1. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Safety Moment National Grid TNUoS Revenue team and Energy Forecasting team DEMAND SEMINAR

2. Housekeeping  Safety procedures  Comfort and wellbeing

3. Agenda  The purpose of today  Transmission tariff setting  Scene setting - An Introduction to TNUoS  How we calculate demand tariffs  What demand forecasts we use for tariff setting  How we develop the demand forecast we need  What is Demand  Impact of Embedded Generation  How we forecast Demand  How we forecast Embedded Generation  TNUoS Demand Forecasting Process  Challenges and Future Work  Opportunity for questions and discussion

4. The purpose of today  Today is an opportunity for you to learn about how we do what we do and to feed back to us any improvements  We will present National Grid’s current approach and processes  We are keen to engage with you on ideas for future development and learn from each other  We’d like this to be an informal information sharing session

5. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Safety Moment Scene setting – TNUoS ‘Money Go Round’

6. Money Go Round 6 National Grid SO Generators Suppliers OFTOs SHET SPT DNOs NGET

7. 7 Total £2,709m NGET £1,786m Revenue 2016/17 Split by TO NIC £45m Offshore £261m SHE Transmission £323m Scottish Power £295m

8. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Safety Moment Scene setting – Who Pays TNUoS?

9. Who Pays TNUoS? 9 Generator  Generators directly connected to the Transmission system, i.e. have a Bilateral Connection Agreement with NGSO with TEC > 0  Generators connected to the Distribution system, BEGA agreement with NGSO and a TEC >= 100MW All Suppliers  Suppliers with HH metered customers  Suppliers with NHH metered customers

10. Supplier Demand Tariffs HH metered customers : HH (£/kW) average triad demand tariff NHH metered customers : NHH (p/kWh) 4pm – 7pm consumption tariff

11. Demand Tariff History  In the early 1990s, just after privatisation there was no concept of NHH consumption charge. This first came in around 2000.  The methodology for calculating HH tariffs was kept unaltered and NHH was bolted on the side.  Hence, HH residual tariff is calculated as if all customers are HH metered, ie. based on total system metered demand.  HH Revenue is determined based on that tariff and HH forecast demand at Triad  NHH tariffs are set to recover the remaining revenue.

12. Demand Revenue 2016/17 £2.7bn £0.45bn £2.26bn HH metered customers NHH metered customers 83.3% paid by Demand (Suppliers) 16.7% paid by Generators

13. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Safety Moment Locational Tariffs - Demand

14. Demand Zones 14

15. HH Demand Tariff = Locational tariff + + + Peak Security Demand Tariff Year Round Demand Tariff Residual Small gens discount recovery

16. The Transmission System Model  We model the transmission system as 900+ nodes (junctions). At the nodes there could be either/neither/both generation and demand.  These nodes are connected by circuits ~1400.

17. Locational Tariffs Demand Transport Model Demand at each node = + Week 24 GSP Demand at time of Peak data provided by Distribution Companies -Embedded generation in SPT >30MW and <100MW -Embedded generation in SHET >10MW and <100MW + Directly Connected Customer Demand (predominantly Network Rail)

18. 2 generation backgrounds  We no longer build just for peak, we also build to accommodate low carbon generation. So we model two generation backgrounds  TEC data for each power station is taken from the TEC register. Tariffs are set based on the contracted position of the year, as of October 31 st in the year preceding. Peak SecurityYear Round

19. Two generation backgrounds Peak Security Biomass, CCGT, CHP, Coal, Hydro, Nuclear, OCGT, Pump Storage all scaled equally to meet demand Interconnectors = 0 Wind = 0 Year Round Interconnectors 100%, Nuclear 85%, Pump Storage 50%, Tidal Wave, Wind 70% Biomass, CCGT, CHP, Coal, Hydro are scaled to meet rest of demand.

20. Year Round Model Peak Security Model Inputs to the Two models Peak Security Generation Year Round Generation Week 24 Demand Circuits stretched by Expansion Factors, circuit impedance Week 24 Demand Circuits stretched by Expansion Factors, circuit impedance

21. Year Round Model Peak Security Model Outputs from Two models MW flows on every Circuit (for Year Round Background) MW flows on every Circuit (for Peak Security background)

22. Zonal Demand Weighted Locational Cost

23. Add the Peak Security and Year Round tariff together to give the total locational tariff

24. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Safety Moment Demand Tariffs Half Hourly Metered Customer Tariffs

25. Zonal Demand Revenue Using forecast triad demand, the revenue recovered from the locational tariff is calculated £-2.398m

26. Demand Revenue and Residual 2016/17 Demand Residual tariff = Residual Revenue divided by Total Triad Demand = (£2,255m - (£-2.398)) 49.8 GW = £ 2,257m 49.8 GW = £45.33/kW Demand Revenue £2,255m Residual Revenue £2,257m Revenue from locational tariffs £-2.3m

27. Demand Residual Tariff We can probably skip this one?

28. Small Generators’ Discount The money paid out to small generators in the small generators’ discount is recovered from demand customers. This year the small generators’ discount was forecast to cost £26.4m. Increase to HH tariffs = £26.4m ÷ 49.8GW = £0.53/kW This collects £0.53/kW x 13.1GW = £6.9m (Leaving £26.4m - £6.9m = £19.5m for NHH tariffs)

29. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Safety Moment Demand Tariffs Non Half Hourly Metered Customer Tariffs

30. Calculating NHH tariffs How much £  How much money do we need to collect in each zone???

31. Calculating NHH tariffs How much £  We know how much we need to collect in total for all customers by zone

32. Calculating NHH Tariffs Total Demand Revenue if all demand was HH

33. Calculating NHH tariffs How much £  We can forecast HH demand by zone and calculate how much money will be recovered from HH customers

34. Calculating NHH Tariffs HH Demand Revenue

35. Calculating NHH tariffs How much £  The money to be recovered from NHH customers is the difference between total demand revenue and HH demand revenue

36. Calculating NHH Tariffs NHH Demand Revenue

37. Calculating NHH tariffs Derive p/kWh tariff  With the revenue for each zone known, the tariff is calculated by dividing by the expected annual consumption between 4pm and 7pm for that zone.

38. Demand Residual Tariff

39. Small Generators’ Discount adjustment The money paid out to small generators in the small generators’ discount is recovered from demand customers. This year the small generators’ discount was forecast to cost £26.4m. HH metered demand tariffs are set to collect £6.9m Leaving £26.4m - £6.9m = £19.5m Increase to NHH tariffs = £19.5m/26.15 TWh = 0.074p/kWh

40. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. What Demand figures have we used to calculate tariffs?

41. What Demand have we used to calculate HH tariffs? Locational Element of tariffs is derived from Week 24 data received from the DNOs Total System Triad demand within each demand charging zone

42. What Demand have we used to calculate NHH tariffs? Total System Triad Demand by zone and HH Triad Demand by zone determines how much money is to be collected from NHH customers in each zone. NHH demand per zone shares that £ cost per kWh forecast

43. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. How we develop the demand forecast we need

44. Demand Forecasting  What is Demand  Impact of Embedded Generation  How we forecast Demand  How we forecast Embedded Generation  TNUoS Demand Forecasting Process  Challenges and Future Work 44

45. What is Demand  What is Demand  Impact of Embedded Generation  How we forecast Demand  How we forecast Embedded Generation  TNUoS Demand Forecasting Process  Challenges and Future Work 45

46. What is Demand 46

47. What is Demand  In Operational Timescales, Demand measured as sum of generation, using operational (lower accuracy) metering  Some variation in list of generators used to define demand  In Settlement Timescales, Demand measured as sum of settlement meters 47

48. Impact of Embedded Generation  What is Demand  Impact of Embedded Generation  How we forecast Demand  How we forecast Embedded Generation  TNUoS Demand Forecasting Process  Challenges and Future Work 48

49. Impact of Embedded Generation  Most demands quoted by National Grid are the generation requirement needed to be met from the Transmission System.  Embedded generation meets local demand and so suppresses the demand on the Transmission System 49

50. Impact of Embedded Generation Saturday 6th June  Sunny  Windy Saturday 13 th June  Overcast  Still

51. Impact of Embedded Generation

57.  Have to correct metered demands for Embedded Generation (PV and Wind) in order to get consistent dataset to model 57

58. How we forecast Demand  What is Demand  Impact of Embedded Generation  How we forecast Demand  How we forecast Embedded Generation  TNUoS Demand Forecasting Process  Challenges and Future Work 58

59.  Known Variables  Time of Year  Time of Day  Day of Week  Weather  Special Events  Bank Holidays  School Holidays  Hidden variables  Unmetered generation:  Wind  Solar  Model Error  Human behaviour  Other generation  Economic factors  ????? How we forecast Demand

60. How we forecast Demand – Time of Year

61. How we forecast Demand – Day of Week

62. GB National Demand: Bank Holiday effect 62

63. 63 Day of week impact Friday Demand curve for weekday in GMT Monday Demand curve for Saturday in GMT Demand curve for Sunday in GMT

64. 64 School Holiday Impact Demand curve for weekday GMT 0% school holiday (black) 100% school holiday (red)

65. 65 The effect of illumination on demand 0 500 1000 1500 2000 2500 3000 3500 4000 4500 05101520253035404550556065707580859095100105110115120125130135140145150155160 Illumination Demand Effect (MW) DULL High Demand BRIGHT Low Demand

66. 66 Temperature Demand Effect (MW) COLD High Demand MILD Low Demand HOT Quite High Demand Temperature

67. 67 Cooling Power of the wind Demand Effect (MW) COLD + STRONG WIND High Demand HOT + LOW WIND Low Demand In the past it was as simple as… …but now we have lots of embedded wind generation Wind

68. 68 Precipitation

69. 69 Temperature (1°C fall in cold conditions) Cloud cover (clear sky to thick cloud) Precipitation (no rain to heavy rain) Temperature (1°C rise in hot conditions) + 500 MW + 1,000 MW + 1,500 MW Cooling power (10 mph rise in cold conditions) + 1,000 MW The Impact of Weather Some Numbers In context 500MW is the equivalent of a town/ city the size of Oxford/ Edinburgh

70. Met Office Forecast Data 70  Data source is Met Office  Forecast data for ~ 106 locations  Forecast arrives 4 times a day. Each forecast is for the next 14 days ahead and at hourly resolution  Weather variables that come through: temperature, solar radiation, wind speed and wind direction Met Office weather files timestamps Files processed & ready to use by Goal run weather file used for GMTBST YYYYMMDD 02:3003:3004:3004:00, 09:00, Nominal (D+1) YYYYMMDD 08:3009:3010:3012:00, BPS (D+1), Pre-Nom (D+2) YYYYMMDD 14:3015:3016:3019:30 YYYYMMDD 20:3021:3022:3023:00

71. Met Office Forecast Data 71  Forecast data for:  Demand calculation: 7 main stations are used, weighted by population, to give National Average  Renewable generation calculations: the data for the nearest weather station to the generator is used  The 7 main stations and their weights: Weather station name Station code Station number Station weighting (% of Nat. Avg.) HeathrowLN77228 Bristol FiltonBR62818 Birmingham C/HBM53516 HawardenMN32114 GlasgowGW13410 LeconfieldLF3827 LeemingLM2577

72. 72 MW peak demand 2012 Greater London9400 Manchester2400 Birmingham2200 Leeds1900 Liverpool1800 Sheffield1200 Glasgow1100 Newcastle1100 Norwich500 Edinburgh500 Bristol400 Cardiff400 Plymouth200 UK City Demands London weather particularly important…

73. GB National Demand: Cardinal Points

74. 74 CP National Demand Underlying Demand Day of week effect Weather Effects Embedded Generation Time of year Holidays Year on year growth Saturday 6GW lower Sunday 7GW lower MODEL Temperature Illumination Wind Speed What makes up a CP national demand?

75.  Each Cardinal Point has a minimum of two forecast models:  At least one conventional model  At least one trend model  Uses recent observed demand(s) to adapt forecast to current levels  Difference between conventional and trend models: NG National Demand forecast models CPTrend model trends on: 1Fprevious day 1F 1Aprevious day 1A 1Bprevious day 1B 2Fin day 1B 2Ain day 1B 2Bin day 1B & in day 2A 3Bin day 1B & in day 2A 3C / DPin day 1B & in day 2A 4Bin day 1B & in day 2A 4Cin day 1B & in day 2A Basic Demand Week Day Component Weather Component Additional Effects Previous relevant demand(s) that a trend model trends on Trend models Basic Demand Week Day Component Weather Component Additional Effects Conventional models

76. GB National Demand: Triad avoidance / CDM 76

77. Triad Avoidance In Demand Forecasts 1200 Day - 11700 Day - 1~ 2100 Day - 1 Initial forecast for tomorrow’s Triad Avoidance volume All forecasts up to day ahead EXCLUDE Triad Avoidance Only exception is ACS Peak forecast Volume of Triad Avoidance estimated Forecast for tomorrow’s Triad Avoidance volume modified in the light of observed effect Demand Forecast updated with latest weather Forecast Triad Avoidance subtracted from Demand Forecast Published Forecast EXCLUDES Triad Avoidance Published Forecast INCLUDES Triad Avoidance Publication time dependent on Operational constraints

78. Triad Avoidance In Demand Forecasts 0900 On Day Triad Forecasts received from Suppliers Forecast for Triad Avoidance volume updated Forecast INCLUDES latest Triad Avoidance forecast Forecast for Triad Avoidance volume updated as necessary Forecast INCLUDES latest Triad Avoidance forecast During Day

79. How well do we do?  Typical spot forecasting error <1%  About 50% of our errors derive directly from errors in weather forecasts  Essentially an irreducible error because of chaotic nature of weather  Remodel twice yearly  Daily check of performance  Constant review of methodology 79

80. How do we forecast Demand  Short term demand forecasts based on forecast weather  Medium / long term forecasts based on ‘Normal’ weather  Use Average Cold Spell to forecast demand that has a 50:50 chance of being exceeded. 80

81. What is Demand – Average Cold Spell 81

82. What is Demand – Average Cold Spell 82

83. What is Demand – Average Cold Spell 83

84. What is Demand – Average Cold Spell 84

85. What is Demand – Average Cold Spell 85

86. What is Demand – Average Cold Spell 86

87. How we forecast Embedded Generation  What is Demand  Impact of Embedded Generation  How we forecast Demand  How we forecast Embedded Generation  TNUoS Demand Forecasting Process  Challenges and Future Work 87

88. Forecasting Wind Generation  National Grid receives metered output data for each of the 110 wind farms  We combine metered output with wind speed data to produce individual wind power curve for each wind farm

89. Forecasting Wind Generation –Directly connected  Individual forecasts produced for each of the 110 wind farms connected to National Grid system  Wind speed forecasts received for 66 separate locations round country  Weather forecasts received every 6 hours for 14 days at hourly resolution  Each wind farm allocated to a weather forecast location  Each individual wind farm’s power curve used to produce forecast for each wind farm’s output for next 14 days  Forecasts used within National Grid to plan system operation

90. Forecasting Wind Generation –Directly connected

91. Forecasting Wind Generation - Embedded  We do demand forecasts for all wind farms 1MW or above that we are aware of  Each of the 410 wind farms allocated to a weather forecast location  Generic power curve used to produce forecast for each wind farm’s output for next 14 days  Forecasts combined to produce national embedded wind forecast  Forecast subtracted from demand forecast  Forecast also published on National Grid website

92. Forecasting PV Generation  Weather forecasts for solar radiation for 28 different sites round country  Forecasts received every 6 hours for next 14 days at hourly resolution  All solar generation allocated to one of the 28 locations  Weather forecasts converted into PV generation forecasts for each location for each hour for next 14 days using generic power curve  PV generation forecasts combined to produce national forecast  PV generation forecast subtracted from demand forecast  Forecast also published on National Grid website

93. TNUoS Demand Forecasting Process  What is Demand  Impact of Embedded Generation  How we forecast Demand  How we forecast Embedded Generation  TNUoS Demand Forecasting Process  Challenges and Future Work 93

94. TNUoS Demand Forecasting Process  New process for this year  Use same methodology as National forecast  Derive correlations based on historic data  Derive separate correlations for:  14 Different Zones, each with separate forecasts for  6 Settlement Periods (33 – 38) for Half Hourly Metered  Total for Non Half Hourly Metered  Peak System Demand based on TNUoS definition 94

95. Challenges and Future Work  What is Demand  Impact of Embedded Generation  How we forecast Demand  How we forecast Embedded Generation  TNUoS Demand Forecasting Process  Challenges and Future Work 95

96. Challenges  We can forecast ACS quite well  To forecast actual values we need to forecast weather a year ahead  Changing nature of demand  Changing patterns of embedded generation 96

97. Future Work  Trying to source data on conventional embedded generation – improved CDM modelling  Improved PV modelling  Project with Met Office to improve weather forecasts  Project with Sheffield University to get estimated PV outturn data  Project with Reading University to improve PV modelling  Sourcing data on PV output to improve models 97

98. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Questions and discussion

99. Charging contact details  Louise 07583 012922 Louise.schmitz@nationalgrid.com  Mary 01926 653845 mary.owen@nationalgrid.com  Paul 07870 832006 paul.hitchcock@nationalgrid.com  Iain Iain.ashworth@nationalgrid.com 07973 766042  Jess 07866 786143 Jessica.neish@nationalgrid.com

100. Energy forecasting contact details  Jeremy Caplin  jeremy.caplin@nationalgrid.com jeremy.caplin@nationalgrid.com  0118 936 3288  Sumit Gumber  sumit.gumber@nationalgrid.com sumit.gumber@nationalgrid.com  0118 936 3250  Andrew Richards  Andrew.richards@nationalgrid.com Andrew.richards@nationalgrid.com  0118 936 3044

101. 101 Forecasts this year  17/18 Forecast - June  17/18 Forecast - October  17/18 Forecast - December  Actual 17/18 Tariffs - January  5 year forecast likely to be February

102. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Demand Charges

103. HH Demand Charge Supplier Demand Charge (£) = Demand Tariff (£/kW) x Average demand at Triad (kW) Calculate for each zone and sum for Supplier liability

104. NHH Demand Charge Supplier Demand Charge (£) = Demand Tariff (p/kWh) x Supplier annual consumption 4pm-7pm (kWh) ÷ 100 Calculate for each zone and sum for Supplier NHH liability

105. Triad determination example – 2005-06 Triad 1: 59.4 GW 28 th Nov SP 35 Triad 2: 58.6 GW 2 nd Feb SP 36 Triad 3: 58.5 GW 5 th Jan SP 35 105

106. Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Managing HH and NHH during P272 implementation

107. Introduction  Demand previously in Profile Classes 5 to 8 was included in the Non-Half-Hour demand charging base.  Following P272 these meters will be transferred to Metering Classes E, F and G which are included in the Half-Hour demand charging base.  Assume P272/P322 implementation is completed by 1 April 2017, i.e. transitional arrangements under CMP241/247 are no longer applicable.

108. PC5-8 as proportion of NHH Chargeable Demand  Profile classes 5 to 8 (Blue) represent 9.4% of Non-Half- Hour metered annual energy consumption between 4 and 7pm.  These will be migrated to Half- hour metering so 2017/18 NHH chargeable demand is reduced by 9.4% from pre- P272 levels.

109. Zonal NHH adjustments for PC5-8  Zonal PC5-8 demand as a proportion of chargeable NHH demand varies from 0.28% in Northern Scotland to 1.08% in Eastern (Totals to 9.4%).  Zonal NHH chargeable demand in each zone is reduced by zonal PC5-8 proportion of pre-P272 national NHH demand forecast.

110. PC5-8 as Proportion of NHH Demand at Triad  Profile classes 5 to 8 (blue) represent 9.2% of Non-Half- Hour demand at Triad.  Different number because this is three 5-5.30pm half-hours not daily 4-7pm.  However similar enough not to have significant impact on tariffs.

111. Zonal HH Adjustments for P272  Zonal PC5-8 demand as a proportion of NHH Triad Demand varies from 0.27% in Northern Scotland to 1.06% in Eastern (Totals to 9.2%).  Zonal HH Triad demand is increased by zonal PC5-8 proportion of national NHH Triad demand.

112. Q&A’s  TNUoS tariff setting  1. What is the split of the £2.2b between HH & NHH customers? Approximately £1.6bn to NHH and £0.6bn HH  2. Why is it called Week 24 data? National Grid receive data from the DNO’s in week 24. The labelling has nothing to do with the time period to which the data relates  3. Could National Grid not use forecast demand for the locational tariffs? Why do you use DNO data? It is stipulated in the charging methodology that DNO data is used for the locational element of the tariff setting.  4. Can you tell us how accurate the Week 24 data is? National Grid undertake sense checks on the data but the processes to provide the data are the responsibility of the DNOs 112

113. Q&A’s  Demand forecasting process  5. How much capacity is embedded? Awaiting information  6. Why do embedded actuals change by a few MW a few days later? Awaiting information  7. Why is capacity different to Sheffield? Awaiting information  8. Demand forecast based on ACS? Yes  9. Wind Speed data collected from wind farms? Yes  10. It is the same process for 5 year forecast? Similar but different correlations 113

114. Q&A’s  11. What has changed in the whole method? It’s a new process, fewer teams involved  12. What is the magnitude of improvement expected? Over a long time period, guess of 500MW  13. Magnitude of new process in forecasting? Error margin is less  14. How consistent is the process in future scenarios? It uses the same assumptions as a scenario would. FES includes embedded and National Grid feeding ACS into FES so similar. Main difference across scenarios is PV and change is underlying base demand. 114