Electricity System Operator Incentives BSUoS Seminar

Transcription

1 Electricity System Operator Incentives BSUoS Seminar 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. Tuesday 15 th February 2011

2 Welcome and Introduction Alan Smart, Energy Operations Manager

3 Agenda Welcome and Introduction Overview of SO Incentives Review David Smith BSUoS methodology Colin Williams BSUoS Forecasts and input assumptions: Energy Katharine Clench Constraints Guilherme Susteras BSUoS Reporting Jo Faulkner Closing remarks and next steps Alan Smart 3

4 Things to note Health and Safety Feedback forms 4

5 Overview of the Electricity SO Incentives Review David Smith, Electricity Codes Manager Place your chosen image here. Turn on the Grid and Guides option under View and check the display drawing guides on screen box for position.

6 Where are we in the SO Incentives Review process? Review of current modelling approach (Ofgem-led with consultancy support) Development by NGET of revised forecasting methodology based on recommendations from Phase 1 Examination of NGET s proposed methodology, including models and modelling approach Phase 1 (6 weeks) Phase 2 (15 weeks) Phase 3 (8 weeks) 6

7 Summary of Phase 1 key findings Aim: Multi-year scheme: Promote system operation efficiency Reduce regulatory and industry burden Ofgem and Frontier suggested clear way forward: New constraint model and revised energy models to provide reliable analysis to support setting scheme parameters Ex-post treatment of unpredictable external factors beyond NGET s control to remove windfall potential 7

8 Evolution of the proposed incentivisation approach Target IBC Adjustments to Target IBC Adjustments to outturn costs Current Ex-ante Two ex-post adjusters Ex-post NIA Proposed Ex-ante forecast updated ex-post Multiple ex-post adjustments None BSUoS Charges Ex-ante forecast Ex-ante forecast 8

9 New scheme structure We believe the proposed approach will remove volatility and allow for sharper scheme parameters: Profit 0 Higher profit cap Steeper sharing factors No (or limited) dead-band (e.g. to cover modelling errors) IBC Existing scheme Lower loss floor Loss 9

10 BSUoS Charging Methodology Impact of BSIS Initial Proposals Colin Williams - Charging and Revenue

11 Agenda Calculation of BSUoS Charges Impact as a result of BSIS 2011/13 Internal Incentive External Incentive 11

12 BSUoS Calculation and Billing Charges apportioned on a /MWh proportionality basis Run Type Definition Processing / Billing Timescales /MWh - one price per HH period, paid by all II* Interim Initial Settlement Day + 5 working days *No invoice sent Calculated half-hourly SF Settlement Final Daily, Settlement Day + 16 working days Billed Daily Two stage Financial Settlement RF Reconciliation Final This will remain unchanged Daily, Settlement Day + 14 months 12

13 BSUoS Charges - Calculation Two main components of BSUoS Internal - internal SO costs e.g. staff, buildings, IS External - costs of the services used to balance the system Electricity related products Balancing Services Contract Costs Balancing Mechanism Bids and Offers Both Internal and External Costs have an Incentive Scheme Adjustment 13

14 BSUoS Calculation Simplified BM Costs Contract Costs / Other Costs External BSUoS Charge BM Unit Metered Volumes BSIS Total BSUoS Total BSUoS Charge HH BSUoS ( ) HH Volume (MWh) = /MWh For all HH periods of a Settlement Day Internal BSUoS Costs Internal BSUoS Charge Customer BSUoS Charges Internal Incentive HH BMU Volume x /MWh = HH BSUoS Charge 14

15 BSUoS Calculation Simplified BM Costs Contract Costs / Other Costs External BSUoS Charge BM Unit Metered Volumes BSIS Incentive Total BSUoS Total BSUoS Charge HH BSUoS ( ) HH Volume (MWh) = /MWh For all HH periods of a Settlement Day Internal BSUoS Costs Internal BSUoS Charge Customer BSUoS Charges Internal Incentive HH BMU Volume x /MWh = HH BSUoS Charge 15

16 Incentivised Balancing Costs Current Methodology 2010/11 IBC Calculation Costs to SO of Balancing Mechanism (Bids / Offers) Net Imbalance Adjustment Transmission Loss Adjustment IBC d = Σj (CSOBM j + BSCCV j + NIA j + TLIC j ) + BSCCA d OM d RT d Balancing Services Contract Costs Reconciliation & adjustment Terms To determine the value of the incentive adjustment to BSUoS Charges the average IBC is calculated. Against this number the incentive adjustment is calculated by comparing against the Incentivised Target 16

17 BSIS 2010/11 - Summary Max 15m Profit Summary of Current Scheme One Year Scheme Fixed Incentivised Cost Target Cap and Collar Sharing Factors Profit / Loss ( m) % Upside Sharing Factor Deadband ( 0 profit or loss) 15% Downside Sharing Factor Min -15m loss Incentivised Balancing Costs ( m) Scottish Generation and IFA Adjusted Scheme 17

18 Impact on Incentivised Balancing Costs from Initial Proposals 2011/13 IBC Calculation Costs to SO of Balancing Mechanism (Bids / Offers) Net Imbalance Adjustment Transmission Loss Adjustment IBC d = Σ j (CSOBM j + BSCCV j + NIA j + TLIC j ) + BSCCA d OM d RT d Balancing Services Contract Costs Reconciliation & adjustment Terms Proposed changes to calculation of IBC Remove NIA and potential removal of RT 18

19 BSIS 2011/13 Initial Proposals Scheme Profit of Loss ( m) Target - y Upside Sharing Factor Limited or no Deadband ( 0 profit or loss) Revised Target Downside Sharing Factor Summary of Initial Proposals Two Year Scheme Ex-Post Updated Target Fixed variances from Target Cap and Collar Sharing Factors Target + y Incentivised Balancing Costs ( m) 19

20 BSUoS Internal Incentive 2010/11 15% Upside Sharing Factor Fixed Target 55,262,715 Summary of Current Scheme Five year scheme Annual adoption of BSIS sharing factors Fixed Target No Cap or Collar Sharing Factors 0 FSOINt ( ) 15% Downside Sharing Factor 20

21 BSUoS Internal Incentive 2011/12 & 2012/13 Fixed Target Summary of Scheme Remain as five year scheme Annual adoption of BSIS sharing factors Fixed Target per year No Cap or Collar Sharing Factors Upside Sharing Factor 0 FSOINt ( ) Downside Sharing Factor 21

22 BSUoS Charges BSIS 2011/13 Impact Summary Calculation of External Incentive Calculation of Internal Incentive Methodology of Charging and Apportioning Billing BSUoS Any Change? X X X Change Detail Two Year External Scheme Variable Target with cap, collar and sharing factors Sharing Factor Remains to be considered on an annual basis No Change to method No Change to method Removal of NIA 22

23 BSUoS Charging Contact Any BSUoS Charging Questions please contact: Colin Williams Tel:

24 BSUoS Forecast - Energy Components Katharine Clench, BSIS Commercial Analyst

25 Content Headline Energy forecast Ex ante/ ex post inputs and assumptions Model sensitivity Black Start and Transmission Losses Waterfall diagrams 25

26 Headline Energy Forecast 2005/6 Year End 2006/7 Year End 2007/8 Year End 2008/9 Year End 2009/10 Year End 2010/11 Latest View THIS MODEL (Apr/11 to Mar/12) THIS MODEL (Apr/12 to Mar/13) All Categories m Energy Imbalance Margin Op. Reserve STOR BM Start Up CMM Energy + Margin Footroom Fast Reserve AS Response BM Response Reactive Blackstart Total (less Constraints and TLA)

27 Headline Energy Forecast 2005/6 Year End 2006/7 Year End 2007/8 Year End 2008/9 Year End 2009/10 Year End 2010/11 Latest View THIS MODEL (Apr/11 to Mar/12) THIS MODEL (Apr/12 to Mar/13) All Categories m Energy Imbalance Margin Op. Reserve STOR BM Start Up CMM Energy + Margin Footroom Fast Reserve AS Response / /13 BM Response Reactive Blackstart m 539.1m Total (less Constraints and TLA)

28 New Modelling Approach Ex-Ante/Ex-Post Approach Ex-Ante Ex-Post Forecast Inputs Modelled Relationships Actual Data Inputs Scheme Target (bundled) 28

29 Ex ante Inputs Modelled relationship STOR volume and price Energy Imbalance Margin Static Response/ FFR Reserve for wind % Fast Reserve Constraints - CMM 2009/10 Volume Weighted Price Trend Frequency Response Footroom Demand Reactive Power 29

30 Ex post Inputs Power Price Energy Imbalance NIV Margin Headroom Wind generation Frequency Response Fast Reserve Ex ante inputs Nuclear generation Footroom RPI Reactive Power 30

31 Assumptions and Sensitivities

32 Ex Post Input Assumptions Power Price SPNIRP (Avg) BM Price (Avg) 32 /MWh Apr-08 Jun-08 Aug-08 Oct-08 Dec-08 Feb-09 Apr-09 Jun-09 Aug-09 Oct-09 Dec-09 Feb-10 Apr-10 Jun-10 Aug-10 Oct-10 Dec-10 Feb-11 Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 ACTUAL FORECAST

33 Ex Post Input Assumptions Power Price Scenarios Power price by: 50% All Categories m THIS MODEL (Apr/11 to Mar/12) THIS MODEL (Apr/12 to Mar/13) Energy Imbalance Margin Operating Reserve STOR BM Start Up CMM Energy Imbalance + Margin Footroom Fast Reserve AS Response BM Response Reactive Blackstart Total (less Constraints and TLA) ~16% +36% +25% ~ 79m increase to each 33 year

34 Ex Post Input Assumptions Power Price Scenarios Power price by: 50% All Categories m THIS MODEL (Apr/11 to Mar/12) THIS MODEL (Apr/12 to Mar/13) Energy Imbalance Margin Operating Reserve STOR BM Start Up CMM Energy Imbalance + Margin Footroom Fast Reserve AS Response BM Response Reactive Blackstart Total (less Constraints and TLA) % -36% -21% -15% ~ 60m decrease to each 34 year

35 35 Ex Post Input Assumptions Headroom Apr-08 Jun-08 Aug-08 Oct-08 Dec-08 Feb-09 Apr-09 Jun-09 Aug-09 Oct-09 Dec-09 Feb-10 Apr-10 Jun-10 Aug-10 Oct-10 Dec-10 Feb-11 Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 MW Headroom (Avg) FORECAST ACTUAL

36 Ex Post Input Assumptions Headroom Scenarios Headroom and by: 40% All Categories m THIS MODEL (Apr/11 to Mar/12) THIS MODEL (Apr/12 to Mar/13) Energy Imbalance Margin Operating Reserve STOR BM Start Up CMM Energy Imbalance + Margin Footroom Fast Reserve AS Response BM Response Reactive Blackstart Total (less Constraints and TLA) ± 6% ± 24% ± 17% ± ~ 26m to each year 36

37 Ex Post Input Assumptions Wind Generation Wind mean generation (MW) / / / Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar 37

38 Ex Post Input Assumptions Wind Scenarios Wind output and by: 15% All Categories m THIS MODEL (Apr/11 to Mar/12) THIS MODEL (Apr/12 to Mar/13) Energy Imbalance Margin Operating Reserve STOR BM Start Up CMM Energy Imbalance + Margin Footroom Fast Reserve AS Response BM Response Reactive Blackstart Total (less Constraints and TLA) ± ~6% ± 8% ± ~ 10m to each year 38

39 Ex Post Input Assumptions Net Imbalance Volume (NIV) 39 MW Apr-08 Jun-08 Aug-08 Oct-08 Dec-08 Feb-09 Apr-09 Jun-09 Aug-09 Oct-09 Dec-09 Feb-10 Apr-10 Jun-10 Aug-10 Oct-10 Dec-10 Feb-11 Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 ACTUAL FORECAST

40 Ex Post Input Assumptions NIV Scenarios NIV and by: All Categories m THIS MODEL (Apr/11 to Mar/12) THIS MODEL (Apr/12 to Mar/13) Energy Imbalance Margin Operating Reserve STOR BM Start Up CMM Energy Imbalance + Margin Footroom Fast Reserve AS Response BM Response Reactive Blackstart Total (less Constraints and TLA) MW ± 4 % ± ~300% ± ~ 90m to each year 40

41 Ex Post Input Assumptions Nuclear Generation Nuclear (Avg) 41 MW Apr-08 Jun-08 Aug-08 Oct-08 Dec-08 Feb-09 Apr-09 Jun-09 Aug-09 Oct-09 Dec-09 Feb-10 Apr-10 Jun-10 Aug-10 Oct-10 Dec-10 Feb-11 Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 ACTUAL FORECAST

42 Ex Post Input Assumptions Nuclear Scenarios Nuclear output to 4500MW and to 8800MW All Categories m THIS MODEL (Apr/11 to Mar/12) THIS MODEL (Apr/12 to Mar/13) Energy Imbalance Margin Operating Reserve STOR BM Start Up CMM Energy Imbalance + Margin Footroom Fast Reserve AS Response BM Response Reactive Blackstart Total (less Constraints and TLA) % and +13% - 43% and +14% - 33m and + 10m to each 42 year

43 Ex Post Input Assumptions RPI 6.00% 5.00% 4.00% 3.00% 2.00% 1.00% 0.00% -1.00% -2.00% 43 Apr-08 Jun-08 Aug-08 Oct-08 Dec-08 Feb-09 Apr-09 Jun-09 Aug-09 Oct-09 Dec-09 Feb-10 Apr-10 Jun-10 Aug-10 Oct-10 Dec-10 Feb-11 Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 ACTUAL FORECAST

44 Black Start and Transmission Losses 2011/12 Black Start 2012/13 Total Availability fees Capital 28.4m 29m 57.4m Testing Transmission Losses 5.5TWh ± 0.5TWh 44

45 Energy Forecast - Range Low = combined output of lower case scenarios High = combined output of upper case scenarios Low Mid 448.6m High 2010/11 (latest view) 2011/12 361m 521.2m 767m 2012/13 377m 539.1m 785m 45

46 Waterfall 2010/11 to 2011/ m 2010/11 Energy Imbalance Margin Footroom Fast Reserve AS Response BM Response Reactive Blackstart Other 2011/12

47 Waterfall 2011/12 to 2012/ m 2011/12 Energy Imbalance Margin Footroom Fast Reserve AS Response BM Response Reactive Blackstart Other 2012/13

48 Energy Summary Energy forecast for 2011/12 and 2012/13 Ex ante and ex post inputs Ex post assumptions Model sensitivities Waterfall diagrams Low Mid High 2011/12 361m 521.2m 767m 2012/13 377m 539.1m 785m 48

49 Constraints Forecast Gil Susteras, Future Requirements Manager

50 Agenda Model overview Unconstrained calibration Ex-ante assumptions Ex-post assumptions Forecast Scenarios and waterfalls 50

51 1. Unconstrained Run (simplified) Generator Availability Generator Dynamic Parameters, efficiencies etc Simulation of interconnected (non-gb) markets Demand Forecast Fuel/ Carbon Prices Wind Output Ex-ante Ex-post Model output Generator FPNs and Interconnector flows to meet forecast demand (assuming infinite Transmission System capability) 51

52 2. Constrained Run (simplified) Generator FPNs and Interconnector flows to meet forecast demand (assuming infinite Transmission System capability) Transmission System modelled by a number of zones divided by boundaries Each boundary has a limit Forecast generation and demand levels assigned to each zone The model re-despatches generation in order to satisfy each boundary limit (or constraint) based on BM Prices IF: zone generation zone demand > zone boundary capability 52

53 Unconstrained calibration results Sample results for key boundaries

54 Scotland Scotland Peaks solid=fpn 2009/10; dashed=plexos 2009/10 Scotland Off-peaks solid=fpn 2009/10; dashed=plexos 2009/10 MW MW Week Week 54

55 Thames Estuary Thames Estuary Peaks solid=fpn 2009/10; dashed=plexos 2009/10 Thames Estuary Off-peaks solid=fpn 2009/10; dashed=plexos 2009/10 MW MW Week Week 55

56 South Wales South Wales Peaks solid=fpn 2009/10; dashed=plexos 2009/10 South Wales Off-peaks solid=fpn 2009/10; dashed=plexos 2009/10 MW MW Week Week 56

57 French Interconnector France (IFA) peak [Positive=flow into GB] solid=fpn 2009/10; dashed=plexos 2009/10 France (IFA) off-peak [Positive=flow into GB] solid=fpn 2009/10; dashed=plexos 2009/10 MW MW Week Week 57

58 Moyle Interconnector Ireland (Moyle) peak [Positive=flow into GB] solid=fpn 2009/10; dashed=plexos 2009/10 Ireland (Moyle) off-peak [Positive=flow into GB] solid=fpn 2009/10; dashed=plexos 2009/10 MW MW Week Week 58

59 Assumptions

60 Ex-ante assumptions Generator Availability: OC2 + stochastic failure rate Generator Dynamic Parameters, efficiencies etc: BM submissions + publicly available information Simulation of interconnected (non-gb) markets: simplified stack (Redpoint s experience) Demand Forecast: National Grid well established process Transmission zones and boundaries: National Grid experience and expected outage plan Generation/demand per zone: Diagrams + GSP historic levels Boundary limits: Power System Studies and operational experience 60

61 Ex-post assumptions Fuel/ Carbon Prices: Argus forward curve and Bloomberg Wind Output: 2009/10 metered output scaled for expected installed capacity (Gone Green scenario) BM Prices: scaled from SRMC 61

62 Forecast

63 Like-for-like run (SRMC based) 2009/10 = /12 = /13 =

64 Pro-rata of values 2009/10 = 120 = 140m 2011/12 = 268 = 313m 2012/13 = 229 = 267m 64

65 Simplified waterfall (1) Total Constraint Costs ( m) /10 Fuel Prices & Generation changes Boundary limits 2011/12 65

66 Simplified waterfall (2) Total Constraint Costs ( m) /10 Fuel Prices & Generation changes Boundary limits 2012/13 66

67 Drivers for variations System boundaries Evolving transmission system Fuel Prices Snapshot based on forward curve; in reality, ex-post input Wind generation Snapshot based on best view of connections; in reality, ex-post input 67

68 Commodity prices effect SRMC ( /MWh) Old CCGT Typical coal unit Coal unit (LCPD opted out) New CCGT 68

69 Wind generation Wind mean generation (MW) / / / Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar 69

70 Sensitivity analysis Commodity prices Wind 70

71 Effect of Movements in Gas Prices (up by 15% in summer) SRMC ( /MWh) /12 forecast up by 60% 2012/13 forecast up by 50% Old CCGT Typical coal unit Coal unit (LCPD opted out) New CCGT 71

72 Effect of Movements in Gas Prices (down by 15% in winter) SRMC ( /MWh) /12 forecast down by 9% 2012/13 forecast down by 3% Old CCGT Typical coal unit Coal unit (LCPD opted out) New CCGT 72

73 Wind sensitivity 2011/12 (±15%) Wind mean generation (MW) /12 forecast up/down by ± 8% 2011/ / Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar 73

74 Wind sensitivity 2012/13 (±15%) Wind mean generation (MW) /13 forecast up/down by ± 8% 2012/ / Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar 74

75 Constraints Forecast - Range Low = combination of all low scenarios High = combination of all high scenarios Low Mid 161m High 2010/11 (latest view) 2011/12 260m 313m 526m 2012/13 238m 267m 422m 75

76 Summary Transmission system evolving in response to new connections Constraint management is a key aspect of the value added by National Grid as System Operator Sharper incentives + Higher requirements = potential increase in CMS contracts Forecast presented is a snapshot based on current best view of controllable and un-controllable drivers 76

77 BSUoS Reporting Jo Faulkner, Balancing Services Manager

78 Intitial Scheme Target Market Length Wholesale Power Price Other Ex- Post Adjustment Waterfall Example Agreed Scheme Target 6.5 SC+CH Constraints -2 EW - Constraints +1 Response -0.5 Outturn 5 78

79 Monthly Forecast & Outturn Example 79 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Month Monthly IBC ( m) Cumulative IBC ( m) Intital Scheme Forecast Agreed Scheme Forecast Latest Forecast Outturn Cumu. Initial Cumu. Revised Cumu. Outturn+Forecast

80 Scheme Chart Example 80 Scheme Profit or Loss ( m)

81 Monthly BSUoS Example 2011/12: 0.95/MWh 2012/13: 1.02/MWh Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 BSUoS charge /MWh May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Month Last Year Value Provisional Outturn Latest Forecast

82 Closing remarks Alan Smart, Energy Operations Manager

83 Next Steps Models to be refreshed with most recent data prior to scheme start CUSC Modification to update Charging Methodology by removing the NIA concept from the BSUoS calculation Licence methodology statements to be developed Ofgem to publish Final Proposals in March

84 Contact us On the web: Our dedicated web pages for electricity SO incentives are available at the following addresses: Talk to us: Ian Pashley: Tel: General enquiries: 84