ENA Open Networks Project Workstream 1: Product 1

Transcription

1 The Voice of the Networks ENA Open Networks Project Workstream 1: Product 1 Mapping current SO, TO and DNO processes 12 th June 2017 Energy Networks Association Document Ref: TDWS1P1 Restriction: None

2 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. 2 P a g e

3 Document Control Version Issue Date Author Comments 1 19/05/2017 Draft reviewed by Working Group 2 12/06/2017 Comments incorporated 3 P a g e

4 Contents Executive Summary... 2 Document Control... 3 Contents... 4 Acronyms... Error! Bookmark not defined. 1. Introduction Operational Planning SO/DNO Interface Process Information provided by the SO to DNOs Information provided by DNOs to SO Reviews DNO Outage Planning TO/SO Operational Planning Investment Planning TO/SO/DNO Interface Process Week 24 submission (DNO to SO) Week 42 submission (SO to DNO) DNO investment planning Planning Assumptions/Information model Planning Load Estimates (PLE) Planning Long Term Development Statement (LTDS) TSO Investment Planning (National Grid) Investment Process & Investment Types Planning Information and Assumptions Network Options Assessment Main DNO and Whole System Interactions TOs/GBSO Interface Investment Planning Customer connection process Transmission customers Generator Connections Demand connections Overlap of criteria between generation and demand connections Design variation Distribution customers P a g e

5 4.3 Statement of Works Process (DNO/TSO Connections) The SO Process for Developing and Procuring Services Appendices A Operational Planning maps A.1 Operational Planning SO/DNO Interface A.2 DNO Operational Planning B Investment Planning maps B.1 Week 24 submission B.2 DNO Investment Planning B.3 TSO Investment Planning B.4 NOA Process C Customer Connection Maps C.1 Statement of Works process C.2 Appendix G process (England and Wales) P a g e

6 Glossary ACS AHS ANM BEGA BELLA BM BSP CNAIM CUSC DER DG DNO DSO DSR DTU EFR ENA ERPS EWAP FCDM FES FFR FiT FR GB GBSO GSP HI HV HVDC JTPM LI LRR LTDS LV MD MITS NDP NG NGET NOA OC OFTO OP Average Cold Spell Average Hot Spell Active Network Management Bilateral Embedded Generation Agreement Bilateral Embedded Licence Exemptible Large Power Station Agreement Balancing Mechanism Bulk Supply Point Common Network Asset Indices Methodology Connection and Use of System Code Distributed Energy Resources Distributed Generator Distribution Network Operator Distribution System Operator Demand Side Response Demand Turn-up Enhanced Frequency Response Energy Network Association Enhanced Reactive Power Services Eight Week Ahead Programme Frequency Control by Demand Management Future Energy Scenarios Fast Frequency Response Feed in Tariff Fast Reserve Great Britain Great Britain System Operator Grid Supply Point Health Index High Voltage High Voltage Direct Current Joint Technical Planning Meeting Load Index Load Related Reinforcement Long Term Development Statement Low Voltage Maximum Demand Main Interconnected Transmission System Network Development Process National Grid National Grid Electricity Transmission Network Options Assessment Operation Code Offshore Transmission Owner Outage Planning 6 P a g e

7 ORPS OTSUA PLE POC RO SFTP SHET SLD SOW SPT SQSS SSE STC STOR TEC TO TOGA (T)SO Obligatory Reactive Services Offshore Transmission System User Assets Planning Load Estimate Point of Connection Renewable Obligation SSH File Transfer Protocol Scottish Hydro Electric Transmission Single Line Diagram Statement of Works Scottish Power Transmission Security and Quality of Supply Standard Scottish Hydro Electric System Operator - Transmission Owner Code Short Term Operating Reserve Transmission Entry Capacity Transmission Operator Transmission Outage and Availability Transmission System Operator 7 P a g e

8 OPERATIONS Individual DNO Liaison and Discussion Grid Code Standard Planning Data As required for Investment Planning SO TOs LIAISON INVESTMENT PLANNING GRID CODE DATA EXCHANGE INTERFACE 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. Interfaces for Grid Code Standard Planning Data exchange DISTRIBUTION TRANSMISSION Joaquin Jimenez Issue 14.0 April 2014 NETWORK OPERATOR (14) Investment Planning NB Grid Code does not provide data from National Grid to Network Operator for asset investment planning purposes (load flow infeeds) Joint Technical Planning Liaison Meetings for further SPD planning data (PC.A.2.1.4) TRANSMISSION OWNERS NGET SPT SHETL NETWORK OPERATOR (14) Operations NGET SYSTEM OPERATOR 8 P a g e

9 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. 9 P a g e

10 Short Term 1 Year ahed 2-5 years ahead 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 DNO develops outage schedule and sends to SO SO develops proposed outage schedule and sends to DNOs DNO reviews and raises issues and concerns NO Is DNO happy with proposed plan? YES SO delivers the Draft National Electricity Transmission System outage plan covering period Years 2 to 5 ahead 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? YES SO delivers the final National Electricity Transmission System outage plan covering Year 1 NO 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? YES SO updates TOGA platform with most up-to-date outage plan NO DNO prepares the Eight Weeks Ahead Programme (EWAP) and submits to NG on a weekly basis FOR COMMENT SO sends declared generation availability to DNO on a daily basis (for few days ahead) SO submits a Power Factory network model to DNO on a weekly basis DNO merges the model with their outage planning model SO sends generation SYNC/ DESYNC schedule for next day to DNOs The following sections describe the information the SO submits to DNOs to feed into their operational planning and vice versa 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 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 10 P a g e

11 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 from the Performance Review, Commercial optimisation team. The data is shown as maximum MW availability and corresponding time (e.g. 19/05/ ). 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/ , OFF 29/06/ ) 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 on a weekly basis. It describes planned outage details for the following 8 weeks including: a. Reference number for outage 11 P a g e

12 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 yearahead planning team at Wokingham. Data include outages that may have impact on transmission network and/or Maximum Export/Import declared Capacity at the GSP 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 P a g e

13 Short Term (~2-3 weeks) Long term (>6months) DNO outage planning Outage request High level checks from Outage Planning Is the outage feasible? YES NO High Level Study of Available options YES Is the outage feasible? YES NO Discussions with requester and proposal of other options Record outage into the plan with high level details Communicate proposed outage to all relevant parties Are there any objections? NO Review long term outage plan Detailed checks Is the outage feasible? YES NO Detailed Study of Available options Is the outage feasible? YES NO Discussions with requester and proposal of other options YES Development of outage details Communicate proposed outage to all relevant parties Are there any objections? NO Proceed with outage and inform control engineers 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. 13 P a g e

14 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: STCP 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. 14 P a g e

15 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 (DNOs may delay this by week 28) Week 42: Described in section 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 17 SO 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 DNOs review and update YES SO and TOs review. Any queries? SO set up Year 1 winter peak model TOs & DNO review compliance with SQSS / P2 Week 42 SO calculate infeed and provide data to DNOs YES DNOs review. Further info? Week 6 TOs release compliance report LTDS NO DNOs merge with distribution network model 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. 15 P a g e

16 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 16 P a g e

17 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 17 P a g e

18 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) 18 P a g e

19 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 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 19 P a g e

20 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 (W 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 Internal databases Data from external databases(fit, Housing, Commercial and Industrial activity, DNVL etc.) Load transfers Infrastructure Development Plan Planning Assumption / Information model Forecasted demand per Primary Substation Planning Load Estimates (PLEs) Excel Tool Historical demand New Connections Historical demand Winter and Summer peak demand per site for last and future 8 years (forecast) 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, 20 P a g e

21 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) 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 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 P a g e

22 Delivery Optioneering Analysis Forecasting DNO Investment Planning START Planning Load Estimates and Load Indices Connection Requests Asset Health Indices Design and Operation Limitations Planning teams analyse existing network (load flows, fault levels, P2 compliance, outage management, other regulatory requirements) NO Are there any constraints (current or future)? YES Select least cost technically acceptable solution Modelling of options Analysis and Optioneering Modelling of Constraint High Level Design Detailed Design Delivery of solution END 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 22 P a g e

23 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 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. 23 P a g e

24 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 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 24 P a g e

25 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 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. 25 P a g e

26 FES Scenarios for Electricty & Gas 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, 12 th 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. 26 P a g e

27 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 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: 2. STCP 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. STCP 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 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: 27 P a g e

28 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 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, 28 P a g e

29 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 Manage 1 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. 1 Connect and Manage guidance document available online: 29 P a g e

30 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 30 P a g e

31 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 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 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 31 P a g e

32 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 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 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 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. 32 P a g e

33 Design Review / Financial sign off Planner (Asset Management) Network Connections Designer Connections Team Customer DNO Connections quotation process for High voltage and above. Connection application made Quotation for connection received Application processed and checked for minimum required information Quotation pack created and sent to customer High level connection designed Technically assess the proposed connection e.g. P2/6 compliance, Thermal, Voltage, and fault level studied Design review and financial sign off 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) 33 P a g e

34 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 SoW Process SO/TO Revised BCA SO to DNO. Customer informed of outcome 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: Size of Power Station Transmission Area SHE Transmission SP Transmission NGET Small <10MW <30MW <50MW Medium MW 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 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) 34 P a g e

35 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. 35 P a g e

36 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 Obligatory Reactive Power Services Yes Voltage (ORPS) Reserve Frequency Voltage Pumped Storage Security 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 startup. Fast Start Large generators Firm Frequency Response (FFR) Included Yes FFR Bridging Included Yes Enhanced Frequency Response (EFR) Included Yes Frequency Control by Dem M ment Included Yes (FCDM) Enhanced Reactive Power Services Yes (ERPS) Spin Gen Spin Gen LF Pump Deload Pump Deload LF Spin Pump Rapid Start Synchronous Compensation Black Start Maximum Generation Intertrips Trip to House Load Yes Yes Summary Optional fast reserve services Large generators 36 P a g e

37 Demand Side Balancing Reserve Yes No longer used. (DSBR) Supplemental Balancing Reserve (SBR) Yes No longer used. Other Services Other Services Capacity Market / Warning Market Trades Cross-Border Trades Constraint contracts Summary 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. 37 P a g e

38 38 P a g e

39 Appendices 39 P a g e

40 A Operational Planning maps A.1 Operational Planning SO/DNO Interface Request for outages from DNO departments Long term planning team receives and processes information Week 8 DNOs proposed outage plan to SO in excel and pdf via DNO outage planning team processes requests and develops a plan for the next 2-5 years Week 13 SO provides to DNOs a copy of the week 8 information submitted by all DNOs Long term planning team prepares outage plan for next 2-5 years Week 28 SO provides draft outage plan in excel and pdf format via DNO outage planning team reviews Revision of outage plan based on DNOs comments Week 30 DNOs confirm receipt and inform SO if unhappy with proposed outages Week 34 Draft National Electricity Transmission System outage plan covering period Years 2 to 5 ahead. Excel and Pdf format via DNO outage planning team Year ahead planning team in Wokingham prepares outage plan for year ahead Week 28 Proposed Year Ahead outage plan in excel and pdf via to DNOs Request for outages from DNO departments Week 32 DNOs submit proposed outage plan to SO. Excel and pdf format via DNO outage planning team processes requests and develops a plan for one year ahead. Year ahead planning team draws up a revised year ahead outage plan Week 34 SO notifies DNO of aspects that might affect their network. SO provides a copy of the week 32 information to all other DNOs DNO outage planning team reviews, comments and raises concerns or issues SO draws up final National Electricity Transmission System outage plan covering Year 1 Week 36 DNO confirms and comments Week 49 Final SO outage plan submitted via in Excel and pdf format 40 P a g e

41 SO notifies DNOs for any proposed changes to the latest outage schedule Notification to DNO via DNOs review notification and raise any concerns Short term planning team develops latest plan and updates TOGA Potential concerns discussed Most up-to-date SO outage schedule uploaded on 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 Short Term Planning team EWAP submitted via in excel and pdf format Outage Planning team prepares the Eight Weeks Ahead Programme FOR COMMENT Commercial Optimisation Team sends declared generation availability to DNOs for a few days ahead Days ahead generation availability via Outage Planning SO control room sends generation SYNC/DESYNC schedule for next day to DNOs Generation SYNC/DESYNC scehduled via fax Outage Planning team 41 P a g e

42 Short Term (~2-3 weeks) Long term (>6months) A.2 DNO Operational Planning DNO outage planning 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 Is the outage feasible? YES NO High Level Study of Available options Load transfers Generation Curtailment (MW) Network reconfiguration Stand-by generation Is the outage feasible? YES NO Discussions with requester and proposal of other options: Alternative outage times Works to be completed Record outage into the plan with high level details NO YES Are there any objections? Communicate proposed outage to all relevant parties (internal, site engineers, NG, generators, customers) 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 Is the outage feasible? YES NO Detailed Study of Available options Load transfers Generation Curtailment (MW) Network reconfiguration Stand-by generation Alternative running arrangement Is the outage feasible? YES NO Discussions with requester and proposal of other options: Alternative outage times Works to be completed YES Development of outage details Running arrangement Load transfers Generation curtailment Communicate proposed outage to all relevant parties (internal, site engineers, NG, generators, customers) Are there any objections? NO Proceed with outage and inform control engineers 42 P a g e

43 B Investment Planning maps B.1 Week 24 submission Week 6 Proposals for Access Periods put forward by SO to DNOs for discussion Week 6-17 Discussions between SO and DNOs to agree Access Periods Week 42 SO sends transmission network to DNO (equivalent) Week 17 Send details of agreed Access Periods, GB Max & Min demand dates (past and forecast) Historical data and forecasted data from PLEs Regional Development Plan and Load transfers New connections (demand and generaration) DNO merges with distribution network model DNO Team prepares week 24 data submission Summing up demand at primaries and netting out generation Fault level and load flow studies Schedule 10 Total DNO daily demand (MW) profiles for: GB max GB min DNO max Schedule 11 GSP Demand Data (MW and MVAr) for: GB max GB min GSP peak Access Period peak Schedule 12 Demand Control Low Frequency Relay Settings Demand control by Voltage reduction and/or demand disconnection Emergency manual disconnection Schedule 14 Equipment data LV switchgear data LV substation infrastructure data Reactive compensation plant Schedule 5 Single Line Drawing Fault Infeeds Demand at GB max date Network alterations and reconfigurations Schedule 11 Small Embedded Power Station data per GSP: Registered capacity Type of generation Control mode Loss of mains protection Table 11C Total DNO: Customers energy per class System Losses Embedded Generation 43 P a g e

44 Delivery Optioneering Analysis Forecasting B.2 DNO Investment Planning DNO Investment Planning START Planning Load Estimates: Maximum Demand Firm Capacity Load Indices Load transfers Connection Requests: Point of Connection Technology Size Asset Health: Health Indices End of Life Mandate for replacement/retrofit Design and Operation Limitations Outages Fault Levels Security of Supply Strategic developments 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 NO Are there any constraints (current or future)? YES Select least regrets and most cost efficient solution Modelling of options: Costs High Level works Wider benefits Analysis and Optioneering: Network reconfiguration Reinforcement/Retrofit Load Transfer ANM DSR Modelling of Constraint Design and Development of the solution Delivery of solution: Procurement Commissioning Tests Hand over to Operations END 44 P a g e

45 B.3 TSO Investment Planning TSO Investment Planning Review Investment Drivers Investment Drivers, Business Plan Entry Infrastructure Reqts (Boundary Capacity) Networks Options Assessment (NOA) - GB Models - SO confirms need for boundary capability Infrastructure Requirements (Other thermal, voltage work) - Grid Code Data - Future Energy Scenarios - ETYS Boundary Req'ts - Business Plan entry Connection Request (eg Generation Development) - Customer data - Size, technology, timescales - Location - Business Plan entry Asset Replacement (eg Primary Equipment) - Condition information - Criticality - Customer impacts - Business Plan entry Analyse Requirements & Identify Options Non-investment option if appropriate (eg customer offer without works). Analysis & Option Identification - SO & TO Development Teams - Power System Analysis (thermal, voltage, stability etc) - PowerFactory & Economic Tools - Security (NETS SQSS, P2) - Outage management - Regulatory constraints No Analysis & Option Identification - SO & TO Development Teams - Power System Analysis (thermal, voltage, stability etc) - Security (NETS SQSS, P2) - Programme, Outages - Indicative Charges - Interactivity Is investment to be taken forward? Yes Analysis & Option Identification - Largely TO Development - Condition Information - Criticality - Ongoing requirements - Customer, wider impacts - Overlaps with other work Determine how to take forward NOA recommendation. Optioneering, Design & Approval Assess Options - Cost - Risks - Programme Select Preferred Option & Confirm Requirements Design & Develop Solution. - Firm Up Scheme Req'ts (SRD for Resources & Outages) - Execution Plan - Value checks & affordability Approval of Investment Delivery Execute & Close Delivery Vehicle - Issue enquiry - Evaluate proposals - Place contract Detailed Design & Assurance Build Assets Commission Assets Accept Assets - Data - Outstanding Works Closure - Data - Costs NOA Process 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 Suitability for Competition Delivery 45 P a g e

46 Mapping current SO, TO, DNO Processes B.4 NOA Process Taken from NOA Report Methodology, Draft 3, 12 th May 2017 NOA High Level Process (Draft) 46 P a g e

47 Mapping current SO, TO, DNO Processes NOA Capability Requirements & Transmission Options (Draft) 47 P a g e

48 Mapping current SO, TO, DNO Processes NOA Boundary Capability Assessment (Draft) 48 P a g e

49 Mapping current SO, TO, DNO Processes NOA Cost Benefit Assessment & Preferred Option Selection (Draft) 49 P a g e

50 Mapping current SO, TO, DNO Processes NOA Report Drafting and Publication 50 P a g e