Chapter 2. Energy and demand projections

Chapter 2 Energy and demand projections 2.1 Overview 2.2 Powerlink s forecasting methodology 2.3 Recent energy and demands 2.4 Forecast data 2.5 Zone forecasts 2.6 Daily and annual load profiles

Chapter 2 2.1 Overview The forecasts presented in this Transmission Annual Planning Report (TAPR) indicate a reduction in energy, summer maximum demand and winter maximum demand compared with the 2013 Annual Planning Report (APR). While there has been significant investment in the resources sector, Queensland on the whole is still experiencing slow economic growth. Furthermore, the continued growth of solar Photovoltaic (PV) combined with consumer response to rising electricity prices has had a dampening effect on electricity usage including maximum demand, and on energy and demand transported across the network. This reduction was presented in Powerlink Queensland s TAPR Energy and Demand Forecast February 2014 Update. Powerlink will continue to update energy and demand forecasts more frequently in the event of further economic uncertainty, volatility in forecasts of key input parameters from external parties and changes in policy and consumer behaviour. Starting from this lower base, the total of existing loads is expected to decline slightly over the rest of the forecast period. Overall growth is expected to be driven by the emerging liquefied natural gas (LNG) industry in South West Queensland. On average, summer maximum demand 1 is forecast to increase at an average rate of 0.9% per annum over the next 10 years. Annual energy is forecast to increase at an average rate of 1.5% per annum over the next 10 years for the medium economic outlook. The LNG industry remains a strong contributor to the 10 year growth forecast. Without the impacts of LNG, forecast maximum demand decline would be 0.2% per annum and forecast energy decline would also be 0.2% per annum over the 10 year forecast period. The maximum demand for summer 2013/14 occurred on 22 January 2014. Scheduled generation on this day peaked at 8,365MW while the native maximum demand was 7,831MW, down 1.0% on the previous summer. Excluding the LNG load, summer maximum demand across the State is forecast to decline. However, there are still expected to be areas of localised growth within the Energex and Ergon Energy networks, necessitating augmentation investment. More information on this will be provided in the Distribution Annual Planning Reports (DAPRs) due for publication in September 2014. Looking ahead Several enhancements were made to the forecasting methodology in the update, which have also been applied in the 2014 TAPR forecast. Firstly, regression models were calibrated to place greater weighting on recent electricity consumer behaviour. Secondly, improved monitoring has provided a better understanding of the impact solar PV has on demand and energy. Thirdly, a new weather correction methodology has been applied to historical demands leading to improvements in the forecasting process. Finally, the latest economic forecasts supplied by the Australian Energy Market Operator (AEMO) from Independent Economics and Frontier Economics 2 have been incorporated. New load in the Surat Basin has started to ramp up. This load is associated with upstream processing facilities for multiple LNG projects and related load growth in the service towns. Only committed LNG proponents are included in the 2014 TAPR medium economic forecasts. While new possible industrial and mining loads (up to 2,000MW) have been identified, these projects remain uncommitted at the time of publication of this TAPR and as such have not been incorporated into this forecast. Figure 2.1 displays the comparison of the summer maximum native demand forecast of the update and the 2014 TAPR, based on 50% probability of exceedance () and medium economic outlook. The 2013 APR forecast is also shown. 1 Where unspecified, maximum demand refers to medium economic outlook, 50%, native maximum demand at time of state peak. 2 Independent Economics and Frontier Economics are consulting companies who were engaged by AEMO to provide economic forecasts. 20

Transmission Annual Planning Report 2014 Energy and demand projections Figure 2.1 Comparison of the medium economic outlooks of the update and the 2014 TAPR demand forecasts 11,000 Maximum native demand (MW) 10,000 9,000 8,000 7,000 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 Financial year Legend Historical Corrected 2013 forecast February 2014 update forecast 2014 forecast 2014 forecast less LNG 2.2 Powerlink s forecasting methodology 2.2.1 Background In accordance with the National Electricity Rules (NER), Powerlink has obtained summer and winter maximum demand forecasts over a 10 year horizon from Distribution Network Service Providers (DNSPs). These connection supply point forecasts are presented in Appendix A. Also in accordance with the NER, Powerlink has obtained summer and winter maximum demand forecasts from other customers that connect directly to the transmission network. These forecasts have been aggregated into demand forecasts for the Queensland region and for 11 geographical zones, defined in Table 2.14 in Section 2.5, using diversity factors observed from historical trends. Energy forecasts for each connection supply point were obtained from the DNSPs and directly connected customers. These have also been aggregated for the Queensland region and for each of the 11 geographical zones in Queensland. Forecasts were also sought from potential direct connect customers who were well advanced with plans for connection to the transmission network. Powerlink enhanced its forecasting methodology in the update. These enhancements are described in more detail the next section. Key economic inputs to this model are provided by AEMO who engaged economic forecasting consultants Independent Economics and Frontier Economics to provide these inputs. Customer forecasts are reconciled to meet the totals obtained from this model. 2.2.2 Powerlink s forecast model The recent emphasis on electricity price rises and management of maximum demand has resulted in noticeable changes in electricity consumer behaviour. Powerlink has made changes to its regression models for both energy and demand so that more weighting is now given to these recent behaviour changes. 21

Chapter 2 The regression models have been calibrated so that if similar economic conditions to the last five years were to reoccur, the expected changes to electricity consumption would be similar. This new approach has resulted in significant reductions in the forecast growth in electricity consumption. Key inputs to Powerlink s maximum demand forecast are: yhistorical State maximum demand by DNSPs in Queensland yhistorical weather data associated with the time of maximum demand by DNSPs yhistorical State maximum demand by transmission direct connect (non DNSP) customers in Queensland yforecast committed maximum demand by transmission direct connect (non DNSP) customers in Queensland yhistorical and forecast Queensland disposable household income yhistorical and forecast Queensland total electricity prices yhistorical and forecast Queensland population yhistorical and forecast Queensland air conditioning penetration yhistorical and forecast solar PV capacity in Queensland. These variables were selected based on the availability of suitable forecasts and best regression fit to historical outcomes. Powerlink s maximum demand forecasting process can be described as follows: 1. Queensland DNSP historical State maximum demands are adjusted to average weather conditions expected at the time of State maximum demand. 2. Queensland DNSP historical weather corrected State maximum demands are increased by the historical solar PV contribution. This gives historical DNSP end use consumption. 3. This DNSP end use consumption is split into temperature sensitive and temperature insensitive components. 4. A regression model is developed to establish the relationship between DNSP temperature insensitive demand with Queensland disposable household income and Queensland total electricity price. From this a forecast of DNSP temperature insensitive demand is derived. 5. A regression model is developed to establish the relationship between DNSP temperature sensitive demand with Queensland population and Queensland air conditioner penetration rates. From this a forecast of DNSP temperature sensitive demand is derived. 6. The Queensland transmission direct connect (non DNSP) customer State maximum demand forecast is determined by assessing forecasts for existing and recently committed customers against historical demands. 7. The Queensland maximum demand forecast is obtained by adding the demands from steps 4, 5 and 6 and reducing by the forecast of solar PV contribution at the time of State maximum demand. Powerlink s energy forecasting process is similar to the demand process except that the DNSP energy is not split into temperature sensitive and insensitive components. 2.2.3 Weather corrected demands The first step in the forecast process is to correct DNSP historical State maximum demands to reflect what would have occurred for average weather conditions associated with State maximum demand. An important requirement of this process is to ensure that corrections up balance with corrections down over a reasonable period of time. This has been designed into the methodology and the results in Figure 2.1 illustrate with similar corrections up as well as down, that this has been achieved. Weather data for Townsville, Rockhampton, Toowoomba and South East Queensland is used for this purpose. The South East Queensland weather data combines data from Brisbane coastal, Brisbane inland, Gold Coast and Sunshine Coast with weightings based on relative demands. For each summer, demand sensitivity to temperature associated with each of these four weather stations is determined. A correction to demand is made based on this sensitivity and the weather variance from average conditions associated with State maximum demand. Weather correction of maximum demands in winter follows a similar process except that South East Queensland is corrected against temperatures at Amberley, as this provides a good fit to the data. 22

Transmission Annual Planning Report 2014 Energy and demand projections 2.2.4 Forecast model inputs Independent Economics and Frontier Economics were engaged by AEMO to develop economic forecasts over three economic scenarios for the 2014 National Electricity Forecasting Report (NEFR) and the 2014 National Transmission Network Development Plan (NTNDP). These scenarios have been used to establish the high, medium and low economic outlooks referred to by Powerlink within this TAPR. Independent Economics and Frontier Economics have assumed a carbon price of $24/t CO2e in 2013/14 and $0/t CO2e from 2014/15, and that carbon pricing is expected to contribute to rising prices from 2020. Forecasts for a range of Queensland economic variables can be found in the NEFR to be published by AEMO in June 2014. Queensland Household Energy Survey Each year Energex, Ergon Energy and Powerlink conduct the Queensland Household Energy Survey to assess consumer behaviours and perceptions regarding the use of electricity. Questions relating to various household appliances, tariffs and energy efficiency provide an insight to consumer motivations and likely future behaviour. Some of this information is used explicitly in Powerlink s forecasting methodology while other qualitative feedback provides an indication for future changes. Air conditioning penetration Domestic air conditioning penetration rates are shown in Figure 2.2. The Queensland Household Energy Survey 2013 (released 2014) showed that air conditioning penetration in South East Queensland rose to 75% while in regional Queensland it rose to 83%. Northern Queensland residences have the highest air conditioning penetration at 91%. Based on historical data and surveyed purchase intentions the current trend shows that penetration is forecast to continue to increase. It is expected that by 2019, South East Queensland will reach 79% penetration with regional Queensland expecting penetration of 90%. Penetration rates forecast in the Queensland Household Energy Survey are used as inputs to Powerlink s demand forecasting model. Figure 2.2 Residences with air conditioning by survey 95 90 Residences with air conditioning (%) 85 80 75 70 65 60 55 50 45 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Year Legend South East Queensland Regional Queensland 23

Chapter 2 Solar PV Following a review of daily profiles for solar PV contributions, changes to the impact of solar PV on the Queensland State maximum demand are shown in Table 2.1. These changes incorporate both the demand reduction and the impact of delaying the time of State maximum demand. Table 2.1 Forecast of Queensland solar PV contribution to State summer maximum demand Year 2013 APR (MW) 2014 TAPR (MW) 2013/14 297 547 2014/15 296 584 2015/16 296 626 2016/17 305 665 2017/18 317 708 2018/19 333 760 2019/20 352 820 2020/21 367 879 2021/22 378 934 2022/23 390 980 Energy efficiency An analysis of the policy measures, incentives and subsidies, relating to energy both nationally and in Queensland, supports the conclusion that there are a number of energy uses that will undergo change in the future. Some of the important measures that affect commercial, industrial and residential electricity uses are: ymandatory Energy Performance Standards (MEPS) and labelling standards for refrigerators, air conditioners and washers ynew residential and commercial building codes yrelevant legislative initiatives (for example, Energy Efficiency Opportunities Act). Uptake of energy efficiency initiatives has been incorporated in Powerlink s forecast model through regression analysis. Inherent in this approach is the assumption that future energy efficiency gains will be at similar levels to past energy efficiency gains. Should greater efficiency gains occur, the electricity demand forecast would be lower. Seasonal variability For each economic outlook, three forecasts are presented to quantify sensitivity of maximum summer and winter demands to a range of drivers. While weather conditions at the time of State maximum demand is an important driver, there are other drivers that can influence seasonal maximum demand. Economic conditions, natural disasters, consumer behaviour and the time of year at which State maximum demand occurs can all influence maximum demand. The three forecasts accounting for seasonal variability are: ya 10% forecast region maximum demand, corresponding to conditions that would be exceeded one year in ten ya 50% forecast region maximum demand, corresponding to conditions that would be exceeded one year in two ya 90% forecast region maximum demand, corresponding to conditions that would be exceeded nine years in ten. 24

Transmission Annual Planning Report 2014 Energy and demand projections 2.2.5 Customer forecasts New large loads The medium economic outlook forecast includes the following loads that have connected since the last APR or have committed to connect in the outlook period: yqgc upstream LNG processing facilities at Kumbarilla Park, near Braemar Substation yqgc upstream LNG processing facilities at Woleebee Creek, near Wandoan South Substation yaplng upstream LNG processing facilities in the Condabri area, near Columboola Substation yaplng upstream LNG processing facilities west of Wandoan South Substation yaplng upstream LNG processing facilities at Orana, between Western Downs and Columboola substations yglng upstream LNG processing facilities west of Wandoan South Substation yqgc upstream LNG processing facilities at Bellevue, near Columboola Substation. The impact of these large customer loads is shown separately in Figure 2.1 as the difference between 2014 Medium 50% demand and 2014 Medium 50% less LNG demand. Possible new large loads There are several proposals for large mining and metal processing or other industrial loads whose development status is not yet at the stage that they can be included (either wholly or in part) in the medium economic forecast. These developments, totalling over 2,000MW, could translate to the additional loads listed in Table 2.2 being supplied by the network. Table 2.2 Possible large loads excluded from the medium economic outlook forecast Zone Description Possible load North Further port expansion at Abbot Point Up to 100MW Central West and North Greater than forecast increase in coal mining and railway load (Bowen Basin area) Up to 150MW Central West and North LNG upstream processing load (Bowen Basin area) Up to 270MW Central West New coal mining load (Galilee Basin area) Up to 1,000MW Surat New coal mining load (Surat Basin area) Up to 100MW Surat Greater than forecast LNG upstream processing load (Surat Basin area) Up to 400MW 2.2.6 Forecasting assumptions Wivenhoe Power Station pumping load Energy delivered to the Wivenhoe Power Station during pumping operation is excluded from both the maximum demand and energy forecasts. Native and transmission delivered demand Transmission delivered demand refers to demand delivered to DNSPs and direct connect customers from Powerlink s transmission network. For all previous APRs, delivered demand also included embedded scheduled generation. Native demand refers to transmission delivered demand plus all generation embedded within the DNSP networks, but does not include solar PV generation. Native demand is in effect the true underlying consumer demand regardless of whether they connect to Powerlink or a DNSP. Native demand with solar PV added in is used as the basis for forecast regression analysis. This TAPR reports forecasts for both transmission delivered and native demand, with particular emphasis on native demand to reflect underlying growth rates. Refer to Figure 2.3. 25

Chapter 2 Interconnector power transfers Energy flows across the Queensland/New South Wales Interconnector (QNI) transmission line and the Terranora Interconnector transmission line are not included in the forecast loads in this chapter as they are not part of the Queensland customer load. These flows will increase or decrease the dispatch of generation and loading on parts of the transmission network within Queensland. 2.2.7 Load forecast definitions The relationship between the classes of generation and the forecast quantities in this TAPR is shown in Figure 2.3. Figure 2.3 Load forecast definitions transmission sent out transmission delivered native Exempted and minor non-scheduled embedded generators Non-scheduled transmission generators (1) etc Transmission losses Distribution losses Wivenhoe pump (2) QNI and Terranora Interconnector Transmission network Distribution network Consumers Scheduled and semi-scheduled transmission generators etc Direct connect customers Scheduled and semi-scheduled embedded generators (3) etc scheduled as generated scheduled sent out Significant non-scheduled embedded generators (4) native as generated native sent out Notes: (1) Includes Invicta, Callide A and Koombooloomba. (2) Depends on Wivenhoe generation. (3) Barcaldine Roma and Townsville Power Station 66kV component. (4) Sugar mills, wind farms, waste generation plant and large industrial customer internal plant but only if there are expected times of net export. 26

Transmission Annual Planning Report 2014 Energy and demand projections 2.3 Recent energy and demands 2.3.1 Recent summers and winters Summer 2013/14 actual maximum native demand for Queensland was 7,831MW, representing a 1.0% drop from the previous summer. The actual native summer energy for Queensland in 2013/14 was 2.2% below the previous summer. Increased use of solar PV and consumer cost consciousness are the main drivers of this reduction. Winter 2013 maximum actual native demand for Queensland was 6,779MW which was 2.4% lower than the previous winter. The native winter energy for Queensland in 2013 was 1.7% lower than the previous winter. Table 2.3 shows a comparison of historical Queensland actual native demands and energy over winter and summer seasons. Table 2.3 Comparison of recent summer and winter actual native energy and demands (1) Winter Native winter energy GWh (2) Maximum native demand MW Summer Native summer energy GWh (3) Maximum native demand MW 2004 10,725 6,416 2004/05 11,434 7,329 2005 10,980 6,551 2005/06 12,246 7,434 2006 11,280 6,942 2006/07 11,876 7,935 2007 11,694 7,276 2007/08 12,157 7,510 2008 11,914 7,593 2008/09 12,536 8,044 2009 11,941 7,169 2009/10 12,904 8,293 2010 11,925 6,918 2010/11 12,016 8,152 2011 11,819 7,185 2011/12 12,242 8,059 2012 11,677 6,934 2012/13 12,229 7,913 2013 11,478 6,769 2013/14 11,966 7,831 Notes: (1) The generation at Barcaldine has been added to the native energy and demand in the 2014 TAPR. (2) Winter includes all the days of June, July and August. (3) Summer includes all the days of December, January and February. 2.3.2 Seasonal growth patterns Energy delivered to DNSPs for recent summers and winters is shown in Figure 2.4. It excludes the energy delivered to major industrial customers connected directly to the transmission network, making it indicative of the underlying trend of domestic and commercial electricity consumption in Queensland. A significant reduction in energy usage is evident since 2010/11. 27

Chapter 2 Figure 2.4 Historical DNSP native energy in Queensland 120 Native energy to DNSPs (GWh per day) 115 110 105 100 95 90 85 80 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Season ending Legend Summer energy to DNSPs Winter energy to DNSPs 2.3.3 Queensland historical maximum demands Queensland region maximum demands for all winters and summers from 2004 are shown in Figure 2.5. Figure 2.5 Historical actual native maximum demand for Queensland 9,000 8,500 Maximum native demand (MW) 8,000 7,500 7,000 6,500 6,000 5,500 5,000 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Season ending Legend Historical summer demand Historical winter demand 28

Transmission Annual Planning Report 2014 Energy and demand projections 2.4 Forecast data The following sections cover forecasts for energy, summer demand and winter demand. The forecast average annual growth rates for the Queensland region over the next 10 years under low, medium and high economic growth outlooks are shown in Table 2.4. These growth rates refer to native quantities as depicted in Figure 2.3. Most of this growth is driven by the emerging LNG industry in South West Queensland. Forecasts by zone are covered in the next section while connection point forecasts, as supplied by Energex and Ergon Energy are shown in Appendix A. Table 2.4 Average annual growth rate over next 10 years Economic growth outlooks Low Medium High Native energy 0.9% 1.5% 2.6% Native summer maximum demand (50% ) 0.6% 0.9% 1.2% Native winter maximum demand (50% ) 1.3% 1.7% 2.1% 2.4.1 Energy forecast Historical Queensland energies are presented in Table 2.5. The first seven energies are defined in Figure 2.3. The last column in Table 2.5 represents the total underlying energy and is the basis for the regression used to derive the energy forecast. Transmission losses are the difference between transmission sent out and transmission delivered energies. Scheduled power station auxiliaries are the difference between scheduled as generated and scheduled sent out energies. The forecast native energy is presented in Table 2.6. The forecast transmission delivered energy is presented in Table 2.7. Table 2.5 Historical native energy (GWh) Year Scheduled as generated Scheduled sent out Native as generated Native sent out Transmission Transmission sent out delivered Native Native plus solar PV 2004/05 49,440 45,714 49,440 45,714 45,375 43,634 43,972 43,972 2005/06 51,193 47,432 51,192 47,431 46,730 45,047 45,748 45,748 2006/07 51,193 47,751 51,473 48,031 47,092 45,347 46,286 46,286 2007/08 51,337 47,910 52,258 48,831 47,297 45,585 47,118 47,118 2008/09 52,591 49,104 53,624 50,137 48,481 46,682 48,338 48,355 2009/10 53,150 49,593 54,434 50,877 48,614 46,745 49,008 49,083 2010/11 51,381 48,020 52,461 49,100 46,990 45,240 47,349 47,639 2011/12 51,147 47,987 52,217 49,057 47,118 45,394 47,334 48,018 2012/13 50,711 47,690 51,905 48,884 47,444 45,650 47,091 48,197 2013/14 (1) 49,603 46,912 50,803 47,841 46,819 45,169 46,453 47,672 Note: (1) These projected end of financial year values are based on revenue and statistical metering data until March 2014. 29

Chapter 2 Table 2.6 Forecast annual native energy (GWh) Year Low growth outlook Medium growth outlook High growth outlook 2014/15 47,386 47,878 48,419 2015/16 49,573 50,932 52,336 2016/17 51,449 53,525 55,826 2017/18 52,045 54,413 58,054 2018/19 51,880 54,414 59,357 2019/20 51,443 54,027 60,071 2020/21 50,944 53,566 60,134 2021/22 50,984 53,752 60,694 2022/23 50,983 53,873 61,102 2023/24 50,725 53,651 60,003 Figure 2.6 compares recent forecasts for annual native energy and historical observations. It also shows the 2014 forecasts (in red) for the three economic outlooks. The energy forecast has dropped since the update forecast due to the 2013/14 energy data being included in the analysis for this TAPR, and some changes to the timing of LNG loads. Figure 2.6 Historical and forecast native energy 70,000 65,000 Annual native energy (GWh) 60,000 55,000 50,000 45,000 40,000 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 Financial year Legend Historical and projected 2013/14 2014 forecast high outlook 2013 forecast medium outlook 2014 forecast medium outlook February 2014 update forecast medium outlook 2014 forecast low outlook 30

Transmission Annual Planning Report 2014 Energy and demand projections Table 2.7 Forecast transmission delivered energy (GWh) Year Low growth outlook Medium growth outlook High growth outlook 2014/15 45,994 46,486 47,027 2015/16 47,920 49,278 50,682 2016/17 49,788 51,863 54,164 2017/18 50,376 52,743 56,385 2018/19 50,203 52,737 57,680 2019/20 49,757 52,341 58,386 2020/21 49,275 51,897 58,465 2021/22 49,331 52,099 59,041 2022/23 49,330 52,220 59,449 2023/24 49,071 51,998 58,350 2.4.2 Summer demand forecast Historical Queensland summer demands are presented in Table 2.8. The first seven demands are defined in Figure 2.3. The 50% temperature corrected demand is the native demand corrected to temperature conditions expected to be exceeded once every two years. The last column of Table 2.8 represents this temperature corrected demand with solar PV added back in. It represents the total underlying demand and is the basis for the regression used to derive the demand forecast. Transmission losses are the difference between transmission sent out and transmission delivered demands. Scheduled power station auxiliaries are the difference between scheduled as generated and scheduled sent out demands. The forecast summer native demand is presented in Table 2.9. The forecast summer transmission delivered demand is presented in Table 2.10. Table 2.8 Historical summer maximum demand (MW) Summer Scheduled Scheduled Native as generated sent out as generated Native sent out Transmission Transmission sent out delivered Native Native Corrected corrected plus solar to 50% PV 2004/05 8,232 7,665 8,232 7,665 7,514 7,177 7,329 7,175 7,175 2005/06 8,295 7,791 8,296 7,792 7,669 7,311 7,434 7,505 7,505 2006/07 8,589 8,124 8,646 8,181 7,945 7,699 7,935 7,928 7,928 2007/08 8,082 7,621 8,188 7,727 7,439 7,222 7,510 7,793 7,793 2008/09 8,677 8,154 8,776 8,253 8,031 7,822 8,044 8,258 8,266 2009/10 8,891 8,441 9,067 8,617 8,306 7,982 8,293 8,307 8,341 2010/11 8,836 8,314 8,911 8,389 8,035 7,798 8,152 8,102 8,232 2011/12 8,707 8,257 8,791 8,340 8,004 7,723 8,059 7,923 8,230 2012/13 8,453 8,080 8,642 8,269 7,944 7,588 7,913 7,928 8,425 2013/14 8,365 7,961 8,532 8,128 7,795 7,498 7,831 7,573 8,120 31

Chapter 2 Table 2.9 Forecast summer native demand (MW) Summer Low growth outlook Medium growth outlook High growth outlook 90% 50% 10% 90% 50% 10% 90% 50% 10% 2014/15 7,700 7,948 8,196 7,773 8,021 8,269 7,847 8,095 8,343 2015/16 7,956 8,205 8,453 8,129 8,378 8,627 8,286 8,535 8,783 2016/17 8,147 8,397 8,646 8,398 8,648 8,898 8,665 8,916 9,166 2017/18 8,187 8,437 8,687 8,470 8,722 8,973 8,898 9,150 9,402 2018/19 8,155 8,406 8,656 8,465 8,717 8,969 9,045 9,298 9,551 2019/20 8,070 8,320 8,570 8,391 8,643 8,895 9,097 9,350 9,604 2020/21 8,000 8,250 8,501 8,334 8,587 8,841 9,112 9,367 9,622 2021/22 7,987 8,238 8,488 8,343 8,596 8,850 9,182 9,438 9,693 2022/23 7,978 8,229 8,479 8,352 8,606 8,860 9,227 9,483 9,740 2023/24 7,951 8,201 8,452 8,332 8,586 8,841 9,210 9,468 9,725 Figure 2.7 compares recent forecasts for summer native demands and historical observations. It also shows the 2014 forecasts (in red) for the three economic outlooks. This TAPR demand forecast is very similar to the update forecast. Figure 2.7 Historical and forecast summer native demand 11,000 10,500 Maximum native demand (MW) 10,000 9,500 9,000 8,500 8,000 7,500 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 7,000 Financial year Legend Historical Corrected February 2014 update forecast medium outlook 2013 forecast medium outlook 2014 forecast high outlook 2014 forecast medium outlook 2014 forecast low outlook 32

Transmission Annual Planning Report 2014 Energy and demand projections Table 2.10 Forecast summer transmission delivered demand (MW) Summer Low growth outlook Medium growth outlook High growth outlook 90% 50% 10% 90% 2014/15 7,343 7,591 7,839 7,415 7,663 7,912 7,490 7,738 7,986 2015/16 7,575 7,823 8,072 7,748 7,997 8,246 7,904 8,153 8,402 2016/17 7,766 8,016 8,265 8,016 8,266 8,516 8,284 8,534 8,785 2017/18 7,805 8,056 8,306 8,089 8,340 8,591 8,517 8,769 9,021 2018/19 7,774 8,024 8,275 8,084 8,335 8,587 8,664 8,917 9,170 2019/20 7,689 7,939 8,189 8,010 8,262 8,514 8,715 8,969 9,222 2020/21 7,619 7,869 8,120 7,953 8,206 8,460 8,731 8,986 9,241 2021/22 7,606 7,856 8,107 7,961 8,215 8,469 8,800 9,056 9,312 2022/23 7,597 7,848 8,098 7,971 8,225 8,479 8,845 9,102 9,358 2023/24 7,570 7,820 8,071 7,950 8,205 8,460 8,829 9,086 9,344 2.4.3 Winter demand forecast Historical Queensland winter demands are presented in Table 2.11. The first seven demands are defined in Figure 2.3. The 50% temperature corrected demand is the native demand corrected to winter temperature conditions expected to be exceeded once in every two years. The last column of Table 2.11 shows this temperature corrected demand with solar PV added back in. As winter demand typically peaks after sunset, this has no impact. Transmission losses are the difference between transmission sent out and transmission delivered demands. Scheduled power station auxiliaries are the difference between scheduled as generated and scheduled sent out demands. The forecast winter native demand is presented in Table 2.12. The forecast winter transmission delivered demand is presented in Table 2.13. Table 2.11 Historical winter maximum demand (MW) 50% 10% 90% 50% 10% Winter Scheduled Scheduled Native as generated sent out as generated Native sent out Transmission Transmission sent out delivered Native Native corrected to 50% Corrected plus solar PV 2004 7,089 6,667 7,163 6,742 6,620 6,295 6,416 6,403 6,403 2005 7,265 6,795 7,294 6,823 6,673 6,401 6,551 6,602 6,602 2006 7,674 7,174 7,762 7,263 7,133 6,813 6,942 7,045 7,045 2007 7,837 7,431 7,899 7,492 7,309 7,092 7,276 7,144 7,144 2008 8,197 7,777 8,292 7,872 7,626 7,348 7,593 7,512 7,512 2009 7,655 7,177 7,769 7,291 7,048 6,926 7,169 7,159 7,159 2010 7,313 6,935 7,586 7,208 6,809 6,519 6,918 6,870 6,870 2011 7,640 7,260 7,797 7,417 7,110 6,878 7,185 7,123 7,123 2012 7,490 7,098 7,538 7,146 6,973 6,761 6,934 7,006 7,006 2013 7,150 6,818 7,295 6,963 6,715 6,521 6,769 6,969 6,969 33

Chapter 2 Table 2.12 Forecast winter native demand (MW) Winter Low growth outlook Medium growth outlook High growth outlook 90% 50% 10% 90% 50% 10% 90% 50% 10% 2014 6,752 7,068 7,383 6,774 7,089 7,405 6,805 7,121 7,436 2015 6,906 7,221 7,535 6,991 7,306 7,621 7,075 7,390 7,704 2016 7,233 7,548 7,862 7,433 7,748 8,063 7,620 7,935 8,250 2017 7,373 7,688 8,003 7,626 7,943 8,259 7,984 8,301 8,618 2018 7,389 7,703 8,016 7,670 7,986 8,301 8,174 8,491 8,808 2019 7,367 7,680 7,993 7,664 7,980 8,295 8,306 8,624 8,941 2020 7,346 7,658 7,970 7,651 7,966 8,282 8,394 8,712 9,029 2021 7,321 7,632 7,944 7,625 7,941 8,256 8,425 8,744 9,062 2022 7,378 7,690 8,001 7,709 8,025 8,341 8,554 8,873 9,192 2023 7,392 7,703 8,015 7,733 8,049 8,365 8,596 8,915 9,235 Figure 2.8 compares recent forecasts for winter native demand and historical observations. It also shows the 2014 forecasts (in red) for the three economic outlooks. Figure 2.8 Historical and forecast winter native demand 10,000 9,500 Maximum native demand (MW) 9,000 8,500 8,000 7,500 7,000 6,500 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 6,000 Legend Financial year Historical Corrected 2013 forecast medium outlook 2014 forecast high outlook 2014 forecast medium outlook 2014 forecast low outlook 34

Transmission Annual Planning Report 2014 Energy and demand projections Table 2.13 Forecast winter transmission delivered demand (MW) Winter Low growth outlook Medium growth outlook High growth outlook 90% 50% 10% 90% 2014 6,402 6,717 7,033 6,423 6,739 7,055 6,455 6,770 7,086 2015 6,556 6,871 7,185 6,641 6,956 7,270 6,725 7,039 7,354 2016 6,858 7,173 7,487 7,058 7,373 7,688 7,245 7,560 7,875 2017 6,998 7,313 7,628 7,251 7,568 7,884 7,609 7,926 8,243 2018 7,014 7,328 7,641 7,295 7,611 7,926 7,799 8,116 8,433 2019 6,992 7,305 7,618 7,289 7,605 7,920 7,931 8,249 8,566 2020 6,971 7,283 7,595 7,276 7,591 7,907 8,019 8,337 8,655 2021 6,946 7,257 7,569 7,250 7,566 7,881 8,050 8,369 8,687 2022 7,004 7,315 7,626 7,334 7,650 7,966 8,179 8,498 8,817 2023 7,017 7,328 7,640 7,358 7,674 7,990 8,221 8,541 8,860 50% 10% 90% 50% 10% 2.5 Zone forecasts The 11 geographical zones referred to throughout this TAPR are defined in Table 2.14 and are shown in the diagrams in Appendix B. In the 2008 APR, Powerlink split the South West zone into Bulli and South West zones. In this 2014 TAPR, Powerlink has split the South West zone into Surat and South West zones. Table 2.14 Zone definitions Zone Far North Ross North Central West Gladstone Wide Bay Surat Bulli South West Moreton Gold Coast Area covered North of Tully, including Chalumbin North of Proserpine and Collinsville, excluding the Far North zone North of Broadsound and Dysart, excluding the Far North and Ross zones South of Nebo, Peak Downs and Mt McLaren, and north of Gin Gin, but excluding the Gladstone zone South of Raglan, north of Gin Gin and east of Calvale Gin Gin, Teebar Creek and Woolooga 275kV substation loads, excluding Gympie West of Western Downs and south of Moura, excluding the Bulli zone Goondiwindi (Waggamba) load and the 275/330kV network south of Kogan Creek and west of Millmerran Tarong and Middle Ridge load areas west of Postmans Ridge, excluding the Bulli zone South of Woolooga and east of Middle Ridge, but excluding the Gold Coast zone East of Greenbank, south of Coomera to the Queensland/New South Wales border Each zone normally experiences its own maximum demand, which is usually greater than that shown in tables 2.18 to 2.21. 35

Chapter 2 Table 2.15 shows the average ratios of forecast zone maximum native demand to zone native demand at the time of forecast Queensland region maximum demands. These values can be used to multiply demands in tables 2.19 and 2.21 to estimate each zone s individual native maximum demand, the time of which is not necessarily coincident with the time of Queensland region native maximum demand. The ratios are based on historical trends. As load has only recently started to ramp up in the Surat zone, ratios for this zone cannot be reliably determined. Table 2.15 Average ratios of zone maximum native demand to zone native demand at time of Queensland region maximum demand Zone Winter Summer Far North 1.16 1.17 Ross 1.21 1.30 North 1.14 1.08 Central West 1.07 1.10 Gladstone 1.04 1.04 Wide Bay 1.09 1.09 Surat N/A N/A Bulli 1.27 1.12 South West 1.12 1.09 Moreton 1.00 1.00 Gold Coast 1.02 1.01 Tables 2.16 and 2.17 show the forecast of transmission delivered energy and native energy for the medium economic outlook for each of the 11 zones in the Queensland region. Tables 2.18 and 2.19 show the forecast of transmission delivered winter maximum demand and native winter maximum demand for each of the 11 zones in the Queensland region. It is based on the medium economic outlook and average winter weather. Tables 2.20 and 2.21 show the forecast of transmission delivered summer maximum demand and native summer maximum demand for each of the 11 zones in the Queensland region. It is based on the medium economic outlook and average summer weather. 36

Transmission Annual Planning Report 2014 Energy and demand projections Table 2.16 Annual transmission delivered energy (GWh) by zone Year Far North Ross North Central West Gladstone Wide Bay Surat Bulli South West Moreton Gold Coast Total Actuals 2004/05 1,673 2,799 2,542 3,269 9,452 1,419 1,898 17,548 3,034 43,634 2005/06 1,745 2,393 2,571 3,363 9,707 1,468 2,074 18,472 3,253 45,047 2006/07 1,770 2,563 2,733 3,169 9,945 1,461 2,012 18,470 3,225 45,347 2007/08 1,818 2,720 2,728 3,165 10,058 1,399 87 1,643 18,683 3,283 45,585 2008/09 1,851 2,772 2,779 3,191 10,076 1,430 94 1,548 19,533 3,408 46,682 2009/10 1,836 2,849 2,719 3,300 10,173 1,427 84 1,253 19,628 3,476 46,745 2010/11 1,810 2,791 2,590 3,152 10,118 1,308 95 1,082 18,887 3,407 45,240 2011/12 1792 2,762 2572 3463 10286 1323 105 1196 18630 3266 45,394 2012/13 1722 2,782 2642 3414 10507 1267 104 1746 18231 3235 45,650 2013/14 1,641 2,928 2,718 3,612 10,280 1,337 359 95 1,330 17,797 3,071 45,169 Forecasts 2014/15 1,590 2,704 2,754 3,870 10,396 1,320 1,391 494 1,289 17,624 3,055 46,486 2015/16 1,577 2,685 2,459 3,912 10,404 1,309 4,150 987 1,276 17,490 3,030 49,278 2016/17 1,571 2,700 2,526 3,900 10,423 1,304 6,544 1,181 1,271 17,424 3,020 51,863 2017/18 1,570 2,697 2,614 3,897 10,446 1,303 7,363 1,168 1,270 17,400 3,017 52,743 2018/19 1,557 2,679 2,634 3,868 10,442 1,293 7,630 1,131 1,258 17,253 2,993 52,737 2019/20 1,546 2,663 2,670 3,842 10,439 1,283 7,457 1,103 1,247 17,120 2,972 52,341 2020/21 1,536 2,649 2,620 3,820 10,436 1,275 7,260 1,077 1,238 17,031 2,954 51,897 2021/22 1,524 2,632 2,940 3,792 10,432 1,265 7,351 1,096 1,226 16,911 2,930 52,099 2022/23 1,513 2,617 3,011 3,769 10,430 1,257 7,584 1,111 1,217 16,801 2,911 52,220 2023/24 1,503 2,602 2,996 3,745 10,427 1,248 7,610 1,086 1,207 16,685 2,891 51,998 37

Chapter 2 Table 2.17 Annual native energy (GWh) by zone Year Far North Ross North Central West Gladstone Wide Bay Surat Bulli South West Moreton Gold Coast Total Actuals 2004/05 1,673 3,010 2,542 3,352 9,452 1,419 1,943 17,548 3,034 43,972 2005/06 1,745 2,937 2,571 3,503 9,707 1,468 2,092 18,472 3,253 45,748 2006/07 1,770 3,141 2,761 3,370 9,945 1,461 2,068 18,545 3,225 46,286 2007/08 1,818 3,371 2,771 3,528 10,058 1,413 87 1,970 18,821 3,283 47,118 2008/09 1,851 3,336 2,950 3,481 10,076 1,437 94 2,040 19,665 3,408 48,338 2009/10 1,836 3,507 3,070 3,636 10,173 1,447 84 2,005 19,773 3,476 49,008 2010/11 1,810 3,219 2,879 3,500 10,118 1,328 95 2,013 18,980 3,407 47,349 2011/12 1,792 3,257 2,861 3,709 10,286 1,348 105 2,014 18,697 3,266 47,334 2012/13 1,722 3,170 2,974 3,767 10,507 1,292 104 1,988 18,331 3,235 47,091 2013/14 1,641 3,148 3,035 3,992 10,280 1,353 400 95 1,544 17,894 3,071 46,453 Forecasts 2014/15 1,632 3,156 3,032 4,010 10,396 1,346 1,426 494 1,535 17,797 3,055 47,878 2015/16 1,619 3,137 3,010 4,052 10,404 1,335 4,185 987 1,523 17,651 3,030 50,932 2016/17 1,613 3,151 3,077 4,040 10,423 1,330 6,579 1,181 1,517 17,593 3,020 53,525 2017/18 1,612 3,149 3,165 4,037 10,446 1,329 7,398 1,168 1,516 17,576 3,017 54,413 2018/19 1,599 3,131 3,185 4,008 10,442 1,319 7,665 1,131 1,504 17,438 2,993 54,414 2019/20 1,588 3,115 3,221 3,982 10,439 1,309 7,492 1,103 1,493 17,313 2,972 54,027 2020/21 1,578 3,101 3,171 3,960 10,436 1,301 7,295 1,077 1,484 17,208 2,954 53,566 2021/22 1,566 3,084 3,491 3,932 10,432 1,291 7,386 1,096 1,473 17,072 2,930 53,752 2022/23 1,555 3,069 3,562 3,909 10,430 1,283 7,619 1,111 1,463 16,962 2,911 53,873 2023/24 1,545 3,054 3,547 3,885 10,427 1,274 7,645 1,086 1,453 16,846 2,891 53,651 38

Transmission Annual Planning Report 2014 Energy and demand projections Table 2.18 State winter maximum transmission delivered demand (MW) by zone Winter Far North Ross North Central West Gladstone Wide Bay Surat Bulli South West Moreton Gold Coast Total Actuals 2004 206 354 323 425 1,092 216 273 2,867 539 6,295 2005 192 178 277 431 1,081 261 272 3,146 564 6,402 2006 207 243 325 409 1,157 228 362 3,288 594 6,813 2007 219 309 286 442 1,165 297 336 3,449 590 7,093 2008 216 285 361 432 1,161 253 17 304 3,654 666 7,349 2009 210 342 328 416 1,125 218 19 306 3,360 601 6,925 2010 227 192 325 393 1,174 179 18 255 3,172 584 6,519 2011 230 216 317 432 1155 222 20 377 3305 605 6,878 2012 214 226 312 426 1201 215 20 346 3207 594 6,761 2013 195 261 335 418 1,200 190 23 17 263 3,040 579 6,521 Forecasts 2014 198 210 320 456 1,202 203 95 48 272 3,129 604 6,739 2015 197 210 319 457 1,207 203 259 110 272 3,120 602 6,956 2016 197 210 304 460 1,209 203 643 149 272 3,123 603 7,373 2017 198 212 322 462 1,209 204 795 155 273 3,134 605 7,568 2018 198 212 322 461 1,210 203 851 149 272 3,129 604 7,611 2019 198 212 328 461 1,210 203 843 144 272 3,129 604 7,605 2020 198 212 340 462 1,210 204 817 142 273 3,131 604 7,591 2021 197 212 335 461 1,210 203 799 143 272 3,128 604 7,566 2022 198 212 376 461 1,210 203 836 146 273 3,130 604 7,650 2023 198 212 386 462 1,210 204 849 144 273 3,133 605 7,674 39

Chapter 2 Table 2.19 State winter maximum native demand (MW) by zone Winter Far North Ross North Central West Gladstone Wide Bay Surat Bulli South West Moreton Gold Coast Total Actuals 2004 206 354 323 475 1,092 216 345 2,867 539 6,417 2005 192 257 277 431 1,081 261 343 3,146 564 6,552 2006 207 322 325 460 1,157 228 361 3,288 594 6,942 2007 219 309 292 520 1,165 297 410 3,478 587 7,274 2008 216 362 365 470 1,161 253 17 407 3,676 666 7,593 2009 210 425 372 466 1,125 218 19 372 3,361 601 7,169 2010 227 319 363 484 1,174 186 18 365 3,198 584 6,918 2011 230 339 360 520 1,155 222 20 430 3,304 605 7,185 2012 214 302 346 460 1,201 215 20 375 3,206 594 6,934 2013 195 304 362 499 1,200 195 89 17 290 3,039 579 6,769 Forecasts 2014 204 310 380 520 1,205 203 145 48 302 3,168 604 7,089 2015 203 309 378 521 1,210 203 310 110 301 3,159 602 7,306 2016 203 309 388 524 1,211 203 694 149 301 3,162 603 7,748 2017 204 312 406 526 1,212 204 846 155 302 3,173 605 7,943 2018 204 311 406 525 1,212 203 901 149 302 3,168 604 7,986 2019 204 311 413 525 1,212 203 893 144 302 3,168 604 7,980 2020 204 311 424 525 1,212 204 868 142 302 3,170 604 7,966 2021 204 311 420 525 1,212 203 850 143 302 3,167 604 7,941 2022 204 311 460 525 1,212 203 887 146 302 3,169 604 8,025 2023 204 312 470 525 1,213 204 899 144 302 3,172 605 8,049 40

Transmission Annual Planning Report 2014 Energy and demand projections Table 2.20 State summer maximum transmission delivered demand (MW) by zone Summer Far North Ross North Central West Gladstone Wide Bay Surat Bulli South West Moreton Gold Coast Total Actuals 2004/05 277 348 342 482 1,107 276 321 3,415 609 7,177 2005/06 284 371 373 492 1,115 292 351 3,437 596 7,311 2006/07 329 386 452 509 1,164 296 317 3,635 611 7,699 2007/08 292 296 386 476 1,193 243 15 256 3,465 600 7,222 2008/09 280 350 317 459 1,178 278 19 341 3,933 667 7,822 2009/10 317 399 414 503 1,177 269 11 241 3,923 729 7,982 2010/11 306 339 371 469 1,172 274 18 174 3,992 683 7,799 2011/12 296 390 390 525 1191 249 18 218 3787 659 7,723 2012/13 277 320 366 536 1213 232 14 241 3754 634 7,588 2013/14 271 330 341 493 1,147 260 30 20 293 3,710 603 7,498 Forecasts 2014/15 265 334 308 496 1,231 256 174 73 291 3,641 594 7,663 2015/16 264 333 287 498 1,231 255 494 124 290 3,629 592 7,997 2016/17 264 334 301 497 1,232 255 738 140 290 3,626 591 8,266 2017/18 264 333 305 496 1,232 254 820 137 289 3,619 590 8,340 2018/19 262 331 311 494 1,232 253 845 129 288 3,603 588 8,335 2019/20 260 328 317 490 1,231 251 815 126 286 3,575 583 8,262 2020/21 259 326 312 487 1,231 250 790 126 284 3,559 581 8,206 2021/22 257 323 347 484 1,230 248 805 130 282 3,532 576 8,215 2022/23 256 321 355 481 1,229 247 837 131 281 3,514 573 8,225 2023/24 255 320 355 479 1,229 246 839 127 280 3,503 572 8,205 41

Chapter 2 Table 2.21 State summer maximum native demand (MW) by zone Summer Far North Ross North Central West Gladstone Wide Bay Surat Bulli South West Moreton Gold Coast Total Actuals 2004/05 277 425 342 528 1,107 276 349 3,415 609 7,329 2005/06 284 447 373 539 1,115 292 351 3,437 596 7,434 2006/07 329 492 457 573 1,164 297 376 3,636 611 7,935 2007/08 292 404 390 534 1,193 243 15 326 3,513 600 7,510 2008/09 280 423 331 509 1,178 278 17 397 3,964 667 8,044 2009/10 317 504 453 536 1,177 269 11 331 3,965 729 8,293 2010/11 306 412 408 551 1,172 274 18 337 3,992 683 8,152 2011/12 296 464 419 598 1,192 249 18 379 3,786 659 8,059 2012/13 277 434 405 568 1,213 241 14 328 3,798 634 7,913 2013/14 271 435 374 561 1,147 260 88 20 317 3,755 603 7,831 Forecasts 2014/15 267 429 371 554 1,233 256 234 73 312 3,698 594 8,021 2015/16 266 428 373 555 1,233 255 554 124 311 3,687 592 8,378 2016/17 266 428 387 555 1,234 255 798 140 311 3,683 591 8,648 2017/18 265 428 392 554 1,235 254 880 137 310 3,677 590 8,722 2018/19 264 426 397 552 1,234 253 905 129 309 3,660 588 8,717 2019/20 262 423 403 548 1,233 251 875 126 307 3,632 583 8,643 2020/21 261 421 398 545 1,233 250 850 126 305 3,617 581 8,587 2021/22 259 418 434 541 1,232 248 865 130 303 3,590 576 8,596 2022/23 258 416 442 539 1,231 247 897 131 301 3,571 573 8,606 2023/24 257 415 441 537 1,231 246 899 127 301 3,561 572 8,586 42

Transmission Annual Planning Report 2014 Energy and demand projections 2.6 Daily and annual load profiles The daily load profiles for the Queensland region on the days of 2013 winter and 2013/14 summer maximum native demands are shown in Figure 2.9. The annual cumulative load duration characteristic for the Queensland region transmission delivered demand is shown in Figure 2.10 for the 2012/13 financial year. Figure 2.9 Winter 2013 and summer 2013/14 maximum transmission delivered demands 9,000 Maximum delivered demand (MW) 8,000 7,000 6,000 5,000 4,000 Summer peak 22 January 2014 Winter peak 1 July 2013 3,000 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 24:00 Time Legend Summer Winter Figure 2.10 Normalised cumulative annual transmission delivered load duration 2012/13 100 90 Percentage of maximum demand (%) 80 70 60 50 40 30 20 100 95 90 0 0.50 1.00 1.5 10 0 0 10 20 30 40 50 60 70 80 90 100 Percentage of time of year (%) 43

44 Chapter 2