Chapter 2. Energy and demand projections

Transcription

1 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

2 Chapter 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 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 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

3 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, / / / / / / / / / / / / / / / / / / / /24 Financial year Legend Historical Corrected 2013 forecast February 2014 update forecast 2014 forecast 2014 forecast less LNG 2.2 Powerlink s forecasting methodology 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 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

4 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 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

5 Transmission Annual Planning Report 2014 Energy and demand projections 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 Forecasts for a range of Queensland economic variables can be found in the NEFR to be published by AEMO in June 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 Residences with air conditioning (%) Year Legend South East Queensland Regional Queensland 23

6 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/ / / / / / / / / / 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

7 Transmission Annual Planning Report 2014 Energy and demand projections 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 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

8 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 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

9 Transmission Annual Planning Report 2014 Energy and demand projections 2.3 Recent energy and demands 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 ,725 6, /05 11,434 7, ,980 6, /06 12,246 7, ,280 6, /07 11,876 7, ,694 7, /08 12,157 7, ,914 7, /09 12,536 8, ,941 7, /10 12,904 8, ,925 6, /11 12,016 8, ,819 7, /12 12,242 8, ,677 6, /13 12,229 7, ,478 6, /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 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

10 Chapter 2 Figure 2.4 Historical DNSP native energy in Queensland 120 Native energy to DNSPs (GWh per day) Season ending Legend Summer energy to DNSPs Winter energy to DNSPs 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, Season ending Legend Historical summer demand Historical winter demand 28

11 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% 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, /06 51,193 47,432 51,192 47,431 46,730 45,047 45,748 45, /07 51,193 47,751 51,473 48,031 47,092 45,347 46,286 46, /08 51,337 47,910 52,258 48,831 47,297 45,585 47,118 47, /09 52,591 49,104 53,624 50,137 48,481 46,682 48,338 48, /10 53,150 49,593 54,434 50,877 48,614 46,745 49,008 49, /11 51,381 48,020 52,461 49,100 46,990 45,240 47,349 47, /12 51,147 47,987 52,217 49,057 47,118 45,394 47,334 48, /13 50,711 47,690 51,905 48,884 47,444 45,650 47,091 48, /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

12 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, /16 49,573 50,932 52, /17 51,449 53,525 55, /18 52,045 54,413 58, /19 51,880 54,414 59, /20 51,443 54,027 60, /21 50,944 53,566 60, /22 50,984 53,752 60, /23 50,983 53,873 61, /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, / / / / / / / / / / / / / / / / / / / /24 Financial year Legend Historical and projected 2013/ forecast high outlook 2013 forecast medium outlook 2014 forecast medium outlook February 2014 update forecast medium outlook 2014 forecast low outlook 30

13 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, /16 47,920 49,278 50, /17 49,788 51,863 54, /18 50,376 52,743 56, /19 50,203 52,737 57, /20 49,757 52,341 58, /21 49,275 51,897 58, /22 49,331 52,099 59, /23 49,330 52,220 59, /24 49,071 51,998 58, 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 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, /06 8,295 7,791 8,296 7,792 7,669 7,311 7,434 7,505 7, /07 8,589 8,124 8,646 8,181 7,945 7,699 7,935 7,928 7, /08 8,082 7,621 8,188 7,727 7,439 7,222 7,510 7,793 7, /09 8,677 8,154 8,776 8,253 8,031 7,822 8,044 8,258 8, /10 8,891 8,441 9,067 8,617 8,306 7,982 8,293 8,307 8, /11 8,836 8,314 8,911 8,389 8,035 7,798 8,152 8,102 8, /12 8,707 8,257 8,791 8,340 8,004 7,723 8,059 7,923 8, /13 8,453 8,080 8,642 8,269 7,944 7,588 7,913 7,928 8, /14 8,365 7,961 8,532 8,128 7,795 7,498 7,831 7,573 8,120 31

14 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, /16 7,956 8,205 8,453 8,129 8,378 8,627 8,286 8,535 8, /17 8,147 8,397 8,646 8,398 8,648 8,898 8,665 8,916 9, /18 8,187 8,437 8,687 8,470 8,722 8,973 8,898 9,150 9, /19 8,155 8,406 8,656 8,465 8,717 8,969 9,045 9,298 9, /20 8,070 8,320 8,570 8,391 8,643 8,895 9,097 9,350 9, /21 8,000 8,250 8,501 8,334 8,587 8,841 9,112 9,367 9, /22 7,987 8,238 8,488 8,343 8,596 8,850 9,182 9,438 9, /23 7,978 8,229 8,479 8,352 8,606 8,860 9,227 9,483 9, /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, / / / / / / / / / / / / / / / / / / / /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

15 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, /16 7,575 7,823 8,072 7,748 7,997 8,246 7,904 8,153 8, /17 7,766 8,016 8,265 8,016 8,266 8,516 8,284 8,534 8, /18 7,805 8,056 8,306 8,089 8,340 8,591 8,517 8,769 9, /19 7,774 8,024 8,275 8,084 8,335 8,587 8,664 8,917 9, /20 7,689 7,939 8,189 8,010 8,262 8,514 8,715 8,969 9, /21 7,619 7,869 8,120 7,953 8,206 8,460 8,731 8,986 9, /22 7,606 7,856 8,107 7,961 8,215 8,469 8,800 9,056 9, /23 7,597 7,848 8,098 7,971 8,225 8,479 8,845 9,102 9, /24 7,570 7,820 8,071 7,950 8,205 8,460 8,829 9,086 9, Winter demand forecast Historical Queensland winter demands are presented in Table 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 The forecast winter transmission delivered demand is presented in Table 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 ,089 6,667 7,163 6,742 6,620 6,295 6,416 6,403 6, ,265 6,795 7,294 6,823 6,673 6,401 6,551 6,602 6, ,674 7,174 7,762 7,263 7,133 6,813 6,942 7,045 7, ,837 7,431 7,899 7,492 7,309 7,092 7,276 7,144 7, ,197 7,777 8,292 7,872 7,626 7,348 7,593 7,512 7, ,655 7,177 7,769 7,291 7,048 6,926 7,169 7,159 7, ,313 6,935 7,586 7,208 6,809 6,519 6,918 6,870 6, ,640 7,260 7,797 7,417 7,110 6,878 7,185 7,123 7, ,490 7,098 7,538 7,146 6,973 6,761 6,934 7,006 7, ,150 6,818 7,295 6,963 6,715 6,521 6,769 6,969 6,969 33

16 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% ,752 7,068 7,383 6,774 7,089 7,405 6,805 7,121 7, ,906 7,221 7,535 6,991 7,306 7,621 7,075 7,390 7, ,233 7,548 7,862 7,433 7,748 8,063 7,620 7,935 8, ,373 7,688 8,003 7,626 7,943 8,259 7,984 8,301 8, ,389 7,703 8,016 7,670 7,986 8,301 8,174 8,491 8, ,367 7,680 7,993 7,664 7,980 8,295 8,306 8,624 8, ,346 7,658 7,970 7,651 7,966 8,282 8,394 8,712 9, ,321 7,632 7,944 7,625 7,941 8,256 8,425 8,744 9, ,378 7,690 8,001 7,709 8,025 8,341 8,554 8,873 9, ,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, / / / / / / / / / / / / / / / / / / / /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

17 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% ,402 6,717 7,033 6,423 6,739 7,055 6,455 6,770 7, ,556 6,871 7,185 6,641 6,956 7,270 6,725 7,039 7, ,858 7,173 7,487 7,058 7,373 7,688 7,245 7,560 7, ,998 7,313 7,628 7,251 7,568 7,884 7,609 7,926 8, ,014 7,328 7,641 7,295 7,611 7,926 7,799 8,116 8, ,992 7,305 7,618 7,289 7,605 7,920 7,931 8,249 8, ,971 7,283 7,595 7,276 7,591 7,907 8,019 8,337 8, ,946 7,257 7,569 7,250 7,566 7,881 8,050 8,369 8, ,004 7,315 7,626 7,334 7,650 7,966 8,179 8,498 8, ,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

18 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 Ross North Central West Gladstone Wide Bay Surat N/A N/A Bulli South West Moreton Gold Coast 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

19 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, /06 1,745 2,393 2,571 3,363 9,707 1,468 2,074 18,472 3,253 45, /07 1,770 2,563 2,733 3,169 9,945 1,461 2,012 18,470 3,225 45, /08 1,818 2,720 2,728 3,165 10,058 1, ,643 18,683 3,283 45, /09 1,851 2,772 2,779 3,191 10,076 1, ,548 19,533 3,408 46, /10 1,836 2,849 2,719 3,300 10,173 1, ,253 19,628 3,476 46, /11 1,810 2,791 2,590 3,152 10,118 1, ,082 18,887 3,407 45, / , , / , , /14 1,641 2,928 2,718 3,612 10,280 1, ,330 17,797 3,071 45,169 Forecasts 2014/15 1,590 2,704 2,754 3,870 10,396 1,320 1, ,289 17,624 3,055 46, /16 1,577 2,685 2,459 3,912 10,404 1,309 4, ,276 17,490 3,030 49, /17 1,571 2,700 2,526 3,900 10,423 1,304 6,544 1,181 1,271 17,424 3,020 51, /18 1,570 2,697 2,614 3,897 10,446 1,303 7,363 1,168 1,270 17,400 3,017 52, /19 1,557 2,679 2,634 3,868 10,442 1,293 7,630 1,131 1,258 17,253 2,993 52, /20 1,546 2,663 2,670 3,842 10,439 1,283 7,457 1,103 1,247 17,120 2,972 52, /21 1,536 2,649 2,620 3,820 10,436 1,275 7,260 1,077 1,238 17,031 2,954 51, /22 1,524 2,632 2,940 3,792 10,432 1,265 7,351 1,096 1,226 16,911 2,930 52, /23 1,513 2,617 3,011 3,769 10,430 1,257 7,584 1,111 1,217 16,801 2,911 52, /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

20 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, /06 1,745 2,937 2,571 3,503 9,707 1,468 2,092 18,472 3,253 45, /07 1,770 3,141 2,761 3,370 9,945 1,461 2,068 18,545 3,225 46, /08 1,818 3,371 2,771 3,528 10,058 1, ,970 18,821 3,283 47, /09 1,851 3,336 2,950 3,481 10,076 1, ,040 19,665 3,408 48, /10 1,836 3,507 3,070 3,636 10,173 1, ,005 19,773 3,476 49, /11 1,810 3,219 2,879 3,500 10,118 1, ,013 18,980 3,407 47, /12 1,792 3,257 2,861 3,709 10,286 1, ,014 18,697 3,266 47, /13 1,722 3,170 2,974 3,767 10,507 1, ,988 18,331 3,235 47, /14 1,641 3,148 3,035 3,992 10,280 1, ,544 17,894 3,071 46,453 Forecasts 2014/15 1,632 3,156 3,032 4,010 10,396 1,346 1, ,535 17,797 3,055 47, /16 1,619 3,137 3,010 4,052 10,404 1,335 4, ,523 17,651 3,030 50, /17 1,613 3,151 3,077 4,040 10,423 1,330 6,579 1,181 1,517 17,593 3,020 53, /18 1,612 3,149 3,165 4,037 10,446 1,329 7,398 1,168 1,516 17,576 3,017 54, /19 1,599 3,131 3,185 4,008 10,442 1,319 7,665 1,131 1,504 17,438 2,993 54, /20 1,588 3,115 3,221 3,982 10,439 1,309 7,492 1,103 1,493 17,313 2,972 54, /21 1,578 3,101 3,171 3,960 10,436 1,301 7,295 1,077 1,484 17,208 2,954 53, /22 1,566 3,084 3,491 3,932 10,432 1,291 7,386 1,096 1,473 17,072 2,930 53, /23 1,555 3,069 3,562 3,909 10,430 1,283 7,619 1,111 1,463 16,962 2,911 53, /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

21 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 , , , , , , , , , , , , , , , , , , , , , , , , , ,521 Forecasts , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ,674 39

22 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 , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ,769 Forecasts , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ,049 40

23 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/ , , , / , , , / , , , / , , , / , , , / , , , / , , , / , / , / , , ,498 Forecasts 2014/ , , , / , , , / , , , / , , , / , , , / , , , / , , , / , , , / , , , / , , ,205 41

24 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/ , , , / , , , / , , , / , , , / , , , / , , , / , , , / , , , / , , , / , , ,831 Forecasts 2014/ , , , / , , , / , , , / , , , / , , , / , , , / , , , / , , , / , , , / , , ,586 42

25 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 ,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/ Percentage of maximum demand (%) Percentage of time of year (%) 43

26 44 Chapter 2