victorian terminal station demand forecasts 2010… · victorian terminal station demand forecasts...

1

VICTORIAN TERMINAL STATION DEMAND FORECASTS 2010/11-2019/20

PREPARED BY: Transmission Services

DOCUMENT NO: 313820

VERSION NO: 6

FINAL

AEMO – TRANSMISSION SERVICES

DISCLAIMER

This publication has been prepared by the Australian Energy Market Operator Limited (AEMO) using

long term load forecast information in relation to each connection point that connects to the Victorian

transmission network. This information has been submitted to AEMO by Distribution Network Service

Providers (DNSPs) and shall form part of an Annual Planning Report to be published by AEMO in its

capacity as a Transmission Network Service Provider in Victoria in accordance with Rule 5.6.2A of the

National Electricity Rules.

This publication also contains certain predictions, estimates and statements that reflect various

assumptions. Further, this publication presents aggregate forecasts of demand at terminal stations

over the next ten years, which are based on the DNSPs’ forecasts and assumptions. All forecasts and

assumptions could change from year to year. Consequently, they may or may not prove to be correct.

Information in this publication does not amount to a recommendation in respect of any possible

investment and does not purport to contain all of the information that a prospective investor or

participant or potential participant in the National Electricity Market might require. The information

contained in this publication might not be appropriate for all persons and it is not possible for AEMO to

have regard to the investment objectives, financial situation, and particular needs of each person who

reads or uses this publication.

The information contained in this publication might contain errors or omissions, and may or may not

prove to be correct. In all cases, anyone proposing to rely on or use the information in this publication

should independently verify and check the accuracy, completeness, reliability, and suitability of that

information (including information and reports provided by third parties) and should obtain independent

and specific advice from appropriate experts. Accordingly, to the maximum extent permitted by law,

neither AEMO, nor any of AEMO’s advisers, consultants or other contributors to this publication (or

their respective associated companies, businesses, partners, directors, officers or employees):

(a) make any representation or warranty, express or implied, as to the currency, accuracy,

reliability or completeness of this publication and the information contained in it; and

(b) shall have any liability (whether arising from negligence, negligent misstatement, or otherwise)

for any statements, opinions, information or matter (expressed or implied) arising out of,

contained in or derived from, or for any omissions from, the information in this publication, or in

respect of a person’s use of the information (including any reliance on its currency, accuracy,

reliability or completeness) contained in this publication.

COPYRIGHT NOTICE

AEMO is the owner of the copyright and all other intellectual property rights in this publication. All

rights are reserved. All material is subject to copyright under the Copyright Act 1968 (Cth) and

permission to copy it, or any parts of it, must be obtained in writing from AEMO.


Table of Contents

1. INTRODUCTION 3

2. DEMAND FORECASTS BY LOCATION 4

3. METHODOLOGY 55

3.1 Date Ranges and times 55

3.2 Embedded Generation 55

3.3 Capacitance and Reactance 56

3.4 Diversity of Demand 56

3.4.1 Terminal Station Diversity 56

3.4.2 System Diversity 57

4. SYSTEM MAXIMUM DEMAND FORECASTS 58

4.1 TSDF System Forecast 58

4.2 VAPR Forecast 58

4.3 Summer Demand 59

4.4 Winter Demand 60

4.5 Comparison of System Forecasts 61

4.6 Reactive Demand Forecasts 62

5. ACTUAL DEMANDS VS. PREVIOUS FORECASTS 63

5.1 Summer 63

5.2 Winter 63

AEMO – TRANSMISSION SERVICES PAGE 3

1. Introduction

AEMO has prepared and makes available demand forecasts for points of connection within

the Victorian transmission network as required by the National Electricity Rules, clause

5.6.2A(b)(1).

For each location, this document provides the:

• Maximum active power demands forecast to occur for summer and winter on average

one year in two (50% probability of exceedance (POE)) and one year in ten (10% POE),

for each of the financial years 2010/2011 to 2019/2020 inclusive;

• Reactive power demands forecast to occur at the same times as the terminal station’s

maximum active demands (for both 50% POE and 10% POE);

• Representative daily active and reactive demand profiles for days of maximum active

power demand; and

• Maximum active and coincident reactive actual demands for the summer and winter

periods of the preceding year (2009/10).

System Participants have supplied AEMO with forecast maximum levels of active demand,

and the associated reactive demand levels, that they expect to be supplied to their licensed

distribution area at the 10% and 50% POE levels, separated according to their points of

connection at each terminal station. Forecasts are provided for summer and winter over a

ten year period. AEMO has aggregated these forecasts by terminal station.

These forecast demands also form an input to the Distribution Businesses' subsequent

connection planning reports.


2. Demand Forecasts by Location

The bulk of this report comprises a summary of the total forecast demand for each location.

In most cases, the locations reported here correspond directly to physical terminal stations.

In other cases, a location may cover only a portion of a terminal station (for example only

some of the buses), or portions of multiple terminal stations. Finally, some locations relate to

direct connect customers, rather than terminal stations.

Where a location supplies electricity at different voltage levels, these are reported separately.

Locations are sorted by abbreviation, which generally includes an abbreviation of the

terminal station name, along with the voltage level. The following locations are included:

Abbreviation Description

APD500 APD500: Portland 500 kV bus

ATS_BLTS66 ATS_BLTS66: Altona/Brooklyn Terminal Station 66 kV bus

ATS_West66 ATS_West66: Altona West Terminal Station 66 kV bus

BATS66 BATS66: Ballarat Terminal Station 66 kV bus

BETS22 BETS22: Bendigo Terminal Station 22 kV bus

BETS66 BETS66: Bendigo Terminal Station 66 kV bus

BLTS22 BLTS22: Brooklyn Terminal Station 22 kV bus

BLTS-SCI66 BLTS-SCI66: Brooklyn-SCI 66 kV bus

BTS22 BTS22: Brunswick Terminal Station 22 kV bus

CBTS66 CBTS66: Cranbourne Terminal Station 66 kV bus

ERTS66 ERTS66: East Rowville Terminal Station 66 kV bus

FBTS66 FBTS66: Fishermans Bend Terminal Station 66 kV bus

FVTS220 FVTS220: Fosterville Terminal Station 220 kV bus

GNTS66 GNTS66: Glenrowan Terminal Station 66 kV bus

GTS66 GTS66: Geelong Terminal Station 66 kV bus

HOTS66 HOTS66: Horsham Terminal Station 66 kV bus

HTS66 HTS66: Heatherton Terminal Station 66 kV bus

HYTS22 HYTS22: Heywood Terminal Station 22 kV bus

JLA220 JLA220: John Lysaght 220 kV bus

KGTS22 KGTS22: Kerang Terminal Station 22 kV bus

KGTS66 KGTS66: Kerang Terminal Station 66 kV bus

KTS66 KTS66: Keilor Terminal Station 66 kV bus

LY66 LY66: Loy Yang Substation 66 kV bus

MBTS66 MBTS66: Mount Beauty Terminal Station 66 kV bus

MTS22 MTS22: Malvern Terminal Station 22 kV bus

MTS66 MTS66: Malvern Terminal Station 66 kV bus

MWTS66 MWTS66: Morwell Terminal Station 66 kV bus


Abbreviation Description

PTH220 PTH220: Point Henry 220 kV bus

RCTS22 RCTS22: Red Cliffs Terminal Station 22 kV bus

RCTS66 RCTS66: Red Cliffs Terminal Station 66 kV bus

RTS22 RTS22: Richmond Terminal Station 22 kV bus

RTS66 RTS66: Richmond Terminal Station 66 kV bus

RWTS22 RWTS22: Ringwood Terminal Station 22 kV bus

RWTS1366 RWTS1366: Ringwood Terminal Station 1&3 66 kV bus

RWTS2466 RWTS2466: Ringwood Terminal Station 2&4 66 kV bus

SHTS66 SHTS66: Shepparton Terminal Station 66 kV bus

SMTS66 SMTS66: South Morang Terminal Station 66 kV bus

SVTS66 SVTS66: Springvale Terminal Station 66 kV bus

TBTS66 TBTS66: Tyabb Terminal Station 66 kV bus

TGTS66 TGTS66: Terang Terminal Station 66 kV bus

TSTS66 TSTS66: Templestowe Terminal Station 66 kV bus

TTS1266 TTS1266: Thomastown Terminal Station 1&2 66 kV bus

TTS3466 TTS3466: Thomastown Terminal Station 3&4 66 kV bus

WETS66 WETS66: Wemen Terminal Station 66 kV bus

WMTS22 WMTS22: West Melbourne Terminal Station 22 kV bus

WMTS66 WMTS66: West Melbourne Terminal Station 66 kV bus

WOTS22 WOTS22: Wodonga Terminal Station 22 kV bus

WOTS66 WOTS66: Wodonga Terminal Station 66 kV bus

YPS11 YPS11: Yallourn PS Terminal Station 11 kV bus


BLTS-SCl66: Brook lyn-SCI 66 kV bus

Summer Demand

2009/10 MD MW MVAR

18 Jan 2010 13:00 61.3 -3.8

10% POE 50% POE

Year MW MVAR MW MVAR

2010/11 66.4

2011/12 66.4 2012113 6,7.1

2013/14 6,7. 1

2014/15 67 .1

2015/16 67.1 2016/17 6,7. 1

2017/18 6,7.1

2018/19 67.1

2019/20 67. 1

6.6

6.G 6.7 6.7

6.7

6.7 6.7 6.7 6.7

6.7

Winter Demand

2009• MD

22 Jun 2009 18:30

10% POE

Yea r MW MVAR 2010, 66.8 6.0 2011 66.8 6.0

2012 66.8 6.0 2013 66.8 6.0

2014 66.8 G.O 2015, 66.8 6.0 2016 66.8 6.0 2017 66.8 6.0

2018 66.8 6.0 2019 66.8 G.O

Notes:

66.4 6.6

66.4 6.6 67.1 6.7 67.1 6.7

67.1 6.7

67.1 6.7 67.1 6.7 67.1 6.7 67.1 6.7

67.1 G.7

MW MVAH 64.G -2.5

50% POE

MW MVAR 66.8 G.O 66.8 G.O

66.8 6.0 66.8 6.0

66.8 6.0 66.8 6.0 66.8 6.0 GG.8 G.O

66.8 6.0 66.8 6.0

Load C11Ne on High Demand Oay 70 ,-- -- -,- -- -,-- -- -,- -- -,-- -- ,-- -- -,

60 +- ------ - - - ---t--- +- ---t I • j

4500 r1"' ,11 n, ~ II l\i, rt ~ ' ,N (

\J II ~ If M ' I I :,o ++-.......... f--H+-+- - -IH-l-+ff-Llf-1-++-'hHl- ++-~ ~r+-- \, H-+f-hl--V-l

20 +----, 11---F--+ - -Hf-t~tt-H-f+-ii!- , tf-lt-+ t--i lt-1 -f--'L.-f,l-tf--tt- ---,

10 +- --- -+ - -++'-...... --+---Hl--<1-..,____,,, .......... -++-- -M--'--l fl-- -t 0 ........ _..,,,...,_, ......... .... __ ~ - -"""' • ., ,,._ I T -' ' _ ... ... 1-, . ..

Forecast BO ,------,-----,-----,------r---

-- M\Y

----· MVA.=tS

70 t=====;;;;::;;;;;j;;===;;;;;;j;====!====;;j;;;=;;;; -- 10;. 1.tw

60 +---------+----t-----+--- - . - .~);. \tw

50 +-----+-----+----!------+----- 1r) 7i-\tv A,:;,.

40 +-----+-----+----!------+-------- $) ';,c. \tv AJ:,o +---------+----+------+---

20 +-----+-----+----!------+---

10 1==::::=::::=:::::::::;j;:::::::::::::::::::==!;:::::::::::::::::::::::::~:::::=:::::::::::;j::::::::== 0 +---------+----t------+---

2010111

·-'V \ I

ao 70

60

50 40 30 20

10 ,0

,., ... , ... _., ...

2012/13 2014115 2016117 201 B/19

Load Curve on High Demand Day

A • ~ A I

I I\ n. ' J Ill 1J 11 \J I H f I 1,1 • ' I

,,., ..... ~ ... .,. ;, ,, 11, r\ I'-.,,' - ........ .,\''-"' l.t"'..,""" .. '"' ·"'

-100 '• •u ~. , u u . ,u I L o UU V o 'UU L U o U U ' u .

Forecast ao ,-------.-----,-----.------r---70 1;;;;;===+===;;;;;;!;====j;;;;;;===+=;;;;; 60 +-----+-----+----+------+---50 +-----+-----+----t------+---40 +-----+-----+----f------+---30 +-----+-----+----+------+---2.0 +-----+-----+----!------+---

10 1=========!::========t========l========::t====: 0 +- --- -+- --- -+ ---- t-- --- -+- --

2010 2012 W14 2016 201B

-- M\",'

----• MVA.=tS

-- 10%.~'i11'

-- 1 %.IMV K

This load is a direct connect customer. This load is typically shut ,down on summer peak days, hence the IVlD ,does not coincide with the system pceak


RWTS22 : Ringwood Ter1m in a l Station 22 kV bus

Summ er Dem an d

2009/10 MD MW MVAR

11 Jan 2010 17:00 90.5 29.1

10% POE 50% POE

Yea r MW MVAR MW MVAR 2010/11 99.4 31.4 91.0 28.8

2011/12 102.2 32.5 93.4 29.7

2012113 105.7 33.7 96.9 30.9

2013/14 107.4 34.3 98.4 31.4

2014/15 109.9 35.2 100.8 32.3

2015/16 112.4 36. 1 103. 1 33. 1

2016/17 115.1 37.0 105.4 33.9

2017/18 117.7 38.0 107.9 34.8

2018/19 120.G 39.0 110.5 35.7

2019/20 123.7 40.0 113. 1 36.G

Wint er Demand

2009, MD MW MVAH 10 Jun 2009 18:00 70.8 2 1.0

10% POE 50% POE

Yea r MW MVAR MW MVAR 2010 76.3 20.4 74.9 20. 1

2011 77. 1 20.6 75.4 20.2

2012 77.4 20.7 75.5 20.2

2013 77.8 20.8 75.6 20.3

2014 78.5 21. 1 76.0 20.4

2015, 79.8 21.4 77. 0 20.7

2016 81.1 21.8 78.0 2 1.0

2017 82.1 22. 1 78.8 2 1.2

2018 83.4 22.5 79.8 2 1.5

2019 84.6 22.9 80.7 2 1.8

Notes:

Load C11Ne on High Demand Oay 100

90 BO -- M\Y

7,0 ,50

50 4 0

----· MVA.=tS ' V /

30 20

_,...,.,.- --~-1!!1"""----.... _, __ -. . 10 ,o

,0:00 4 :00 B:00 12:00 1·6:00 20:00 0:00

Forecas t

SO +------+------!-----+------+--- -- 1•) \. ltVAl,

60 +------+------!-----+------+--- ---- · c,,%. \tVAl-

40 t:::;: __ ;;:: _;;::;_;:::;;_;:;;_::;_;:_;J;_;:;._,;._;.;:_ ;.; __ ;;:; • .::.. ,:;::_~ __ ;;:::_a':::_;;._,:_';_;, __ ~ _,'==';;';;';':-~ -'t':": ~

20 +------+-----+------+-----+---

0 +------+-----+------+-----+---

2010111 2012/13 2014115 2016117 201 B/19

Load Curve on High Demand Dai ao 70 . - / '-... -- M\",' 60

/ '- ----• MVA.=tS 50

/ ' 40 ./ -.....

30

20 _,,.. _____

--... -· ... -- ------~ ,-10 ---- ---·------,0

0:00 4:oo, 6:00 12:00, 16:00 20:00, 0:00

Forec ast 90 ao 70 -- 10%.~'i11'

60 - • - .:1)% \t'i\ '

50 40 -- 1 %.IMV K

30 ----• -:1)%. \0/ A,~

20 10

0

2010 2012 W 14 2016 201B


3. Methodology

For notes on individual terminal stations, please see its sheet above.

3.1 Date Ranges and times

Summer 2010/11 refers to the period 01 November 2010 to 30 April 2011. Winter 2009

refers to the period 01 May 2009 to 31 October 2009. Demand figures are based on 30

minute energy forecasts. Where an interval time is noted, it refers to the end time of the 30-

minute interval.

Where shown in this document, time of day is Australian Eastern Standard Time. Daylight Saving Time is not used for summer in this document.

3.2 Embedded Generation

Actual demands at a location for distribution network/s connected will be the total of:

• Customer demand connected to the distribution network/s; plus

• Losses in the distribution network/s; less

• Generation exported into the distribution network/s from generators embedded in the

distribution network/s.

In forecasting location maximum demands presented in this report, System Participants have assessed the aggregate level of export, at times of each location’s maximum demand, from small generators embedded in the distribution network/s connected to the station. Where possible, these assumptions have been formed using historical performance during high load periods. This aggregate export has been treated in the Terminal Station Demand Forecasts as negative demand. That is, the locations’ Maximum Demand Forecasts presented in this document have been reduced by the total export of relevant embedded generators.

Output from embedded wind generators is handled in the same manner; that is, it has been estimated and treated as negative demand for the relevant terminal stations.

Conversely, the Terminal Station Maximum Demand Forecasts presented include demand supplied by larger embedded generators scheduled by AEMO. That is, the Terminal Station Maximum Demand Forecasts presented have not been reduced by the total export of these particular embedded generators.


Examples of larger embedded generators are:

• Morwell power station units G1-3;

• Clover power station;

• Hume power station;

• Somerton power station;

• Bairnsdale power station; and

• Anglesea power station.

3.3 Capacitance and Reactance

Reactive loading forecasts presented are the reactive loading levels expected to be imposed

on locations by licensed distribution areas. Thus they incorporate the reactive losses of the

distribution network, including any reactors, and are offset by line and cable charging and

those capacitors in the distribution network assessed by System Participants to be in service

at the relevant time. Terminal station capacitors, compensators, reactors and transformation

reactive losses are not considered as part of the demand.

3.4 Diversity of Demand

3.4.1 Terminal Station Diversity

Where only one System Participant has a point of connection at a location, demand forecasts are presented as provided by the System Participant.

Where more than one System Participant has a point of connection at a location, AEMO determines the proportion of demand contributed by each Participant at the time of maximum demand for the location. In some instances, a Participant does not experience its maximum demand at the same time as the terminal station. AEMO refers to this as diversity between the Participant’s maximum demand and the location’s maximum demand. This diversity is represented by a “terminal station diversity factor”.

The terminal station diversity factor is based on the historical behaviour of the terminal station and Participant demands. It assists AEMO in using the demand forecasts provided by Participants to calculate the maximum demand of the location. Each participant’s demand forecast is assigned a diversity factor for each relevant location. The diversity factor scales the demand forecast to represent the demand contributed by the Participant at the time of location maximum demand. The scaled demand forecasts are summed to obtain aggregate demand forecasts for these location.


3.4.2 System Diversity

When calculating system demand forecasts, AEMO determines the proportion of demand contributed by each Participant (by location) at the time of system maximum demand. In some instances, a Participant does not experience its maximum demand at the same time as the system maximum. AEMO refers to this as diversity between the Participant’s maximum demand and the system maximum demand. This diversity is represented by a “system diversity factor”.

The system diversity factors are based on the historical behaviour of the Participants’ demands at time of system maximum demand. It assists AEMO in using the demand forecasts provided by Participants to calculate the forecast system maximum demand. Each participant’s demand forecast is assigned a system diversity factor. The diversity factor scales the demand forecast to represent the demand contributed by the Participant at the time of system maximum demand. The scaled demand forecasts are summed to obtain aggregate system maximum demand forecasts. Winter and summer forecasts derived from the Terminal Station Demand Forecasts are compared against AEMO’s system forecasts, as presented in the following section.


4. System Maximum Demand Forecasts

4.1 TSDF System Forecast

From the individual location forecasts at 10% and 50% POE for summer and winter, AEMO has used the following steps to derive a corresponding overall Victorian forecast:

• Multiplied each Participant’s demand forecasts for its points of connection by the relevant system diversity factor to produce terminal station demand forecasts for the time of system peak demand (see Methodology section above);

• Aggregated these system-diversified terminal station demand forecasts;

• Ensured that the Loy Yang Switching station is not double-counted at Morwell Terminal Station;

• Adjusted the overall forecast by adding:

o Transmission losses as expected on a maximum demand day;

o Demand representing expected power station internal usage.

4.2 VAPR Forecast

Maximum demand forecasts for the Victorian electricity system are also available in the 2010 Victorian Annual Planning Report (VAPR) which is published in June, and available from

www.aemo.com.au. The VAPR forecast is determined using a “top-down” approach, based on factors such as:

• Historical electricity demand;

• Economic and population growth; and

• Trends in electricity demand.

For the purpose of comparison with the TSDF, the following applies:

• The medium economic growth scenario is selected.

• The VAPR forecast is based on demand as measured at the generator terminals. No adjustment is required for transmission losses and power station internal usage.

• Unlike the TSDF, the VAPR forecast includes the contribution of wind farms embedded within the distribution networks. To enable a comparison with the TSDF, this contribution is removed.


4.3 Summer Demand

Figure 4-1 displays summer TSDF forecasts and VAPR forecasts for both 10% POE and 50% POE.

FIGURE 4-1- TSDF AND VAPR SUMMER MAXIMUM DEMAND FORECASTS

The TSDF forecasts at both 10% and 50% POE are considerably higher than the VAPR forecasts. For 10% POE, the gap varies from 5.4% in the first forecast year to 10.6% in the final year. For 50% POE, it varies from 6.3% to 12.3%.


4.4 Winter Demand

Figure 4-2 displays winter TSDF forecasts and VAPR forecasts for both 10% POE and 50% POE.

FIGURE 4-2 TSDF AND VAPR WINTER MAXIMUM DEMAND FORECASTS

Overall, Participant forecasts are well in excess of the VAPR projections. For 10% POE, the gap varies from 5.5% in the first forecast year to 12.6% in the final year. For 50% POE, it varies from 4.8% to 10.0%.


4.5 Comparison of System Forecasts

A discrepancy between the VAPR forecast and the aggregated TSDF is to be expected, given the very different methods used to develop them. The VAPR is focused on forecasting the total Victorian system demand, whereas the TSDF uses local information and connection information to develop forecasts for each terminal station. The TSDF is aggregated to a system total for comparative purposes.

As in previous years, the aggregated TSDF forecasts are higher than the VAPR forecasts.

The VAPR forecasts have increased since last year, but the aggregated TSDF forecasts

have increased by a larger amount. As a result, the gap between the two has grown.

In checking the forecasts submitted for individual locations, AEMO has identified those that

have markedly increased, and sought clarification from the participant. A variety of reasons

were nominated for the increases; a sample of typical responses is listed below.

• Increased demand due to planned residential developments;

• Increased applications for customer connections;

• Recovery from global financial crisis; higher expectations for economic growth;

• Positive correction to the forecast after adjusting for last year’s actual weather

conditions.

Another factor contributing to the increase in the aggregated TSDF is a change in

methodology for direct-connect customers. In previous years, the system diversity factor for

direct-connect customers was calculated as for other locations. In this year’s report, a more

conservative assumption has been made for planning purposes, to assign these loads a

system diversity factor of 100%.


4.6 Reactive Demand Forecasts

Figure 4-3 shows the aggregate reactive demands forecast by System Participants to be drawn from terminal station points of connection (usually stations’ lower voltage terminals) at the times of Victorian system maximum summer and winter active power demand. The higher levels of motorised cooling demand in summer are considered mainly responsible for the higher reactive demand in summer compared to winter.

Calculation of power factors indicates little change over the forecast horizon, regardless of

POE or season.

FIGURE 4-3 - FORECAST OF REACTIVE DEMAND DRAWN FROM TERMINAL STATION

LOW VOLTAGE BUSBARS


5. Actual Demands vs. Previous Forecasts

5.1 Summer

AEMO assessed the temperature conditions at time of Victorian maximum demand during the 2009/10 year. The highest summer half-hourly native demand of 10,253 MW occurred at 4:00pm on 11 January 2010. On this day, Melbourne’s overnight minimum temperature was 19.1˚C and the daily maximum temperature was 43.1˚C, giving an average temperature of 31.1˚C.

This Native Demand figure includes:

• Demand met by generated scheduled by AEMO;

• Significant non-scheduled generation. This includes the two largest hydro generators and all the wind farms in Victoria.

• An estimation of demand that would have occurred, in the absence of high prices and supply constraints. This includes load shedding and Demand Side Participation (DSP), and accounts for 135 MW out of the 10,253 noted above.

At the time of this year’s maximum demand, the most recent TSDF was the 2009 report, which covered the period from 2009/10 to 2018/19. For each location, Figure 5-1 and Figure 5-2 compare the unadjusted maximum actual demand against the forecast demand for summer 2009/10.

5.2 Winter

AEMO has assessed the temperature conditions for the 2009 winter maximum demand, recorded as 8,156 MW for the half hour ending 6:00 pm on 10 June 2009. No load shedding or DSP was present at this time. On this day, Melbourne’s minimum temperature was 5.7˚C and the maximum temperature was 12.5˚C, providing a daily average temperature of 9.1˚C.

For each location, Figure 5-3 and Figure 5-4 compare the unadjusted maximum actual demand against the forecast demand for winter 2009.


PAGE 64

FIGURE 5-1 SUMMER ACTUAL DEMAND BY LOCATION VS FORECAST


PAGE 65

FIGURE 5-2 SUMMER REACTIVE ACTUAL DEMAND BY LOCATION VS FORECAST


PAGE 66

FIGURE 5-3- WINTER ACTUAL DEMAND BY LOCATION, VS FORECAST


PAGE 67

FIGURE 5-4

– W

INT

ER

ACTUAL REACTIVE DEMAND BY LOCATION, VS FORECAST

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