1. SLIDE 1 FCAS CAUSER PAYS: STAGE 1 DISPUTE MEETING BACKGROUND 15 MARCH 2016 PRESENTED BY LOUISE THOMSON

2. SLIDE 2 WHY ARE WE HERE? Oct/ Nov 2015 Local market ancillary service requirement for 35MW regulation FCAS from SA. Very high FCAS Prices – Costs recovered from Market Participants in SA only. Basis applied for recovery – published ‘Causer Pays’ factors determined under AEMO procedure, including portfolio factors, but applied only for generators with units in SA. But what do participants think is a ‘fair’ outcome? Winners and losers – negotiation is possible in stage 1 – you collectively have control. Stage 2 focus on legal interpretation – Participants lose control.

3. SLIDE 3 NOT FOR DISCUSSION TODAY AEMO decision to invoke the local requirement Interpretation of, or compliance with, National Electricity Rules The optimal solution AWEFS scheduling error

4. SLIDE 4 ORIGIN COMMENTS

5. SLIDE 5 FCAS CAUSER PAYS: STAGE 1 DISPUTE MEETING TECHNICAL WALKTHROUGH 15 MARCH 2016 PRESENTED BY CHRIS MUFFETT

6. SLIDE 6 INTRODUCTION

7. SLIDE 7 WHO PAYS FOR REGULATION FCAS? Since 2001, regulation FCAS has been recovered on the principle of causer pays This involves two different methodologies: o For participants with appropriate metering (either generation or load), costs are apportioned based on the most recent contribution factor (MPF) – set out in NER 3.15.6A(i)(1) o The residual contribution (RMPF) is apportioned amongst market customers based on energy – set out in NER 3.15.6A(i)(2)

8. SLIDE 8 LOCALISED RECOVERY In 2009 a Rule change took effect which requires regulation FCAS costs to be recovered from the region or regions relevant to the requirement o Requirements can be global (sourced from any region) or local (sourced from a subset of regions) Regulation requirements are recovered from relevant region(s): o From market participants with a contribution factor AND that are related to the region(s) (i.e. associated with a connection point) o From market customers with energy in the region(s) The methodology for localised recovery is set out at: http://www.aemo.com.au/Electricity/Market-Operations/Ancillary-Services/Specifications- and-Standards/Efficient-Dispatch

9. SLIDE 9 CONTRIBUTION FACTORS (MPFS) Contribution factors (also known as MPFs or causer pays factors) are calculated according to the Causer Pays Procedure: http://www.aemo.com.au/Electricity/Market-Operations/Ancillary-Services/Process- Documentation/Ancillary-Services-Causer-Pays-Contribution-Factors The factor represents the degree to which a generator or market participant contributes to the need for regulation services

10. SLIDE 10 HOW IS REGULATION FCAS RECOVERY SETTLED? The calculation of regulation FCAS recovery is performed in the settlement component of AEMO’s Electricity Market Management System (EMMS) The calculation is based on: o Dispatch outcomes, including FCAS prices and the constraint cost for each binding FCAS requirement (global or local) o Contribution factors applicable for that settlement period o Metering data used to determine customer energy A high level overview of the calculation is available at: http://www.aemo.com.au/Electricity/Data/Ancillary-Services/Ancillary-Services-Payments- and-Recovery

11. SLIDE 11 CURRENT METHODOLOGY

12. SLIDE 12 OVERVIEW Contribution factors are calculated so as to represent the net contribution of the market participants “portfolio” For localised requirements, only contribution factors for market participants relevant to the affected region(s) are used o A market participant is relevant if it has a market generator or metered facility in the affected region(s) The local residual contribution is determined by apportioning the global residual to each region based on regional customer energy

13. SLIDE 13 METHODOLOGY – FACTOR CALCULATION Determined every 4 weeks based on historical frequency performance Calculation process involves: o Determining deviations using 4 second data o Calculating a performance factor based on the deviation and the regulation requirement (frequency indicator) o Aggregating factors over time o Aggregating factors over portfolio o Scaling factors according to overall system factors Calculation of the residual involves determining the un- metered proportion, and applying consistent scaling MPFs (metered and residual) are normalised such that AMPF = 100

14. SLIDE 14 METHODOLOGY – FACTOR APPLICATION Regulation FCAS recovery is calculated using the following steps: o The cost of each requirement (FCAS constraint) is determined in each DI – it is adjusted based on the amount of regulation service dispatched for delayed contingency service o Relevant participants are determined for each requirement in each DI, based on the region(s) related to the requirement  The CMPF is the sum of MPFs for relevant participants  The CRMPF is the scaled global RMPF

15. SLIDE 15 METHODOLOGY – RECOVERY AMOUNTS The recovery amount for each market participant is the sum of MPF-based and energy-based costs: o MPF-based costs are determined for relevant market participant’s as: MPF / (CMPF + CRMPF) * Requirement Cost o Energy-based costs are determined for market participant’s as: TCE / ATCE * CRMPF / (CMPF + CRMPF) * Requirement Cost  TCE and ATCE excludes connection points with a metered contribution factor

16. SLIDE 16 SPECIFIC REGIONAL FACTOR METHODOLOGY

17. SLIDE 17 OVERVIEW Metered factors determined only by reference to SA generating units o Raw factor taken for each generator (DUID) o Netting of factors only performed between units in SA o Aggregated for each market participant (company identifier) Residual (non-metered) factor determined as a scaled proportion of the NEM residual factor o Weighted by customer energy over the sample period MPFs determined by normalising the metered and residual factors over the total

18. SLIDE 18 CALCULATION INPUTS Based on published raw data for causer pays: o Effective period: 10 October 2015 to 7 November 2015 o Sample period: 23 August 2015 to 19 September 2015 o http://www.aemo.com.au/Electricity/Market-Operations/Ancillary-Services/Process- Documentation/~/media/Files/Electricity/Market%20Operations/AS/2015/Agg%20Factors%20 23%20August%202015%20to%2020%20September%202015_Revision%201.ashx http://www.aemo.com.au/Electricity/Market-Operations/Ancillary-Services/Process- Documentation/~/media/Files/Electricity/Market%20Operations/AS/2015/Agg%20Factors%20 23%20August%202015%20to%2020%20September%202015_Revision%201.ashx o Effective period: 8 November 2015 to 5 December 2015 o Sample period: 20 September 2015 to 17 October 2015 o http://www.aemo.com.au/Electricity/Market-Operations/Ancillary-Services/Process- Documentation/~/media/Files/Electricity/Market%20Operations/AS/2015/Agg%20Factors%20 20%20September%202015%20to%2018%20October%202015_Revision%201.ashx http://www.aemo.com.au/Electricity/Market-Operations/Ancillary-Services/Process- Documentation/~/media/Files/Electricity/Market%20Operations/AS/2015/Agg%20Factors%20 20%20September%202015%20to%2018%20October%202015_Revision%201.ashx Energy scaling performed using market customer energy o SETCPDATAREGION

19. SLIDE 19 METHODOLOGY – METERED FACTORS Filter the list of metered units to only those in the SA1 region Aggregate across each market participant the separate factors: LEF, LNEF, REF, RNEF o Note that scheduled/semi-scheduled have been aggregated with non-scheduled, which is different to current processes Calculate the overall factor for each market participant as: N(LEF) + N(REF) + LNEF + RNEF, and floor at 0 o Where N(x) = min(x,0) Calculate the MPF for each market participant as: Factor / (sum(metered factors) + residual factor)

20. SLIDE 20 METHODOLOGY – RESIDUAL FACTOR The residual is calculated by scaling the NEM residual factor: o Extract the NEM residual (un-metered) factor from the raw data o Scale down based on SA regional energy / NEM energy

21. SLIDE 21 ALTERNATE RESIDUAL FACTOR It is also possible to estimate the regional residual factor by deriving the individual contributions: o SDRF (system deviation residual factor) o SFRF (system forecast error residual factor) These are derived by apportioning the total SDF and SFF between metered and non-metered components. o However SDF is 0 across both sample periods o Therefore apportionment cannot be precisely determined This is because of the contribution of the interconnector on frequency performance, hence it is not possible to rely on this method o It is used as an estimate only, showed as alternate RMPF

22. SLIDE 22 CONTRIBUTION FACTORS 11 OCTOBER TO 7 NOVEMBER Residual MPF Proposed: 33.74 Alternate: 31.49 Row LabelsSum of N(LEFa)Sum of N(REFa)Sum of LNEFaSum of RNEFaFactorMPF AGLHydro0.00 -8.09-38.83-46.9213.53 AGLSAGen-0.750.00-54.9237.02-18.645.37 CANUNDAWF0.00 -1.10-2.35-3.451.00 CathRocks0.00 -1.330.88-0.450.13 EnergyAus0.00 0.082.540.00 FlindersOpServ0.00-2.864.64-20.38-18.605.36 Infratil0.00 -2.41-5.98-8.392.42 LakeBonneyWind0.00 16.09-61.33-45.2413.05 MtMillarWF0.00 -0.23-1.08-1.310.38 OriginEnergy0.00 8.56-50.57-42.0112.11 PacificHydroCG0.00 1.22-9.73-8.512.45 PelicanPoint0.00 SnowtownWF0.00 -1.06-10.58-11.633.35 SnowtownWF20.00 -44.7430.43-14.314.13 StarfishHillWF0.00 -0.14-0.44-0.580.17 SynergenPower0.00 1.200.150.00 WaterlooWF0.00 -0.41-9.31-9.722.80 Total-229.7866.26 NEM Residual Load-1654.22 SA1 Energy (sample period)958951.90 NEM Energy (sample period)13554984.75 SA1 Residual Load-117.0333.74 SA1 Aggregate-346.81100.00 SA1 SDF 0.00 SA1 SFF -105.60 SA1 SDRF (estimated) 0.00 SA1 SFRF (estimated) -105.60 SA1 Residual Load -105.6031.49

23. SLIDE 23 CONTRIBUTION FACTORS 8 NOVEMBER TO 5 DECEMBER Residual MPF Proposed: 31.46 Alternate: 25.07 Row LabelsSum of N(LEFa)Sum of N(REFa)Sum of LNEFaSum of RNEFaFactorMPF AGLHydro0.00 -13.19-27.31-40.5010.97 AGLSAGen-4.110.00-26.5163.190.00 CANUNDAWF0.00 -0.68-1.64-2.320.63 CathRocks0.00 -1.130.01-1.130.30 EnergyAus0.00 -0.370.470.00 FlindersOpServ0.00-4.179.48-35.46-30.158.16 Infratil0.00 -0.28-0.50-0.790.21 LakeBonneyWind0.00 10.36-46.41-36.059.76 MtMillarWF0.00 -1.82-0.81-2.630.71 OriginEnergy0.00 -11.92-2.05-13.973.78 PacificHydroCG0.00 -1.73-7.51-9.242.50 PelicanPoint0.00 2.49-18.75-16.264.40 SnowtownWF0.00 -7.68-14.17-21.855.92 SnowtownWF20.00 -45.43-18.79-64.2217.39 StarfishHillWF0.00 0.020.120.00 SynergenPower0.00 1.13-1.43-0.300.08 WaterlooWF0.00 -3.66-10.00-13.663.70 Total-253.0768.54 NEM Residual Load-1709.46 SA1 Energy (sample period)887655.51 NEM Energy (sample period)13061720.80 SA1 Residual Load-116.1731.46 SA1 Aggregate-369.24100.00 SA1 SDF 0.00 SA1 SFF -84.65 SA1 SDRF (estimated) 0.00 SA1 SFRF (estimated) -84.65 SA1 Residual Load -84.6525.07

24. SLIDE 24 ESTIMATED FINANCIAL IMPACT

25. SLIDE 25 APPROACH The total cost of locally sourced SA services was calculated: o 11-Oct to 7-Nov: $25,328,160 o 8-Nov to 10-Nov: $1,275,775 o Total (over the 5 weeks): $26,603,935 Using the SA region specific factors and residual: o The MPF-based cost for each market participant is estimated by apportioning the local costs to the MPFs for the 2 periods o The energy-based cost for each market participant is estimated by apportioning the residual using SA regional customer energy

26. SLIDE 26 IMPACT The estimated adjustment is the difference between the actual settled regulation FCAS and the proposed methodology o There are some minor discrepancies because of the SA component of global requirements

27. SLIDE 27 QUESTIONS

28. SLIDE 28 OTHER MATERIAL

29. SLIDE 29 PARTICIPANT IDENTIFIER ISSUE AEMO market systems use a Participant Identifier (PID) to reflect responsibility or association in all dispatch and settlement processes o When originally implemented, the PID reflected each registered participant in the NEM o However as a result of changes in industry structure, many registered participants have multiple PIDs for different components of their portfolio In almost all settlement calculations, breaking up a portfolio across multiple PIDs does not impact the net result o However localised recovery is based on whether a participant is related to a region, and can have different results when done for each individual PID

30. SLIDE 30 PARTICIPANT IDENTIFIER EXAMPLE Previous (incorrect) calculation PortfolioFactor G1 (on P2)50 G250 Region 1 Cost = $100 Region 2 Cost = $1 G1P1G2P1G1P2 PIDRegion 1 costRegion 2 cost G1P100 G1P201 G2P11000 Corrected calculation PortfolioFactor G1 (on P2)50 G250 Region 1 Cost = $100 Region 2 Cost = $1 G1P1G2P1G1P2 PIDRegion 1 costRegion 2 cost G1P100 G1P2501 G2P1500

31. SLIDE 31 SETTLEMENT CORRECTION AEMO implemented software changes to correct the PID issue on 2 December 2015, and involved the following impact to billing periods: o Wk42 was resettled in a special revision in Wk48 Final o Wk43 was resettled in a special revision in Wk49 Final o Wk44 was resettled in a special revision in Wk50 Final o Wk45 was corrected in the Final o Wk46 was corrected in the Final