ENA Open Networks Project Workstream 1: Product 1 · The report consists of four sections,...

The Voice of the Networks

ENA Open Networks Project

Workstream 1: Product 1

Mapping current SO, TO and DNO processes

12th June 2017

Energy Networks Association

Document Ref: TDWS1P1

Restriction: None

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Executive Summary

Product 1 of ENA Open Networks Project (Workstream 1) seeks to capture the data

and processes underlying the DNOs and SO/TOs operational and investment

planning, including the role of ancillary services and customer connections. The

interface between DNOs and SO/TOs is critical for the effective development of these

plans and as such the Grid Code defines firm procedures to facilitate the

collaboration between the organisations.

The investment planning process involves an exchange of data between the SO and

DNOs. The SO submits an equivalent model of the transmission network to DNOs

(Week 42 model) which then feeds into the DNOs investment planning. DNOs merge

this with their model and produce a set of data to be submitted back to the SO (Week

24). Week 24 submissions contains information about past and forecasted demand

on agreed dates and times, as well as details on a reduced version of the distribution

network.

DNO investment planning makes use of historical demand data as well as information

related to economic growth within their area of operation. Customer connection

requests, network limitations and condition of assets are also taken into account.

Operation planning teams from SO, TOs and DNOs work closely together in order to

develop their operational plan. The Grid Code, again, defines strict processes with

the aim to coordinate the SO, TOs and DNOs outage planning and optimise whole

system operation without compromising its security.

DNO operational planning focuses on outages required by different parties including

the SO/TOs, customers and internal DNO teams. Outage planners consider a number

of factors before approving an outage and prioritize the security of supply.

Customers apply for connection to transmission or distribution network depending

on the size of their generation or demand. The TOs and DNOs run a set of studies and

check to accommodate customer’s request at least cost but without compromising

the system’s security. A process called SOW is in place to manage the interface

between the transmission and distribution networks where connections at the latter

are deemed to have the potential to impact the transmission system.

The SO utilises a range of services to support secure and economic system

operation. These services, traditionally supplied by transmission-connected

generators only, are increasingly being sourced from DER too.

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Document Control

Version Issue Date Author Comments

1 19/05/2017 Draft reviewed by Working Group

2 12/06/2017 Comments incorporated

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Contents

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

Document Control ............................................................................................................... 3

Contents .............................................................................................................................. 4

Acronyms ................................................................................. Error! Bookmark not defined.

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

2. Operational Planning ............................................................................................... 10

2.1 SO/DNO Interface Process ............................................................................... 10

2.1.1 Information provided by the SO to DNOs ................................................. 10

2.1.2 Information provided by DNOs to SO ....................................................... 11

2.1.3 Reviews ................................................................................................... 12

2.2 DNO Outage Planning ...................................................................................... 12

2.3 TO/SO Operational Planning ............................................................................ 14

3. Investment Planning ................................................................................................ 15

3.1 TO/SO/DNO Interface Process ......................................................................... 15

3.1.1 Week 24 submission (DNO to SO) .......................................................... 15

3.1.2 Week 42 submission (SO to DNO) .......................................................... 19

3.2 DNO investment planning ................................................................................. 20

3.2.1 Planning Assumptions/Information model ................................................ 20

3.2.2 Planning Load Estimates (PLE) ............................................................... 21

3.2.3 Planning .................................................................................................. 21

3.2.4 Long Term Development Statement (LTDS) ............................................ 23

3.3 TSO Investment Planning (National Grid) ......................................................... 24

3.3.1 Investment Process & Investment Types ................................................. 24

3.3.2 Planning Information and Assumptions .................................................... 25

3.3.3 Network Options Assessment .................................................................. 26

3.3.4 Main DNO and Whole System Interactions .............................................. 27

3.4 TOs/GBSO Interface Investment Planning ........................................................ 27

4. Customer connection process ................................................................................ 28

4.1 Transmission customers ................................................................................... 28

4.1.1 Generator Connections ............................................................................ 28

4.1.2 Demand connections ............................................................................... 31

4.1.3 Overlap of criteria between generation and demand connections ............ 32

4.1.4 Design variation ....................................................................................... 32

4.2 Distribution customers ...................................................................................... 32

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4.3 Statement of Works Process (DNO/TSO Connections) ..................................... 34

5. The SO Process for Developing and Procuring Services ..................................... 36

Appendices ....................................................................................................................... 39

A Operational Planning maps .................................................................................... 40

A.1 Operational Planning SO/DNO Interface ........................................................... 40

A.2 DNO Operational Planning ................................................................................ 42

B Investment Planning maps ...................................................................................... 43

B.1 Week 24 submission ......................................................................................... 43

B.2 DNO Investment Planning ................................................................................ 44

B.3 TSO Investment Planning ................................................................................. 45

B.4 NOA Process .................................................................................................... 46

C Customer Connection Maps ......................................................................................... 51

C.1 Statement of Works process ............................................................................. 51

C.2 Appendix G process (England and Wales) ........................................................ 52

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Glossary

ACS Average Cold Spell

AHS Average Hot Spell

ANM Active Network Management

BEGA Bilateral Embedded Generation Agreement

BELLA Bilateral Embedded Licence Exemptible Large Power Station Agreement

BM Balancing Mechanism

BSP Bulk Supply Point

CNAIM Common Network Asset Indices Methodology

CUSC Connection and Use of System Code

DER Distributed Energy Resources

DG Distributed Generator

DNO Distribution Network Operator

DSO Distribution System Operator

DSR Demand Side Response

DTU Demand Turn-up

EFR Enhanced Frequency Response

ENA Energy Network Association

ERPS Enhanced Reactive Power Services

EWAP Eight Week Ahead Programme

FCDM Frequency Control by Demand Management

FES Future Energy Scenarios

FFR Fast Frequency Response

FiT Feed in Tariff

FR Fast Reserve

GB Great Britain

GBSO Great Britain System Operator

GSP Grid Supply Point

HI Health Index

HV High Voltage

HVDC High Voltage Direct Current

JTPM Joint Technical Planning Meeting

LI Load Index

LRR Load Related Reinforcement

LTDS Long Term Development Statement

LV Low Voltage

MD Maximum Demand

MITS Main Interconnected Transmission System

NDP Network Development Process

NG National Grid

NGET National Grid Electricity Transmission

NOA Network Options Assessment

OC Operation Code

OFTO Offshore Transmission Owner

OP Outage Planning

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ORPS Obligatory Reactive Services

OTSUA Offshore Transmission System User Assets

PLE Planning Load Estimate

POC Point of Connection

RO Renewable Obligation

SFTP SSH File Transfer Protocol

SHET Scottish Hydro Electric Transmission

SLD Single Line Diagram

SOW Statement of Works

SPT Scottish Power Transmission

SQSS Security and Quality of Supply Standard

SSE Scottish Hydro Electric

STC System Operator - Transmission Owner Code

STOR Short Term Operating Reserve

TEC Transmission Entry Capacity

TO Transmission Operator

TOGA Transmission Outage and Availability

(T)SO Transmission System Operator

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1. Introduction

This report is the output of Product 1 from the ENA Open Networks Project working group / Workstream 1. It captures processes and data that underlie the DNO and SO/TO investment and operational planning as well as the interface between them. Process maps have been developed to improve the understanding of the given information.

The report consists of four sections, Investment Planning, Operational Planning, Customer Connections and Ancillary Services. Each section provides details on critical steps that individual organisations follow to plan the development and operation of their networks.

The interface between SO/TO and DNOs is key to the planning process and as such explicitly dictated by the Grid Code. The diagram below is a good representation of this interface and the Grid Code sections referring to it. The four areas represent Asset Management and Operations within a DNO and TO/SO while the arrows connecting the areas reflect the associated data and processes.

GR

ID

CO

DE

DA

TA E

XC

HA

NG

E IN

TER

FAC

E

Interfaces for Grid Code Standard Planning Data exchange

INV

ES

TM

EN

T P

LA

NN

ING

OP

ER

AT

ION

S

NETWORK OPERATOR (14)Investment Planning

TRANSMISSION

OWNERS

NGET

SPT

SHETL

NGET SYSTEM

OPERATORNETWORK OPERATOR (14)

Operations

DISTRIBUTION TRANSMISSION

Joint Technical Planning Liaison Meetings for further SPD planning data (PC.A.2.1.4)

Grid C

ode S

tanda

rd P

lannin

g D

ata

As

required for

Invest

ment P

lannin

g

SO

– T

Os

LIA

ISO

N

Indiv

idual D

NO

Lia

ison

and D

iscu

ssio

n

NB Grid Code does not

provide data from

National Grid to Network Operator

for asset investment planning

purposes (load f low infeeds)

Joaquin Jimenez Issue 14.0

April 2014

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There are fourteen DNOs connected in the GB system who are responsible for developing and

maintaining the regional distribution networks:

DNO Area Company

1 East England UK Power Networks

2 East Midlands Western Power Distribution

3 London UK Power Networks

4 North Wales, Merseyside and Cheshire SP Energy Networks

5 West Midlands Western Power Distribution

6 North East England Northern Powergrid

7 North West England Electricity North West

8 North Scotland SSEN (Scottish Hydro Electric)

9 South Scotland SP Energy Networks

10 South East England UK Power Networks

11 Southern England SSEN (Southern Electric)

12 South Wales Western Power Distribution

13 South West England Western Power Distribution

14 Yorkshire Northern Powergrid

The GB onshore transmission system is owned by three regional transmission companies:

• National Grid Electricity Transmission plc (NGET) for England and Wales (above

132kV)

• Scottish Power Transmission Limited for southern Scotland (132kV and above)

• Scottish Hydro Electric Transmission plc for northern Scotland and the Scottish islands

groups (132kV and above)

These companies (TO - Transmission Owners) are permitted to develop, operate and maintain a high voltage system within their own distinct onshore transmission areas.

Offshore Transmission Owners (OFTOs) are not considered in this study.

National Grid Electricity Transmission plc (NGET) undertakes the role of the System Operator (SO) for the GB transmission system. The SO is responsible for ensuring the stable and secure operation of the whole transmission system.

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2. Operational Planning

2.1 SO/DNO Interface Process

The following diagram illustrates the interaction between the SO and DNOs for exchanging operational data as required by the Grid Code. A more detailed diagram with associated timelines can be found in Appendix A.

Operational Planning SO/DNO Interface Point

Sho

rt T

erm

2-5

year

s ah

ead

1 Ye

ar a

hed

DNO develops outage schedule and sends to SO

SO develops proposed outage schedule and sends

to DNOs

DNO reviews and raises issues and concerns

Is DNO happy with proposed plan?

NO

SO delivers the Draft National Electricity

Transmission System outage plan covering period Years

2 to 5 ahead

YES

SO updates the draft outage plan and sends proposed

schedule to DNOs

DNO develops outage schedule and sends to

SO

SO revises proposed outage plan and sends

schedule to DNOs

DNO reviews and raises issues and

concerns

Is DNO happy with proposed plan?

NO

SO delivers the final National Electricity

Transmission System outage plan covering Year 1

YES

SO revises outage plan on a short term basis and

notifies DNO

DNO reviews and raises issues and concerns

Is DNO happy with proposed change?

NO

SO updates TOGA platform with most up-to-date

outage planYES

DNO prepares the Eight Weeks Ahead Programme (EWAP) and submits to NG

on a weekly basis

SO submits a Power Factory network model to DNO on a

weekly basis

DNO merges the model with their outage planning model

SO sends declared generation availability to DNO on a daily basis (for

few days ahead)

SO sends generation SYNC/DESYNC schedule for next

day to DNOs

FOR COMMENT

The following sections describe the information the SO submits to DNOs to feed into their operational planning and vice versa.

2.1.1 Information provided by the SO to DNOs

This section is a brief description of the information provided by the SO to the DNOs with regards to outage planning. Most of the requirements below are dictated by the OC2 section of the Grid Code.

Week 28

In week 28 (around July), the SO delivers a year ahead draft outage plan (April to March). It is usually an excel file sent via email and accompanied by a pdf with the following information:

a. Reference number

b. Plant

c. Time of isolation

d. Type of outage

e. Return to service emergency time

f. Details of the work to be carried out

g. Safety documentation

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DNO outage planners (OP) have meetings with the SO before the formal issue of the plan in order to discuss concerns and negotiate alignment between distribution and transmission outage plans. After submission, OP confirm acceptance and review; a meeting may follow to discuss any potential issues and concerns. DNOs have up to week 36 to notify the SO if unhappy with proposed plan.

A similar process is conducted for the 2-5 year ahead time period, with data again being submitted in Week 28.

Week 49

In week 49, the SO submits the final outage plan as a revision of the week 28 one year ahead submission. The plan incorporates the discussions that take place before and after the Week 28 data submission.

TOGA (Transmission Outage and Generation Availability) platform

TOGA is a self-service data exchange platform, which contains the most up-to-date outages schedule. DNOs and other SO customers access it on a daily basis to inform their processes. The SO sends notifications before updating the outage schedule on TOGA in order for DNOs to raise any potential concerns. The format of the information provided is similar to week 28 data.

OC2 weekly model

The SO submits a network model (DigSILENT PowerFactory) to DNOs on a weekly basis. The model represents distribution networks with equivalents and it is up to each DNO to merge their models. The model is a snapshot of how the SO is planning to run the transmission network for the week ahead. The model is uploaded on an SFTP drive by the Customer Network Data – Network Access Planning team and includes forecasted peak transmission connected generation for the following week.

Availability of Generation

The SO updates DNOs about availability of generation as declared by generators (synchronous generator only, not HVDC and windfarms). The update is undertaken on a daily basis; it is looking a few days ahead and includes only generators that affect the respective DNO network. This information is provided by the SO control room via email from the Performance Review, Commercial optimisation team. The data is shown as maximum MW availability and corresponding time (e.g. 19/05/2015 1900 – 2200).

Synchronisation / De-synchronisation data

The SO submits data around expected synchronisation and de-synchronisation times of generators in the area (synchronous generator only, not HVDC and windfarms). The submission is completed on a daily basis; it is looking one day ahead and includes information for generators that affect the DNO network only. The data is provided in table format through a Fax from the SO control room. The table is populated with ON and OFF actions corresponding to each generator and the associated timestamp (e.g. ON at 19/05/2015 1900, OFF 29/06/2015 2200)

2.1.2 Information provided by DNOs to SO

The next section describes information that DNOs provide to the SO.

Eight Weeks Ahead Programme or EWAP

EWAP is a report submitted by the DNO to the SO and other interested parties (network rail, generators, critical customers etc.) via email on a weekly basis. It describes planned outage details for the following 8 weeks including:

a. Reference number for outage

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b. Circuits to be taken out of service

c. Start and end date

d. Work description

e. Comments

f. Type of outage

Outage planning report (week 8)

In week 8, DNOs send a report with planned outages required for works to be carried out in the next 2-5 years. Its format is similar to the EWAP above and it is submitted to the SO short term planning team at Wokingham.

Outage planning report (week 32)

In week 32, DNOs send a report with planned outages required for works to be carried out during next year. Its format is similar to the EWAP above and it is submitted to the SO year-ahead planning team at Wokingham. Data include outages that may have impact on transmission network and/or Maximum Export/Import declared Capacity at the GSP.

2.1.3 Reviews

DNO Outage Planners sit in a number of meetings before or after the official submission dates. The objective of the meetings is to discuss proposed schedules, plans and practicalities around outages, raise awareness of future works and maintain a channel of communication between the planning teams.

1. JTPM (Joint Technical Planning Meeting). This meeting involves people from the DNO

outage planning and asset management teams as well as the TOs and SO. It takes place

2-3 times per year; there is no fixed period and it depends on availability and number of

issues identified. It is a forum where the SO/TO and DNOs present a high level list of works

to be carried out in the next few years. Participants discuss plan and raise concerns on

potential issues

2. Meeting with SO Year Ahead planners to discuss week 28 and 49 data. This is an ad-hoc

meeting

3. Formal meeting around Q1 of each year to discuss week 49 data with SO/TO Current Year

Planners. The meeting takes place after SO/TO internal handover from Year Ahead to

Current Planners.

4. Access meeting: Every three months with Current Year Planners to discuss network

configuration of the next 3 months

5. Operation Liaison Meetings - Meetings with TO Site responsible engineers to discuss site

issues and practicalities of required outages

2.2 DNO Outage Planning

The section below attempts to capture the steps followed by the DNOs outage planning teams for assessing and approving a requested outage. The following diagram is a brief overview of the process and it shows a sequence of specific checks and assessments that take place in the long and short term. A more detailed version of the diagram can be found in Appendix A.2.

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DNO outage planningSh

ort

Ter

m (

~2-3

wee

ks)

Long

ter

m (

>6m

ont

hs)

Outage request

High level checks from Outage Planning

Is the outage feasible?

NOHigh Level Study of Available options


NODiscussions with requester and proposal of other options

YES

Record outage into the plan with high level details

YES

Review long term outage

plan

Detailed checks


Detailed Study of Available options


Discussions with requester and proposal of other options

Communicate proposed outage to all relevant parties

Are there any objections?

Proceed with outage and inform control engineers

NO NO

YES

Development of outage details

YES

NO

YES

Communicate proposed outage to all relevant parties


YES

NO

DNO teams or customers have to submit a request for outage slots to the Outage Planning (OP) teams. This usually takes the form of an excel spreadsheet, which contains the following information:

a. Plant or Circuit to be taken out of service

b. Emergency Time Recovery

c. Date and time of outage

d. Details for the works to be carried out

The outage planners use this information to carry out a first set of checks that include:

a. Technical Limitation Records (TLRs) for the part of the network around the plant/circuit

b. Network abnormalities

c. Relevant Policies and Procedures

d. System Loads (historical demand and generation for the same period)

e. Fault Levels and Power Flows

f. Clashes with already scheduled outages (SO/TO and DNO)

g. Third party network reconfigurations (IDNOs, SO/TO, Network Rail, London

Underground etc.)

h. Line patrols

i. Site checks

j. Protection Settings

The above checks consist of a high-level analysis to assess whether the requested outage is feasible. The main objective of the outage planning team is to minimise the risk to customers (generation and demand) by making sure, where possible, that the next potential loss will not interrupt their supply and will not have any detrimental effect on the network.

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If the request is not feasible, the outage planner will study a number of options that may help to accommodate the outage. The set of available options includes:

a. Load transfers

b. Generation Curtailment (MW)

c. Network reconfiguration

d. Stand-by generation

If the available options are not sufficient, the outage planner will examine other periods when the outage may be more feasible and discuss with the requester. It might also be the case that a number of works need to be completed first before the outage takes place.

The final agreed outage and its details are then recorded into the DNOs outage plan for informing all relevant parties (National Grid, IDNOs, customers with private networks, Network Rail etc.). The outage planning team reviews the outage if any of the relevant parties raise concerns.

A very similar process is followed in the short term, closer to the actual date of the requested outage. The analysis is carried out in greater detail including more up-to-date information with regards to system loads (generation and demand), network configuration and technical limitations. The planners also check alternative network running arrangements that minimise the risk to customers and maintain the network’s security.

At the end of the process, the outage planning team will develop a set of information that describes the outage and the works to be carried out. This consists of:

1. Visio file with proposed running arrangement

2. Date and time of outage

3. Works to be carried out

4. Emergency Return to Service time

5. Any other additional requirements (stand-by generator etc.)

The information is again submitted to relevant parties, including the DNO operation engineers, who review and comment on the proposed outage. If any concerns are raised, the outage planning team will review the plan and follow the same process until the outage is approved. The approved outage and associated details are forwarded to the control room for implementation.

2.3 TO/SO Operational Planning

TO/SO process mapping follows the requirements of STC Processes (STCP11.1 and 11.2) for Outage Planning and Outage Data Exchange between TO/SO. These documents can be found below:

STCP11-1 - Outage

Planning.pdf

STCP 11-2 Outage

Data Exchange.pdf

OFTOs have been considered only as a connecting party not impactful on overall process mapping.

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3. Investment Planning

3.1 TO/SO/DNO Interface Process

This section describes the investment planning procedures with respect to the TO/SO/DNO Interface. The purpose of these processes is for the TO to establish whether the system is compliant with the National Electricity Transmission System Security and Quality of Supply Standard (commonly referred to as the NETS SQSS or SQSS) and trigger remedial works if not. As the following diagram demonstrates, TO/SO/DNO investment planning consists of a loop of exchanging data between the parties. Key dates of the process are:

• Week 17: The SO makes an official request to DNOs for data including SLDs, agreed

Access periods and times of Min/Max GB demand.

• Week 24: Described in section 3.1.1 (DNOs may delay this by week 28)

• Week 42: Described in section 3.1.2

• Week 6: TO confirms compliance with SQSS

The week 42 model provided to DNOs by the SO is used to produce the week 24 data submission for next year.

Week 17SO request data including SLDs,

agreed Access Periods & times of Max/Min demands.

Week 24 (28)DNOs compile data &

provide to SO

SO acknowledge receipt of data to

DNO.

SO inform NG users and TOs of data

availability

SO and TOs review. Any queries?

DNOs review and update YES

SO set up Year 1 winter peak model

TOs & DNO review compliance with SQSS / P2

Week 42SO calculate infeed and provide

data to DNOs

DNOs review. Further info?

YES

NO

DNOs merge with distribution network model

Week 6TOs release compliance report LTDS

3.1.1 Week 24 submission (DNO to SO)

Week 24 data (DNO may delay the submission up to week 28) is developed based on the following guidance notes and submitted to SO (Customer Network Data Team) using the Data Exchange Portal.

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DNO Guidance

Notes v8.pdf

A brief summary of the information included in the week 24 (or 28) submission is as follows:

1. Total Network Operator Demand Profiles (Schedule 10)

Half-hour daily demand profiles in MW are submitted in Schedule 10. The data reflects the DNO's total demand and it is calculated by summing up the demand at primary substations (historical and forecast):

a. Table 10a - User’s Total System Demand Profile - Day of User’s Peak Demand (date

and time calculated by DNO)

b. Table 10b - User’s Total System Demand Profile - Day of GB Peak Demand (date and

time provided by SO in week 17)

c. Table 10c - User’s Total System Demand Profile - Day of GB Minimum Demand (date

and time provided by SO in week 17)

In addition, the tables include generation netted out (summated over all Grid Supply Points for the peak half hour of the day).

2. Demand Data per GSP for SQSS Compliance Assessments (Schedule 11 and 17)

Data is calculated by summing up the demand at primary substations (historical and forecast) and netting out generation. The calculations are carried out for the last and the next eight financial years (forecast).

a. Schedule 17: Access Period Data. Table with a visual indication of Access Periods

agreed between NG and DNOs by week 17

b. Demand data for Time of GB Transmission System Peak/Minimum Demand. Dates

and times given by SO. Forecast per primary site from Planning Load Estimates.

c. Demand data for Time of GSP Peak Demand. The date and time are calculated by the

DNO by summing up the demand at primary substations and netting out generation.

Forecast per primary site from Planning Load Estimates.

d. Demand data for Time of GSP Peak within Access Period. The date and time are

calculated by the DNO by summing up the demand at primary substations and netting

out generation. Forecast per primary site from Planning Load Estimates. In addition, a

table with available load transfer per Access Group is provided.

More specifically, the tables include the following information:

• Date and time

• Power Factor

• GSP Demand at time specified (MW and MVAR)

• Deduction made for Small Power Stations, Medium Power Stations and Customer

Generating Plant (MW)

• Reference to Single Line Diagram and to node and branch data spreadsheet

3. Table 11C: User’s Total System Active Energy Data

a. Energy for customers per class (LV, HV, EHV, Rail, Public Lighting)

b. System Losses

c. Energy from Embedded generating plant under 100MW

d. Forecast for next 8 financial years

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4. Embedded Small Power Stations >1MW ( Schedule 11)

A list of embedded generators above 1MW with information such as:

a. Reference number

b. Connected node as named in the SLD

c. Fuel type

d. Registered capacity (MW)

e. Control Mode (power factor or voltage control)

f. Geographical location

g. Type of loss of mains protection

h. Loss of mains protection setting

5. Embedded Generation Data (Schedule 11)

A table for each GSP with the following information for the last and the following eight financial years (forecast)

a. For each GSP where there are Embedded Small Power Stations, Medium Power

Stations or Customer Generating Stations the following information is provided:

i. No. of Small Power Stations, Medium Power Stations or Customer Power

Stations

ii. Number of Generating Units within these stations

iii. Summated Capacity of all these Generating Units in MW

b. Where the DNO places a constraint on the capacity of an Embedded Large Power

Station

i. Station Name

ii. Generating Unit

iii. System constrained Capacity

iv. Reactive Dispatch Network Restriction

c. Where the DNO places a constraint on the capacity of an Offshore Transmission

System at an Interface Point

i. Offshore Transmission System Name

ii. Interface Point Name

iii. Maximum Export Capacity

iv. Maximum Import Capacity

6. Demand Control (Schedule 12)

a. Low Frequency Relay Settings (Table 12a)

This table provides information about automatic demand disconnection for different

frequency set points. The calculation is carried out per GSP and is based on a

preselected set of sites that are equipped with the necessary relays. Total demand to

be disconnected is calculated by summing up the demand at those primaries on GB

peak day.

b. Demand Control by Voltage Reduction and/or Demand Disconnection (Table 12b).

DNOs inform SO whether Demand Control is to be implemented either by

i. A combination of voltage reduction and Demand Disconnection

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ii. Demand Disconnection alone,

Together with the magnitude of the voltage reduction stages (where applicable) and

for Demand Disconnection stages, the demand reduction anticipated.

c. Emergency Manual Disconnection (Table 12c)

The table lists the available cumulative demand disconnection 5/10/15/20/25 and 30

minutes after an SO instruction. It is shown per GSP and expressed in percentage of

GSP peak demand on GB peak day. It is calculated by summing up the demand of all

primary substations fed by the respective GSP. Demand disconnection is carried out

manually by DNO control room.

7. Equipment Data (Schedule 14)

a. LV Switchgear data (Table 14a). The table contains the information for all DNO circuit

breakers at each GSP:

i. Rated voltage (kV)

ii. Operating voltage (kV)

iii. Rated 3-phase rms short-circuit breaking current, (kA)

iv. Rated 1-phase rms short-circuit breaking current, (kA)

v. Rated 3-phase peak short-circuit making current, (kA)

vi. Rated 1-phase peak short-circuit making current, (kA)

vii. Rated rms continuous current (A)

viii. DC time constant applied at testing of asymmetrical breaking abilities (secs)

b. LV Substation Infrastructure Data (Table 14b). The table contains the information for

DNO Substation Infrastructure at each GSP. A single value for the entire substation

is supplied, provided it represents the most restrictive item of current carrying

apparatus.

i. Rated 3-phase rms short-circuit withstand current (kA)

ii. Rated 1-phase rms short-circuit withstand current (kA).

iii. Rated 3-phase short-circuit peak withstand current (kA)

iv. Rated 1- phase short-circuit peak withstand current (kA)

v. Rated duration of short circuit withstand (secs)

vi. Rated rms continuous current (A)

c. Reactive Compensation Plant Data (Table 14c). Table showing all independently

switched reactive compensation equipment not operated by the SO and connected to

the DNO’s system, other than power factor correction equipment associated directly

with Customers' Plant and Apparatus.

i. Type of equipment (e.g. fixed or variable);

ii. Capacitive and/or inductive rating or its operating range in MVAr;

iii. Details of any automatic control logic to enable operating characteristics to be

determined;

iv. The point of connection to the DNO System (including OTSUA) in terms of

electrical location and System voltage

8. Network Data (Schedules 5 and 13)

19 | P a g e

a. Single Line Diagram

DNOs submit a Single Line Diagram (SLD) to the SO. The SLD illustrates the normal

configuration of the distribution network. The network is reduced based on rules

defined in the Grid Code. It also shows node demand as calculated using the week 42

network model on GB peak day. Future works (reinforcements, replacements, new

connection etc.) are shown as mark-ups.

b. Network Data (Schedule 5)

This table contains the following information for the nodes and lines shown in the SLD:

Nodes data:

i. Voltage

ii. P, Q, S and power factor

iii. I’’,I’, X/R

iv. R0, X0 and B

Electrical parameters for lines:

i. Seasonal rating in MVA (winter, summer, spring, autumn)

ii. R1, X1 and B1

iii. R0,X0 and B0

iv. Rm, Xm and Bm

v. Info on couplings

Electrical parameters for transformers:

i. HV and LV vector group

ii. Grounding and earthing (type and Ohms)

iii. Tap range and step

iv. R1, X1, B1 and R0, X0, B0

v. Base rating in MVA

c. Fault Infeed data (Schedule 13)

The table contains fault infeed data for nodes in the SLD forecasted for the following 8

years

Demand and fault infeed data calculated using the week 42 network model for GB peak day.

By Week 6, the TO is required to provide the DNO’s with details of the week’s defining the proposed start and finish of each access period for each Transmission Interface Circuit and the connection points in each access group.

In addition to this, by week 6 the TO is required to issue to the DNO’s the results of any assessments undertaken to confirm whether the connection points are compliant against the SQSS

A diagram summarising the week 24 submission can be found in Appendix B.1

3.1.2 Week 42 submission (SO to DNO)

Week 42 model is submitted by SO (Customer Network Data, Network Access Planning) to DNOs. The SO is obliged to provide this Network Data under the Planning Code section of

20 | P a g e

the Grid Code to enable DNOs to model the National Electricity Transmission System in relationship to short circuit contribution.

The week 42 data is included in excel tables and submitted to DNOs for them to produce the equivalent transmission network in their modelling tools. The data comprise of fault infeeds from transmission network at the interface point, data for SGTs and lines interconnecting GSPs, and ratings for circuit breakers at the GSPs. Although not required by the Grid Code the SO also submits a network diagram showing the network configuration used to derive the week 42 data. The data is produced for GB peak winter demand. More information can be found in the guidance note below:

Guidance Note of

NG Network Data (Week42) Submission to DNOs- Revised.doc

3.2 DNO investment planning

This chapter captures the processes followed by DNOs during their investment planning. The outcome of these processes feed directly or indirectly to the interface data exchanged with TO/SO.

The first two sections give a brief overview of the general tools used by DNOs to forecast demand and assess their networks capacity. The diagram below is a high-level description of this process but not all steps are necessarily carried out by all DNOs

Planning Assumption / Information model

Planning Load Estimates (PLEs) Excel Tool

Data from external databases(FiT, Housing,

Commercial and Industrial activity, DNVL etc.)

Historical demand

Forecasted demand per Primary Substation

Load transfers

Infrastructure Development Plan

New Connections

Historical demand

Winter and Summer peak demand per site for last and future 8 years

(forecast)

Internal databases

3.2.1 Planning Assumptions/Information model

DNOs use a variety of models estimating future demand, to support their investment planning. To forecast effectively, these models, in addition to historic demand data and internal generation databases, may also take into account information available from government or other organisations. The information is directly connected to economic development and demand growth and may include, but not limited to:

• jobs,

• housing growth,

• commercial floor space,

• electric vehicle registrations,

• databases with FiT and RO information,

21 | P a g e

• planning applications

The outcome of the forecasting model is usually an anticipated demand growth per substation, which is used to inform the development of the Planning Load Estimates (see below).

3.2.2 Planning Load Estimates (PLE)

Planning Load Estimates (PLEs) or equivalents are developed once a year and are used by various parts of the DNO business as they contain critical substation information such as forecasted maximum demand (summer and winter), date and time of peak, firm capacity and power factors. PLEs are used predominantly by planners, to inform investment planning.

In order to obtain maximum demand per substation (value, date and time), DNOs look at historical data from past year and carry out a cleansing exercise to filter out any network or measurement abnormalities that result in non-representative values.

DNOs may also apply ACS (Average Cold Spell) and AHS (Average Hot Spell) to peak demand for winter and summer respectively. These factors are used to account for extreme conditions (e.g. very low temperatures) that occurred during the time of peak but are not representative for the respective time period. Average values are estimated using historical weather data from stations located around the country.

The substation maximum demand (MD) values for the current year are used as the starting point to forecast the MD for a number of years ahead. There are a number of aspects that must be considered during development of the PLEs. These include:

1. Relevant outcomes from regional infrastructure development plans (including new

substations, changes in substation firm capacity and load transfer actions)

2. Underlying load growth – incremental underlying load growth on individual substations is

added to each current year value to obtain a future forecast. The incremental additions

shall be obtained by the forecasting model described above.

3. New connections – impacts of new loads that are above the normal incremental demand

growth at a particular substation

Power Factors for each substation are usually obtained by measurements and are reviewed regularly.

3.2.3 Planning

The following section gives a high-level overview of the general processes being followed by DNOs to develop their investment plan. The diagram on the following page is a graphical representation of these processes and how they are interconnected. It is divided into four sections representing the different timeframes during which the plan is developed and implemented. A more detailed version of the diagram is in Appendix B.2.

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DNO Investment PlanningD

eliv

ery

Fo

reca

stin

gA

nal

ysis

Op

tio

nee

rin

g

Design and Operation Limitations

Asset Health Indices

Planning teams analyse existing network (load flows, fault levels, P2 compliance, outage management, other regulatory requirements)

Connection Requests

Are there any constraints (current or future)?

Planning Load Estimates and Load Indices

Modelling of Constraint

YES

Analysis and Optioneering

Modelling of options

Select least cost technically acceptable solution

High Level Design

Detailed Design

Delivery of solution

START

END

NO

The first stage (forecasting) includes the following activities:

1. DNOs produce the Planning Load Estimates (PLEs) or equivalent which may contain,

among others, the following key information:

a. Summer and Winter firm capacity per substation for the last and the next 8 years

b. Summer and Winter peak demand per substation for the last and the next 8 years

c. Summer and Winter power factor per substation

PLEs show whether any substation is presently, or forecasted to be, out of firm capacity and drive the Load Related Reinforcements (LRR).

2. DNOs receive connection applications from demand and generation customers. These

applications are forwarded to the planning teams for assessment. This information drives

the customer-led reinforcements.

3. Asset Management is responsible for monitoring the condition of the DNO assets and

report any replacement requirements. They are using CNAIM (Common Network Asset

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Indices Methodology) to produce Health and Criticality Indices that reflect the age and

likelihood of failure of assets as well as the impact of their failure in terms of number of

customers being affected. When a need for asset replacement is identified, the team

forwards a mandate to the planning team with details of the intervention required

(replacement, refurbishment etc.).

The second stage corresponds to the analysis carried out by the planning teams taking into account the information provided above as well as other operation and design requirements. The latter may include outage restrictions, fault levels, strategic investments and regulatory requirements such as P2 compliance and LI (Load Index) targets. The LI tables are produced based on PLEs and contain information about the previous year’s loading of the DNO substations.

Planners use the above information to identify current or future constraints in the network. A thorough analysis of the constraint and an investigation of a number of options to resolve it (optioneering) is then carried out. The analysis includes power flow and fault level studies, site specific issues, timescales, costs, safety and environmental concerns as well as security and quality of supply considerations. In addition, it takes into account other projects and the wider network state and limitations. It must be noted that constraints are not looked at in isolation but planners try to align solutions and projects (e.g. they may opt to bring a reinforcement (load-growth driven) scheme forward to harmonise it with an asset replacement (asset condition/health driven) scheme).

The optioneering study carried out draws from a pool of available solutions ranging from conventional asset replacement to more innovative approaches such as Demand Side Response and Active Network Management. The optimal solution is then selected to proceed to the next stage.

After approval, the document is forwarded to delivery teams, responsible for producing a more detailed design which describes the development of the proposed solution looking into the design, procurement, commission, test and commission of the project.

3.2.4 Long Term Development Statement (LTDS)

Every DNO produces a Long Term Development Statement (LTDS) that provides developers with sufficient network data, forecasts and commentary to carry out initial assessments of project feasibility. The statement also informs existing users of the distribution network about development proposals.

The LTDS contains the following information:

1. Circuit data

2. Transformer data

3. Load Information (past and forecast for next 5 years)

4. Fault Level Information

5. Generation

6. New connections interest (both demand and generation)

The development process is similar to week 24 data but it includes much more details about the distribution network (e.g. 33kV assets, geographical arrangements etc.). The week 42 network model submitted by the SO feeds into the LTDS preparation as well.

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3.3 TSO Investment Planning (National Grid)

This chapter captures the process followed by National Grid in the development and delivery of transmission investments. Transmission network investments are developed and delivered through the National Grid TO function. The National Grid SO (GBSO) inputs to this process on system access and operability aspects. Further details of National Grid TO investment process are included below.

Recently, the Network Options Assessment process has been introduced to determine transmission boundary capacity requirements and preferred reinforcements. This process is operated by the GBSO and is also detailed in this section.

3.3.1 Investment Process & Investment Types

The key internal National Grid TO investment process is referred to as the Network Development Process (NDP). This comprises a number of stages with “gates” to manage the transition of investments between stages. This is illustrated in the diagram below.

High Level Network Development Process

The stages of the Network Development Process operate as follows:

Establish Drivers – Investment projects broadly comprise i) customer driven works (eg

local and enabling works for new generation connections), ii) other load related work to

meet system security standards, and iii) non-load related work to replace equipment on

the basis of condition and criticality. (A recommendation to proceed with a transmission

boundary investment through the NOA process is also, in effect, an investment driver.)

Initial Business Plan Entry – A project is included in the investment plan if it is needed to

meet an investment driver. A portfolio of the works required (investment plan) to meet

our current understanding of all investment drivers is maintained with provisional costs

and milestones. A Needs Case document is created for each project to record the need,

a high-level assessment is undertaken and a standard solution is used to provide a cost

forecast and milestones for business planning. When the milestones indicate that it is

necessary to begin pre-construction works, the project is further progressed. For

customer connections, there are additional works to provide a customer offer. An

Investment Team is formed to develop the works to offer a contracted date against a

reasonable scope. The customer project is progressed if the customer agrees the offer.

Select Options - The driver for work is reviewed before optioneering is undertaken to

identify with more certainty the scope, programme, forecast cost and risks. Sufficient

work is undertaken to assess options and identify the preferred option; this will be

selected based on a financial (Net Present Value) and whole life value approach. This

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stage will typically span two to six months. Forecast costs will be updated and the project

will move to the next stage for full development and sanction.

Develop & Sanction - Further work is undertaken to develop the preferred option to the

level of accuracy required to achieve financial sanction and move into the delivery

phase; this stage will typically span five to fourteen months. The purposes of this stage

are to confirm commitment to the preferred option, refine the design to identify

efficiencies and address outstanding risks and opportunities, and provide baseline

scope, outputs, programme and forecast costs for future tracking. A financial (Net

Present Value) and whole life value approach will be used to identify the option to be

taken forward for sanction. A specification for procurement and delivery activities will

also form part of the Project Execution Plan.

Execute Project - This stage encompasses the delivery phase, from tendering and

contract award through physical works on site to commissioning and completion of asset

data drawings. Once physical works have been completed, a Project Manager’s report

will be finalised to confirm that the outputs identified in the Needs Case have been

physically delivered and recorded in the appropriate business systems.

Review & Close Project - A Closure Paper is presented to the appropriate governance

body. Checks are carried out to confirm that the scheme elements have been closed in

all business systems, and that all reported costs are final and complete.

The Network Development Process is further represented in Appendix B3 on TSO Investment Planning. This shows the 3 main investment drivers being customer connecton requests, the need to provide transmission infrastructure capacity to meet NETS SQSS requirements and the need to replace existing assets due to their deteriorating condition. From the National Grid TO’s perspective, the NOA process also provides an investment driver for a sub-set of transmission infrastructure capacity.

3.3.2 Planning Information and Assumptions

The key planning information that is used to determine investment projects include:

For customer driven connections, in its connection application, the customer provides

data on the size, location, timing and technical parameters of the generation or demand

development. This includes standard planning data as per the Grid Code provisions.

DNO demand estimates (see section 3.1.1) are used to assess the requirement for local

supply point reinforcement.

Asset health information and condition reports are used to help determine requirements

for non-load related asset replacement work. These will be used with system criticality

information and regulatory outputs to prioritise the investments that are taken forward.

Each year, the National Grid SO produces a set of holistic energy scenarios that are used by National Grid and others for planning. The Future Energy Scenarios (FES) are produced annually through a process of industry analysis and consultation. They normally cover 3 to 4 holistic scenarios covering a 20 to 25 year period. From the investment persective, the FES are used to inform the need for load related works.

26 | P a g e

FES Scenarios for Electricty & Gas

3.3.3 Network Options Assessment

To identify the need and preferred options for wider load related work to increase transmission boundary capabilities, the Network Options Assessment (NOA) process is used. This process is further described in STC Procedure STCP 21-1 and in the NOA Report Methodology (Draft 3, 12th May 2017).

This process is developing year to year. The latest high level process is illustrated below. The more detailed elements of the process are shown in Appendix B4.

Overall, the GBSO co-ordinates the NOA process and carries out the cost benetit analysis to recommend preferred reinforcement options. In broad terms, where there is a need to increase boundary capabilities to meet future boundary transfers, options for reinforcements are worked up and evaluated. These options include TO network reinforcement options and any non-network reinforcement options based on “smart” use of the existing network or on commercial arrangements with transmission service providers.

27 | P a g e

Where the GBSO recommends through the NOA process that a particular transmission reinforcement is taken forward, the TO will account of this recommedation in its investment planning.

3.3.4 Main DNO and Whole System Interactions

The 2 main areas where the SO, TOs and DNO’s interface on investment are:

Grid supply point security & investment requirements.

Distributed generation connection impacting the transmission network.

3.4 TOs/GBSO Interface Investment Planning

Coordination of TO investment plans with the GBSO is defined in the STC. The three main processes associated with this are detailed in the following documents:

1. STCP18-1 Connection and Modification Application, this document details the

process and timelines with which the Scottish TOs exchange information with the SO

to provide connection offers to developers requesting connection (Section 4.1). Link:

http://www2.nationalgrid.com/WorkArea/DownloadAsset.aspx?id=8589935636

2. STCP16-1 - Investment Planning, this document details the process and timelines

with which the Scottish TOs exchange information with the SO to develop investment

plans for the GB transmission system. Link:


3. STCP21-1 - Network Options Assessment (NOA), this document details the process

and timelines with which all the TOs exchange information with the SO to develop

reinforcement options for the main MITS (Main Interconnected Transmission System)

boundaries. Link:


Any wider TO MITS reinforcement investment will follow a similar process to the NDP plan

described in Section 3.3.1 and the information exchange between the TO and GBSO is

governed by item 2.

The NOA process in item 3 describes the process for wider system reinforcements on the

main MITS boundaries. The NOA methodology is under review with the latest draft in:






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4. Customer connection process

4.1 Transmission customers

This section discusses the analysis carried out by the TOs in assessing generation and

demand connections. Generation and demand connection applications are received from

current and prospective users of the transmission system. Upon receipt of a connection

application, the TO undertakes the relevant connection studies using the planning data

provided by the applicant to determine the appropriate connection works required to

accommodate the connection in accordance with the SQSS.

Affected TOs and Applications Steering Groups

For connections to the NGET transmission network that might impact the Scottish Transmission companies (and vice-versa), the System Operator and Transmission Owner Code (STC) requires that all of the affected Transmission Owners and the System Operator input to the application process through an Application Steering Group. This group will meet through the application to ensure that potential impacts on other transmission networks are considered.

Connect and Manage

In some cases it may not be feasible to meet the customers requested connection data and complete all of the transmission reinforcement works that may be required. Where the customer can connect and operate ahead of the wider works being completed, a “Connect and Manage” arrangement can be put in place.

4.1.1 Generator Connections

Section 2 of the SQSS covers the onshore generation connection design criteria to be applied

by the TO in the analysis of generator connections. The criteria focus on two main areas; i.e.

loss of power infeed and connection capacity requirements. In addition to the generation

connection criteria of the SQSS section2, the MITS design criteria of section 4 should also be

maintained considering the new generator. For defined relevant secured events in the SQSS,

29 | P a g e

the connection design should not result in generation disconnection beyond the specified loss

of power infeed. This is important for the system wide security. Equally, for defined relevant

secured events in the SQSS, the remaining assets should not be overloaded and the voltage

level at user sites should remain within the relevant planning limits. Additionally, the system

should remain stable.

When all the works required to comply with the SQSS sections 2 and 4 have been identified,

the Connect and Manage1 criteria are applied to determine those works which are enabling

for the connection and those that can be categorised as wider works. Enabling works are those

works required between the connection point and the nearest MITS substation, where the

‘MITS substation’ for the purposes of Connect and Manage is defined as a transmission

substation with connections to more than four transmission circuits excluding Grid Supply

Point (GSP) transformer circuits. Enabling works are the minimum transmission reinforcement

works that need to be completed before a generator can be connected and given firm access

to the transmission network. Wider works on the other hand on the other hand are the other

transmission reinforcement works (i.e. not Enabling Works) associated with reinforcing the

network to accommodate the new generator and ensure compliance with the SQSS. In

exceptional circumstances, the boundary between enabling works and wider works will extend

beyond the nearest MITS substation, such as in long radial parts of the network.

Generator connection categories:

Directly connected: These are generators that are directly connected to the

transmission system. They are modelled explicitly within connection studies.

Embedded: These generators are connected to the distribution systems and can

be large, medium or small in size:

Large embedded generators are explicitly modelled when carrying out

connection studies

Small embedded generators are represented by their equivalents at the

GSP for the purposes of determining loss of power infeed and

transmission capacity requirements.

Key assumptions:

The key modelling assumptions for the local transmission network relate to the

need to ensure that there is sufficient capacity to minimise constraints within a

local generation group in order to facilitate efficient market operation. Therefore, it

is necessary to model generation operating regimes representing credible

conditions which result in the transmission system being placed under greatest

stress, typically,, the following conditions are chosen to represent this condition:

Winter Peak conditions, here the plant dispatch will be greatest, resulting in

highest flows on the transmission circuits, however during winter conditions

the seasonal ratings will also be the highest, this can result in off peak

conditions being more onerous.

1Connect and Manage guidance document available online: http://www2.nationalgrid.com/WorkArea/DownloadAsset.aspx?id=5639

30 | P a g e

Summer minimum conditions, here the local and or total system demand

maybe at its lowest, whilst the generation dispatched on the GB system would

be less than that of a peak dispatch, at a local level, dependant on the plant

types the generation dispatch could be quite similar to that the lower demand

results in less demand being netted off thus resulting in higher loadings on

transmission assets, in addition during summer periods the transmission plant

seasonal ratings will also be at their lowest .

Alternative scenarios reflecting different loading conditions and seasonal

ratings may also be considered such as Spring/Autumn

Generation dispatch in the local area is set to represent credible operating

regimes of the generator types e.g. it is credible that thermal power stations

could all be running at full output in the same local generation group. It is also

possible that some or all of them could be off the grid. For loss of power

infeed calculations the generators that would be disconnected from the

system as a result of the secured event are set to their registered capacity

values.

The boundary of the local area is fluid as it depends on a number of factors such

as the topology of the network and the number, size and types of generators

involved within the area. The guiding principle is that the local network capacity

should not unduly restrict efficient market operation.

For the wider system, the MITS capacity requirements should be maintained as

per SQSS section 4 following the connection of the new generator. The capability

of the transmission network will be determined by considering a boundary or a

number of boundaries relevant to the generator under study. This assessment is

based on winter peak conditions as set out in SQSS section 4:

Winter circuit ratings applied to all transmission plant

Demand is set to Average Cold Spell (ACS) peak demand

Generation is dispatched according to technology specific scaling factors

specified in the SQSS.

Study input data:

Location of generator /connection point

Capacity of the generator in MW – Transmission Entry Capacity (TEC)

Technology, e.g. Thermal (nuclear, gas, etc.), Hydro, Wind, Marine, Pumped

storage, etc.

Machine and generator transformer parameters and associated circuit data

Connection date

Study model preparation:

For the local transmission capacity study, the GB network model for the relevant

year is prepared by representing all contracted generation in the area local to the

connection point for the current assessment. Where there are other generators

contracted to connect in the same area in later years, it may also be necessary to

prepare the network model a later year to ensure that other works already

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identified for other generators are taken into account in determining the

transmission works required for the current connection assessment.

In order to ensure that the thermal requirements can be met, the network is set

up to represent conditions that ought to reasonably be foreseen during when the

asset ratings are lowest. Demand is set to its minimum value to allow the

identification and evaluation of any thermal capacity limitation on the local

transmission network assets under credible operating regimes for the generators

in the local area, including the one being studied.

For the MITS study, the network model is set according to criteria specified in

SQSS section4. This based around winter peak system conditions.

When generation and demand has been dispatched, the system model is

conditioned to ensure that it represents a credible operating point, i.e. voltages

are well within limits and generators are operating within their active and reactive

power ranges and with sufficient reactive margin on the network. Where stability

studies are to be performed, the dynamic models of all active plant will also need

to be setup and initialised.

Generation connection study

The following studies are performed for generator connections:

Loss of infeed: SQSS section 2.5 details the calculation method for loss of

infeed while section 2.6 specifies the relevant contingency criteria and limits

for assessment. If the loss of infeed limit is exceeded as a result of the

generator being assessed, works will be required to be specified to address

the issue.

Voltage, thermal, and stability: SQSS sections 2.8 - 2.14 specifies the

connection capacity requirements. SQSS section 4 specifies criteria for MITS

capacity requirements. The criteria cover the secured events and the voltage

and thermal requirements to be considered. They also require that there

should not be system instability as a result of any of the relevant secured

events. Where voltage, thermal or stability performance is determined to be

outside the SQSS limits, works will need to be identified to rectify any issues

identified.

Fault level: For all generator connections, fault level studies are carried out to

determine the correct switchgear short circuit rating and ensure that the

existing assets are adequately rated for the prospective fault level taking into

account the new generator. If fault level constraints are identified, works will

need to be identified to rectify any limitations.

4.1.2 Demand connections

Demand connection criteria are covered in SQSS section 3. In practice, there two main types

of demand connections from a transmission perspective. These are:

Directly connected demand user

Grid Supply Point

The connection analysis approach for these two from a transmission perspective is the same.

SQSS section3 is mainly concerned with the security of demand, considering both an

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individual point (directly connected or GSP) and a group of demand points to form a demand

group.

Key assumptions:

The transmission network capacity is planned to meet the ACS peak demand

subject to loss of supply criteria in SQSS Section 3 Table 3.1.

Maintenance period demand security also considered.

Large embedded generation is expected to contribute to demand security subject

to criteria in SQSS Section 3 Table 3.2.

The study input data and network model setup are broadly the same. Specific contingencies

and performance limits are specified in SQSS Section3. Equally, criteria of SQSS Section 4

should continue to be met following a new demand connection and it may be necessary to

identify remedial works to restore compliance with SQSS section 4.

4.1.3 Overlap of criteria between generation and demand connections

It is common to have both generation and demand served by the same transmission network.

When assessing a generator or demand connection within such a composite group, both

SQSS section 2 and SQSS section 3 are applied such that the more onerous of the two will

dictate any works necessary to meet SQSS compliance.

4.1.4 Design variation

The deterministic criteria in the SQSS set the minimum requirements for transmission system

design. Design variations are however permitted subject to conditions specified in each of the

main sections of the SQSS. For example, a design variation for a generator connection can

be adopted to facilitate a customer choice connection design that is lower than the standard

planning level subject to meeting the conditions set out in SQSS sections 2.16 – 2.17. Equally,

for a design over the minimum deterministic standard specified in the SQSS, an economic

justification has to be provided in accordance with SQSS Appendix G.

4.2 Distribution customers

The following section gives a high-level description of the process followed when a customer raises a request for connection at the distribution network.

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DNO Connections quotation process for High voltage and above.

Cus

tom

erC

onn

ecti

ons

Team

Plan

ner

(Ass

et

Man

agem

ent)

Des

ign

Rev

iew

/

Fina

nci

al s

ign

off

Net

wo

rk

Con

nec

tion

s D

esig

ner

Connection application made

Application processed and checked for minimum required

information

Technically assess the proposed connection e.g. P2/6 compliance,

Thermal, Voltage, and fault level studied

Design review and financial sign off

Quotation pack created and sent to customer

Quotation for connection received

High level connection designed

Customers submit connection applications to DNO Connection teams who are responsible for managing the communication with the customers. An application shall provide the DNO with at least the following information:

a. Location (address, OS grid reference etc.)

b. Size of generation or demand

c. Type of technology (or type of demand)

After receiving the application, the Networks Connections design team produces a high-level design of the customer’s connection and forwards to the planning team for a detailed assessment.

The planning team then conducts a number of checks and network studies to identify technically feasible points of connection (POCs) that satisfy the customer’s request. These may include:

• Network Assessment - Running Arrangements - Circuit complexity - P2/6 compliance - PLE (or equivalent) Analysis - Historical data - Line/cable and transformer ratings - Fault levels and switchgear rating - Automation - Protection settings

• Network studies (DigSilent, PSSE, IPSA etc.) - Voltage rise - Voltage step change - Load Flows (MW/MVAr) - Fault levels (three phase/single phase)

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The aforementioned assessment/studies produce a number of options with associated costs and requirements, which are then provided back to the connections team. The options are described in detail, including the requirement for any additional equipment and/or potential network reinforcements. Some of the options studied may be rejected due to unreasonably high costs or technical limitations.

The customer will be presented with the most cost efficient POC only. The customer receives the offer and has a specific timeframe in which to accept or reject it.

4.3 Statement of Works Process (DNO/TSO Connections)

Customer Applies to DNO

DNO Connection

offer inc. req. for SoW

Customer Accepts Offer. DNO initiates SoW with SO

Revised BCA SO to DNO. Customer informed of

outcome

SoW Process SO/TO

Small and Medium embedded generators connecting to the distribution network do not require a direct agreement with National Grid as SO; instead they will have a connection agreement with the DNO. However, medium power stations can choose to have a BEGA or BELLA (direct agreement with NG). The definition of a Small generator varies between different parts of the network, as a consequence of differing transmission network topologies. The table below shows these differences:

Transmission Area

Size of Power

Station

SHE Transmission SP Transmission NGET

Small <10MW <30MW <50MW

Medium - - 50MW to <100MW

Large ≥10MW ≥30MW ≥100MW

When an embedded generator wishes to connect to the distribution network they will apply to the DNO, who must then determine whether they reasonably believe the new generator may have a significant system effect on the transmission system, and therefore be deemed Relevant. Where the generator is Relevant, the DNO will request that the SO conduct an assessment to determine the extent of the impact. This process is the Statement of Works (SoW) process as defined in CUSC Section 6.5.5.

Where the TO’s SoW studies indicate that there is an impact to the transmission system or works may be required, and the DG applicant wishes to proceed, the project moves to Project Progression and the DNO submits either a Confirmation of Project Progression or a Modification Application.

The SOW submission consists of the following data for each relevant generator:

Site name

Registered capacity

Voltage

Location (e.g. postcode)

Connection substation

Technology type

Connection status (connected, contracted or offered)

Control mode (voltage or power factor)

Fault infeed at BSP (I”, I’ and X/R)

Impedance between generator terminals and DNO network (R,X and C)

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Minimum morning and afternoon load at BSP

A detailed map of the SOW process is included in Appendix C.1.

Work is currently underway to develop a revised version of the Statement of Works process.

Reference should be made to ENA Open Networks Project: WS1: Product 7 for further details.

The diagram in Appendix C.2 describes the Appendix G process, which was developed as

part of the ongoing work now covered under Product 7. Since this methodology is now

business as usual across a number of DNOs, it has been included in this report for

completeness.

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5. The SO Process for Developing and Procuring Services

The SO utilises a range of services to support secure and economic system operation. Around 30 different types of service are currently used to provide reserve, frequency management, voltage management and other capability. These services are summarised in the table below.

Increasingly these services are being sourced from Distributed Energy Resources (DER) as well as from providers connected at transmission voltages. Engagement with DER providers and aggregators around service provision is being coordinated through the Power Responsive initiative. The Power Responsive column in the table indicates those services where DER participate.

At present, whole system network industry processes to develop and put in place services are not available. The current suite of SO services have either followed from mandatory requirements placed on generators or have been developed with providers to address system need as these have arisen.

Type of Service

Service

Power Responsive

2016 Report

Details on NG

Website Notes

Instructed Bids and Offers Balancing market

Frequency Mandatory Frequency Response Yes

Voltage Obligatory Reactive Power Services (ORPS)

Yes

Reserve

Short Term Operating Reserve (STOR) Included Yes

STOR Runway Included Yes

Enhanced Optional STOR Yes No longer used.

Fast Reserve (FR) Included Yes

Demand Turn-up (DTU) Included Yes

Low SEL / Super SEL Summary

BM Start-up Yes

Hot Standby Yes Bundled with BM start-

up.

Fast Start Large generators

Frequency

Firm Frequency Response (FFR) Included Yes

FFR Bridging Included Yes

Enhanced Frequency Response (EFR) Included Yes

Frequency Control by Dem M’ment (FCDM)

Included Yes

Voltage Enhanced Reactive Power Services (ERPS)

Yes

Pumped Storage

Spin Gen

Optional fast reserve services

Spin Gen LF

Pump Deload

Pump Deload LF

Spin Pump

Rapid Start

Synchronous Compensation

Security

Black Start Yes

Maximum Generation Yes

Intertrips Summary

Trip to House Load Large generators

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Demand Side Balancing Reserve (DSBR)

Yes No longer used.

Supplemental Balancing Reserve (SBR) Yes No longer used.

Other Services

Other Services

Capacity Market / Warning

Market Trades

Cross-Border Trades Summary

Constraint contracts Summary

A high level process illustrating the typical approach to developing and procuring services is shown on the following figure. This process is indicative of how the Enhanced Frequency Response (EFR) service and other new services have been developed recently and involves a number of stages through to utilisation of the service:

• Steps 1 & 2 - Identifying the need and high level service characteristics.

• Steps 3 & 4 – Engaging with potential providers and establishing interest in the service.

• Steps 5 & 6 – Refining the service specification and carrying out pre-qualification.

• Steps 7 & 8 – Running the procurement process and assessing returns.

• Step 9 – Putting in place any contract requirements with providers.

• Step 10 – Providers putting in place the equipment to provide and control the service.

• Steps 11 & 12 - Setting up the systems to enable the service to be utilised together with

any aggregation or optimisation of service providers.

• Step 13 – Dispatch of the service to meet system needs.

• Steps 14 & 15 – Metering and settlement for the services provided.

• Step 16 – Any reporting association with the ongoing use of the service.

Alongside this process an Account Management team in SO will work with potential service providers and other stakeholders in developing and implementing the service.

Going forward, as part of its Future Role of System Operator programme, National Grid is assessing how it can simplify the range of services required in the areas of reserve, frequency management etc. It is consulting with service providers on how services might be best procured.

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Appendices

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A Operational Planning maps

A.1 Operational Planning SO/DNO Interface

Week 28SO provides draft outage plan in excel and pdf format via email

Week 30DNOs confirm receipt and inform

SO if unhappy with proposed outages

Week 8DNOs proposed outage plan to

SO in excel and pdf via email

Request for outages from DNO departments

DNO outage planning team processes requests and develops

a plan for the next 2-5 years

Long term planning team receives and processes

information

Week 13SO provides to DNOs a copy of

the week 8 information submitted by all DNOs

DNO outage planning team reviews

Week 28Proposed Year Ahead outage

plan in excel and pdf via email to DNOs

Year ahead planning team in Wokingham prepares outage

plan for year ahead

DNO outage planning team processes requests and develops

a plan for one year ahead.

Revision of outage plan based on DNOs comments

Week 34Draft National Electricity Transmission System outage plan covering period

Years 2 to 5 ahead. Excel and Pdf format via email

Week 32DNOs submit proposed outage plan to SO. Excel

and pdf format via email

Week 34SO notifies DNO of aspects that might affect

their network. SO provides a copy of the week 32 information to all other DNOs

Week 36DNO confirms and comments

Week 49 Final SO outage plan submitted via email in Excel

and pdf format

Request for outages from DNO departments

Long term planning team prepares outage plan for next 2-

5 years

Year ahead planning team draws up a revised year ahead outage

plan

DNO outage planning team reviews, comments and raises

concerns or issues

SO draws up final National Electricity Transmission System

outage plan covering Year 1

DNO outage planning team

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Most up-to-date SO outage schedule uploaded on TOGA

SO notifies DNOs for any proposed changes to the latest

outage schedule

Notification to DNO via email DNOs review notification and raise any concerns

Potential concerns discussedShort term planning team

develops latest plan and updates TOGA

DNOs Outage Planning team advises TOGA regularly for the

most up-to-date SO outage schedule

Customer Network Data team submits the NG Power Factory

model to DNOs

SO model uploaded on an SFTP drive. PFD format

DNOs receive the model and merge it with their system

Outage Planning team prepares the Eight Weeks Ahead

Programme

EWAP submitted via email in excel and pdf format

Short Term Planning team

Commercial Optimisation Team sends declared generation

availability to DNOs for a few days ahead

Days ahead generation availability via email

Outage Planning

SO control room sends generation SYNC/DESYNC

schedule for next day to DNOs

Generation SYNC/DESYNC scehduled via fax

Outage Planning team

FOR COMMENT

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A.2 DNO Operational Planning

DNO outage planning

Sho

rt T

erm

(~

2-3

we

ek

s)Lo

ng

term

(>

6m

on

ths)

Outage request

with:

ETR

Plant/Circuit

Date and time

Works

High level checks

Technical limitations

Load flows and plant

ratings

Fault levels

Outage plan clashes (NG

and DNO)

Network security


NO

High Level Study of

Available options

Load transfers

Generation Curtailment

(MW)

Network reconfiguration

Stand-by generation


NO

Discussions with requester

and proposal of other

options:

Alternative outage times

Works to be completed

YES

Record outage into the plan with high level details

YES

Review long term outage

plan

Detailed checks

Technical limitations

Load flows and plant ratings

Fault levels

Outage plan clashes (NG and

DNO)

Running arrangement

Network security


Detailed Study of Available

options

Load transfers

Generation Curtailment (MW)

Network reconfiguration

Stand-by generation

Alternative running

arrangement


Discussions with requester

and proposal of other

options:

Alternative outage times

Works to be completed

Communicate proposed

outage to all relevant

parties (internal, site

engineers, NG,

generators, customers)


Proceed with outage and

inform control engineers

NO NO

YES

Development of outage

details

Running arrangement

Load transfers

Generation curtailment

YES

NO

YES

Communicate proposed

outage to all relevant

parties (internal, site

engineers, NG,

generators, customers)


YES

NO

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B Investment Planning maps

B.1 Week 24 submission

Historical data and forecasted data from PLEs

DNO Team prepares week 24 data submission

Week 6Proposals for Access Periods put forward by SO to

DNOs for discussion

Week 6-17Discussions between SO and DNOs to agree

Access Periods

Week 17Send details of agreed Access Periods, GB Max &

Min demand dates (past and forecast)

Week 42 SO sends transmission network to DNO

(equivalent)

DNO merges with distribution network model

Fault level and load flow studies

Schedule 5 Single Line Drawing Fault Infeeds Demand at GB max date Network alterations and

reconfigurations

Regional Development Plan and Load transfers

New connections (demand and generaration)

Schedule 10Total DNO daily demand (MW) profiles for: GB max GB min DNO max

Schedule 11GSP Demand Data (MW and MVAr) for: GB max GB min GSP peak Access Period peak

Schedule 12Demand Control Low Frequency Relay Settings Demand control by Voltage

reduction and/or demand disconnection

Emergency manual disconnection

Schedule 14Equipment data LV switchgear data LV substation infrastructure data Reactive compensation plant

Summing up demand at primaries and netting out generation

Schedule 11Small Embedded Power Station data per GSP: Registered capacity Type of generation Control mode Loss of mains protection

Table 11CTotal DNO:

Customers energy per class System Losses Embedded Generation

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B.2 DNO Investment Planning

DNO Investment Planning

Del

iver

yFo

reca

stin

gA

nal

ysis

Op

tio

ne

eri

ng

Design and Operation Limitations Outages Fault Levels Security of Supply Strategic developments

Asset Health: Health Indices End of Life Mandate for

replacement/retrofit

Planning teams analyse existing network: Load flow and fault level studies using PowerFactorty, PSSE or equivalent software Security of Supply (P2 standard) Outage management Contingency Analysis Business Plan targets Other regulatory requirements

Connection Requests: Point of Connection Technology Size

Are there any constraints (current

or future)?

Planning Load Estimates: Maximum Demand Firm Capacity Load Indices Load transfers

Modelling of Constraint

YES

Analysis and Optioneering: Network reconfiguration Reinforcement/Retrofit Load Transfer ANM DSR

Modelling of options: Costs High Level works Wider benefits

Select least regrets and most cost efficient solution

Design and Development of

the solution

Delivery of solution: Procurement Commissioning Tests Hand over to Operations

START

END

NO

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B.3 TSO Investment Planning

TSO Investment Planning

De

live

ry

Exe

cute

& C

lose

NO

A P

roce

ssO

pti

on

ee

rin

g,

De

sign

& A

pp

rova

lA

nal

yse

Re

qu

ire

me

nts

& I

de

nti

fy O

pti

on

sIn

vest

me

nt

Dri

vers

,

Bu

sin

ess

Pla

n E

ntr

y

Review Investment Drivers

Infrastructure Requirements(Other thermal, vol tage work)- Grid Code Data- Future Energy Scenarios- ETYS Boundary Req'ts- Bus iness Plan entry

Connection Request(eg Generation Development)- Customer data- Size, technology, timescales- Location- Bus iness Plan entry

Asset Replacement

(eg Primary Equipment)- Condition information- Cri tica lity- Customer impacts- Bus iness Plan entry

Analysis & Option Identification- SO & TO Development Teams- Power System Analysis(thermal, voltage, s tability etc)

- PowerFactory & Economic Tools- Securi ty (NETS SQSS, P2)- Outage management- Regulatory constraints

Analysis & Option Identification- SO & TO Development Teams- Power System Analysis(thermal, voltage, s tability etc)

- Securi ty (NETS SQSS, P2)- Programme, Outages - Indicative Charges- Interactivi ty

Analysis & Option Identification- Largely TO Development- Condition Information- Cri tica lity- Ongoing requirements - Customer, wider impacts- Overlaps with other work

Is investment to be taken

forward?

No Yes

Assess Options- Cost

- Risks- Programme

Select Preferred Option & Confirm Requirements

Infrastructure Reqts(Boundary Capacity)Networks Options Assessment (NOA)- GB Models- SO confi rms need for boundary capability

Des ign & Develop Solution.- Fi rm Up Scheme Req'ts

(SRD for Resources & Outages)- Execution Plan- Value checks & affordability

Approval of Investment

Issue

Req'ts

Proposed Options- TO Tx options- Other options (non-build)- Costs

Boundary Capability Assessment for Options

Cost Benefit Analysis of Options- BID3 Model

Select Preferred Options

Assess Sui tability for Competition

Del ivery Vehicle- Issue enquiry- Evaluate proposals

- Place contract

Deta iled Design& Assurance

Bui ld AssetsCommission Assets

Accept Assets- Data- Outstanding

Works

Closure- Data- Costs

Del ivery

Determine how to take forward NOA recommendation.

Non-investment option i f appropriate (eg customer offer without works).

Mapping current SO, TO, DNO Processes

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B.4 NOA Process

Taken from NOA Report Methodology, Draft 3, 12th May 2017

NOA High Level Process (Draft)


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NOA Capability Requirements & Transmission Options (Draft)


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NOA Boundary Capability Assessment (Draft)


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NOA Cost Benefit Assessment & Preferred Option Selection (Draft)


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NOA Report Drafting and Publication


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C Customer Connection Maps

C.1 Statement of Works process

DG CUSTOMER APPLIES TO DNO

FOR CONNECTION

DNO REQUIRED TO MAKE OFFER WITHIN

70 DAYS

DOES THE CONNECTION BREACH 50MW* CUMULATIVE

OR IS IT 50MW

NONOT SUBJECT TO

SOW MAKE OFFER

MAKE OFFER SUBJECT TO SOW

SINGLE OR BULK SOW SUBMISSION

MADE TO SO

SO PROVIDES TO WITH DATA

TO FEEDS BACK TO SO

IS THERE AN IMPACT ON THE

NETS

SO FEEDS BACK TO DNO

INFORM CUSTOMER NO IMPACT ON THE

NETS

PROJECT PROGRESSION

REQUIRED

INFORM CUSTOMER OF NETS IMPACT

CUSTOMER DECIDES WHETHER TO MOVE

FORWARD


FORWARD

TO UNDERTAKE DETAILED STUDIES

AND PROVIDES DETAILS OF WORKS, TIMESCALES, COSTS,

ETC.

DNO PROVIDES INFORMATION TO

DG CUSTOMER


FORWARD

IS THERE SUFFICIENT DETAILEDSO/TO INFORMATION

AVAILABLE

NO

YES

YES

NO YES NO

*DNO DEPENDENT

CUSTOMER ACCEPTS OFFER (OR

PAYS FOR SOW)

**CUSTOMER DRIVEN

YES**


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C.2 Appendix G process (England and Wales)

Customer applies

Offer made against Materiality Headroom

TSO approves changes and contractualises DER

NG provides revised BCA inc. Appendix G & Materiality Headroom

DNO National Grid

Customer accepts & pays

Appendix G updated/monthly process

Appendix G re-issued

Materiality Limit updated

Identifies changes to technical reqs (if required)

Appendix G re-issued

Is materiality headroom

reachedNo

TO runs studies

DNO raises SoW/Mod AppYes

Records updated

DNO provides GSP technical data via SoW/Mod App

DER contracted

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