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.
AEMO – TRANSMISSION SERVICES
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
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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.
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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
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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
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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 ,-- -- -,- -- -,-- -- -,- -- -,-- -- ,-- -- -,
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-- M\Y
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2010111
·-'V \ I
ao 70
60
50 40 30 20
10 ,0
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2012/13 2014115 2016117 201 B/19
Load Curve on High Demand Day
A • ~ A I
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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
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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-
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20 +------+-----+------+-----+---
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2010111 2012/13 2014115 2016117 201 B/19
Load Curve on High Demand Dai ao 70 . - / '-... -- M\",' 60
/ '- ----• MVA.=tS 50
/ ' 40 ./ -.....
30
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--... -· ... -- ------~ ,-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
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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.
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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.
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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.
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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.
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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%.
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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%.
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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%.
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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
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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.
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FIGURE 5-1 SUMMER ACTUAL DEMAND BY LOCATION VS FORECAST
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FIGURE 5-2 SUMMER REACTIVE ACTUAL DEMAND BY LOCATION VS FORECAST
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FIGURE 5-3- WINTER ACTUAL DEMAND BY LOCATION, VS FORECAST
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FIGURE 5-4
– W
INT
ER
ACTUAL REACTIVE DEMAND BY LOCATION, VS FORECAST