SOUTH AUSTRALIAN ELECTRICITY MARKET ECONOMIC TRENDS REPORT SOUTH AUSTRALIAN ADVISORY FUNCTIONS

Transcription

1 SOUTH AUSTRALIAN ELECTRICITY MARKET ECONOMIC TRENDS REPORT SOUTH AUSTRALIAN ADVISORY FUNCTIONS Published: October 2015

2 IMPORTANT NOTICE Purpose The purpose of this report is to provide information about South Australian electricity market economic trends. AEMO publishes this South Australian Electricity Market Economic Trends Report in accordance with its additional advisory functions under section 50B of the National Electricity Law. Unless otherwise indicated, this publication is based on information available to AEMO as at 31 August 2015, although AEMO has endeavoured to incorporate more recent information where practicable. Disclaimer AEMO has made every effort to ensure the quality of the information in this report but cannot guarantee that information, analysis and assumptions are accurate, complete or appropriate for your circumstances. This report does not include all of the information that an investor, participant or potential participant in the South Australian electricity market might require, does not amount to a recommendation of any investment. Anyone proposing to use the information in this report (including information and reports provided by third parties) should independently verify and check its accuracy, completeness and suitability for that purpose, and obtain independent and specific advice from appropriate experts. Accordingly, to the maximum extent permitted by law, AEMO and its officers, employees and consultants involved in the preparation of this report: make no representation or warranty, express or implied, as to the currency, accuracy, reliability or completeness of the information in this report; and are not liable (whether by reason of negligence or otherwise) for any statements, opinions, information or other matters contained in or derived from this report, or any omissions from it, or in respect of a person s use of the information in this report. The material in this publication may be used in accordance with the copyright permissions on AEMO s website. Australian Energy Market Operator Ltd ABN info@aemo.com.au NEW SOUTH WALES QUEENSLAND SOUTH AUSTRALIA VICTORIA AUSTRALIAN CAPITAL TERRITORY TASMANIA

3 CONTENTS 1. INTRODUCTION Generating system capacities 5 2. DEMAND DURATION CURVES Summer demand duration curves Winter demand duration curves Non-scheduled generation duration curves AVERAGE DAILY DEMAND PROFILES Summer workday average daily demand profiles Winter workday average daily demand profiles SPOT PRICE DURATION CURVES AVERAGE SPOT PRICES NATIVE ENERGY REQUIREMENTS 19 MEASURES AND ABBREVIATIONS 23 Units of measure 23 Abbreviations 23 GLOSSARY 24 APPENDIX A. TEMPERATURE DURATION CURVES 25 APPENDIX B. SMALL NON-SCHEDULED GENERATION FORECAST METHODOLOGY 26 AEMO

4 TABLES Table 1 South Australian generating system seasonal and nameplate capacities 6 Table 2 South Australian spot price occurrences of very high or negative values 16 Table 3 South Australian spot price trends since Table 4 Annual electrical energy requirement breakdown (GWh) 21 Table 5 Small non-scheduled generation forecasting categories 26 FIGURES Figure 1 Summer demand duration curves 8 Figure 2 Summer demand duration curves (top 10% of demands) 8 Figure 3 Winter demand duration curves 9 Figure 4 Annual generation duration curves for selected non-scheduled generating systems 10 Figure 5 Summer workday average demand profiles 12 Figure 6 Winter workday average demand profiles 13 Figure 7 South Australian spot price duration curves 15 Figure 8 South Australian spot price duration curves (top 1% of prices) 16 Figure 9 Comparison of financial year volume-weighted average prices 18 Figure 10 Comparison of summer volume-weighted average prices 18 Figure 11 Adelaide city temperature duration curve (summer generation period) 25 Figure 12 Adelaide city temperature duration curve (winter generation period) 25 AEMO

5 1. INTRODUCTION The South Australian Electricity Market Economic Trends Report (SAEMETR) provides observations on trends in demand, wholesale price and annual energy requirements for the South Australian region of the National Electricity Market (NEM). The report is organised into sections: Section 2: Demand duration curves for the last three summers and winters, and non-scheduled generation duration curves for the last three financial years. Section 3: Average workday demand profiles for the last three summers and winters. Section 4: Spot price duration curves for the last four financial years. Section 5: Average spot prices since financial year, both time-weighted and volumeweighted, with a breakdown by renewable and non-renewable generation. Section 6: Native energy supply and consumption requirement since financial year and forecast to South Australian demand refers to the operational demand met by local scheduled, semi-scheduled and selected non-scheduled generating systems plus interconnector imports from Victoria. 1 Operational demand does not include demand supplied by rooftop photovoltaic (PV) generation. South Australian generating systems included in operational demand are shown in Table 1. For this report, however, the following adjustments apply: In Sections 2 to 5, demand is operational demand less output from Angaston, Port Stanvac 1 and Port Stanvac 2 generating systems. In Section 6, native demand is operational demand plus selected small non-scheduled generating systems less than 30 MW as defined in the 2015 National Electricity Forecasting Report (NEFR). 2 All time references in this report are to NEM Standard Time Generating system capacities Table 1 lists the fuel type and nameplate capacities of South Australian scheduled, semi-scheduled and significant non-scheduled generating systems used in this report s analysis, as at August Nameplate capacity is the maximum continuous output or consumption in MW of an item of equipment as specified by the manufacturer, or as subsequently modified. This list represents South Australian generators that meet operational consumption, with the remainder supplied from interconnector imports. 1 Operational reporting includes the electrical energy used by all residential, commercial, and large industrial consumption, and transmission losses (as supplied by scheduled, semi-scheduled and significant non-scheduled generating units). Significant non-scheduled generating units in South Australia are Angaston, Port Stanvac 1, Port Stanvac 2 and all non-scheduled wind farms. It does not include the output of small non-scheduled generating systems, typically less than 30 MW capacity. 2 AEMO NEFR. Available at: Viewed: 30 September NEM Standard Time is equivalent to Australian Eastern Standard Time and is not altered during daylight saving time. 4 More information about South Australian generating systems is available at Advisory-Functions/Generation-Information. AEMO

6 Table 1 South Australian generating system seasonal and nameplate capacities Power station Scheduled generating systems Fuel type Nameplate capacity (MW) (August 2015) Dry Creek Gas 156 Hallett GT Gas Ladbroke Grove Gas 80 Mintaro Gas 90 Northern Coal 546 Osborne Gas 180 Pelican Point Gas 478 Playford B Coal 240 Port Lincoln GT Diesel 73.5 Quarantine Gas 224 Snuggery Diesel 63 Torrens Island A Gas 480 Torrens Island B Gas 800 Semi-scheduled generating systems (Wind farms) Clements Gap Wind Farm Wind 56.7 Hallett 1 (Brown Hill) Wind 94.5 Hallett 2 (Hallett Hill) Wind 71.4 Hallett 4 (North Brown Hill) Wind Hallett 5 (The Bluff) Wind 52.5 Lake Bonney 2 Wind 159 Lake Bonney 3 Wind 39 Snowtown Wind Farm Wind 98.7 Snowtown Stage 2 North Wind 144 Snowtown Stage 2 South Wind 126 Waterloo Wind Farm Wind 111 Significant non-scheduled generating systems Angaston Diesel 50 Canunda Wind Farm Wind 46 Cathedral Rocks Wind Farm Wind 66 Lake Bonney Wind Farm Wind 80.5 Mount Millar Wind Farm Wind 70 Port Stanvac 1 Diesel 28.8 Port Stanvac 2 Diesel 28.8 Starfish Hill Wind Farm Wind 34.5 Wattle Point Wind Farm Wind 90.8 AEMO

7 2. DEMAND DURATION CURVES Demand duration curves represent the percentage of time that electricity demand (in megawatts, MW) is at or above a given level over a defined period. For this analysis, demand is the South Australian operational demand less demand met by the Angaston, Port Stanvac 1 and Port Stanvac 2 generating systems. Information on interconnector imports and exports is provided in the South Australian Historical Market Information Report (SAHMIR) on AEMO s website. 5 Figures 1 to 3 show demand duration curves for South Australia. Separate curves are shown for summer and winter (summer is the period from 1 November to 31 March, and winter from 1 June to 31 August). Factors contributing to changes in demand over time include: Increasing rooftop PV generation. Increasing energy efficiency savings. Population changes. Reductions in residential and commercial consumption. Seasonal weather conditions. 2.1 Summer demand duration curves Figures 1 and 2 show the demand duration curves for South Australia for summer to Figure 2 identifies the top 10% of summer demand periods, focusing on the upper levels of generation supplied and interconnector imports. Comparison of these curves shows that: Demand during summer was lower than the previous two years. Major contributors to this were lower air-conditioning load due to more moderate summer temperatures and increased rooftop PV generation due to growth in PV installations. The trend in temperature across the three summers can be seen in Figure 11 in Appendix A. Each summer has had progressively lower operational demand for approximately 95% of the time. This is part of the downward trend in the state s operational consumption as reported in the 2015 South Australian Electricity Report (SAER). 6 As noted in the SAER, a contributing factor to this trend is that residential and commercial per capita consumption has declined, despite recent population growth and state income increases. The per capita decline is attributable to increased rooftop PV generation, and reduced household usage driven primarily by increased residential electricity prices. 5 AEMO SAHMIR. Available at: Historical-Market-Information-Report. Viewed: 7 September AEMO SAER. Available at: Report. Viewed: 7 September AEMO

8 South Australian summer demand (MW) South Australian summer demand (MW) SOUTH AUSTRALIAN ELECTRICITY MARKET ECONOMIC TRENDS REPORT Figure 1 Summer demand duration curves 3,500 3,000 2,500 2,000 1,500 1, % 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Cumulative percentage of the summer season Summer Summer Summer Figure 2 Summer demand duration curves (top 10% of demands) 3,500 3,300 3,100 2,900 2,700 2,500 2,300 2,100 1,900 1,700 1,500 0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 10% Cumulative percentage of the summer season Summer Summer Summer AEMO

9 South Australian winter demand (MW) SOUTH AUSTRALIAN ELECTRICITY MARKET ECONOMIC TRENDS REPORT 2.2 Winter demand duration curves Figure 3 shows the demand duration for winter 2013 to For South Australia, winter demand duration curves tend to be flatter than the summer demand curves. A flatter duration curve indicates that demand is generally more constant and exhibits fewer periods of extreme peaks and troughs. Comparison of these curves shows that for approximately 60% of the time, the winter 2015 demand in South Australia was higher than for winter 2013 and 2014, although the differences between years are relatively small. A major contributor to this is increased heating load due to the cooler than average days and nights during winter Figure 12 in Appendix A provides more information on the trend in temperature across the three winters. Figure 3 Winter demand duration curves 3,500 3,000 2,500 2,000 1,500 1, % 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Cumulative percentage of the winter season Winter 2013 Winter 2014 Winter Bureau of Meteorology. Adelaide in winter 2015: below average temperatures and below average rainfall. Available at: Viewed: 25 September AEMO

10 South Australian non-scheduled generation (MW) SOUTH AUSTRALIAN ELECTRICITY MARKET ECONOMIC TRENDS REPORT 2.3 Non-scheduled generation duration curves Figure 4 shows the aggregate annual generation duration curves from selected South Australian nonscheduled generating systems (outlined in Section 1), for financial years to In , aggregate non-scheduled generation decreased by 9% (104 GWh) compared with This is attributed to less non-scheduled wind farm generation during , which corresponds with less wind measured at wind farm locations. 8 Further information on historical non-scheduled generation is published in the SAHMIR. 9 Figure 4 Annual generation duration curves for selected non-scheduled generating systems % 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Cumulative percentage of the year Based on AEMO s analysis of average wind speed measurements from wind farm sites across South Australia. 9 AEMO. South Australian Historical Market Information Report. Available at: Advisory-Functions/~/media/Files/Other/planning/SAAF/2015_SAHMIR.ashx. Viewed: 25 September AEMO

11 3. AVERAGE DAILY DEMAND PROFILES Average daily demand profiles represent the demand (in MW) for each 5-minute dispatch interval of a day, averaged over the relevant days of the selected period. Changes to the average daily demand profile over time can provide insights into the impact of increasing small-scale renewable generation and demand-side management. For this analysis, demand is the South Australian operational demand less demand met by the Angaston, Port Stanvac 1 and Port Stanvac 2 generating systems. Only South Australian workdays are included in the analysis - weekends and gazetted public holidays are excluded. 3.1 Summer workday average daily demand profiles Figure 5 shows the South Australian average workday demand profile for summer to Comparison of these profiles shows that: Average demand has been decreasing each summer, particularly between daylight hours (about 8:00 am to 8:00 pm). AEMO attributes this to increasing rooftop PV generation due to growth in rooftop PV installations, energy efficiency gains and other demand factors discussed in Section 2.1. Average demand consistently rises at 11:30 pm due to the controlled switching of electric hot water systems. The Australian Energy Regulator (AER) has noted that off-peak hot water load caused changes in demand of 15 20% at exactly 2330 each day. 10 Rooftop PV generation in South Australia increased by 340 GWh from to financial years, an annual average growth rate of 29%. Analysis of Figure 5 indicates that this has lowered the summer workday average demand profile peak, and moved it from between 4:30 pm and 5:30 pm in to a less distinct peak from between 6:00 pm and 7:00pm in South Australian Council for Social Services (SACOSS). High SA Electricity Prices: A Market Power Play? Page 10. Available at: Viewed: 25 September AEMO

12 12:00 AM 2:00 AM 4:00 AM 6:00 AM 8:00 AM 10:00 AM 12:00 PM 2:00 PM 4:00 PM 6:00 PM 8:00 PM 10:00 PM 12:00 AM South Australian summer workday average demand (MW) SOUTH AUSTRALIAN ELECTRICITY MARKET ECONOMIC TRENDS REPORT Figure 5 Summer workday average demand profiles 2,500 2,000 1,500 1, Time of day (NEM time) Summer Summer Summer AEMO

13 12:00 AM 2:00 AM 4:00 AM 6:00 AM 8:00 AM 10:00 AM 12:00 PM 2:00 PM 4:00 PM 6:00 PM 8:00 PM 10:00 PM 12:00 AM South Australian winter workday average demand (MW) SOUTH AUSTRALIAN ELECTRICITY MARKET ECONOMIC TRENDS REPORT 3.2 Winter workday average daily demand profiles Figure 6 shows the South Australian average winter workday demand profile for winter 2013 to Comparison of these profiles shows that: Average demand has been generally steady each winter, apart from the morning and evening peaks where there has been some small increase in AEMO attributes the growth in the evening peak to increased heating load, as discussed in Section 2.2. Morning and evening peaks are higher in winter than summer, which is most likely due to the heating loads in winter. Average demand consistently rises at 11:30 pm due to the controlled switching of electric hot water systems, as discussed for the average summer workday daily profile. Figure 6 Winter workday average demand profiles 2,500 2,000 1,500 1, Time of day (NEM time) Winter 2013 Winter 2014 Winter 2015 AEMO

14 4. SPOT PRICE DURATION CURVES Spot price duration curves show how frequently a particular 30-minute spot price occurs over a given period. Spot prices are calculated in real fourth quarter (Q4) dollars. There are a number of supply and consumption factors that influence spot price over time. Supply factors include: The available capacity of generating systems. The availability of wind generation. The costs of generation (for example, changes in fuel costs). Non-market generation, which includes rooftop PV and some embedded generation. Interconnector flows and network constraints. Consumption factors include: Temperature-dependent loads (heating and cooling). Consumer behaviour (for example, residential and commercial consumer response to higher prices reflected in increased energy efficiency savings). Large industrial loads, for example manufacturing and mining consumption. Policy changes (for example, carbon pricing and the Renewable Energy Target) can affect both supply and consumption. Figure 7 and Figure 8 show the spot price duration curves for financial years to Figure 7 shows a step increase from to due to the imposition of a carbon price in July 2012, and a step decrease from to following the repeal of the carbon price in July Since the repeal, South Australian spot prices have returned to the pre-carbon price levels shown in the curve. The impact of carbon pricing makes it difficult to assess underlying trends in spot prices over this period. AEMO

15 Figure 7 South Australian spot price duration curves AEMO

16 Figure 8 illustrates that in the past three financial years, the top 1% of spot prices have been above $100 per megawatt-hour (MWh). Prices are presented on a logarithmic scale. Figure 8 South Australian spot price duration curves (top 1% of prices) NOTE: Logarithmic scale applied to vertical axis Table 2 shows the number of times that the spot price for South Australia exceeded certain thresholds. The higher incidence of prices above $400/MWh during was due to a combination of factors, including high demand, low wind, planned network outages reducing import capability, unplanned generation outages and the planned withdrawal of up to 800 MW of generation capacity 11. There were many more occurrences of negative prices during and than in the interim years. Negative prices typically occur overnight during low demand coinciding with high wind generation and dispatch close to minimum stable levels for thermal plant. Table 2 South Australian spot price occurrences of very high or negative values Financial Year greater than $400/MWh Number of times the spot price for South Australian was greater than $1000/MWh greater than $5000/MWh less than $0/MWh Including Northern power station after March 2013, which moved to summer-only operation AEMO

17 5. AVERAGE SPOT PRICES Volume-weighted average price (VWAP) takes into account the amount and price of electricity for a given interval (which is more reflective of wholesale revenues) while time-weighted average price does not take into account the different volumes of energy sold for a given interval. South Australian large-scale renewable energy generation is dominated by wind farms, which have low operating costs. However, when wind generation is unavailable, higher cost fossil-fuelled generation (coal, gas or diesel) or interconnector imports are used to meet consumption. Table 3 compares the VWAP received for South Australian renewable generation, fossil-fuelled generation, and total market generation, on a financial year basis and each summer since The time-weighted spot price for each financial year is also shown for comparison. VWAP values are based on 30-minute average dispatched volumes and the corresponding spot price (in real Q dollars). Renewable generation comprises the semi-scheduled and non-scheduled wind farms listed in Table 1. Table 3 South Australian spot price trends since Financial year SA renewable generation SA fossil-fuelled generation Total SA market generation SA spot price Financial year Summer a Financial year Summer a Financial year Summer a Financial year Volumeweighted average Volumeweighted average Volumeweighted average Volumeweighted average Volumeweighted average Volumeweighted average Timeweighted average ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) a. Summer is defined as November to March inclusive within the Australian mainland. Figures 9 and 10 show that South Australian fossil-fuelled generation has received a higher VWAP than renewable generation. This indicates that, during times of high renewable generation, spot prices are typically lower than average. For more information on these trends, refer to the South Australian Wind Study Report (SAWSR). 12 Summer VWAPs are typically higher than the financial year VWAPs due to the greater proportion of high demand days occurring during summer. This difference was reasonably pronounced until after which a relative convergence has emerged. A noticeable upward shift in VWAPs occurred in and , during carbon pricing, as discussed in Section AEMO. South Australian Wind Study Report. Available at: Functions/South-Australian-Wind-Study-Report. AEMO

18 Volume-weighted average price (real Q4 $/MWh) Volume-weighted average price (real Q4 $/MWh) SOUTH AUSTRALIAN ELECTRICITY MARKET ECONOMIC TRENDS REPORT Figure 9 Comparison of financial year volume-weighted average prices Financial year Renewables Fossil-fuelled Total market Figure 10 Comparison of summer volume-weighted average prices Summer Renewables Fossil-fuelled Total market AEMO

19 6. NATIVE ENERGY REQUIREMENTS Introduction Table 4 shows actual native energy supply and consumption for South Australia since and forecast to under three different growth scenarios. Historical and forecast data is based on information reported in AEMO s 2015 Electricity Statement of Opportunities (ESOO) and 2015 NEFR. The ESOO, published in August 2015, compares current and future committed generation capacity against forecast operational consumption and maximum demand to identify potential supply shortfalls. 13 It does not consider market prices, profitability, or other costs and incentives, such as schemes supporting renewable energy generation, that affect commercial decisions to invest in or withdraw generation or transmission capacity. Consequently, proposed generation or transmission projects not yet committed at the time of ESOO publication were not incorporated in this assessment. It is expected that an efficient market would respond and adapt appropriately to market signals, so, the future outlook may differ from what is reported here. The NEFR forecasts operational consumption and demand, and small non-scheduled generation, based on historical levels, interviews with key stakeholders, and econometric modelling. 14 The energy supply and consumption presented in Table 4 does not include rooftop PV generation. Historical output The Historical output section of Table 4 presents actual generation and interconnector flows for South Australia. Data in the SA consumption section is sourced from the 2015 NEFR except for NEFR consumption is derived using high resolution average Supervisory Control and Data Acquisition (SCADA) data. The exception is Small non-scheduled generation data which is revenue metered data sourced from the Market Settlements and Transfer Solutions (MSATS) system. 16 Data in the SA generation and NEM balancing columns is derived using 5-minute SCADA readings of generation (excluding small non-scheduled generation) and interconnector flows. This data differs from the generation and interconnector flow data reported elsewhere in this report, which uses cleared dispatch and trading values. This approach is taken because the 5-minute SCADA readings are more closely aligned with the high resolution SCADA data reported in the NEFR, and hence produces a closer alignment between the generation and consumption sections of Table 4. Data in the Other renewables and Other non-scheduled columns is derived from selected small nonscheduled generating systems. This includes Angaston, Port Stanvac 1 and Port Stanvac 2 power stations, plus a contribution from small embedded generators less than 30 MW, as reported in the 2015 NEFR AEMO Electricity Statement of Opportunities (ESOO). Available at: Opportunities. Viewed: 26 August AEMO National Electricity Forecasting Report (NEFR). Available: Electricity-Forecasting-Report. Viewed: 26 August Data for this most recent year is able to incorporate the full financial year s generation, instead of 9 months of actuals and 3 months estimates, which the NEFR reported due to it being published in June Refer to Table C.3.2 of the 2015 NEFR s Forecasting Methodology Information Paper. Available at: Viewed: 25 September Refer to Notes 15 and 16. AEMO

20 Key observations from the Historical output section are: Generation from wind farms and interconnector imports from Victoria have generally increased. Total renewable generation for was 4,279 GWh, 3.1% higher than in Generation from scheduled generating systems has generally decreased. Native consumption (as generated) has been decreasing since Some anomalies noted include: The sudden increase in Other renewables values from This is due to changes in AEMO s methodology rather than a ramp-up in generation output. 18 Comparatively larger NEM balancing residuals in and This is due to lower quality SCADA readings from non-scheduled wind farms captured at that time. Forecast requirements The forecast sections of Table 4 show AEMO s forecast electricity consumption for South Australia, and the generation and interconnector flows required to balance that consumption. The forecast values for consumption are derived from the 2015 NEFR and the forecast generation from the 2015 ESOO. Both NEFR and ESOO modelling is defined by three economic growth and energy consumption scenarios. Further information on the low, medium, and high operational consumption scenarios is available on the AEMO website. 19 Small non-scheduled generation, Other renewables and Other non-scheduled values are augmented with the NEFR and ESOO modelling results. Appendix B explains how small non-scheduled generation forecasts were calculated. Key observations from the three forecast scenarios are: The Wind values are relatively stable across the entire period, with no new wind farm projects committed at the time of the ESOO modelling. 20 Minor variations in forecast output are attributed to modelling artefacts. The Scheduled values show a decline from early in the forecast period. This is attributed to the modelled withdrawal of Northern Power Station by December and Torrens Island A from April Alinta Energy s announcement 22 that Northern Power Station will close on 31 March 2016 was too late for inclusion in ESOO modelling. The Native consumption (as generated) values are fairly flat for the medium scenario and are increasing for the high scenario, from the middle of the forecast period. The Imports VIC-SA values for the medium and high scenarios decrease from the middle of the forecast period, with Scheduled values increasing proportionally in response. The decrease in interconnector imports is attributed to forecast tightening supply conditions in Victoria. The large balancing residuals shown for the three forecast sections are attributed to: Differences in the way that the ESOO and NEFR models estimate system auxiliary energy use. The ESOO s inclusion of forecast consumption by electric vehicles in its demand targets, which were not incorporated in the NEFR forecasts. Discrepancies between demand traces used for market modelling in the ESOO, compared to those obtained from the NEFR forecasts. For example, periods of negative demand forecast in the NEFR were treated as zero demand periods in the supply-demand market modelling for the ESOO. 18 The sudden rise in generation is due to a combination of an increased number of generating systems being sampled for all years, plus a change in the sampling methodology which did not have reliable data prior to AEMO Scenario Descriptions. Available at: Viewed 26 August The first MW of the Hornsdale wind farm progressed to committed status on 21 August 2015 and is expected to be operating by November This announcement was too late for inclusion in AEMO's ESOO modelling. 21 AEMO s ESOO modelling tested the effect of withdrawal on the summer maximum demand. 22 Alinta Energy. Flinders Operations Update 7/10/2015. Available at: Viewed: 7 October AEMO

21 Table 4 Annual electrical energy requirement breakdown (GWh) 23 Historical output Wind (SS, NS) Other renewables (NS) SA generation NEM balancing SA consumption Other nonscheduled (NS) Scheduled (S) Total generation Imports Vic-SA Balancing residual Exports SA-Vic Native consumption (as generated) Auxiliary energy use Native Consumption (sent out) Transmission network losses Operational customer sales ,478 13,367 1, , , , , ,978 14, , , , , ,274 14, , , , , ,401 13,796 1, , , , , ,912 13,956 1, , , , , ,391 12,959 1, , , , , ,028 12,533 1, , , , , ,662 11,818 1, , , , , ,245 11,528 2, , , , Low scenario forecast , ,298 9,999 3, , , , , ,658 9,317 4, , , , , ,379 8,007 4, , , , , ,328 7,080 5, , , , , ,132 6,947 5, , , , , ,982 6,805 4, , , , , ,978 6,756 4, , , , , ,922 6,658 4, , , , , ,883 6,549 4, , , , , ,906 6,544 4, , , , Small nonscheduled generation 23 The following should be noted when interpreting this table: Wind generation includes generation that occurred during commissioning of the site (such as Snowtown Stage 2 during ). The Heywood Interconnector upgrade is assumed to be effective from July Only committed new generation supply is assumed. This is consistent with the ESOO, which only reports on existing and committed generation capacity, and announced withdrawals. SS stands for Semi-scheduled, NS for Non-scheduled and S for Scheduled Native consumption (as generated) is the sum of the generation supplied by wind, other renewables, other non-scheduled, and scheduled generating systems, plus net interconnector imports. Native consumption (sent out) is Native consumption (as generated) less Auxiliary energy use (shown as a negative quantity). Operational customer sales is Native consumption (sent out) less Transmission network losses (which has been shown as a negative quantity). It includes distribution network losses, but excludes small non-scheduled generation. Small non-scheduled generation is the aggregate of the generating systems listed in Table C.3.2 of the 2015 NEFR s Forecasting Methodology Information Paper. Available at: Viewed: 25 September AEMO

22 Wind (SS, NS) Medium scenario forecast Other renewables (NS) SA generation NEM balancing SA consumption Other nonscheduled (NS) Scheduled (S) Total generation Imports Vic-SA Balancing residual Exports SA-Vic Native consumption (as generated) Auxiliary energy use Native Consumption (sent out) Transmission network losses Operational customer sales , ,499 10,317 3, , , , , ,992 9,806 4, , , , , ,952 8,742 4, , , , , ,003 7,798 5, , , , , ,936 7,804 5, , , , , ,934 7,803 5, , , , , ,066 7,944 4, , , , , ,093 8,955 3, , , , , ,348 9,180 3, , , , , ,740 9,567 3, , , , High scenario forecast , ,603 10,477 3, , , , , ,247 10,108 4, , , , , ,589 9,431 4, , , , , ,947 8,802 5, , , , , ,146 9,070 5, , , , , ,487 9,423 4, , , , , ,848 10,761 3, , , , , ,174 12,078 2, , , , , ,589 12,482 2, , , , Small nonscheduled generation , ,064 12,960 2, , , , AEMO

23 MEASURES AND ABBREVIATIONS Units of measure Abbreviation GWh MW MWh Unit of measure Gigawatt hour Megawatt Megawatt hour Abbreviations Abbreviation AEMO AER ESOO NEFR NEM PV SACOSS SAHMIR SCADA VWAP Expanded name Australian Energy Market Operator Australian Energy Regulator Electricity Statement of Opportunities National Electricity Forecasting Report National Electricity Market Photovoltaic South Australian Council of Social Service South Australian Historical Market Information Report Supervisory Control and Data Acquisition Volume-Weighted Average Price AEMO

24 GLOSSARY Term as-generated cooling load heating load interconnector interconnector flow generating system generating unit generation nameplate capacity native consumption non-scheduled generating unit operational consumption SCADA scheduled generating unit semi-scheduled generating unit sent-out spot price summer winter Definition A measure of demand or energy (in megawatts (MW) and megawatt hours (MWh), respectively) at the terminals of a generating system. This includes consumer load, transmission and distribution losses, and generating system auxiliary loads. The amount of heat energy that would need to be removed from a space (cooling) to maintain the temperature in an acceptable range. Cooling loads typically occur during high temperatures which are more prevalent during summer. The amount of heat energy that would need to be added to a space to maintain the temperature in an acceptable range. Heating loads typically occur during lower temperatures and are more prevalent during winter. A transmission line or group of transmission lines that connects the transmission networks in adjacent regions. The quantity of electricity in MW being transmitted by an interconnector. A system comprising one or more generating units, which includes auxiliary or reactive plant, and is located on the generator s side of the connection point. The actual generator of electricity and all the related equipment essential to its functioning as a single entity. The production of electrical power by converting another form of energy in a generating unit. The maximum continuous output or consumption in MW of an item of equipment as specified by the manufacturer, or as subsequently modified. This includes all residential, commercial, and large industrial consumption, and transmission losses (as supplied by scheduled, semi-scheduled, significant nonscheduled, and small non-scheduled generating units). Native consumption equals operational consumption plus generation from small non-scheduled generating units. A generating unit so classified in accordance with Chapter 2 of the National Electricity Rules (NER). Significant non-scheduled generation is: wind and solar generators greater than 30 MW, generators treated as scheduled generators in dispatch, generators that are required to model network constraints, and generators previously classified as scheduled. Includes all residential, commercial, and large industrial consumption, and transmission losses (as supplied by scheduled, semi-scheduled and significant non-scheduled generating units). Supervisory Control and Data Acquisition. A system that gathers real-time data from remote terminal units and other communication sources in the field and enables operators to control field devices from their consoles. A generating unit that has its output controlled through the central dispatch process and that is classified as a scheduled generating unit in accordance with Chapter 2 of the National Electricity Rules (NER). A generating unit that has a total capacity of at least 30 MW, intermittent output, and may have its output limited to prevent violation of network constraint equations. A measure of demand or energy (in megawatts (MW) or megawatt hours (MWh), respectively) at the connection point between the generating system and the network. This measure includes consumer demand and transmission and distribution losses. The price in a trading interval for one megawatt hour (MWh) of electricity at a regional reference node. Prices are calculated for each dispatch interval (five minutes) over the length of a trading interval (a 30-minute period). The six dispatch prices are averaged each half hour to determine the price for the trading interval. Unless otherwise specified, refers to the period 1 November 31 March (for all regions except Tasmania), and 1 December 28 February (for Tasmania only). Unless otherwise specified, refers to the period 1 June 31 August (for all regions). AEMO

25 Adelaide City Temperature ( C) Adelaide City Temperature ( C) SOUTH AUSTRALIAN ELECTRICITY MARKET ECONOMIC TRENDS REPORT APPENDIX A. TEMPERATURE DURATION CURVES Figure 11 Adelaide city temperature duration curve (summer generation period) % 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Cumulative percentage of Summer Season Summer Summer Summer Figure 12 Adelaide city temperature duration curve (winter generation period) % 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Cumulative percentage of Winter Season Winter 2013 Winter 2014 Winter 2015 AEMO

26 APPENDIX B. SMALL NON-SCHEDULED GENERATION FORECAST METHODOLOGY Forecasts for South Australia s small non-scheduled generation (SNSG) were sourced from the 2015 NEFR and included existing SNSG generating systems, as well as potential future SNSG projects. Forecasts for existing operational SNSG systems were based on characteristics such as generation capacity and historical data. Forecasts for future SNSG projects (committed, advanced, and prospective) 24 were developed based on characteristics of similar, existing SNSGs, such as location and generator class (fuel source). Forecast output was estimated using a weighted average of the historical capacity factors for each project, based on the past five years of data. SNSG forecasts were developed for three SNSG uptake scenarios that corresponded to the 2015 NEFR high, medium, and low scenarios, as described by Table 5. Table 5 Small non-scheduled generation forecasting categories 2015 NEFR Scenario Related SNSG scenario Categories included High High uptake Operational generating systems, plus committed, advanced and prospective projects Medium Moderate uptake Operational generating systems, plus committed, and advanced projects Low Slow uptake Operational generating systems, plus committed projects Further, the differences between scenario forecasts can be attributed to: The approach to calculating capacity factors: capacity factors in the low scenario were calculated using the lowest three historical capacity factors over the past five years, and capacity factors in the high scenario were calculated using the highest three. Situations where there were less than five years of historical data. In some instances, there were only three years of data so the highest annual output would set the high scenario, the lowest output would set the low scenario and the medium would be an average across the three years. The relatively small number of SNSG systems in South Australia (compared to other NEM regions). As there are only 11 small non-scheduled generators in South Australia, differences between the scenario assumptions are made more visible. 24 AEMO Generator Information for SA, 2014, December 10. Available at: Information/~/media/Files/Other/planning/esoo/2014/Generation_Information_SA_2014_Dec_10.ashx. Viewed: 28 September AEMO