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AM/NeL֓qp&%-ܲ4>Xl%9^%r]$WrUĮ0XDz} )?{DݵދVݙ6XMWo? fU|ǟ-1󹬯k=f/N!|f05*}Ur2@-k½"hlh kÜcM~WA&#w>CX%ěD3oXjC@E.zd-[%w*z4|V6+uxzF;9##w2\]|@7^UL&kCy-|b֬V*fbnV1^©(YdJ+h( >Pu7&> >> /MediaBox [0 0 595.2 841.919] /Contents [252 0 R] >> endobj 254 0 obj << /Filter [/FlateDecode] /Length 1781 >> stream xuWێ}WԓA3 IAֆ}jIm%+W/9u5bX@ԩS_gMH(dmdU-ll2/]$iɶ,J[R4Iײ/c]*6*lUJ}><|!eMyuTqF?$WѶ]©T7s"?9.OήKoîzЯٻ`c80RT pa?y}gyCe} PKC^бT9EZK7v> EtVkӶl%k*^o83suЃ1< pܻ@jٔȷ1l?k=Kez@Κ n%p-(qw QT'ANyn@|:.D;"F:dr렿wdvy(5jF qo3o,Ҟ5o~}ƞQ,yƇ4cb~dFcN0zIsL^F!}Q:W4JjDk Cj]V+7Ke7;lCoMLͱXM8y8h yW`d ǹNC:l;Z\Aڝ빈:ne[b>iq;;' (™5y"Thք:W<Ϸ]zm/B) 6L [ߑizgYzUnwV'!֤ϟt@r:ɹ 4kQh`g[m\4TQ-W;~NP:xuidjzmDCo[? endstream endobj 253 0 obj << /Type /Page /Parent 1 0 R /Resources<< /ProcSet[/PDF/Text] /Font << /F5 14 0 R /F2 10 0 R >> >> /MediaBox [0 0 595.2 841.919] /Contents [254 0 R] >> endobj 1 0 obj << /Type /Pages /Count 29 /Kids [ 4 0 R 8 0 R 18 0 R 19 0 R 22 0 R 25 0 R 27 0 R 31 0 R 33 0 R 128 0 R 35 0 R 38 0 R 41 0 R 146 0 R 168 0 R 43 0 R 177 0 R 47 0 R 51 0 R 53 0 R 210 0 R 55 0 R 215 0 R 222 0 R 234 0 R 58 0 R 61 0 R 251 0 R 253 0 R ] >> endobj 255 0 obj << /Type /Outlines /First 256 0 R /Last 257 0 R /Count 261 >> endobj 256 0 obj << /Title (Ernst & Young \( we  or EY \) has been engaged by the Australian Energy Market Operator \( you , AEMO  or the Client \) to provide electricity market modelling services to assist AEMO in calculating a number of market parameters in accordance with the Western Australian Wholesale Electricity Market Rules \(the Services \), in accordance with our Assignment commencing 1 August 2018, under the Master Services Consultancy Agreement entered into by AEMO and EY commencing 5 December 2016.) /Parent 255 0 R /Next 258 0 R /Dest [8 0 R /XYZ 82.5 731.2 0]>> endobj 258 0 obj << /Title (EY has prepared the Report for the benefit of AEMO and has acted upon the instructions of AEMO and had no third party interest in mind while performing the work. EY has not been engaged to act, and has not acted, as advisor to any other party. Accordingly, EY makes no representations as to the appropriateness, accuracy or completeness of the Report for any other party's purposes.) /Parent 255 0 R /Next 259 0 R /Prev 256 0 R /Dest [8 0 R /XYZ 82.5 550.7 0]>> endobj 259 0 obj << /Title (No reliance may be placed upon the Report or any of its contents by any recipient of the Report for any purpose and any party receiving a copy of the Report must make and rely on their own enquiries in relation to the issues to which the Report relates, the contents of the Report and all matters arising from or relating to or in any way connected with the Report or its contents.) /Parent 255 0 R /Next 260 0 R /Prev 258 0 R /Dest [8 0 R /XYZ 84 498.2 0]>> endobj 260 0 obj << /Title (EY disclaims all responsibility to any other party for any loss or liability that the other party may suffer or incur arising from or relating to or in any way connected with the contents of the Report, the provision of the Report to the other party or the reliance upon the Report by the other party.) /Parent 255 0 R /Next 261 0 R /Prev 259 0 R /Dest [8 0 R /XYZ 82.5 445.7 0]>> endobj 261 0 obj << /Title (No claim or demand or any actions or proceedings may be brought against EY arising from or connected with the contents of the Report or the provision of the Report to any party. EY will be released and forever discharged from any such claims, demands, actions or proceedings.) /Parent 255 0 R /Next 262 0 R /Prev 260 0 R /Dest [8 0 R /XYZ 84 405.2 0]>> endobj 262 0 obj << /Title (Modelling work performed as part of our scope inherently requires assumptions about future behaviours and market interactions, which may result in forecasts that deviate from future conditions. There will usually be differences between estimated and actual results, because events and circumstances frequently do not occur as expected, and those differences may be material.) /Parent 255 0 R /Next 263 0 R /Prev 261 0 R /Dest [8 0 R /XYZ 86 277.2 0]>> endobj 263 0 obj << /Title (EY have consented to the Report being published electronically on AEMO website for the purpose of undertaking a public consultation. EY have not consented to distribution or disclosure beyond this. The material contained in the Report, including the EY logo, is copyright and copyright in the Report itself vests in AEMO. The Report, including the EY logo, cannot be altered without prior written permission from EY.) /Parent 255 0 R /Next 264 0 R /Prev 262 0 R /Dest [8 0 R /XYZ 82.5 224.7 0]>> endobj 264 0 obj << /Title (We take no responsibility that the projected outcomes will be achieved, ifany. Further, the outcomes are contingent on the collection of assumptions as provided and no consideration of other market events, announcements or other changing circumstances are reflected in this Report. Neither Ernst&Young nor any member or employee thereof undertakes responsibility in any way whatsoever to any person in respect of errors in this Report arising from incorrect information provided to us or other information sources used.) /Parent 255 0 R /Next 265 0 R /Prev 263 0 R /Dest [8 0 R /XYZ 86 172.2 0]>> endobj 265 0 obj << /Title (EY s liability is limited by a scheme approved under Professional Standards Legislation.) /Parent 255 0 R /Next 266 0 R /Prev 264 0 R /Dest [8 0 R /XYZ 82.5 108.2 0]>> endobj 266 0 obj << /Title (Table of contents) /Parent 255 0 R /Next 267 0 R /Prev 265 0 R /Dest [18 0 R /XYZ 80.5 769.7 0]>> endobj 267 0 obj << /Title (1. Introduction) /Parent 255 0 R /Next 268 0 R /Prev 266 0 R /Dest [19 0 R /XYZ 114.5 769.7 0]>> endobj 268 0 obj << /Title (EY has been engaged by AEMO to provide electricity market modelling services to assist AEMO in calculating ancillary services parameters for the Wholesale Electricity Market \(WEM\) in Western Australia, in accordance with the Western Australian Wholesale Electricity Market Rules \(Rules\).) /Parent 255 0 R /Next 269 0 R /Prev 267 0 R /Dest [19 0 R /XYZ 78 732.7 0]>> endobj 269 0 obj << /Title (The ancillary services parameters are:) /Parent 255 0 R /Next 270 0 R /Prev 268 0 R /Dest [19 0 R /XYZ 78 684.7 0]>> endobj 270 0 obj << /Title (% The proposed Margin_Peak and Margin_Off-Peak values \(Margin Values\) for 2019-20 and for the purpose of clause 3.13.3A\(a\)\(i\) and 3.13.3A\(a\)\(ii\) of the Rules.) /Parent 255 0 R /Next 271 0 R /Prev 269 0 R /Dest [19 0 R /XYZ 99 666.7 0]>> endobj 271 0 obj << /Title (% The proposed SR_Capacity_Peak and SR_Capacity_Off-peak values \(SR Capacity Values\) for 2019-20 and for the purpose of clause 3.22.1\(e\) and 3.22.1\(f\) of the Rules.) /Parent 255 0 R /Next 272 0 R /Prev 270 0 R /Dest [19 0 R /XYZ 99 636.7 0]>> endobj 272 0 obj << /Title (% The proposed L  parameter of Cost_LR, representing the Load Rejection Service Cost for the period from 2019-20 to 2021-22 for the purposes of clause 3.13.3B\(a\) of the Rules.) /Parent 255 0 R /Next 273 0 R /Prev 271 0 R /Dest [19 0 R /XYZ 99 606.7 0]>> endobj 273 0 obj << /Title (This report provides an overview of the assumptions and methods to be used to calculate the values listed above. It should be read in conjunction with EY s Wholesale Electricity Market modelling and Backcasting Report dated 29 August 2018, which provides key inputs and outputs to be used for the market modelling project \(Project\) as well as information on the construct of calibrated bidding profiles to emulate 2017-18 financial year observed dispatch patterns for each generator and balancing prices in the WEM.) /Parent 255 0 R /Next 274 0 R /Prev 272 0 R /Dest [19 0 R /XYZ 78 570.7 0]>> endobj 274 0 obj << /Title (In preparing this report, we have used information that has been made publicly available through industry consultations and various industry publications to the extent practicable. We note that the initial set of assumptions have been selected by AEMO based on consultation between EY and AEMO. We note that there is a significant range of alternative assumptions that, in isolation or in aggregate, could transpire to produce outcomes that will differ to those that will be modelled.) /Parent 255 0 R /Next 275 0 R /Prev 273 0 R /Dest [19 0 R /XYZ 74.5 486.7 0]>> endobj 275 0 obj << /Title (All prices in this report refer to real June 2018 dollars unless otherwise labelled. All annual values refer to the fiscal year \(1 July  30 June\) unless otherwise labelled.) /Parent 255 0 R /Next 276 0 R /Prev 274 0 R /First 277 0 R /Last 277 0 R /Count -1 /Dest [19 0 R /XYZ 79 414.7 0]>> endobj 277 0 obj << /Title (1.1 Background) /Parent 275 0 R /Dest [19 0 R /XYZ 114.5 378.7 0]>> endobj 276 0 obj << /Title (AEMO is required to determine, procure, schedule and dispatch generation facilities to meet the ancillary service requirements in accordance with the Rules. The modelling undertaken here is focused on the following two ancillary services in the WEM:) /Parent 255 0 R /Next 278 0 R /Prev 275 0 R /Dest [19 0 R /XYZ 79 355.7 0]>> endobj 278 0 obj << /Title (% Spinning Reserve Ancillary Service \(SRAS\): which is the service of holding online capacity associated with a synchronised generator, a dispatchable load or an interruptible load in reserve to respond to a frequency event associated with a contingency event involving either the loss of a single generator unit or a single transmission network element.) /Parent 255 0 R /Next 279 0 R /Prev 276 0 R /Dest [19 0 R /XYZ 99.5 313.7 0]>> endobj 279 0 obj << /Title (% Load Rejection Reserve Service \(LRRS\): which is the service of holding online capacity associated with a synchronised generator or dispatchable load in reserve to respond to a sudden decrease of system load.) /Parent 255 0 R /Next 280 0 R /Prev 278 0 R /Dest [19 0 R /XYZ 99 259.7 0]>> endobj 280 0 obj << /Title (In setting the ancillary service requirements, AEMO must consider the ancillary service standards and the SWIS operating standards as defined within the Rules:) /Parent 255 0 R /Next 281 0 R /Prev 279 0 R /Dest [19 0 R /XYZ 74.5 211.7 0]>> endobj 281 0 obj << /Title (% SRAS requirements: AEMO is required to ensure sufficient spinning reserve to cover the loss of 70% of the generator with the highest total output in a particular period. This may be relaxed if AEMO expects that the shortfall will be intermittent in nature and last no longer than thirty minutes. The SRAS requirement is dynamic and varies from period to period. It is dependent upon generation dispatch outcomes in each period.) /Parent 255 0 R /Next 282 0 R /Prev 280 0 R /Dest [19 0 R /XYZ 99.5 181.7 0]>> endobj 282 0 obj << /Title (% LRRS requirements: The amount of load rejection reserve must ensure that system over frequency is below 51 Hz for credible load rejection events. The largest credible load rejection event is typically set by the loss of a network transmission element \(for example, the loss of the 220 kV transmission circuit supplying the Eastern Goldfields region\). This value has been determined to be 120 MW by AEMO. This may be relaxed by up to 25% \(setting a requirement of 90 MW\) by AEMO where it considers the probability of a network transmission fault is rare.) /Parent 255 0 R /Next 283 0 R /Prev 281 0 R /First 284 0 R /Last 284 0 R /Count -1 /Dest [22 0 R /XYZ 99 739.7 0]>> endobj 284 0 obj << /Title (1.2 Provision of ancillary services) /Parent 282 0 R /Dest [22 0 R /XYZ 114.5 655.7 0]>> endobj 283 0 obj << /Title (There is currently no market for the provision of SRAS or LRRS with Synergy acting as the default service provider. AEMO may contract with individual market participants to provide these services if these services can be provided at a lower cost compared to Synergy. AEMO procured a total of 68MW through spinning reserve contracts for the 2018-19 year through a long-term interruptible load contract \(42 MW\) and two short-term contracts with scheduled generators \(26 MW in total\). No contracts have been procured for LRRS.) /Parent 255 0 R /Next 285 0 R /Prev 282 0 R /Dest [22 0 R /XYZ 78 632.7 0]>> endobj 285 0 obj << /Title (Synergy acts as the default provider of LRRS through capable generators in the Synergy Balancing Portfolio. Generators are not explicitly dispatched or enabled to be provide this service,4 but do so naturally based on their generator output in a period taking into account their minimum stable generation value.) /Parent 255 0 R /Next 286 0 R /Prev 283 0 R /First 287 0 R /Last 287 0 R /Count -1 /Dest [22 0 R /XYZ 78 548.7 0]>> endobj 287 0 obj << /Title (1.3 Ancillary services parameters) /Parent 285 0 R /Dest [22 0 R /XYZ 114.5 488.7 0]>> endobj 286 0 obj << /Title (The cost of providing these services are borne by market participants through ancillary service settlement calculations, which use administered market parameters determined by AEMO and approved by the Economic Regulation Authority \(ERA\). The parameters that are the focus of this modelling are outlined in Table 1. These parameters are calculated and proposed to the ERA for use in regulatory determinations.) /Parent 255 0 R /Next 288 0 R /Prev 285 0 R /Dest [22 0 R /XYZ 78 466.2 0]>> endobj 288 0 obj << /Title (Margin_Peak; Margin_Off-Peak) /Parent 255 0 R /Next 289 0 R /Prev 286 0 R /Dest [22 0 R /XYZ 84 335.2 0]>> endobj 289 0 obj << /Title (Margin Values are used to compensate Synergy as the default provider of spinning reserve and represents the opportunity cost associating with making capacity available for the service.) /Parent 255 0 R /Next 290 0 R /Prev 288 0 R /Dest [22 0 R /XYZ 211.5 364.7 0]>> endobj 290 0 obj << /Title (Margin Values are applied to the balancing price and the quantity of spinning reserve provided to determine an availability payment  to Synergy.) /Parent 255 0 R /Next 291 0 R /Prev 289 0 R /Dest [22 0 R /XYZ 211.5 329.7 0]>> endobj 291 0 obj << /Title (Margin Values are used to compensate Synergy as the default provider of spinning reserve and represents the opportunity cost associating with making capacity available for the service. Margin Values are applied to the balancing price and the quantity of spinning reserve provided to determine an availability payment  to Synergy.Margin Values are calculated for peak and offpeak trading intervals.) /Parent 255 0 R /Next 292 0 R /Prev 290 0 R /Dest [22 0 R /XYZ 211.5 364.7 0]>> endobj 292 0 obj << /Title (SR_Capacity_Peak; SR_Capacity_Off-Peak) /Parent 255 0 R /Next 293 0 R /Prev 291 0 R /Dest [22 0 R /XYZ 82 265.7 0]>> endobj 293 0 obj << /Title (SR_Capacity Values are the modelled requirement for Spinning Reserve Service for Peak and Off-Peak Trading Intervals assumed in forming the Margin Values.) /Parent 255 0 R /Next 294 0 R /Prev 292 0 R /Dest [22 0 R /XYZ 209.5 286.2 0]>> endobj 294 0 obj << /Title (SR_Capacity Values are the modelled requirement for Spinning Reserve Service for Peak and Off-Peak Trading Intervals assumed in forming the Margin Values.SR_Capacity values are calculated for peak and off-peak trading intervals and used by AEMO for determining the quantity of spinning reserve service to compensate for providers in accordance with clause 9.9.2\(f\) of the Rules.) /Parent 255 0 R /Next 295 0 R /Prev 293 0 R /Dest [22 0 R /XYZ 209.5 286.2 0]>> endobj 295 0 obj << /Title (Cost_LR Value) /Parent 255 0 R /Next 296 0 R /Prev 294 0 R /Dest [22 0 R /XYZ 82.5 192.7 0]>> endobj 296 0 obj << /Title (The Cost_LR parameters represents the payment to a market generator for the costs of providing LRRS and the system restart services.) /Parent 255 0 R /Next 297 0 R /Prev 295 0 R /Dest [22 0 R /XYZ 209.5 225.7 0]>> endobj 297 0 obj << /Title (Generators that provide LRRS are compensated through the L  parameter.) /Parent 255 0 R /Next 298 0 R /Prev 296 0 R /Dest [22 0 R /XYZ 210.5 200.7 0]>> endobj 298 0 obj << /Title (The Cost_LR parameters represents the payment to a market generator for the costs of providing LRRS and the system restart services.) /Parent 255 0 R /Next 299 0 R /Prev 297 0 R /First 300 0 R /Last 300 0 R /Count -1 /Dest [22 0 R /XYZ 209.5 225.7 0]>> endobj 300 0 obj << /Title (1.4 Report structure) /Parent 298 0 R /Dest [25 0 R /XYZ 114.5 769.7 0]>> endobj 299 0 obj << /Title (The following summarises the structure of the remainder of this report:) /Parent 255 0 R /Next 301 0 R /Prev 298 0 R /Dest [25 0 R /XYZ 78 746.7 0]>> endobj 301 0 obj << /Title (% Section 2 presents a method for the calculation of Margin Values for the 2019-20 financial year) /Parent 255 0 R /Next 302 0 R /Prev 299 0 R /Dest [25 0 R /XYZ 99 728.7 0]>> endobj 302 0 obj << /Title (% Section 3 presents a method and discussion of the calculation of the load rejection cost parameter) /Parent 255 0 R /Next 303 0 R /Prev 301 0 R /Dest [25 0 R /XYZ 99 710.7 0]>> endobj 303 0 obj << /Title (% Section 4 provides a summary of market related assumptions to be applied in the modelling) /Parent 255 0 R /Next 304 0 R /Prev 302 0 R /Dest [25 0 R /XYZ 99 680.7 0]>> endobj 304 0 obj << /Title (% Section 5 provides a summary of facility related assumptions to be applied in the modelling.) /Parent 255 0 R /Next 305 0 R /Prev 303 0 R /Dest [25 0 R /XYZ 99 662.7 0]>> endobj 305 0 obj << /Title (2. Margin values calculation method) /Parent 255 0 R /Next 306 0 R /Prev 304 0 R /First 307 0 R /Last 307 0 R /Count -1 /Dest [27 0 R /XYZ 90 769.7 0]>> endobj 307 0 obj << /Title (2.1 Synergy s spinning reserve payment) /Parent 305 0 R /Dest [27 0 R /XYZ 114.5 732.7 0]>> endobj 306 0 obj << /Title (1. the margin Synergy could reasonably have been expected to earn on energy sales forgone due to the supply of Spinning Reserve Service during & Trading Intervals; and) /Parent 255 0 R /Next 308 0 R /Prev 305 0 R /Dest [27 0 R /XYZ 118 649.7 0]>> endobj 308 0 obj << /Title (2. the loss in efficiency of Synergy s Scheduled Generators that System Management has scheduled \(or caused to be scheduled\) to provide Spinning Reserve Service during & Trading Intervals that could reasonably be expected due to the scheduling of those reserves; .) /Parent 255 0 R /Next 309 0 R /Prev 306 0 R /Dest [27 0 R /XYZ 118 613.7 0]>> endobj 309 0 obj << /Title (These clauses of the Rules imply that Synergy s spinning reserve payment should compensate Synergy for the opportunity cost it incurs for being the default supplier of spinning reserve services. This cost is referred to as Synergy s availability cost. The forecasting of Synergy s availability cost is a key component in the overall calculation of the Margin_Peak and Margin_Off-Peak values.) /Parent 255 0 R /Next 310 0 R /Prev 308 0 R /First 311 0 R /Last 311 0 R /Count -1 /Dest [27 0 R /XYZ 78 565.7 0]>> endobj 311 0 obj << /Title (2.2 Synergy s spinning reserve opportunity cost) /Parent 309 0 R /Dest [27 0 R /XYZ 114.5 493.7 0]>> endobj 310 0 obj << /Title (Synergy s opportunity cost of providing spinning reserve in each trading interval 5a of a financial year, 5a=1,2,3, &,5G, is given by:) /Parent 255 0 R /Next 312 0 R /Prev 309 0 R /Dest [27 0 R /XYZ 78 470.7 0]>> endobj 312 0 obj << /Title (545a=55a12 5]5a595a"5H5a+5;5a"5@5a"5<5a,) /Parent 255 0 R /Next 313 0 R /Prev 310 0 R /Dest [27 0 R /XYZ 201.5 446.7 0]>> endobj 313 0 obj << /Title (545a"e0, 5O"e5]5a"e5N, 595a"e0,) /Parent 255 0 R /Next 314 0 R /Prev 312 0 R /Dest [27 0 R /XYZ 223.5 412.2 0]>> endobj 314 0 obj << /Title (545a=55a12 5]5a595a"5H5a+5;5a"5@5a"5<5a,545a"e0, 5O"e5]5a"e5N, 595a"e0, 5H5a"e0, 5;5) /Parent 255 0 R /Next 315 0 R /Prev 313 0 R /Dest [27 0 R /XYZ 201.5 446.7 0]>> endobj 315 0 obj << /Title (\(1\)) /Parent 255 0 R /Next 316 0 R /Prev 314 0 R /Dest [27 0 R /XYZ 498.5 411.7 0]>> endobj 316 0 obj << /Title (where:) /Parent 255 0 R /Next 317 0 R /Prev 315 0 R /Dest [27 0 R /XYZ 79.5 364.7 0]>> endobj 317 0 obj << /Title (% 545a is Synergy s spinning reserve opportunity cost for trading interval 5a) /Parent 255 0 R /Next 318 0 R /Prev 316 0 R /Dest [27 0 R /XYZ 93.5 346.7 0]>> endobj 318 0 obj << /Title (% 55a is a coefficient) /Parent 255 0 R /Next 319 0 R /Prev 317 0 R /Dest [27 0 R /XYZ 93.5 322.7 0]>> endobj 319 0 obj << /Title (% 5]5a is the balancing price for trading interval 5a, which is bound by the balancing price floor 5N and the balancing price ceiling 5O) /Parent 255 0 R /Next 320 0 R /Prev 318 0 R /Dest [27 0 R /XYZ 93.5 298.7 0]>> endobj 320 0 obj << /Title (% 595a is the spinning reserve requirement in trading interval 5a) /Parent 255 0 R /Next 321 0 R /Prev 319 0 R /Dest [27 0 R /XYZ 93.5 262.7 0]>> endobj 321 0 obj << /Title (% 5H5a is the MW capacity necessary to cover the requirement for providing upwards load following ancillary services \(LFAS\) for trading interval 5a) /Parent 255 0 R /Next 322 0 R /Prev 320 0 R /Dest [27 0 R /XYZ 93.5 238.7 0]>> endobj 322 0 obj << /Title (% 5;5a is the MW quantity of non-spinning reserve compliant upwards LFAS capacity in trading interval 5a; or LFAS capacity which is subject to a contract for spinning reserve in the trading interval 5a.) /Parent 255 0 R /Next 323 0 R /Prev 321 0 R /Dest [27 0 R /XYZ 93.5 202.7 0]>> endobj 323 0 obj << /Title (% 5@5a is the MW capacity of long term interruptible load contracts \(non-Synergy\) for spinning reserve, with terms that require AEMO to prioritise them for spinning reserve over the use of generation units) /Parent 255 0 R /Next 324 0 R /Prev 322 0 R /Dest [31 0 R /XYZ 93.5 769.7 0]>> endobj 324 0 obj << /Title (% 5<5a is the MW capacity of short term non-Synergy \(i.e. independent power producer\) spinning reserve contracts in trading interval 5a) /Parent 255 0 R /Next 325 0 R /Prev 323 0 R /Dest [31 0 R /XYZ 93.5 721.7 0]>> endobj 325 0 obj << /Title (% The scalar of one half on the right hand side of Equation \(1\) converts MW values into MWh values for each half hour trading interval.) /Parent 255 0 R /Next 326 0 R /Prev 324 0 R /Dest [31 0 R /XYZ 99 685.7 0]>> endobj 326 0 obj << /Title (To summarise Equation \(1\) in words, Synergy s spinning reserve opportunity cost is defined by multiplying a coefficient against:) /Parent 255 0 R /Next 327 0 R /Prev 325 0 R /Dest [31 0 R /XYZ 77 649.7 0]>> endobj 327 0 obj << /Title (% The balancing price, and) /Parent 255 0 R /Next 328 0 R /Prev 326 0 R /Dest [31 0 R /XYZ 99 619.7 0]>> endobj 328 0 obj << /Title (% The volume of spinning reserve provided by Synergy units that are not also providing upwards LFAS services.) /Parent 255 0 R /Next 329 0 R /Prev 327 0 R /First 330 0 R /Last 330 0 R /Count -1 /Dest [31 0 R /XYZ 99 601.7 0]>> endobj 330 0 obj << /Title (2.3 Calculating the opportunity cost of providing spinning reserve) /Parent 328 0 R /Dest [31 0 R /XYZ 114.5 565.7 0]>> endobj 329 0 obj << /Title (The ERA s 2018 Determination paper \(2018 Determination\) suggested possible improvements to the previous method of availability cost estimation. The ERA indicated that these recommendations  & could be considered by AEMO in future reviews of margin values.  \(p. 19\). As part of the process that led to the development of this Report, EY discussed the 2018 Determination with AEMO in consultation with the ERA s Secretariat. The method developed for this Report has been informed by:) /Parent 255 0 R /Next 331 0 R /Prev 328 0 R /Dest [31 0 R /XYZ 78 542.7 0]>> endobj 331 0 obj << /Title (% The ERA s recommendations outlined in Appendix 2 of its 2018 Determination, and) /Parent 255 0 R /Next 332 0 R /Prev 329 0 R /Dest [31 0 R /XYZ 99 464.7 0]>> endobj 332 0 obj << /Title (% Further discussions with AEMO and the ERA s Secretariat that have led to a refinement of the recommendations in the ERA s 2018 Determination.) /Parent 255 0 R /Next 333 0 R /Prev 331 0 R /Dest [31 0 R /XYZ 98.5 446.7 0]>> endobj 333 0 obj << /Title (One of the ERA s recommendations relates to estimation of the spinning reserve payment for each Synergy unit on the basis of its efficient opportunity costs. The ERA defined the opportunity cost of spinning reserve for a generation unit \(that is able to provide the service\) as being equivalent to the net revenue forgone in the balancing market due to its reservation of capacity. Consistent with the ERA s approach, EY will assume that a generation unit s net revenue forgone in the balancing market is equal to:) /Parent 255 0 R /Next 334 0 R /Prev 332 0 R /Dest [31 0 R /XYZ 79 410.7 0]>> endobj 334 0 obj << /Title (% The loss of revenue due to reduced energy sales attributable to the generation unit s reservation of capacity, minus) /Parent 255 0 R /Next 335 0 R /Prev 333 0 R /Dest [31 0 R /XYZ 99 332.7 0]>> endobj 335 0 obj << /Title (% The operating costs that would have otherwise been incurred if the unit had not reserved its capacity. The calculation of reduced operating costs will account for changes to the efficiency of a unit associated with its reserving of capacity in line with the approach proposed by the ERA in its 2018 Determination.) /Parent 255 0 R /Next 336 0 R /Prev 334 0 R /Dest [31 0 R /XYZ 99 302.7 0]>> endobj 336 0 obj << /Title (The method we propose to use is based upon Equation A4 provided in the ERA s 2018 Determination. The total opportunity cost, 565V5`5V, for generation unit 5V providing quantity 5`5V, 5`5V"e0, of spinning reserve in each trading interval, will be found by solving the definite) /Parent 255 0 R /Next 337 0 R /Prev 335 0 R /Dest [31 0 R /XYZ 78 242.7 0]>> endobj 337 0 obj << /Title (565V5`5V= 5D5V"5`5V5D5V5]"5S5V5e5V) /Parent 255 0 R /Next 338 0 R /Prev 336 0 R /Dest [31 0 R /XYZ 215.5 194.7 0]>> endobj 338 0 obj << /Title (\(2\)) /Parent 255 0 R /Next 339 0 R /Prev 337 0 R /Dest [31 0 R /XYZ 498.5 180.2 0]>> endobj 339 0 obj << /Title (The value of 5D5V can be no greater than a generation unit s maximum rated capacity, and may be further constrained by any out-of-merit output offered into the balancing market. This reflects the idea that the opportunity cost of any reserve capacity that would not otherwise be dispatched in the energy market is equal to zero.) /Parent 255 0 R /Next 340 0 R /Prev 338 0 R /Dest [33 0 R /XYZ 78 739.7 0]>> endobj 340 0 obj << /Title (Estimation of 5S5V5e5V will entail fitting a polynomial function to heat rate data for each generation unit, then multiplying this function by an assumed per MW half hourly cost that reflects the opportunity cost of fuel plus non-fuel variable operating costs. The opportunity cost of fuel cost assumption will include relevant pipeline transport costs. Consistent with the ERA s approach to short run marginal cost estimation, we are of the view that the best basis for the opportunity cost of fuel is the spot price, or alternatively the market price for new fuel contracts. The opportunity cost of pipeline capacity may be considered zero if contracted pipeline capacity rights cannot be on sold to third parties in the short run. Our intention is to assume the same per unit cost of fuel/fuel transport that an economically rational market generator would use in making the short run decision whether to generate or not.) /Parent 255 0 R /Next 341 0 R /Prev 339 0 R /Dest [33 0 R /XYZ 78 679.7 0]>> endobj 341 0 obj << /Title (The method for calculating the opportunity cost of a generation unit is described graphically in Figure 1 below, which is an adaptation of Figure A5 provided in Appendix 2 of the ERA s 2018 Determination.) /Parent 255 0 R /Next 342 0 R /Prev 340 0 R /First 343 0 R /Last 343 0 R /Count -1 /Dest [33 0 R /XYZ 78 547.7 0]>> endobj 343 0 obj << /Title (2.4 Modelling of availability cost) /Parent 341 0 R /Dest [33 0 R /XYZ 114.5 221.7 0]>> endobj 342 0 obj << /Title (In light of Equation \(1\) and the requirements of the Rules more generally, our proposed method for calculating the availability cost includes the following steps:) /Parent 255 0 R /Next 344 0 R /Prev 341 0 R /Dest [33 0 R /XYZ 74.5 198.7 0]>> endobj 344 0 obj << /Title (1. Preliminary dispatch and generation outage model run. This will provide a preliminary view of the dispatch outcome for the market on the basis of historical balancing merit order profiles. Monte Carlo simulation will be applied to produce multiple time series incorporating unplanned generation outage events. This will be used to simulate dynamic changes to the state of the availability of plant, which will then be used as an input to the 2-4-C market dispatch model \(step 2 below\). Probabilistic modelling of the contingency and maximum ramp rate conditions of the system will provide an input to determine the required level of spinning reserve in each trading interval. EY s Wholesale Electricity Market modelling and Backcasting Report dated 29 August 2018, provides greater detail on the market modelling implementation. The dispatch outcomes will provide visibility over the balancing merit order and therefore the expected level of output that generation units would sell into the balancing market if they were not providing spinning reserve.) /Parent 255 0 R /Next 345 0 R /Prev 342 0 R /Dest [33 0 R /XYZ 114.5 168.7 0]>> endobj 345 0 obj << /Title (2. Half hourly forecasting of the least cost mix of upwards LFAS providers. This forecast will be made on the basis of an assumed merit order for the provision of upwards LFAS. The simulation conducted in step 1 above will determine the set of plants available for LFAS provision. The assumed LFAS requirement will be on the basis of AEMO forecasts - this will be an input into the calculation of spinning reserve requirements \(step 3 below\). This step will also identify the amount of upwards LFAS that is not also eligible to provide spinning reserve.) /Parent 255 0 R /Next 346 0 R /Prev 344 0 R /Dest [128 0 R /XYZ 115 679.7 0]>> endobj 346 0 obj << /Title (3. Calculation of a dynamic spinning reserve requirement. The outputs of steps 1 and 2 will be used to calculate the requirement in each trading interval, consistent with clause 3.10.2 of the Rules. See section 2.5 below for more detail on the on the calculation of the dynamic spinning reserve requirement.) /Parent 255 0 R /Next 347 0 R /Prev 345 0 R /Dest [128 0 R /XYZ 114 589.7 0]>> endobj 347 0 obj << /Title (4. Half hourly, non-linear optimisation forecast of the spinning reserve mix. This step will solve for the minimum cost mix of all Synergy and non-Synergy generation units that are able to provide spinning reserve in each half hour trading interval of the modelling period. The optimisation will be on the basis of the marginal cost functions of all units available to provide spinning reserve in each half hour trading interval, and will be initially independent of the balancing price. This method will be applied under an equality constraint: the sum of all units  spinning reserve levels will be set equal to the spinning reserve requirement in each half hour \(determined in step 3 above\). Further constraints will ensure the output of each generation unit providing spinning reserve remains within its rated operational bounds. Plants on outage \(determined in step 1 above\) will be constrained off in the modelling. See Section 2.6 below for more detail on the spinning reserve cost optimisation method.) /Parent 255 0 R /Next 348 0 R /Prev 346 0 R /Dest [128 0 R /XYZ 115 535.7 0]>> endobj 348 0 obj << /Title (5. Half hourly, balancing price modelling. The outputs from steps 1 to 4 will be used as inputs to the 2-4-C dispatch model. The model will be run to provide a balancing price forecast for each trading interval over the modelling period. See EY s Wholesale Electricity Market modelling and Backcasting Report dated 29 August 2018 for detail on how this type of modelling is conducted.) /Parent 255 0 R /Next 349 0 R /Prev 347 0 R /Dest [128 0 R /XYZ 115 397.7 0]>> endobj 349 0 obj << /Title (6. Half hourly, forecast of the total opportunity cost of spinning reserve. This step will apply the same optimisation algorithm as step 4, but will now include the balancing price derived from step 5 as an input. The minimised objective cost function will give the total opportunity cost of spinning reserve for each half hour trading interval. See Section 2.6 below for more details on the spinning reserve cost optimisation method.) /Parent 255 0 R /Next 350 0 R /Prev 348 0 R /Dest [128 0 R /XYZ 115 331.7 0]>> endobj 350 0 obj << /Title (7. Calculation of Synergy s availability cost. Upon completion of step 6, a mathematical filter will be applied to the minimised objective cost function to calculate Synergy s availability payment. See Section 2.7 below.) /Parent 255 0 R /Next 351 0 R /Prev 349 0 R /First 352 0 R /Last 352 0 R /Count -1 /Dest [128 0 R /XYZ 114 265.7 0]>> endobj 352 0 obj << /Title (2.5 Dynamic spinning reserve requirement) /Parent 350 0 R /Dest [35 0 R /XYZ 114.5 769.7 0]>> endobj 351 0 obj << /Title (Clauses 3.10.2 of the Rules stipulate the principles that the standard for spinning reserve should satisfy as being:) /Parent 255 0 R /Next 353 0 R /Prev 350 0 R /Dest [35 0 R /XYZ 78.5 746.7 0]>> endobj 353 0 obj << /Title ( \(a\) the level must be sufficient to cover the greater of:) /Parent 255 0 R /Next 354 0 R /Prev 351 0 R /Dest [35 0 R /XYZ 119 716.7 0]>> endobj 354 0 obj << /Title (i. 70% of the total output, including Parasitic Load, of the generation unit synchronised to the SWIS with the highest total output at that time; and) /Parent 255 0 R /Next 355 0 R /Prev 353 0 R /Dest [35 0 R /XYZ 145.5 698.7 0]>> endobj 355 0 obj << /Title (ii. the maximum load ramp expected over a period of 15 minutes;) /Parent 255 0 R /Next 356 0 R /Prev 354 0 R /Dest [35 0 R /XYZ 145.5 668.7 0]>> endobj 356 0 obj << /Title (\(b\) the level must include capacity utilised to meet the Load Following Service standard under clause 3.10.1, so that the capacity provided to meet the Load Following requirement is counted as providing part of the Spinning Reserve requirement; ) /Parent 255 0 R /Next 357 0 R /Prev 355 0 R /Dest [35 0 R /XYZ 117 650.7 0]>> endobj 357 0 obj << /Title (5L5a = max0.75:5a, 0.5"575a, 5a=1,2,3,) /Parent 255 0 R /Next 358 0 R /Prev 356 0 R /Dest [35 0 R /XYZ 189.5 568.7 0]>> endobj 358 0 obj << /Title (\(3\)) /Parent 255 0 R /Next 359 0 R /Prev 357 0 R /Dest [35 0 R /XYZ 498.5 568.7 0]>> endobj 359 0 obj << /Title (% 5:5a 5:5a>0, is the total output, including parasitic load, of the synchronised generation unit that is generating the highest total output in trading interval 5a,) /Parent 255 0 R /Next 360 0 R /Prev 358 0 R /Dest [35 0 R /XYZ 93.5 523.2 0]>> endobj 360 0 obj << /Title (% "575a represents the change in operational demand between trading interval 5a and trading interval 5a") /Parent 255 0 R /Next 361 0 R /Prev 359 0 R /Dest [35 0 R /XYZ 93.5 487.2 0]>> endobj 361 0 obj << /Title (5F5a = 5L5a"5H5a+5;5a"5@5a, 5a=1,2) /Parent 255 0 R /Next 362 0 R /Prev 360 0 R /Dest [35 0 R /XYZ 190.5 433.2 0]>> endobj 362 0 obj << /Title (\(4\)) /Parent 255 0 R /Next 363 0 R /Prev 361 0 R /First 364 0 R /Last 364 0 R /Count -1 /Dest [35 0 R /XYZ 498.5 433.2 0]>> endobj 364 0 obj << /Title (2.6 Spinning reserve optimisation) /Parent 362 0 R /Dest [35 0 R /XYZ 114.5 403.2 0]>> endobj 363 0 obj << /Title (EY s spinning reserve optimisation tool will be used to answer two questions for each trading interval in the forecast period:) /Parent 255 0 R /Next 365 0 R /Prev 362 0 R /Dest [35 0 R /XYZ 78 380.7 0]>> endobj 365 0 obj << /Title (1. What level of output will each generation unit that is available to provide spinning reserve operate at to meet the spinning reserve requirement at least overall cost?) /Parent 255 0 R /Next 366 0 R /Prev 363 0 R /Dest [35 0 R /XYZ 116.5 350.7 0]>> endobj 366 0 obj << /Title (2. What is the lowest overall opportunity cost at which the spinning reserve requirement can be met?) /Parent 255 0 R /Next 367 0 R /Prev 365 0 R /Dest [35 0 R /XYZ 116.5 320.2 0]>> endobj 367 0 obj << /Title (Expressing the problem mathematically, the spinning reserve optimisation tool solves the following nonlinear, constrained minimisation problem conducted for 5a=1,2,3, &5) /Parent 255 0 R /Next 368 0 R /Prev 366 0 R /Dest [35 0 R /XYZ 78 284.2 0]>> endobj 368 0 obj << /Title (minimise5Z5V"d5`5V"d5D5V5V=15A565V5`5Vsubject to5V=15A) /Parent 255 0 R /Next 369 0 R /Prev 367 0 R /Dest [35 0 R /XYZ 235.5 248.2 0]>> endobj 369 0 obj << /Title (\(5\)) /Parent 255 0 R /Next 370 0 R /Prev 368 0 R /Dest [35 0 R /XYZ 498.5 219.7 0]>> endobj 370 0 obj << /Title (where 5Z5V 5Z5V"e0, denotes the minimum generation level of generation unit 5V, 5A is the number of generation units in the market that are able to provide spinning reserve, and where the operator  indicates summation notation; 5a subscripts have been suppressed for clarity. An outage of any plant 5V in the trading interval is accounted for by setting 5Z5V=5D5V=0, which constrains the spinning reserve quantity 5`5V to zero.) /Parent 255 0 R /Next 371 0 R /Prev 369 0 R /Dest [35 0 R /XYZ 79.5 167.7 0]>> endobj 371 0 obj << /Title (The optimisation concept is depicted in Figure 2 below, where the marginal opportunity cost spinning reserve for a generation unit is equal to the balancing price minus the generation unit s heat rate based marginal cost function, but horizontally reflected so that costs are given a function of increasing spinning reserve rather than increasing output of energy. In the diagram, the optimisation has resulted in the reserved output from three Synergy and one non-Synergy plant being treated as in-merit.) /Parent 255 0 R /Next 372 0 R /Prev 370 0 R /First 373 0 R /Last 373 0 R /Count -1 /Dest [38 0 R /XYZ 78 733.7 0]>> endobj 373 0 obj << /Title (2.7 Calculation of availability cost) /Parent 371 0 R /Dest [38 0 R /XYZ 114.5 353.7 0]>> endobj 372 0 obj << /Title (Expression \(5\) solves for the least cost combination of spinning reserve quantities from the 5A generation units, which includes both Synergy and non-Synergy plant. If we let 5`5V" denote the optimal amount of spinning reserve provided by generation units 5V=1, 2, 3 &,5A, i.e. to achieve the least cost solution to Equation \(5\), then Synergy s availability cost can be calculated as fol) /Parent 255 0 R /Next 374 0 R /Prev 371 0 R /Dest [38 0 R /XYZ 78 330.7 0]>> endobj 374 0 obj << /Title (54=5V=15A565V5`5V".5d5V, 5d5V=1 if unit 5V is a Synergy plant0 oth) /Parent 255 0 R /Next 375 0 R /Prev 372 0 R /Dest [38 0 R /XYZ 223 269.7 0]>> endobj 375 0 obj << /Title (\(6\)) /Parent 255 0 R /Next 376 0 R /Prev 374 0 R /Dest [38 0 R /XYZ 498.5 259.2 0]>> endobj 376 0 obj << /Title (where 5d5V is a filter that removes the opportunity cost of non-Synergy plant from the summation of 54. Again 5a subscripts have been suppressed in Equation \(6\) for clar) /Parent 255 0 R /Next 377 0 R /Prev 375 0 R /First 378 0 R /Last 378 0 R /Count -1 /Dest [38 0 R /XYZ 79.5 223.7 0]>> endobj 378 0 obj << /Title (2.8 Calculation of SR_Capacity_Peak and SR_Capacity_Off-Peak parameters) /Parent 376 0 R /Dest [38 0 R /XYZ 114.5 187.7 0]>> endobj 377 0 obj << /Title (Synergy is compensated for its provision of spinning reserve services in accordance with an administered payment process defined by the formula prescribed in clause 9.9.2\(f\) of the Rules. The spinning reserve payment formula that applies to each trading interval 5a in a financial year, 5a=1,2,3, &,5G, is given b) /Parent 255 0 R /Next 379 0 R /Prev 376 0 R /Dest [38 0 R /XYZ 78 147.7 0]>> endobj 379 0 obj << /Title (\(7\)) /Parent 255 0 R /Next 380 0 R /Prev 377 0 R /Dest [41 0 R /XYZ 498.5 758.2 0]>> endobj 380 0 obj << /Title (where 5E5a denotes Synergy s spinning reserve revenue requirement, and 5>5a is the SR_Capacity_Peak parameter if trading interval 5a is a peak trading interval, or is the SR_Capacity_Off-Peak parameter otherwise.) /Parent 255 0 R /Next 381 0 R /Prev 379 0 R /Dest [41 0 R /XYZ 79.5 734.2 0]>> endobj 381 0 obj << /Title (If 5>5a is solved separately for each trading interval, then letting 5E5a=545a it can be shown) /Parent 255 0 R /Next 382 0 R /Prev 380 0 R /Dest [41 0 R /XYZ 74.5 686.2 0]>> endobj 382 0 obj << /Title (\(8\)) /Parent 255 0 R /Next 383 0 R /Prev 381 0 R /Dest [41 0 R /XYZ 498.5 650.7 0]>> endobj 383 0 obj << /Title (For the purposes of market settlement, 5>5a is expressed as two fixed values, one being an average across peak trading intervals for a year and the other being an average across non-peak trading intervals for a year. As such, and in light of Equation \(8\), AEMO requires the SR_Capacity_Peak parameter to be given b) /Parent 255 0 R /Next 384 0 R /Prev 382 0 R /Dest [41 0 R /XYZ 77.5 626.7 0]>> endobj 384 0 obj << /Title (5>5a=5a"5C595a+5;5a5C , ") /Parent 255 0 R /Next 385 0 R /Prev 383 0 R /Dest [41 0 R /XYZ 217.5 561.2 0]>> endobj 385 0 obj << /Title (\(9\)) /Parent 255 0 R /Next 386 0 R /Prev 384 0 R /Dest [41 0 R /XYZ 498.5 555.2 0]>> endobj 386 0 obj << /Title (where 5C is the set of peak trading intervals in the year, set membership is denoted by the symbol ", the cardinality of a setis denoted5C, and the symbol " denotes the universal quantifier \(which means for all \).) /Parent 255 0 R /Next 387 0 R /Prev 385 0 R /Dest [41 0 R /XYZ 79.5 519.7 0]>> endobj 387 0 obj << /Title (Similarly, for the purposes of market settlement, AEMO requires the SR_Capacity_Off-Peak parameter to be given by:) /Parent 255 0 R /Next 388 0 R /Prev 386 0 R /Dest [41 0 R /XYZ 78 471.7 0]>> endobj 388 0 obj << /Title (5>5a=5a"5B595a+5;5a5B , ") /Parent 255 0 R /Next 389 0 R /Prev 387 0 R /Dest [41 0 R /XYZ 217 430.2 0]>> endobj 389 0 obj << /Title (\(10\)) /Parent 255 0 R /Next 390 0 R /Prev 388 0 R /Dest [41 0 R /XYZ 498.5 424.2 0]>> endobj 390 0 obj << /Title (where 5B is the set of off-peak trading intervals in the year) /Parent 255 0 R /Next 391 0 R /Prev 389 0 R /First 392 0 R /Last 392 0 R /Count -1 /Dest [41 0 R /XYZ 79.5 400.2 0]>> endobj 392 0 obj << /Title (2.9 Calculation of Margin_Peak and Margin_Off-Peak parameters) /Parent 390 0 R /Dest [41 0 R /XYZ 114.5 376.2 0]>> endobj 391 0 obj << /Title (This section will propose a method of calculating the Margin_Peak and Margin_Off-Peak parameters consistent with the recommendations proposed by the ERA in section A2.2 of its 2018 Determination.) /Parent 255 0 R /Next 393 0 R /Prev 390 0 R /Dest [41 0 R /XYZ 78 353.2 0]>> endobj 393 0 obj << /Title (The steps outlined in the preceding sub-sections of this report enable calculation of the variables contained in the equation in Figure 3 below.) /Parent 255 0 R /Next 394 0 R /Prev 391 0 R /Dest [41 0 R /XYZ 78 305.2 0]>> endobj 394 0 obj << /Title (/) /Parent 255 0 R /Next 395 0 R /Prev 393 0 R /Dest [146 0 R /XYZ 178 633.2 0]>> endobj 395 0 obj << /Title (This allows for estimation of the margin peak and margin off-peak parameters, 55a, by means of regression analysis. EY will adopt a standard approach to regression analysis and reporting, summarised by Figure 4 below.) /Parent 255 0 R /Next 396 0 R /Prev 394 0 R /Dest [146 0 R /XYZ 78 611.7 0]>> endobj 396 0 obj << /Title (/) /Parent 255 0 R /Next 397 0 R /Prev 395 0 R /Dest [146 0 R /XYZ 191.5 323.7 0]>> endobj 397 0 obj << /Title (As outlined in Figure 4 above, model specification is part of a process that depends upon the preliminary analysis of the input data and examination of the residuals from a number of model fitting attempts. One possible function form for the regression models will be:) /Parent 255 0 R /Next 398 0 R /Prev 396 0 R /Dest [146 0 R /XYZ 79 290.2 0]>> endobj 398 0 obj << /Title (545a=5 5M5a+5b5a, 5b5a~5ܩ0,5) /Parent 255 0 R /Next 399 0 R /Prev 397 0 R /Dest [146 0 R /XYZ 213 236.7 0]>> endobj 399 0 obj << /Title (\(11\)) /Parent 255 0 R /Next 400 0 R /Prev 398 0 R /Dest [146 0 R /XYZ 498.5 230.7 0]>> endobj 400 0 obj << /Title (where 5b5a is a random error term, 5 is the coefficient to be estimated by minimising the sum of the squared residuals from the regression, and whe) /Parent 255 0 R /Next 401 0 R /Prev 399 0 R /Dest [146 0 R /XYZ 79.5 206.7 0]>> endobj 401 0 obj << /Title (5M5a=125]5a.max0,5>5a"5H5a"5@5a"5<5) /Parent 255 0 R /Next 402 0 R /Prev 400 0 R /Dest [146 0 R /XYZ 278.5 170.7 0]>> endobj 402 0 obj << /Title (\(12\)) /Parent 255 0 R /Next 403 0 R /Prev 401 0 R /Dest [146 0 R /XYZ 498.5 157.7 0]>> endobj 403 0 obj << /Title (A potential limitation of the model specification in Equation \(12\) is that it would require two regressions using truncated time series data, one for estimation of the Margin_Peak coefficient and the other for estimation of the Margin_Off-Peak coefficient. This may result in difficulties in testing for and managing issues related to serial correlation of the residuals. Whether these problems manifest will not be known until the residuals of the model are able to be examined and the validity of the model assessed through hypothesis testing. Considerations in this phase of the regression procedure may include:) /Parent 255 0 R /Next 404 0 R /Prev 402 0 R /Dest [146 0 R /XYZ 79 133.2 0]>> endobj 404 0 obj << /Title (% As discussed above, any autocorrelation in the residuals should be corrected for, noting that the regression will be made using modelled time-series data) /Parent 255 0 R /Next 405 0 R /Prev 403 0 R /Dest [168 0 R /XYZ 100 739.7 0]>> endobj 405 0 obj << /Title (% The residuals may not exhibit constant variance, the application of robust statistical method may be recommended in this case) /Parent 255 0 R /Next 406 0 R /Prev 404 0 R /Dest [168 0 R /XYZ 99 709.7 0]>> endobj 406 0 obj << /Title (% Function form  for this simple regression one choice is between a model specification with an additive error term \(optimal for a normal error distribution\) or multiplicative \(optimal for a log-normal error distribution\).) /Parent 255 0 R /Next 407 0 R /Prev 405 0 R /Dest [168 0 R /XYZ 98.5 679.7 0]>> endobj 407 0 obj << /Title (For example, model specification on the basis of a multiplicative error term may be as follows:) /Parent 255 0 R /Next 408 0 R /Prev 406 0 R /Dest [168 0 R /XYZ 77.5 631.7 0]>> endobj 408 0 obj << /Title (545a=51 5M5a5I5a525b5a, 5b5a~!5ܩ1) /Parent 255 0 R /Next 409 0 R /Prev 407 0 R /Dest [168 0 R /XYZ 206 597.2 0]>> endobj 409 0 obj << /Title (\(13\)) /Parent 255 0 R /Next 410 0 R /Prev 408 0 R /Dest [168 0 R /XYZ 498.5 596.2 0]>> endobj 410 0 obj << /Title (where 5I5a is a dummy variable that takes on the value of one when 5a is a peak trading interval and the number 5R otherwise. If this specification proves valid, the result will) /Parent 255 0 R /Next 411 0 R /Prev 409 0 R /Dest [168 0 R /XYZ 79.5 572.2 0]>> endobj 411 0 obj << /Title (545a"H51 5M5a, 51=51 if 5a is a peak trading interval51.5R52 otherwi) /Parent 255 0 R /Next 412 0 R /Prev 410 0 R /Dest [168 0 R /XYZ 202.5 536.2 0]>> endobj 412 0 obj << /Title (\(14\)) /Parent 255 0 R /Next 413 0 R /Prev 411 0 R /Dest [168 0 R /XYZ 498.5 522.2 0]>> endobj 413 0 obj << /Title (This specification would roughly double the degrees of freedom of the regression compared to the case where the problem was broken up into two separate modelling exercises. It would also provide one continuous time series of residuals which would allow for autocorrelation to be tested and corrected for if present.) /Parent 255 0 R /Next 414 0 R /Prev 412 0 R /Dest [168 0 R /XYZ 78 496.2 0]>> endobj 414 0 obj << /Title (3. Load rejection cost calculation method) /Parent 255 0 R /Next 415 0 R /Prev 413 0 R /Dest [43 0 R /XYZ 114.5 769.7 0]>> endobj 415 0 obj << /Title (Providers of LRRS are paid through monthly ancillary service settlement calculations determined by AEMO using the Cost_LRD parameter, which is an administered market parameter determined by the ERA for a three year forward looking period.) /Parent 255 0 R /Next 416 0 R /Prev 414 0 R /Dest [43 0 R /XYZ 78 732.7 0]>> endobj 416 0 obj << /Title (The Cost_LRD parameter is used for:) /Parent 255 0 R /Next 417 0 R /Prev 415 0 R /Dest [43 0 R /XYZ 78 690.7 0]>> endobj 417 0 obj << /Title (% calculating the cost borne by market participants according to the proportion of their consumption according to clause 9.3.7.) /Parent 255 0 R /Next 418 0 R /Prev 416 0 R /Dest [43 0 R /XYZ 98 594.7 0]>> endobj 418 0 obj << /Title (Cost_LRD is specified in clause 3.22.1\(g\) of the Rules, which states:) /Parent 255 0 R /Next 419 0 R /Prev 417 0 R /Dest [43 0 R /XYZ 78.5 558.7 0]>> endobj 419 0 obj << /Title (\(i\) Cost_LR divided by 12 as a monthly amount; and) /Parent 255 0 R /Next 420 0 R /Prev 418 0 R /Dest [43 0 R /XYZ 135.5 510.7 0]>> endobj 420 0 obj << /Title (\(ii\) The monthly amount for Dispatch Support Service.) /Parent 255 0 R /Next 421 0 R /Prev 419 0 R /Dest [43 0 R /XYZ 135 486.7 0]>> endobj 421 0 obj << /Title (Clause 3.13.3B of the Rules specifies that Cost_LR must cover the costs for providing LRRS.) /Parent 255 0 R /Next 422 0 R /Prev 420 0 R /First 423 0 R /Last 423 0 R /Count -1 /Dest [43 0 R /XYZ 78.5 462.7 0]>> endobj 423 0 obj << /Title (3.1 Load rejection reserve cost) /Parent 421 0 R /Dest [43 0 R /XYZ 114.5 438.7 0]>> endobj 422 0 obj << /Title (The Rules do not explicitly discuss the methodology or calculation of Cost_LR, except that it must cover the costs for providing the services.) /Parent 255 0 R /Next 424 0 R /Prev 421 0 R /Dest [43 0 R /XYZ 78 409.7 0]>> endobj 424 0 obj << /Title (There is currently no market or contract market that exists for this service. LRRS costs are currently borne by Synergy as the default service provider for LRRS as part of its obligation under clause 3.11.7A of the Rules, which requires Synergy to make its capacity to provide LRRS available to AEMO to enable it to meet obligations prescribed in the Rules.) /Parent 255 0 R /Next 425 0 R /Prev 422 0 R /First 426 0 R /Last 426 0 R /Count -1 /Dest [43 0 R /XYZ 78 373.7 0]>> endobj 426 0 obj << /Title (3.2 Calculating the cost of providing load rejection reserve service) /Parent 424 0 R /Dest [43 0 R /XYZ 114.5 265.7 0]>> endobj 425 0 obj << /Title (LRRS is currently provided by generators in the Synergy Balancing Portfolio only. Although provision for dispatchable loads to provide this service is discussed in the Rules,) /Parent 255 0 R /Next 427 0 R /Prev 424 0 R /Dest [43 0 R /XYZ 78 236.7 0]>> endobj 427 0 obj << /Title (Synergy generators that provide LRRS are typically not required to be enabled to provide this service, but do so by being online and having an output in the correct range as a by-product of being dispatched in the balancing market and for other ancillary services \(such as load following and spinning reserve\). That is, by providing energy into the balancing market or by being enabled for other ancillary services, generators will innately provide reserves for load rejection, if the generator is technically capable to do so within the response times specified in the Rules.) /Parent 255 0 R /Next 428 0 R /Prev 425 0 R /Dest [177 0 R /XYZ 78 721.7 0]>> endobj 428 0 obj << /Title (As generators are not typically enabled for LRRS, there may be a scenario where the prevailing dispatch of generation in the balancing merit order does not meet the LRRS requirement and generators may need to be committed on out of merit.) /Parent 255 0 R /Next 429 0 R /Prev 427 0 R /Dest [177 0 R /XYZ 79 637.7 0]>> endobj 429 0 obj << /Title (Shortfalls in LRRS may be present during periods of low demand \(either at night or where rooftop solar PV output is high\) causing baseload generators to operate close to or at their minimum stable operating point. During these periods, AEMO may dispatch a generator capable of providing LRRS out of merit to meet the requirement.) /Parent 255 0 R /Next 430 0 R /Prev 428 0 R /Dest [177 0 R /XYZ 78 589.7 0]>> endobj 430 0 obj << /Title (In calculating the cost associated with a generator being constrained on to provide LRRS, we therefore consider the cost associated with committing a generator out-of-merit in a trading interval, which is defined by:) /Parent 255 0 R /Next 431 0 R /Prev 429 0 R /Dest [177 0 R /XYZ 74.5 529.7 0]>> endobj 431 0 obj << /Title (5?5V5a=5F5a5N5_5a5b5]_ 5P5\\5`5a5V5a+5S5b5R5Y_ 5P5\\5`5a5V5a+) /Parent 255 0 R /Next 432 0 R /Prev 430 0 R /Dest [177 0 R /XYZ 193 481.7 0]>> endobj 432 0 obj << /Title (where:) /Parent 255 0 R /Next 433 0 R /Prev 431 0 R /Dest [177 0 R /XYZ 79.5 457.7 0]>> endobj 433 0 obj << /Title (% 5?5V5a is the total cost of unit 5V supplying out-of-merit generation associated with LRRS in trading interval 5a) /Parent 255 0 R /Next 434 0 R /Prev 432 0 R /Dest [177 0 R /XYZ 93.5 439.7 0]>> endobj 434 0 obj << /Title (% 5F5a5N5_5a5b5]_ 5P5\\5`5a5V5a includes the opportunity costs of fuel, water, internal power, additional labour and wear and tear directly attributable to the startup of unit 5V in trading interval 5a) /Parent 255 0 R /Next 435 0 R /Prev 433 0 R /Dest [177 0 R /XYZ 93.5 403.7 0]>> endobj 435 0 obj << /Title (% 5S5b5R5Y_ 5P5\\5`5a5V5a is the cost of the fuel used in of unit 5V s modelled production of electrical energy for out of merit generation in trading interval 5a) /Parent 255 0 R /Next 436 0 R /Prev 434 0 R /Dest [177 0 R /XYZ 93.5 367.7 0]>> endobj 436 0 obj << /Title (% 5B&5@_ 5P5\\5`5a5V5a is the additional variable operational costs associated with the out of merit generation of unit 5V in trading int) /Parent 255 0 R /Next 437 0 R /Prev 435 0 R /Dest [177 0 R /XYZ 93.5 331.7 0]>> endobj 437 0 obj << /Title (The total cost of providing LRRS for the simulated year, for a set of generator units 5V=1, 2, 3 &,5A, for each of the 5a=1, 2, 3 &,5G trading intervals in a year, is given by:) /Parent 255 0 R /Next 438 0 R /Prev 436 0 R /Dest [177 0 R /XYZ 78 295.7 0]>> endobj 438 0 obj << /Title (565\\5`5a_5?=5a=15G5V=15A5?5V5a.5d5V, 5d5V=1 if unit 5V is a Synergy plant0) /Parent 255 0 R /Next 439 0 R /Prev 437 0 R /Dest [177 0 R /XYZ 184 253.7 0]>> endobj 439 0 obj << /Title (\(15\)) /Parent 255 0 R /Next 440 0 R /Prev 438 0 R /First 441 0 R /Last 441 0 R /Count -1 /Dest [177 0 R /XYZ 498.5 249.2 0]>> endobj 441 0 obj << /Title (3.3 Constrained on payment mechanism) /Parent 439 0 R /Dest [47 0 R /XYZ 114.5 769.7 0]>> endobj 440 0 obj << /Title (Market generators in the WEM are compensated through constrained on payments for being dispatched out of merit. Constrained on payments compensate generators for the quantity of energy that is dispatched out of merit, relative to their theoretical energy schedule, at a price that is above the balancing price. This is consistent with the principle that generators that are required to operate, should receive sufficient compensation to meet their short run marginal cost when dispatched.) /Parent 255 0 R /Next 442 0 R /Prev 439 0 R /Dest [47 0 R /XYZ 80 740.7 0]>> endobj 442 0 obj << /Title (Constrained on payments are determined by AEMO as part of settlement calculations for each trading interval. Constrained on payments for the Synergy Balancing Portfolio are a function of the portfolio constrained on quantity \(PCQ\) and a portfolio constrained on compensation price \(PCCP\) for that trading interval, defined in clause 6.17.5 of the Rules as:) /Parent 255 0 R /Next 443 0 R /Prev 440 0 R /Dest [47 0 R /XYZ 78.5 662.7 0]>> endobj 443 0 obj << /Title (% The PCQ equals the lesser of the maximum energy less the minimum energy \(if any\), in MWh, which could have been dispatched from the balancing price quantity pair in the Synergy balancing portfolio supply curve and any upwards out-of-merit generation for the Synergy Balancing Portfolio.) /Parent 255 0 R /Next 444 0 R /Prev 442 0 R /Dest [47 0 R /XYZ 99 608.7 0]>> endobj 444 0 obj << /Title (% The PCCP equals the loss factor adjusted price that is higher than but closest to the balancing price, taking into account the actual Synergy Balancing Portfolio SOI quantity, less the balancing price.) /Parent 255 0 R /Next 445 0 R /Prev 443 0 R /First 446 0 R /Last 446 0 R /Count -1 /Dest [47 0 R /XYZ 99 554.7 0]>> endobj 446 0 obj << /Title (3.4 Upwards out of Merit Generation) /Parent 444 0 R /Dest [47 0 R /XYZ 114.5 506.7 0]>> endobj 445 0 obj << /Title (As part of calculating constrained on payments, AEMO is required to determine the upwards out-of-merit generation that has been dispatched from the Synergy Balancing Portfolio.) /Parent 255 0 R /Next 447 0 R /Prev 444 0 R /Dest [47 0 R /XYZ 79 478.2 0]>> endobj 447 0 obj << /Title (As part of this calculation, the Rules makes a distinction to what is considered as non-qualifying constrained on generation, which represents the increase in energy due to the dispatch of a network control service contract \(NCS\) or for the following ancillary services:) /Parent 255 0 R /Next 448 0 R /Prev 445 0 R /Dest [47 0 R /XYZ 79 442.2 0]>> endobj 448 0 obj << /Title (% Upwards LFAS enablement) /Parent 255 0 R /Next 449 0 R /Prev 447 0 R /Dest [47 0 R /XYZ 100 400.2 0]>> endobj 449 0 obj << /Title (% Upwards LFAS backup enablement, and) /Parent 255 0 R /Next 450 0 R /Prev 448 0 R /Dest [47 0 R /XYZ 100 376.2 0]>> endobj 450 0 obj << /Title (% The spinning reserve response quantity.) /Parent 255 0 R /Next 451 0 R /Prev 449 0 R /Dest [47 0 R /XYZ 99 352.2 0]>> endobj 451 0 obj << /Title (LRRS does not feature in the definition of non-qualifying constrained on generation and as such, any enablement for purpose of providing load rejection reserve is included in the upwards out-of-merit generation calculated for the purpose of constrained on payments.) /Parent 255 0 R /Next 452 0 R /Prev 450 0 R /First 453 0 R /Last 453 0 R /Count -1 /Dest [47 0 R /XYZ 78 328.2 0]>> endobj 453 0 obj << /Title (3.5 Upwards out of merit generation costs associated with load rejection reserve) /Parent 451 0 R /Dest [47 0 R /XYZ 114.5 280.2 0]>> endobj 452 0 obj << /Title (In considering the calculation of the upwards out of merit generation costs associated with LRRS for the Synergy Balancing Portfolio, we note that there is an overlap between the constrained on payment mechanism and the cost associated with dispatching the Synergy Balancing Portfolio out of merit to meet the LRRS requirement.) /Parent 255 0 R /Next 454 0 R /Prev 451 0 R /Dest [47 0 R /XYZ 74.5 234.2 0]>> endobj 454 0 obj << /Title (We note that the only circumstance when the Synergy Balancing Portfolio out-of-merit generation quantities are not eligible for compensation payments is when AEMO determines that a generator has not complied with dispatch instructions.) /Parent 255 0 R /Next 455 0 R /Prev 452 0 R /Dest [51 0 R /XYZ 80.5 769.7 0]>> endobj 455 0 obj << /Title (The Synergy Balancing Portfolio is required to offer into the balancing market on a short run marginal cost \(SRMC\) basis as part of market power mitigation measures in the WEM.) /Parent 255 0 R /Next 456 0 R /Prev 454 0 R /Dest [51 0 R /XYZ 78 721.7 0]>> endobj 456 0 obj << /Title (Notwithstanding the potential for different interpretations of what an SRMC offer could entail, the Rules includes mechanisms to compensate any SRMC associated with start-up and generation that is dispatched out of merit, based on a supply curve that is reflective of the costs of their shortrun production.) /Parent 255 0 R /Next 457 0 R /Prev 455 0 R /Dest [51 0 R /XYZ 79 685.7 0]>> endobj 457 0 obj << /Title (Therefore, it would appear that the Rules require out of merit generation that is dispatched specifically for LRRS to be compensated through the constrained on mechanism. The outcome of this is that the cost of providing LRRS which may necessitate out of merit dispatch on start-up is recovered through the constrained on payment mechanism during normal market operation. Specifically, the Synergy Balancing Portfolio recovers its short-run marginal costs for energy in the Balancing Market and recovers ancillary services costs in either the LFAS markets, application of margin values in settlements or by contractual mechanisms.) /Parent 255 0 R /Next 458 0 R /Prev 456 0 R /Dest [51 0 R /XYZ 78 625.7 0]>> endobj 458 0 obj << /Title (On the basis that this assessment is correct, an appropriate evaluation of upwards out of merit generation associated with LRR is zero. The Cost_LR parameter is therefore limited to consideration of generation that is constrained off \(downwards out of merit generation\) due to units responding to a load rejection event occurring.) /Parent 255 0 R /Next 459 0 R /Prev 457 0 R /First 460 0 R /Last 460 0 R /Count -1 /Dest [51 0 R /XYZ 79 535.7 0]>> endobj 460 0 obj << /Title (3.6 Constrained off generation as a result of a load rejection reserve event) /Parent 458 0 R /Dest [51 0 R /XYZ 114.5 475.7 0]>> endobj 459 0 obj << /Title (AEMO is required to calculate the downwards out of merit generation in a trading interval to determine constrained off payments to Synergy s Balancing Portfolio. The Rules excludes load rejection reserve response quantities from contributing to the downwards out of merit generation calculation.) /Parent 255 0 R /Next 461 0 R /Prev 458 0 R /Dest [51 0 R /XYZ 79 430.2 0]>> endobj 461 0 obj << /Title (A generating unit may be instructed to curtail its generation output or be disconnected entirely in response to a load rejection event and as a result would incur lost revenue resulting from foregone energy sales at the prevailing balancing price. It would be reasonable to expect that units that respond to a load rejection reserve event should be compensated for providing the service as part of the Cost_LR. We consider energy sales foregone to be a reasonable approximation of the L  parameter of Cost_LR to cover the costs for providing this service in accordance with the Rules.) /Parent 255 0 R /Next 462 0 R /Prev 459 0 R /First 463 0 R /Last 463 0 R /Count -1 /Dest [51 0 R /XYZ 79 370.2 0]>> endobj 463 0 obj << /Title (3.7 Calculation of Cost_L) /Parent 461 0 R /Dest [53 0 R /XYZ 114.5 769.7 0]>> endobj 462 0 obj << /Title (We consider that the energy sales forgone as a result of a generator unit being constrained off or curtailed to provide LRRS will be a function of the prevailing balancing price at the time of the load rejection event occurring and the load rejection reserve response quantity.) /Parent 255 0 R /Next 464 0 R /Prev 461 0 R /Dest [53 0 R /XYZ 80.5 740.7 0]>> endobj 464 0 obj << /Title (Load rejection events can occur at any time of the year and is dependent on network outages and the coincident system conditions. However, load rejection events that have led to over-frequency in the WEM are rare and the response required from LRRS has historically been limited to within a 30 minute trading interval.) /Parent 255 0 R /Next 465 0 R /Prev 462 0 R /Dest [53 0 R /XYZ 78 692.7 0]>> endobj 465 0 obj << /Title (We consider a rudimentary analysis of the foregone energy sales of a load rejection event in Table 2. We consider an upper bound scenario assuming the load rejection event occurs during a trading interval at the maximum balancing price for a sustained period of two trading intervals, under the assumption that AEMO will not decommit a generation unit in response to a load rejection event. We also consider that same analysis based on the observed market average balancing price for the 2017-18 year. We also consider a maximum of two events occurring in a year as reasonable, based on network outage statistics of key bulk transmission circuits.) /Parent 255 0 R /Next 466 0 R /Prev 464 0 R /Dest [53 0 R /XYZ 80.5 638.7 0]>> endobj 466 0 obj << /Title (Load rejection response quantity) /Parent 255 0 R /Next 467 0 R /Prev 465 0 R /Dest [53 0 R /XYZ 83 500.7 0]>> endobj 467 0 obj << /Title (Load rejection response quantity \(MW, sustained over time\)) /Parent 255 0 R /Next 468 0 R /Prev 466 0 R /Dest [53 0 R /XYZ 83 500.7 0]>> endobj 468 0 obj << /Title (120 MW \(set by AEMO requirement\)) /Parent 255 0 R /Next 469 0 R /Prev 467 0 R /Dest [53 0 R /XYZ 315.5 495.2 0]>> endobj 469 0 obj << /Title (Load rejection response time \(highly conservative\)) /Parent 255 0 R /Next 470 0 R /Prev 468 0 R /Dest [53 0 R /XYZ 83 466.7 0]>> endobj 470 0 obj << /Title (Maximum balancing price \(highly conservative\)) /Parent 255 0 R /Next 471 0 R /Prev 469 0 R /Dest [53 0 R /XYZ 85 442.7 0]>> endobj 471 0 obj << /Title ($302 / MWh \(based on maximum STEM price\)) /Parent 255 0 R /Next 472 0 R /Prev 470 0 R /Dest [53 0 R /XYZ 315.5 443.2 0]>> endobj 472 0 obj << /Title (Average balancing price) /Parent 255 0 R /Next 473 0 R /Prev 471 0 R /Dest [53 0 R /XYZ 84 419.2 0]>> endobj 473 0 obj << /Title (Average balancing price \(based on observed market data for 2017-18 FY\)) /Parent 255 0 R /Next 474 0 R /Prev 472 0 R /Dest [53 0 R /XYZ 84 419.2 0]>> endobj 474 0 obj << /Title ($53.35) /Parent 255 0 R /Next 475 0 R /Prev 473 0 R /Dest [53 0 R /XYZ 315.5 413.7 0]>> endobj 475 0 obj << /Title (Total energy sales foregone @ max balancing price for a single event) /Parent 255 0 R /Next 476 0 R /Prev 474 0 R /Dest [53 0 R /XYZ 83.5 385.2 0]>> endobj 476 0 obj << /Title ($36,240) /Parent 255 0 R /Next 477 0 R /Prev 475 0 R /Dest [53 0 R /XYZ 315.5 379.7 0]>> endobj 477 0 obj << /Title (Total energy sales foregone @ maximum balancing price for two events) /Parent 255 0 R /Next 478 0 R /Prev 476 0 R /Dest [53 0 R /XYZ 83.5 351.7 0]>> endobj 478 0 obj << /Title ($72,480) /Parent 255 0 R /Next 479 0 R /Prev 477 0 R /Dest [53 0 R /XYZ 315.5 346.2 0]>> endobj 479 0 obj << /Title (Total energy sales foregone @ average balancing price for a single event) /Parent 255 0 R /Next 480 0 R /Prev 478 0 R /Dest [53 0 R /XYZ 83.5 318.2 0]>> endobj 480 0 obj << /Title ($6,402) /Parent 255 0 R /Next 481 0 R /Prev 479 0 R /Dest [53 0 R /XYZ 315.5 312.7 0]>> endobj 481 0 obj << /Title (Total energy sales foregone @ average balancing price for two events) /Parent 255 0 R /Next 482 0 R /Prev 480 0 R /Dest [53 0 R /XYZ 83.5 284.7 0]>> endobj 482 0 obj << /Title ($12,804) /Parent 255 0 R /Next 483 0 R /Prev 481 0 R /Dest [53 0 R /XYZ 315.5 279.2 0]>> endobj 483 0 obj << /Title (We note that the assessment undertaken in Table 2 would overstate the costs associated with LRRS as it does not take into account the energy contribution required for downwards LFAS enablement or backup downwards LFAS enabled as prescribed in the Rules for the trading interval. LFAS enablement is typically also provided by the Synergy Balancing Portfolio.) /Parent 255 0 R /Next 484 0 R /Prev 482 0 R /Dest [53 0 R /XYZ 80.5 244.7 0]>> endobj 484 0 obj << /Title (Notwithstanding the above simplification, the total energy sales that are foregone are still relatively small, with the annual total estimated cost of LRRS to be estimated at $72,480 in the upper bound scenario defined and $12,804 for the typical scenario defined.) /Parent 255 0 R /Next 485 0 R /Prev 483 0 R /Dest [210 0 R /XYZ 79 733.7 0]>> endobj 485 0 obj << /Title (If the above assessment is correct and reasonable, we propose that the overall energy sales foregone that could be attributed to Cost_LR is also minor and negligible in the context of the WEM and that Cost_LR is zero.) /Parent 255 0 R /Next 486 0 R /Prev 484 0 R /Dest [210 0 R /XYZ 74.5 685.7 0]>> endobj 486 0 obj << /Title (4. Market related assumptions) /Parent 255 0 R /Next 487 0 R /Prev 485 0 R /Dest [55 0 R /XYZ 114.5 769.7 0]>> endobj 487 0 obj << /Title (The key market related assumptions applied in the modelling for ancillary services are summarised in Table 3 below. Additional information is provided further below.) /Parent 255 0 R /Next 488 0 R /Prev 486 0 R /Dest [55 0 R /XYZ 78 732.7 0]>> endobj 488 0 obj << /Title (Energy, Rooftop PV, Behind-the-meter storage, Electric vehicles, Industrial demand) /Parent 255 0 R /Next 489 0 R /Prev 487 0 R /Dest [55 0 R /XYZ 84 653.2 0]>> endobj 489 0 obj << /Title (AEMO 2018 Electricity Statement of Opportunities \(ESOO\) Expected Scenario) /Parent 255 0 R /Next 490 0 R /Prev 488 0 R /Dest [55 0 R /XYZ 219 653.2 0]>> endobj 490 0 obj << /Title (AEMO 2018 Electricity Statement of Opportunities \(ESOO\) Expected Scenario 50% Probability of Exceedance \(POE\) for peak demand) /Parent 255 0 R /Next 491 0 R /Prev 489 0 R /Dest [55 0 R /XYZ 219 653.2 0]>> endobj 491 0 obj << /Title (New entrant market generators) /Parent 255 0 R /Next 492 0 R /Prev 490 0 R /Dest [55 0 R /XYZ 85 593.2 0]>> endobj 492 0 obj << /Title (Generation retirements) /Parent 255 0 R /Next 493 0 R /Prev 491 0 R /Dest [55 0 R /XYZ 84.5 557.2 0]>> endobj 493 0 obj << /Title (Synergy s announced 380 MW base retirement schedule) /Parent 255 0 R /Next 494 0 R /Prev 492 0 R /Dest [55 0 R /XYZ 218 557.2 0]>> endobj 494 0 obj << /Title (Fuel prices) /Parent 255 0 R /Next 495 0 R /Prev 493 0 R /Dest [55 0 R /XYZ 83.5 527.2 0]>> endobj 495 0 obj << /Title (AEMO 2018 Gas Statement of Opportunities \(GSOO\) - Base fuel price trajectory) /Parent 255 0 R /Next 496 0 R /Prev 494 0 R /Dest [55 0 R /XYZ 219 533.2 0]>> endobj 496 0 obj << /Title (Demand response) /Parent 255 0 R /Next 497 0 R /Prev 495 0 R /Dest [55 0 R /XYZ 84.5 484.7 0]>> endobj 497 0 obj << /Title (DSM capacity to be modelled as per AEMO 2018 ESOO with 57 MW in 2018-19 and 66 MW from 2019-20 onwards for the duration of the study period.) /Parent 255 0 R /Next 498 0 R /Prev 496 0 R /First 499 0 R /Last 499 0 R /Count -1 /Dest [55 0 R /XYZ 218.5 496.7 0]>> endobj 499 0 obj << /Title (4.1 Demand modelling) /Parent 497 0 R /Dest [55 0 R /XYZ 114.5 436.7 0]>> endobj 498 0 obj << /Title (Demand assumptions used in modelling include; annual energy projections, peak demand, the uptake of rooftop solar PV, electric vehicles \(EVs\) and behind-the-meter battery storage based on AEMO s 2018 ESOO. An overview of these parameters over the forecast period is provided in Table 4 below.) /Parent 255 0 R /Next 500 0 R /Prev 497 0 R /First 501 0 R /Last 501 0 R /Count -1 /Dest [55 0 R /XYZ 78.5 414.2 0]>> endobj 501 0 obj << /Title (4.1.1 Energy projections) /Parent 498 0 R /Dest [55 0 R /XYZ 114.5 214.7 0]>> endobj 500 0 obj << /Title (One of the primary considerations when forecasting the electricity market is the future demand for electricity, which is expressed in terms of energy consumption and peak demands. The expected scenario from the AEMO ESOO2018 \(Expected Growth Scenario\) has been adopted as the source of electricity demand and energy projection. Figure 5 shows this expected trajectory in annual operational energy consumption \(to be met by large-scale generation facilities\) for the WEM.) /Parent 255 0 R /Next 502 0 R /Prev 498 0 R /Dest [55 0 R /XYZ 79 193.2 0]>> endobj 502 0 obj << /Title (/) /Parent 255 0 R /Next 503 0 R /Prev 500 0 R /First 504 0 R /Last 504 0 R /Count -1 /Dest [215 0 R /XYZ 168.5 567.2 0]>> endobj 504 0 obj << /Title (4.1.2 Peak demand) /Parent 502 0 R /Dest [215 0 R /XYZ 114.5 533.7 0]>> endobj 503 0 obj << /Title (Figure 6 shows AEMO s expected peak demand forecast based on a 50% POE. Peak demands are significantly influenced by weather conditions, particularly hot temperatures in summer and cold temperatures in winter, driving cooling and heating air conditioning loads, respectively.) /Parent 255 0 R /Next 505 0 R /Prev 502 0 R /Dest [215 0 R /XYZ 77.5 512.2 0]>> endobj 505 0 obj << /Title (The peak demand \(and near-peak demand conditions\) increases the risk of price volatility, and therefore the magnitude of the peak demand in any given year is a significant factor in determining overall wholesale market pricing trends. EY has used AEMO's published peak demand forecasts representing a 50% probability of exceedance \(POE\) peak demand level.) /Parent 255 0 R /Next 506 0 R /Prev 503 0 R /Dest [215 0 R /XYZ 78 470.2 0]>> endobj 506 0 obj << /Title (The 50% POE peak represents a typical year, with a one in two chance of the peak demand being exceeded in at least one half hour of the year and is representative of a statistically likely  scenario.) /Parent 255 0 R /Next 507 0 R /Prev 505 0 R /Dest [215 0 R /XYZ 78 416.2 0]>> endobj 507 0 obj << /Title (/) /Parent 255 0 R /Next 508 0 R /Prev 506 0 R /First 509 0 R /Last 509 0 R /Count -1 /Dest [215 0 R /XYZ 139.5 186.2 0]>> endobj 509 0 obj << /Title (4.1.3 Rooftop PV) /Parent 507 0 R /Dest [215 0 R /XYZ 114.5 152.7 0]>> endobj 508 0 obj << /Title (Modelling uses AEMO s expected scenario for rooftop PV uptake from the AEMO ESOO 2018. Figure 7 shows the rooftop PV trajectory used in this scenario. The uptake in rooftop PV systems in recent years has been rapid in the WEM, driven by favourable government policies and attractive payback periods. While many of the supportive government policies have now been removed \(or significantly scaled back\), AEMO still expects significant growth in rooftop PV uptake due to decreasing costs of PV systems and increasing \(real or customer perceived\) retail energy costs.) /Parent 255 0 R /Next 510 0 R /Prev 507 0 R /Dest [215 0 R /XYZ 80 131.2 0]>> endobj 510 0 obj << /Title (/) /Parent 255 0 R /Next 511 0 R /Prev 508 0 R /First 512 0 R /Last 512 0 R /Count -1 /Dest [222 0 R /XYZ 155 546.2 0]>> endobj 512 0 obj << /Title (4.1.4 Behind-the-meter storage) /Parent 510 0 R /Dest [222 0 R /XYZ 114.5 513.7 0]>> endobj 511 0 obj << /Title (EY separately models behind-the-meter \(domestic\) storage profiles and EV charging profiles to capture their impact on the shape of grid demand without changes to the total underlying operational energy forecast by AEMO based on information provided in AEMO s ESOO 2018. Figure 8 demonstrates this uptake.) /Parent 255 0 R /Next 513 0 R /Prev 510 0 R /Dest [222 0 R /XYZ 78 492.2 0]>> endobj 513 0 obj << /Title (/) /Parent 255 0 R /Next 514 0 R /Prev 511 0 R /First 515 0 R /Last 515 0 R /Count -1 /Dest [222 0 R /XYZ 176.5 255.2 0]>> endobj 515 0 obj << /Title (4.1.5 Electric vehicles) /Parent 513 0 R /Dest [222 0 R /XYZ 114.5 222.7 0]>> endobj 514 0 obj << /Title (Modelling assumptions use AEMO s expected scenario for electric vehicle \(EV\) uptake trajectory from the AEMO ESOO2018. The uptake of electric vehicles is projected to provide a new source of electrical load as consumers switch from petrol-based vehicles to those that rely on charging from the grid. Within the study period however, the overall contribution from EVs to the annual SWIS operational energy forecast is expected to be less than 0.1%. AEMO expects that the impact of EV s on peak demand to be negligible.) /Parent 255 0 R /Next 516 0 R /Prev 513 0 R /Dest [222 0 R /XYZ 80 201.2 0]>> endobj 516 0 obj << /Title (/) /Parent 255 0 R /Next 517 0 R /Prev 514 0 R /First 518 0 R /Last 518 0 R /Count -1 /Dest [234 0 R /XYZ 194 591.2 0]>> endobj 518 0 obj << /Title (4.1.6 New entrant market generators) /Parent 516 0 R /Dest [234 0 R /XYZ 114.5 557.7 0]>> endobj 517 0 obj << /Title (The following new entrant generators are included based on capacity credit certification within the study period. Table 5 provides a summary of the SWIS new entrant list. New entrant renewable projects are assumed to offer all capacity into the Balancing Market at a -$40/MWh to reflect an implicit contracted LGC revenue.) /Parent 255 0 R /Next 519 0 R /Prev 516 0 R /First 520 0 R /Last 520 0 R /Count -1 /Dest [234 0 R /XYZ 78 536.2 0]>> endobj 520 0 obj << /Title (4.1.7 Thermal generation retirements) /Parent 517 0 R /Dest [234 0 R /XYZ 114.5 297.2 0]>> endobj 519 0 obj << /Title (In accordance with the Energy Minister s directive for the retirement of generation capacity in the WEM, Synergy s 380MW retirement schedule is modelled, presented in Table 6.) /Parent 255 0 R /Next 521 0 R /Prev 517 0 R /First 522 0 R /Last 522 0 R /Count -1 /Dest [234 0 R /XYZ 74.5 275.7 0]>> endobj 522 0 obj << /Title (4.2 Fuel prices) /Parent 519 0 R /First 523 0 R /Last 523 0 R /Count -1 /Dest [58 0 R /XYZ 114.5 769.7 0]>> endobj 523 0 obj << /Title (4.2.1 Gas prices) /Parent 522 0 R /Dest [58 0 R /XYZ 114.5 746.7 0]>> endobj 521 0 obj << /Title (Short-term gas pricing is not considered in the modelling. The assumed gas price trajectory for the SWIS for uncontracted gas supplies is based on publicly available information from AEMO s Gas Statement of Opportunities \(GSOO\). As existing gas generators  current gas contracts roll off, it is assumed that these generators will be forced to adopt this price trajectory for their future gas contracts. The gas fuel price trajectory is presented in Figure 10.) /Parent 255 0 R /Next 524 0 R /Prev 519 0 R /First 525 0 R /Last 525 0 R /Count -1 /Dest [58 0 R /XYZ 78 725.2 0]>> endobj 525 0 obj << /Title (4.2.2 Coal prices) /Parent 521 0 R /Dest [58 0 R /XYZ 114.5 441.2 0]>> endobj 524 0 obj << /Title (For this Project, the coal price is assumed to remain constant at $2.60/GJ for the study period as per the 2018-19 Margin Valuereview.) /Parent 255 0 R /Next 526 0 R /Prev 521 0 R /First 527 0 R /Last 527 0 R /Count -1 /Dest [58 0 R /XYZ 77.5 419.7 0]>> endobj 527 0 obj << /Title (4.3 Demand response) /Parent 524 0 R /Dest [58 0 R /XYZ 114.5 383.7 0]>> endobj 526 0 obj << /Title (DSM capacity to be modelled as per AEMO 2018 ESOO with 57 MW in 2018-19 and 66 MW from 2019-20 onwards for the duration of the study period.) /Parent 255 0 R /Next 528 0 R /Prev 524 0 R /Dest [58 0 R /XYZ 78.5 360.7 0]>> endobj 528 0 obj << /Title (5. Facility related assumptions) /Parent 255 0 R /Next 529 0 R /Prev 526 0 R /Dest [61 0 R /XYZ 114.5 769.7 0]>> endobj 529 0 obj << /Title (As part of the private consultation process, AEMO and EY is approaching and seeking feedback on the confidential values in Table 7 below.) /Parent 255 0 R /Next 530 0 R /Prev 528 0 R /Dest [61 0 R /XYZ 79 732.7 0]>> endobj 530 0 obj << /Title (Input assumption) /Parent 255 0 R /Next 531 0 R /Prev 529 0 R /Dest [61 0 R /XYZ 81 677.2 0]>> endobj 531 0 obj << /Title (Description) /Parent 255 0 R /Next 532 0 R /Prev 530 0 R /Dest [61 0 R /XYZ 219 677.2 0]>> endobj 532 0 obj << /Title (Average heat rates) /Parent 255 0 R /Next 533 0 R /Prev 531 0 R /Dest [61 0 R /XYZ 85 617.2 0]>> endobj 533 0 obj << /Title (The amount of energy used by the unit per MWh of energy sent out.) /Parent 255 0 R /Next 534 0 R /Prev 532 0 R /Dest [61 0 R /XYZ 218 641.2 0]>> endobj 534 0 obj << /Title (The amount of energy used by the unit per MWh of energy sent out.Data provided will be used to derive a marginal heat rate curve \(e.g. quadratic function, piecewise linear function, etc\).) /Parent 255 0 R /Next 535 0 R /Prev 533 0 R /Dest [61 0 R /XYZ 218 641.2 0]>> endobj 535 0 obj << /Title (Auxiliary factors) /Parent 255 0 R /Next 536 0 R /Prev 534 0 R /Dest [61 0 R /XYZ 85 551.2 0]>> endobj 536 0 obj << /Title (The average percentage of energy generated used to power plant auxiliaries such as fans, motors, feed pumps etc.) /Parent 255 0 R /Next 537 0 R /Prev 535 0 R /Dest [61 0 R /XYZ 218 557.2 0]>> endobj 537 0 obj << /Title (Fixed operating and maintenance costs) /Parent 255 0 R /Next 538 0 R /Prev 536 0 R /Dest [61 0 R /XYZ 83.5 497.2 0]>> endobj 538 0 obj << /Title (Plant operational costs that are incurred regardless of energy generated and does not vary with the level of output that the plant produces expressed as $ per MW of nameplate capacity for a year e.g. lighting, fixed scheduled maintenance.) /Parent 255 0 R /Next 539 0 R /Prev 537 0 R /Dest [61 0 R /XYZ 218 509.2 0]>> endobj 539 0 obj << /Title (Variable operating and maintenance costs) /Parent 255 0 R /Next 540 0 R /Prev 538 0 R /Dest [61 0 R /XYZ 84.5 425.2 0]>> endobj 540 0 obj << /Title (Non-fuel operational cost that varies with the level of output that the plant produces. Includes wear and tear on plant and equipment directly attributable to the production of output and the value of water and other inputs used to produce electricity output.) /Parent 255 0 R /Next 541 0 R /Prev 539 0 R /Dest [61 0 R /XYZ 219 437.2 0]>> endobj 541 0 obj << /Title (Start-up and shut-down costs) /Parent 255 0 R /Next 542 0 R /Prev 540 0 R /Dest [61 0 R /XYZ 84 256.7 0]>> endobj 542 0 obj << /Title (Start-up costs include the opportunity costs of fuel, water, internal power, additional labour and wear and tear directly attributable to the start-up.) /Parent 255 0 R /Next 543 0 R /Prev 541 0 R /Dest [61 0 R /XYZ 218 364.7 0]>> endobj 543 0 obj << /Title (Start-up is defined as the period from zero output to minimum generation. Start-up costs depend on whether a hot start, warm start or cold start occurs, which is determined by the time period elapsed since the plant's previous shut down.) /Parent 255 0 R /Next 544 0 R /Prev 542 0 R /Dest [61 0 R /XYZ 218 316.7 0]>> endobj 544 0 obj << /Title (Additionally the number of hours that must have elapsed for the plant to be considered to be in each of these states is a part of this information request. Only costs additional to those associated with variable output are to be included.) /Parent 255 0 R /Next 545 0 R /Prev 543 0 R /Dest [61 0 R /XYZ 219 256.7 0]>> endobj 545 0 obj << /Title (Start-up costs include the opportunity costs of fuel, water, internal power, additional labour and wear and tear directly attributable to the start-up.Start-up is defined as the period from zero output to minimum generation. Start-up costs depend on whether a hot start, warm start or cold start occurs, which is determined by the time period elapsed since the plant's previous shut down. Additionally the number of hours that must have elapsed for the plant to be considered to be in each of these states is a part of this information request. Only costs additional to those associated with variable output are to be included.Cost of resources required to shut-down and decommit a plant. This includes costs additional to those associated with variable output, such as fuel, water, operating and maintenance costs of shutting a plant down within a trading interval period. Variable costs incurred when decreasing facility power output to zero should not be included.) /Parent 255 0 R /Next 546 0 R /Prev 544 0 R /Dest [61 0 R /XYZ 218 364.7 0]>> endobj 546 0 obj << /Title (Fuel price and transport charge) /Parent 255 0 R /Next 547 0 R /Prev 545 0 R /Dest [251 0 R /XYZ 83.5 697.2 0]>> endobj 547 0 obj << /Title (The best basis for the opportunity cost of fuel is usually the current spot price, or alternatively the current market price for fuel contracts. Pipeline capacity charges should be converted to a $/GJ value \(and may be considered zero if they cannot be on sold to third parties\). We are seeking the fuel/fuel transport price that a market participant will use when making a decision as to whether to generate or not.) /Parent 255 0 R /Next 548 0 R /Prev 546 0 R /Dest [251 0 R /XYZ 218 727.2 0]>> endobj 548 0 obj << /Title (Planned maintenance periods) /Parent 255 0 R /Next 257 0 R /Prev 547 0 R /Dest [251 0 R /XYZ 84 619.2 0]>> endobj 257 0 obj << /Title (Planned maintenance periods for the study period.) /Parent 255 0 R /Prev 548 0 R /Dest [251 0 R /XYZ 218 613.2 0]>> endobj 2 0 obj << /Type /Catalog /Pages 1 0 R /Outlines 255 0 R >> endobj xref 0 549 0000000000 65535 f 0000423804 00000 n 0000530945 00000 n 0000000015 00000 n 0000004174 00000 n 0000000320 00000 n 0000000586 00000 n 0000001079 00000 n 0000012753 00000 n 0000004327 00000 n 0000004591 00000 n 0000005207 00000 n 0000005459 00000 n 0000005598 00000 n 0000005867 00000 n 0000006404 00000 n 0000006658 00000 n 0000007172 00000 n 0000024363 00000 n 0000045058 00000 n 0000012941 00000 n 0000013106 00000 n 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