , t h e r e a r e s o m e p r e m i s e s w h e r e c h a r g e s a r e s p e c i f i c t o t h a t s i t e . I n t h e s e i n s t a n c e s t h e c h a r g e s a r e i d e n t i f i e d b y t h e c o r e M P A N . T h e D i s t r i b u t o r I D f o r Harlaxton Energy Networks Limited i s 2 9 . O t h e r D i s t r i b u t o r I D s c a n b e r e f e r e n c e d i n t h e g l o s s a r y .

1 . 9 . A d d i t i o n a l l y i t c a n b e u s e f u l t o u n d e r s t a n d t h e p r o f i l e c l a s s p r o v i d e d i n t h e s u p p l e m e n t a r y d a t a . T h e p r o f i l e c l a s s w i l l b e a n u m b e r b e t w e e n 0 0 a n d 0 8 . T h e f o l l o w i n g l i s t p r o v i d e s d e t a i l s o f t h e a l l o c a t i o n o f p r o f i l e c l a s s e s t o t y p e s o f c u s t o m e r s :

 ‘ 0 1 ’ – D o m e s t i c c u s t o m e r s w i t h u n r e s t r i c t e d s u p p l y  ‘ 0 2 ’ – D o m e s t i c c u s t o m e r s w i t h r e s t r i c t e d l o a d , f o r e x a m p l e o f f - p e a k h e a t i n g  ‘ 0 3 ’ – N o n - d o m e s t i c c u s t o m e r s w i t h u n r e s t r i c t e d s u p p l y  ‘ 0 4 ’ – N o n - d o m e s t i c c u s t o m e r s w i t h r e s t r i c t e d l o a d , f o r e x a m p l e o f f - p e a k h e a t i n g  ‘ 0 5 ’ – N o n - d o m e s t i c m a x i m u m d e m a n d c u s t o m e r s w i t h a L o a d F a c t o r o f l e s s t h a n 2 0 %  ‘ 0 6 ’ – N o n - d o m e s t i c m a x i m u m d e m a n d c u s t o m e r s w i t h a L o a d F a c t o r b e t w e e n 2 0 % a n d 3 0 %

P A G E 36 O F 41 Harlaxton Energy Networks Limited A P R 2 0 1 7 – V 1 . 1

 ‘07’ – Non-domestic maximum demand customers with a Load Factor between 30% and 40%  ‘08’ – Non-domestic maximum demand customers with a Load Factor over 40% or non-half-hourly metered generation customers  ‘00’ – Half-hourly metered demand and generation customers 1.10. Unmetered Supplies will be allocated to profile class 01, 08 and 00 depending on the type of load or the measurement method of the load.

1.11. The allocation of the profile class will affect your charges. If you feel t hat you have been allocated the wrong profile class, please contact your Sup plier as they are responsible for this.

Y o u r c h a r g e s 1.12. All distribution charges that relate to our Distributor ID 29 are provide d in this statement (please refer to attached Annexes). 1.13. You can identify your charges by referencing your line loss factor clas s, from Annex 1. If the MPAN is for a Designated EHV Property then the charges will be found in Annex 2. In a few instances, the charges maybe contain ed in Annex 3. When identifying charges in Annex 2, please note that some line loss factor classes have more than one charge. In this instance you will n eed to select the correct charge by cross referencing with the core MPAN pr ovided in the table.

1.14. Once you have identified which charge structure applies to your MPA N then you will be able to calculate an estimate of your distribution charge u sing the calculator provided in the spreadsheet ‘Schedule of charges and other tables’ found in the sheet called ‘Charge Calculator’. This spreadsheet c an be downloaded from www.harlaxtonenergynetworks.co.uk

R e d u c i n g y o u r c h a r g e s 1.15. The most effective way to reduce your energy charges is to red uce your consumption by switching off or using more energy efficient appliances. However, there are also other potential opportunities to reduce your distri bution charges; for example, it may be beneficial to shift demand or generati on to a better time period. Demand use is likely to be cheaper outside t he peak periods and generation credits more beneficial, although the ability to directly benefit will be linked to the structure of your supply charges.

1.16. The calculator mentioned above provides the opportunity to establish a for ecast of the change in distribution charges that could be achieved if you ar e able to change any of the consumption related inputs.

R e a c t i v e p o w e r a n d r e a c t i v e p o w e r c h a r g e s 1.17. Reactive power is a separately charged component of connections that are half-hourly metered. Reactive power charges are generally avoidable if ‘best practice’ design of the properties’ electrical installation has been provi ded in order to maintain a power factor between 0.95 and unity at the Metering Poi nt.

1.18. Reactive Power (kVArh) is the difference between working power (active power measured in kW) and total power consumed (apparent power me asured in kVA). Essentially it is a measure of how efficiently electrical power is transported through an electrical installation or a Distribution System.

1.19. Power flowing with a power factor of unity results in the most efficient loadin g of the Distribution System. Power flowing with a power factor of less tha n 0.95 results in much higher losses in the Distribution System, a need to po tentially provide higher capacity electrical equipment and consequently a highe r bill for you the consumer. A comparatively small improvement in power facto r can bring about a significant reduction in losses since losses are proportional to the square of the current.

1.20. Different types of electrical equipment require some ‘reactive power’ in addition to ‘active power’ in order to work effectively. Electric motors, transform ers and fluorescent lighting, for example, may produce poor power factors due to the nature of their inductive load. However, if good design practice is app lied then the poor power factor of appliances can be corrected as near as poss ible to source. Alternatively poor power factor can be corrected centrally near to the meter.

1.21. There are many advantages that can be achieved by correcting poor power factor. These include: reduced energy bills through lower reactive charges, lower capacity charges and reduced power consumption and reduced voltage drop in long cable runs.

S i t e - s p e c i f i c E D C M c h a r g e s 1.22. A site classified as a Designated EHV Property is subject to a locational based charging methodology (referred to as EDCM) for higher voltage netwo rk users. Distributors use two approved approaches: Long Run Incremental Cos t Pricing

(LRIC) and Forward Cost Pricing (FCP) and we mirror whichever appr oach is used by the incumbent distributor in the distribution services area. Th e EDCM will apply to Customers connected at Extra High Voltage or connected at High Voltage and metered at a high voltage substation.

1.23. EDCM charges are site-specific, reflecting the degree to which the loc al and higher voltage networks have the capacity to serve more demand or gener ation without the need to upgrade the electricity infrastructure. The cha rges also reflect the networks specifically used to deliver the electricity to the sit e as well as the usage at the site. Generators with non-intermittent output and deemed to be providing beneficial support to our networks may qualify to receive payment.

1.24. The charges under the EDCM comprise of the following individual compon ents:

a) F i x e d c h a r g e - This charge recovers operational costs associated with th ose connection assets that are provided for the ‘sole’ use of the custom er. The value of these assets is used as a basis to derive the charge.

b) C a p a c i t y c h a r g e ( p e n c e / k V A / d a y ) - This charge comprises the rel evant FCP/LRIC component, the National Grid Electricity Transmission cost and other regulated costs.

Capacity charges are levied on the MIC, MEC, and any exceeded capacity. You may wish to review your MIC or MEC periodically to ensure it r emains appropriate for your needs as you may be paying for more capacity t han you require. If you wish to make changes contact us via the details in par agraph 1.12

The FCP/LRIC cost is locational and reflects our assessment of future network reinforcement necessary at voltage of connection (local) and beyo nd at all higher voltages (remote) relevant to the customer’s connection. This r esults in the allocation of higher costs in more capacity congested parts of the network reflecting the greater likelihood of future reinforcement in these areas, and the allocation of lower costs in less congested parts of the network. The local FCP/LRIC cost is included in the capacity charge.

Our regulated costs include direct and indirect operational costs and a residual amount to ensure recovery of our regulated allowed revenue. The capacity charge recovers these costs using the customer usage profile and the relevant

assets being used to transport electricity between the source substatio n and customer’s Metering Point.

c) S u p e r - r e d u n i t c h a r g e ( p e n c e / k W h ) - This charge recovers the remote FCP/LRIC component. The charge is positive for import and negative for ex port which means you can either reduce your charges by minimising consumpti on or increasing export at those times. The charge is applied on consumpti on during the Super-red time period as detailed in Annex 2.

1.25. Future charge rates may be affected by consumption during the Super-red period. Therefore reducing consumption in the Super-red time period may be beneficial.

1.26. R e a c t i v e P o w e r -The EDCM does not include a separate charge comp onent for any reactive power flows (kVAr) for either demand or generation. H owever, the EDCM charges do reflect the effect on the network of the customer’s p ower factor, for example unit charges can increase if your site power factor is poor (lower than 0.95). Improving your site’s power factor will also red uce the maximum demand (kVA) for the same power consumed in kW thus pr oviding scope to reduce your agreed capacity requirements.

A n n e x 1 - S c h e d u l e o f c h a r g e s f o r u s e o f t h e d i s t r i b u t i o n s y s t e m b y L V a n d H V D e s i g n a t e d P r o p e r t i e s

A n n e x 2 - S c h e d u l e o f c h a r g e s f o r u s e o f t h e d i s t r i b u t i o n s y s t e m b y D e s i g n a t e d E H V P r o p e r t i e s ( i n c l u d i n g L D N O s w i t h D e s i g n a t e d E H V P r o p e r t i e s / e n d - u s e r s )

A n n e x 3 - S c h e d u l e o f c h a r g e s f o r u s e o f t h e d i s t r i b u t i o n s y s t e m b y p r e s e r v e d / a d d i t i o n a l L L F c l a s s e s

A n n e x 4 - C h a r g e s a p p l i e d t o L D N O s w i t h L V a n d H V e n d - u s e r s

A n n e x 5 - S c h e d u l e o f l i n e l o s s f a c t o r s

A n n e x 6 - A d d e n d u m t o c h a r g i n g s t a t e m e n t d e t a i l i n g c h a r g e s f o r n e w D e s i g n a t e d E H V P r o p e r t i e s

As HARL operates across all DNO areas, spreadsheets for the Annexes d etailed above have been created for each DNO area, and are available to downloa d from www.harlaxtonenergynetworks.co.uk or can be requested by email to [email protected]. PAGE 41 OF 41 Harlaxton Energy Networks Limited APR 2017 – V1.1