1. EXECUTIVE SUMMARY ABOUT THIS REPORT... 6 Document purpose... 6 Legislative compliance... 6

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2 CONTENTS 1. EXECUTIVE SUMMARY ABOUT THIS REPORT... 6 Document purpose... 6 Legislative compliance DEMAND MANAGEMENT... 8 Demand for network capacity... 9 Demand challenges across our network Our valued customers Key residential energy appliances Network tariff and rebate optimisation DEMAND MANAGEMENT PRINCIPLES AND STRATEGY Long-term principles Long-term strategy Demand reduction potential and Demand Management strategic planning Data services and network modelling Industry and market engagement DEMAND MANAGEMENT PROGRAM FORECASTS Demand management forecast 2013/ Long term demand management forecasts Demand reduction targets THE WAY FORWARD Demand Reduction Potential Review and Demand Management strategic plan APPENDIX DEMAND MANAGEMENT PROJECT SUMMARIES Summary of 2013/14 performance targets Ergon Energy Demand Management Plan 2013/2014 1

3 FIGURES AND TABLES Figure 1: Demand management delivery progress as at 30 May Figure 2: Forecast demand reduction outcomes 1 July 2013 to 30 June Figure 3: Ergon Energy load duration curve Figure 4: Ergon Energy System-wide Maximum Demand forecast 2012/ Figure 5: Ergon Energy load duration curve 2011 Mondays Figure 6: Ergon Energy system wide energy forecast 2012 to 2025 (MMRF Model) Figure 7: Network load profiles by region (2010/11) Figure 8: Estimated customer segment contribution 2025 summer mid-afternoon peak Figure 9: Demand planning regions Figure 10: Residential consumption by segments (Ergon Energy Queensland 2011/12) Figure 11: Commercial and Industrial consumption by segments 2011/ Figure 12: North Queensland average household consumption and demand profile Figure 13: PV connections to date (actual and estimated) Figure 14: Long-term demand management principles Figure 15: Long-term demand management strategy Figure 16: Ergon Energy average demand management delivery costs Figure 17: Ergon Energy s non-network implementation process Figure 18: Ergon Energy demand reduction targets July 2013 to June Table 1: Demand management program budget 1 July 2013 to 30 June Table 2: Demand Management Plan legislative requirements... 7 Table 3: Air conditioning penetration forecast Table 4: Domestic Load Control tariff penetration by region Table 5: Demand side engagement progress summary (at March 2013) Table 6: Demand Management Plan budget 2013/ Table 7: Demand Management budget 1 July 2013 to 30 June Table 8: Summary of 2013/14 performance targets Ergon Energy Demand Management Plan 2013/2014 2

4 GLOSSARY AER Broad-based demand management BSP C&I DMIA DNSP DRPR FIT MMRF model Australian Energy Regulator Initiatives that aim to reduce demand across the network, rather than at specific points on the network. Bulk Supply Point; a point in the electricity supply network where supply is provided to the sub-transmission network. Commercial and Industrial customers Demand Management Innovation Allowance Distribution Network Service Provider Demand Reduction Potential Review Feed-in-tariff, as part of the Solar Bonus Scheme The Monash Multi-Regional Forecasting model is a multi-regional, dynamic computable general equilibrium model of Australia s six state and two territory economies. N-1 A system which has the capability to withstand a credible single contingency involving an outage of the largest and most critical system element (transformer, feeder, etc.) without an interruption to supply of greater than one minute. NEM National Electricity Market POE Probability of Exceedence. 10POE; peak load forecast which has a 10% probability of being exceeded in any year (i.e. A forecast likely to be exceeded only once every 10 years), based on normal expected growth rates and temperature corrected starting loads. 50POE; Forecast Peak load forecast which has a 50% probability of being exceeded in any year (i.e. an upper range forecast likely to be exceeded only once every two years). Targeted/network constraint demand management ZS Initiatives that aim to address specific network constraints by reducing demand on the network at the location and time of the constraint. Zone Substation; a site incorporating equipment that provides control and voltage transformation from the sub-transmission or transmission network to the distribution network. Ergon Energy Demand Management Plan 2013/2014 3

5 1. EXECUTIVE SUMMARY Ergon Energy is pleased to present its Demand Management Plan 2013/14 for Queensland Energy Regulator approval in compliance with Clause 127(1) of the Electricity Amendment Regulation (No. 1) The plan describes the existing and proposed demand management programs, their estimated total cost and how those programs contribute to Ergon Energy s commitment to minimising electricity cost increases through reducing the need for network augmentation. For 2013/14, Ergon Energy estimates a Demand Management Plan 2013/14 budget total of approximately $15 million with the annual demand reduction target of 24MVA. The 2013/14 Demand Management Plan outlays the continuance of the existing programs while also enhancing the program portfolio through the addition of new measures and refinement of existing initiatives for improved cost effectiveness. The review of existing programs include all Non-Network Alternative (NNA) funded programs such as Energy Sense Communities, Residential Brownfield, Residential Pool Pump, Direct Load Control, Network Constraints projects, and Smart Network and Pricing Signals. Additionally, Ergon Energy will continue to report on programs such as Townsville Network Demand Management, Your Power Qld, powersavvy, and Demand Management Innovation Allowance projects. A summary of the budgeted resources across these programs for 2013/14 appear in Table 1: Table 1: Demand management program budget 1 July 2013 to 30 June 2014 DM Portfolio Network Constraint & Targeted Program Broad-based & Residential Program Smart Network Program Energy Conservation & Isolated Communities Demand Management Innovation Allowance Energy Sense Communities Program Management Program Management Total 2013/14 Operational Expenditure ($'000) 2013/14 Capital Expenditure (S'000) 6,794-2,104-2,720-1,292-1, ,418 - Total (S'000) 6,794 2,104 2,720 1,292 1, ,418 Ergon Energy Demand Management Plan 2013/2014 4

6 In 2010/11 Ergon Energy set a demand reduction target of 122MVA for the current regulatory period (2010 to 2015). As of May 2013, 88% (107MVA) of the regulatory period target has been achieved. Achieving the demand reduction target for 2013/14 will enable Ergon Energy to deliver on the full regulatory period target. Delivered to date: 107 MVA 20 MVA 41 MVA 46 MVA Target by : 72 MVA Reg Control Period Target 122 MVA / 103 MW MVA 29 MVA 25 MVA 24 MVA 26 MVA 22 MVA 33 MVA 28 MVA Figure 1: Demand management delivery progress as at 30 May 2013 Ergon Energy s proposed Demand Management portfolio of new and revised programs is projected to meet the 2013/14 target of 24MVA through the following program categories. Network Constraint & Targeted Program MVA Target - 24 MVA Broad-based, Residential & Smart Network Programs 13 MVA 11 MVA Figure 2: Forecast demand reduction outcomes 1 July 2013 to 30 June 2014 Ergon Energy Demand Management Plan 2013/2014 5

7 2. ABOUT THIS REPORT DOCUMENT PURPOSE This document aims to provide our stakeholders with a detailed insight into our demand management planning and operations. Its purpose is three fold: To lead, demand management activities by the Ergon Energy network business through setting strategies, targets, budgeted programs and specific initiatives To inform, Ergon Energy s regulatory submissions, with the next pricing proposal covering the fiveyear period from July 2015 To comply, with Clause 127(1) of the Electricity Amendment Regulation (No. 1) 2009 (Regulation), which requires that Ergon Energy prepare a demand management plan for each financial year. LEGISLATIVE COMPLIANCE This Demand Management Plan satisfies the various requirements of the regulation, as set out in the table over. Ergon Energy s approach to expenditure forecast can be explained across three dimensions: The governance and decision making processes that influence short-term and long-term forecasts The process for consolidating lower level forecasts and establishing a five-year capital and operating expenditure forecast for the next regulatory control period consistent with Rule requirements Various estimation processes and methodologies employed for developing forecasts at the category level. Ergon Energy Demand Management Plan 2013/2014 6

8 Table 2: Demand Management Plan legislative requirements 127C(1) 127C(2)(a) 127C(2)(a)(i) 127C(2)(a)(ii) 127C(2)(a)(iii) 127C(2)(b) 127C(2)(b)(i) 127C(2)(b)(ii) 127C(2)(b)(iii) 127C(4) Ergon Energy must, for each financial year, prepare a demand management plan. Ergon Energy must include its long-term strategy for demand management (the strategy) in the plan. The strategy must include the principles intended to guide the achievement of the strategy. The strategy must include a description of existing and planned programs for demand management for the next five financial years. The strategy must include any identified opportunities to achieve the strategy. Ergon Energy must include the proposed initiatives to be carried out under the strategy in 2013/14 in the plan. Each proposed initiative for 2013/14 must include a description of that initiative. Each proposed initiative for 2013/14 must include a forecast of the capital and operating costs that Ergon Energy reasonably considers will be the likely costs for the year. Each proposed initiative for 2013/14 must include Ergon Energy s performance targets for the initiative. Ergon Energy must on or before 30 April 2013 give the regulator a copy of the Demand Management Plan. This document satisfies this requirement. Section 5.2 Section 5.1 Sections 6 & Appendix Sections 6, 7 & Appendix Section 6.1 Appendix Section 6.1 Appendix This report Ergon Energy Demand Management Plan 2013/2014 7

9 MW 3. DEMAND MANAGEMENT Ergon Energy has Australia s largest single distribution network with an area covering 97% of Queensland including 33 isolated systems and servicing over 710,000 customers. Our investments in the distribution network are designed to achieve full compliance with the security of supply standards. This is reflected in our capital expenditure program with significant portion allocated to distribution-initiated capital works to ensure that system maximum (or peak) demand can be met at all times. However, the capacity required to meet maximum demand is used only for brief periods during the year, reducing overall asset utilisation. This can be observed through steepening load duration curves % 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Time Figure 3: Ergon Energy load duration curve 2011 An alternative to network augmentation is to address demand at a lower cost than network augmentation, i.e. measures undertaken to meet and modify customer demand and behaviour by shifting or reducing demand through non-network alternatives. The main objective is to shape the load curve for optimal use of available assets and resources and improve the overall efficiency of Ergon Energy s asset investments. Ergon Energy Demand Management Plan 2013/2014 8

10 MW DEMAND FOR NETWORK CAPACITY Over the last decade, Ergon Energy has seen a significant growth in its system-wide coincident maximum demand and declining trend in annual load factor (ratio of the average demand to maximum demand). Maximum demand is a volatile parameter and difficult to predict accurately. Analysis of actual maximum demand highlights that over the last three years there has been a relative softening in maximum demand mainly due to milder summers. However, the December 2012 maximum demand of 2,380MW was the highest for the December reading for the last three years. Usually as a result of the warm weather, January and February show cycles that often results in February having the seasonal maximum demand. For the summer season of 2012/13, these demand cycles were interrupted with the wet and cooler weather experienced from cyclone Oswald hitting in the later part of January this year. Taking into account the temperature variations, the revised economic growth, and the take-up rate of air conditioning, Ergon Energy has revised downwards its system-wide maximum demand from previous forecast estimates. However, the revised forecasts still represent a growth projection average of 2.9% with continuing pressure on network capital investments. Unaddressed, this will continue to impact Ergon Energy s asset utilisation with reduced capital productivity Average Actual Actual Revised Ave Max 10 POE+Uplift 50 POE+Uplift 10 POE+Uplift Figure 4: Ergon Energy System-wide Maximum Demand forecast1 2012/13 1 The forecast is developed from applying a multivariate analysis using Gross State Product (GSP), maximum and minimum temperatures together with air conditioning load as drivers. Temperature correction is carried out over a 50 year time span to produce annualised 50 POE values. The actuals are for current customers and the projections are semi-organic (little to no DM, but planned projects are included in the GSP contribution through tax receipts). The average maximum demand (average actual) is the average of all maximum demand values and has been taken with new updated GSP values. The 10 POE and 50 POE maximum demand (upper curves in the graph) are the previous GSP figures which indicated stronger growth in outer years. 50 POE average maximum demand is indicated as "Revised" on the chart. Ergon Energy Demand Management Plan 2013/2014 9

11 0 Nov Dec 2 Oct 4 6 Aug Sep Apr Apr May Jun Jul Jan Feb Mar MWh Factors such as season, temperature, and time of day have strong influences on maximum demand. In Ergon Energy s case the vast geographical spread of its service area means large variability in maximum demand is observed across the network. In the discussion of maximum demand this is a critical point of difference between Ergon Energy and other electricity distributors. To accommodate this, the network load profiles are segmented into four peak periods: Summer afternoon peak: 1 5pm Summer evening peak: 5 9pm Winter morning peak: am Winter evening peak: 5 8pm These can be observed in the following three-dimensional model of the Monday extractions of half hourly load curves in MWh. It demonstrates the wide variation in load curves across the year. The winter days (centre) show a definite well from midday to late afternoon and conversely for the summer days (as shown in orange as peaking) exhibit a definite convex curve during this period hr timeframe (half hour intervals) Figure 5: Ergon Energy load duration curve 2011 Mondays Ergon Energy Demand Management Plan 2013/

12 DEMAND CHALLENGES ACROSS OUR NETWORK When looking at rising maximum demand trends, the primary concern is the disproportionate rate of growth compared to customer numbers and overall energy consumption. It is also worth noting that because system wide demand is the total aggregate of the individual substations, it is possible to have a decline in system-wide maximum demand whilst having increased pressure on network investments due to local constraint areas. In our recently completed study of Ergon Energy Demand Reduction Potential Review (DRPR), energy loads were forecast at regional level by CSIRO using the MMRF model 2. The modelling has provided customer segmentations of system wide energy consumption with forecasts for Electric Vehicle (EV) and photovoltaic (PV) impacts. It indicates a slow increase in residential and commercial energy consumption, and a rapid increase in industrial consumption energy consumption that tapers off after 2020 due to reduced industrial energy intensity 3. Figure 6: Ergon Energy system wide energy forecast 2012 to 2025 (MMRF Model) In addition to the MMRF model energy demand forecast, for each region the mix of customer segments was analysed to develop sectoral load profiles into contributions to peak demand through aggregation at regional level of the zone substation level forecasts. The variability across regions can be seen in Figure 7. 2 Produced by Institute for Sustainable Futures & CSIRO for Ergon Energy using the Monash Multi Regional Forecasting Model (MMRF) 3 The energy intensity of industrial sub-sectors is assumed to decline in line with historical rates of improvement consistent with broad technological change and competitiveness pressures for export oriented industries. Ergon Energy Demand Management Plan 2013/

13 Residential Commercial and Industrial Note that when the residential and Commercial & Industrial profiles are combined, the overall maximum period for the region and the sectoral variation is not visible with most regions peaking around 3-4pm. Combined Residential and Commercial & Industrial Figure 7: Network load profiles by region (2010/11) Ergon Energy Demand Management Plan 2013/

14 Peak Contribution (MW at Zone Substation level) The sectoral load profiles are then translated into contributions to 2025 summer afternoon peak demand (Figure 8). This demonstrates a high level of variability with respect to the sectoral contributions to peak demand across the Ergon Energy service area, according to the nature of economic activity in each region Far North - East North - Mt Isa North - East Mackay Fitzroy South Fitzroy North Wide Bay- Burnett Darling Downs West Residential Commercial Industrial Figure 8: Estimated customer segment contribution 2025 summer mid-afternoon peak With such wide-ranging characteristics across the distribution network, Ergon Energy is adopting a regional based planning approach for the demand management program. The methodology involves assessment of demand management potential at each zone substation and bulk supply point level, which are then aggregated to establish the demand management program for the region. Ergon Energy has defined nine demand management planning regions, which are: Far North-East, North-Mt Isa, North- East, Mackay, Fitzroy South, Fitzroy North, Wide Bay-Burnett, Darling Downs and West. The regions have been developed to capture the benefits of alignment with climatic, socio-economic, growth, pricing factors and reconciliation with the existing six network planning regions. Figure 9: Demand planning regions Ergon Energy Demand Management Plan 2013/

15 OUR VALUED CUSTOMERS One of Ergon Energy's strategic priorities is to increase the customer value by providing a more cost efficient and dependable electricity service that meet identified customer needs and expectations. Targeted demand management initiatives and broad-based programs can contribute towards this purpose through deferral of network investments and improved asset utilisation. Variations in peak demand across regions often match variations in the customer mix between the regions. Our ability to understand and manage demand depends on our understanding of customers in each region. Ergon Energy supports profiling its retail residential customer base by utilising an external residential customer segmentation model 4. The model adds an extra profiling dimension to existing customer data using many different demographic or behavioural measures, including by electricity consumption, life-stage, household income, bill payment method and payment risk profile. Figure 10 illustrates the energy consumption by life-stages. Share of customers % 30% kwh pa 9,000 8,500 25% 8,000 20% 7,500 7,000 15% 6,500 6,000 10% 5,500 5% 5,000 4,500 0% Beginnings In Transit Mid Lifers Modest Means Boomers Retirees Customers kwh Average Residential kwh 4,000 Figure 10: Residential consumption by segments (Ergon Energy Queensland 2011/12) To reduce rising bill impacts, many residents have already undertaken various behavioural energy efficient steps (e.g. clothesline, ensuring dishwasher/washing machine is full, setting the air conditioner to the appropriate temperature, installing water efficient shower heads and ceiling insulation). While these energy use changes can be beneficial for customers, they are less predictable for network planners and managers. More predictable and permanent energy use changes are usually harder and face the following common barriers: Lack of information/knowledge customers say they are not aware of all the ways they can save energy and particularly be more demand conscious. Lack of time to look for other options customers feels they do not have the time to search for this information or don t know where to start. Already feel they are doing all that they can many customers feel they have already made changes but haven t seen an impact on their bill and/or they don t know what else they could do. 4 Ergon Energy has accessed and integrated the Acxiom Personics Residential Customer Segmentation Model. Ergon Energy Demand Management Plan 2013/

16 Customers Annual Consumption GWh pa Upfront costs outweigh the long term savings customers believe the cost of things like buying new more energy efficient appliances or solar initiatives are too expensive and not worth the incremental savings. Across Commercial and Industrial customers, electricity affordability is a concern relative to other business costs. There are sound opportunities to reduce peak period energy use and reduce energy bills for these customers. Once again achieving energy use changes can be challenging for the following reasons: Commercial and Industrial customers are generally less aware of these opportunities when electricity is a low share of total costs They are unfamiliar with energy conservation and demand management options They have limited funding and financing availability across competing business needs. Segmentation of Ergon Energy s business consumers (distribution and retail) shows that the Agriculture, Government and Retail sectors have the largest number of customers, while the Mining industry is by far the greatest consumer (Figure 11). 35% 3,500 30% 3,000 25% 2,500 20% 2,000 15% 1,500 10% 1,000 5% 500 0% 0 Figure 11: Commercial and Industrial consumption by segments 2011/12 For our large customers, our focus is on tailored communications and engagement so that we can understand and benefit this key customer group. For example, engagement at an early stage in a major project s lifecycle provides the opportunity to influence the design and manage the demand requirement for new connections. Likewise with contributions to energy upgrades on existing connections or entering network support agreements for generation and curtailable loads New customer connections Industry In provision of service to new major customers, Ergon Energy sees significant opportunities for customers to reduce their demand, their connection costs and avoid network augmentation. Through early engagement, preferably before the customers have developed their plans in detail and factoring in lead times for commissioning to allow for load expansion, we find there are opportunities to reduce their requirements. In the case of new customer connections, where there is a network benefit (i.e. deferral), Ergon Energy sees opportunity for additional incentives for customers to go above and beyond (e.g. chilled water systems, embedded generation). Ergon Energy Demand Management Plan 2013/

17 KEY RESIDENTIAL ENERGY APPLIANCES Over the last decade, Ergon Energy s distribution network has experienced a significant increase in residential peak demand. More importantly, the residential demand will generally make up a higher proportion of the load during critical peak periods. 5 The driving factors behind this are customers usage behaviour, particularly during critical peak periods and lifestyle choices, i.e. appliance ownership. In terms of appliance ownership, air-conditioners have the largest impact on peak demand, as illustrated in the North Queensland 6 average household consumption profile (Figure 12). Water Heating 1% 13% Peak (5pm - 8pm) Consumption Laundry Appliances Refrigeration Lighting 1% 1% 7% 5% 5% 9% 8% 10% Pool 5% 6% Electronics & Entertainment 11% 15% Cooking Cooling 7% 12% 30% 57% Figure 12: North Queensland average household consumption and demand profile 7 Findings from the recently conducted Queensland Household Energy Survey (QHES) 2012 indicate that Northern Queensland households also have the highest level of air conditioning penetration (91%) across Ergon Energy s service area. Moreover, 28% of these customers are predicted to purchase an additional or replacement unit within the next five years. The regional diversity is also characterised in the QHES modelling which shows the air conditioner penetration in Southern Queensland is currently the lowest. However, it is predicted to have the greatest penetration growth, increasing from 65% to 74% by 2018 (Table 3). 5 Productivity Commission 2012, Electricity Network Regulatory Frameworks, Draft Report, Canberra. 6 North Queensland here represents Northern, Central and Regional Queensland. 7 Climate Works Australia 2012, Ergon Energy DSM cost curve project, Final Report Ergon Energy Demand Management Plan 2013/

18 Table 3: Air conditioning penetration forecast Residential air conditioning Historically, the main drivers of peak demand for a Queensland residential customer falls across three main appliances hot water systems, air conditioning and pool pumping equipment. With controlled-supply tariff solutions for hot water and pool pumping, air conditioning remains the prime household appliance peak demand contributor causing a summer maximum peak load profile. The introduction of planned Tariff 13 from 1 July 2013 presents an option to positively influence peak demand through behavioural change in the use of air conditioning appliances with minimal impact on customer comfort and energy sales. Tariff 13 has been specifically designed for connection with peaksmart air conditioning when connected with a AS demand response compliant device Residential hot water systems Hot water systems are an area with significant room for improvement in managing behaviour related to peak demand. One of the key uptake barriers in this space has been that solar hot water systems were cheaper to run (if the electric element is manually controlled) when connected to Tariff 11. This is due to the minimum usage fee associated with the economy tariff up to 30 June Removal of the minimum monthly payment amount on Tariffs 31 and 33 from 1 July 2012 means customers only pay for what they use with no minimum charge. Ergon Energy s Hot Water System Incentive was designed to leverage this opportunity by offering eligible residential customers to apply for a $100 one off rebate when connecting replacement or existing hot water systems to Tariff 31 or 33. The incentive was promoted via an engagement program with manufacturers, suppliers, electricians and plumbers and supported by an integrated marketing communication program for customers Residential pool pump Ergon Energy s Pool Pump program is an example of successful behaviour change within the residential sector. The program offered incentives which were designed to encourage pool owners to either connect their pool pump to Tariff 33 or purchase a five-star energy efficient pool pump. The initial program was scheduled to run for five years and planned to achieve accumulated 6.63MVA peak demand reductions. Customer response in the first two years was far greater than originally forecasted. The huge success of this program to date has meant demand reduction outcomes have been brought forward, allowing for the 8 Colmar Brunton 2012, Queensland Household Energy Survey 2012, for Energex, Ergon Energy and Powerlink. Ergon Energy Demand Management Plan 2013/

19 shortening of the planned program for future years. As of May 2013, 7339 customers have subscribed to Tariff 33 and 3598 purchased energy efficient pumps Solar Photovoltaic Solar PV is an appliance that has increased customer choice in electricity supply for those customers that can afford to invest in such systems. Solar PV has been adopted enthusiastically by customers across the network, installed on the rooftops of 17% of detached houses and 13% of all residential customers (as at March 2013). Around 80,000 customers will ultimately take advantage of the 44 cents/kwh net Feed in Tariff (FIT) offered by the Queensland Government, which closed to new applicants on 10 July This group of customers are less likely to shift their load outside typical peak demand periods, being encouraged by the fit to maximise export during the day and shift energy consumption as much as possible and as a consequence usually into evening peak demand periods. This is a negative outcome for demand management and network costs. This negative impact will reduce if the gap between fit and Tariff 11 reduces. Current PV connection application levels are at around 1,400 per month for the current 8 cents/kwh FIT (Figure 13). With the predicted continued rise in power prices and substantial lowering of the cost of solar PV systems, it is expected that the number of PV installations will continue to grow at current rates. The 8 cents/kwh fit is incentivising more customers to shift discretionary electricity consumption to daylight hours to maximise the value of using their own generation as opposed to using power on Tariff 11 (at 25 cents/kwh, 2012/13 rate) in the evening. There is also an increasing number of system/customers losing access to the 44c FIT, or customers who have never been eligible for a fit, who are similarly incentivised to shift load into the daylight hours PV Connections Actual Forecast Figure 13: PV connections to date (actual and estimated) High penetration of solar PV generation that fluctuates over the day with sunlight variability can result in significant power flow swings, increasing the potential for network instability and outages. This is currently driving new network augmentation investments. However, customers generating and consuming their own energy can reduce the need for distribution capacity when this aligns with daylight hours. This effect will expand beyond daylight hours with the future adoption of customer and network energy storage options. Ergon Energy Demand Management Plan 2013/

20 To manage this impact Ergon Energy is undertaking the following activities: 1. Investigating the impact of PV generation on feeder and substation profiles. 2. Developing advanced planning tools that integrate distributed energy resources and renewables into network planning, forecasting and optimisation (Australian Research Council Linkage Project, and National and International Research Alliances Program models). 3. Raising awareness of the potential economic value daylight saving could currently provide by aligning PV generation with evening peaks and extending future storage discharge into evening peaks. 4. Developing a long-term Inverter Energy Systems Strategy and participating in Inverter Energy System Standards to set suitable business and industry directions. 5. Consideration of changing customer energy preferences in tariff reform activities that enable better customer choice and independence Electricity storage For Ergon Energy, an area that is closely related to PV distributed generation is electricity storage. It is likely that with the developments of affordable storage solutions, there will be increasingly energy storage offerings for the residential and commercial sectors. While the residential uptake of electricity storage is currently extremely low, the combination of reduced 8 cents/kwh net FIT for new connections, increasing electricity prices and time-of-use price signals can further encourage the PV customers to self-consume rather than export to the grid. From a peak demand management perspective, Ergon Energy sees this as potentially positive development as storage can effectively provide a smoothing service. Electricity storage incorporated with PV solar systems also has the potential to address voltage and current fluctuation problem in the network caused by large inflows of distributed generation to the grid. Ergon Energy s Single Wire Earth Return (SWER) network is another area that faces significant challenges in voltage regulation. SWER lines are both costly to maintain and have limited redundancies. Ergon Energy sees opportunities with network integrated storage solutions to alleviate some of the problems in the SWER network. The trial deployment of Grid Utility Storage Solution (GUSS) on the SWER network has delivered positive non network alternative results and network integration experience. GUSS options are currently breaking even in SWER locations and an operational deployment program is progressing across feasible locations Electric vehicles Electric Vehicles (EV) provide both opportunity and risk for Ergon Energy. If the introduction and connection of EVs and EV charging is managed in an appropriate way then there are significant benefits through increasing asset utilisation, increasing energy sales and adding a controllable load for network management. On the other hand, if the introduction and charging is poorly managed the risk for Ergon Energy can be substantial with impacts that include, increased peak demand, voltage issues, increased assets at risk and requirement for further investments resulting in lowering of asset utilisation. The challenge for Ergon Energy is to predict the EV uptake rate and their impact on the network over the next 10 years. There is no clear view as to the market uptake rates of EVs, although some best guesses indicate 2020 as to the likely change from early adopters to mass market (CSIRO, 2012) 9. Therefore, Ergon Energy has undertaken an EV trial to better understand the impacts this technology may have on the network in the future and to investigate strategies to manage these impacts. This initial EV trial involved five 9 CSIRO 2012, EV PV Diffusion Modelling Ergon Energy Demand Management Plan 2013/

21 Mitsubishi i-mievs (plug-in, all-electric hatchbacks) to provide a real world study of the effects of EV integration. These vehicles were used by participating customers over an eight month period. This trial has proven useful in preparing Ergon Energy for the possible widespread introduction of EVs by modelling changing patterns in consumption, daily peak demand, billing preferences and allowing Ergon Energy to forecast future network augmentation costs. NETWORK TARIFF AND REBATE OPTIMISATION Ergon Energy has traditionally incentivised demand management participation through the use of tariffs (T31, T33) and direct customer rebates (for e.g. Pool pump save a bomb program). Finding the optimal mix of tariff and rebate incentives is important to ensure efficient investment in demand management. Cost reflective network tariffs that charge higher prices in peak periods can encourage changes in customer behaviour and energy choices. Ergon Energy considers that that the reflection of network pricing signals in retail tariffs presents a significant opportunity to improve asset utilisation and encourage customer demand management. The impacts of tariff reform will vary between different customers and a transitional approach is necessary to reduce price shocks to customers. Due to the inflexibility of pricing over time and between regions, direct customer rebates provide a means of increasing customer demand management incentives. These are best used in network constrained areas with a high need for demand management. Improving network tariff signals has significant opportunity to increase customer demand management incentives and work efficiently with demand management programs for example, kva tariffs with power factor improvements and time-of-use with peak-smart appliances. Tariff 31 and Tariff 33 remain the strongest and most effective demand management tariff signal to customers with current penetrations presented below: Table 4: Domestic Load Control tariff penetration by region 10 Billing Accounts Under Load Control Capricornia Far North Mackay North South West Wide Bay & Burnett Network wide 62,075 62,162 38,721 78,292 56,787 71, ,560 Base % 94,195 66% 102,658 61% 57,953 67% 103,875 75% 93,433 61% 100,880 71% 552,944 67% 10 As at end of March 2013 Ergon Energy Demand Management Plan 2013/

22 4. DEMAND MANAGEMENT PRINCIPLES AND STRATEGY Ergon Energy will develop, fund and execute demand management as a core business function and essential means for maintaining a highly utilized network and ensuring its investments in new network capacity are optimised. Ergon Energy s demand management practices will create value for its business and customers, and position Ergon Energy as the Australia s demand management leader and innovator. These are the key considerations in developing Ergon Energy s demand management principles and long-term strategy. LONG-TERM PRINCIPLES Ergon Energy s principles that guide the development of the demand management strategy and plan are similar to those that apply to its 2030 Network Vision, which was jointly developed with Queensland distribution businesses. The guiding principles are presented below. Prudent & efficient investment planning Demand management solutions are incorporated into asset and network planning processes to improve asset utilisation. Demand Management Principles Network certainty There must be a reasonable degree of reliance on firm load reduction which can be trusted at times of peak demand to ensure that security standards are met. Access to information and education Customers and stakeholders constantly need to be provided with relevant information to make informed decisions. Incentivise uptake Customers will be incentivised to encourage and reward their participation in demand management. Benefits realisation Demand management activities need to be coordinated at the network level to ensure that benefits are visible and measurable. Governance framework A robust and comprehensive governance framework is essential for coordination of the delivery of demand management initiatives. Risk Management Demand management can help manage financial and network risk. Figure 14: Long-term demand management principles Ergon Energy Demand Management Plan 2013/

23 $/kva LONG-TERM STRATEGY Ergon Energy s long-term demand management strategy is summarised in the diagram below. Our demand strategy recognises the importance of our external partnerships with parties such as the Queensland Government, Commonwealth Government, Energex, research institutions and other parties who have similar goals relating to energy efficiency and maximum demand. CUSTOMER FOCUS Empowering our customers by helping them to recognise the importance and benefits of best practice demand management and how they can play their part. Demand Management Strategy INTEGRATION Driving Demand Management solutions into our business that best suit the circumstances of our customers in network constrained areas. INNOVATION Building on the experience, knowledge and customer support gained through customer trials and demonstration initiatives to implement broad based demand management solutions. COLLABORATION Investing in partnerships with Energex, the Queensland Government and other parties to leverage learnings and data with which to develop optimal demand management initiatives. Figure 15: Long-term demand management strategy Long term demand management efficiency The cost of capacity being delivered though demand management is currently performing competitively against network capacity options. Through finding efficiencies in delivery, the cost of demand management has also been reducing Full DM program Demand reduction projects only (incl. PM costs) Figure 16: Ergon Energy average demand management delivery costs Ergon Energy Demand Management Plan 2013/

24 Demand reduction projects are those developed to deliver a specific MVA reduction. The full demand management program includes research, trial, strategic and administration activities that do not have a specified MVA reduction target. Currently, the key costs of doing demand management include search and development costs, incentive payments and verification costs. Further opportunity for reducing the cost of doing Demand Management, exist through improving market engagement, efficiency and finding customer financing solutions. DEMAND REDUCTION POTENTIAL AND DEMAND MANAGEMENT STRATEGIC PLANNING In 2012/13, Ergon Energy completed a Demand Reduction Potential Review (DRPR) to develop estimates of electricity demand reduction potential and assess a broad range of demand management options across its distribution network. Built on two analytical work streams, the DRPR developed detailed energy and peak demand forecasts for the period out to 2025 together with an extensive assessment of a range of demand reduction and energy conservation measures. In order to assess the effectiveness of different demand reduction solutions, the DCODE model was adapted by the Institute of Sustainable Futures, University of Technology Sydney. The model enables cost comparison of the different demand management measures through generation of levelised cost curves to compare different demand reduction options. The DRPR developed estimates of technical and average achievable potential for more than 40 demand reduction measures applicable within the residential, commercial and industrial sector. The study estimated the economically achievable potential available to reduce peak demand ranges from 5% to 15% of forecast system peak demand by Based on the findings of the DRPR study, Ergon Energy commissioned DNV KEMA to produce a Demand Management Strategic Plan to guide investment in demand management activities. The Demand Management Strategic Plan details actions and initiatives designed to set up managing network demand through non-network alternatives as part of Ergon Energy s business as usual operations for the long term. The strategic plan also contains recommendations on initiatives required to underpin effective programs and policy directions that should be pursued by Ergon Energy. A summary of the recommendations is contained in section 7.1. DATA SERVICES AND NETWORK MODELLING Ergon Energy s strategy of delivering efficient investments is underpinned by technology and data management strategies. It recognises the importance of data collection, accuracy, currency, and the integration of information from a wide range of sources to better manage the network and improve asset utilisation. For Ergon Energy SCADA and metering systems have been the primary sources of dynamic data from power network assets. The primary focus of the SCADA system is the operation and control of the high voltage network which is primarily managed at the substation level. This is being expanded to include intelligent devices installed along the feeders. Additionally, as Ergon Energy moves towards an intelligent electricity grid there will be an exponential increase in the number of intelligent devices, presenting significant opportunities to collect real-time information on the state of the network and the devices themselves. The challenge for Ergon Energy is to develop the tools and processes and enhance the knowledge base to capitalise on this substantial data inflow. Ergon Energy Demand Management Plan 2013/

25 The network of the future requires planning that analyses many intersecting factors. Our investments in collaborative projects such as Australian Research Council (ARC) Linkage Project, and National and International Research Alliances Program (NIRAP) are examples of our commitment towards future network planning. The NIRAP project aims to create a comprehensive model of the electricity grid to be used as a world-first planning tool in understanding the management and coupled problems of increasing the proportion of renewable sources of power supply. From a consumer behavioural change point of view, the ARC Linkage Project investigates from a multi-disciplinary perspective the complexity and significance of factors that impact consumer energy demand. Recent investments in the Dynamic Feeder Rating project and upgrade of the Distribution Feeder Database further demonstrates Ergon Energy s objective of leveraging technology and the associated data services to maximise asset utilisation and reduces Ergon Energy s cost to serve. The Dynamic Feeder Rating monitors the environmental and network parameters (temperature of overhead cables, underground cables, local weather data, etc.) to optimise the network capacity. Ultimately our data management strategy aims towards an integrated modelling approach that considers the state of the network and the factors which potentially impact the network such as environmental, regulatory, economic, technology, customers and information beyond the meter, particularly around consumers behaviour patterns along with dynamics of behavioural change. INDUSTRY AND MARKET ENGAGEMENT Ergon Energy s current approach to demand management is underpinned by the need to demonstrate prudent and efficient investment in our network. It involves active engagement with non-network providers for delivery of efficient and cost effective non-network options as alternatives to network expenditure. Figure 17 illustrates a simplified view of the Ergon Energy s non-network process. Identify network constraint locations Propose network investment solution Apply regulatory (RIT-D) test Parties Involved Ergon Energy Ergon Energy, NNA Solution Providers Ergon Energy, AER No DM solution identified DM solution identfied Develop DM solution including seeking funding Implement DM solution Ergon Energy, NNA Solution Providers Ergon Energy, Qld Govt., Federal Govt., DMIA, NNA Solution Providers Ergon Energy, NNS Solution Providers, Customers Proceed with optimised network solution Ergon Energy Figure 17: Ergon Energy s non-network implementation process Ergon Energy Demand Management Plan 2013/

26 Given that the local demand management industry is still in the early stages, Ergon Energy believes its role is to develop and build market capability in this area in the short term. Initiatives undertaken to do this include: Setup of the preferred supplier contracting panel, PCP 97 - Panel for Specialist Services in Non-Network Alternative and Demand Management. This enables Ergon Energy to efficiently develop and procure capability from Demand Side Participants in implementing demand management solutions. Currently more than 30 firms are registered in this panel. Partnerships with research institutions and international technology providers such as the Guided Innovation Alliance with the Queensland University of Technology and other parties that has been set up to focus on key priorities for the electricity distribution sector. Development and piloting of a Trade Ally Network comprising of qualified energy service providers targeting Ergon Energy s smaller business customers for demand reduction activities at a lower cost model. This is expected to substantially increase the efficiency of non-network solutions whilst maintaining appropriate quality assurance. Proposed development of a Demand Reduction Incentive Map (DRIM), where customer demand reduction incentives reflective of the value of capital deferral and network security risk will be provided to the market. Ergon Energy s Regulatory Test consultation process generally consists of a Request for Information (RFI) stage that allows registered participants and interested parties an opportunity to provide feedback and advice on possible network and non-network solutions. During the various stages of this consultative process, there are opportunities for interested parties to provide feedback on the options. The final report takes into consideration industry feedback received and outlines a course of action to ensure a reliable and cost-efficient solution to an area s growing demand. A summary of the Final Report is placed on the AEMO website, with the full version of the Final Report available on Ergon Energy's website. The goal of these activities is to develop a robust, active and competitive NNA market, thus promoting innovation and driving down cost. Table 5 provides a progress summary of regulatory test activities to date. Ergon Energy Demand Management Plan 2013/

27 Table 5: Demand side engagement progress summary (at March 2013) Regulatory Tests Market response Market progression Market engagement Townsville 1 response Contract award Design Malanda 2 responses PCP97 Network Support Agreement Moranbah 3 responses Closed tender Design, Network Support Agreement Palm Island 6 responses Survey/feasibility - St. George 10 responses Closed tender - Charleville 11 responses Closed tender - Ergon Energy Demand Management Plan 2013/

28 5. DEMAND MANAGEMENT PROGRAM FORECASTS Ergon Energy s Demand Management Plan for 2013/14 includes a wide range of initiatives across its distribution area. A summary of the Ergon Energy s demand management portfolio for 2013/14 is set out in section 6.1, followed by five year forward program of work in section 6.2. Detailed information for each initiative is listed in the appendix section. DEMAND MANAGEMENT FORECAST 2013/14 Ergon Energy s forecast operating and capital expenditure for 2013/14 is estimated at $15 million as set out in the following table. The 2013/14 program is comprised entirely of operating expenditure 11. The largest allocation is against Network Constraint and Targeted Programs, which have the potential to directly defer or avoid planned capital investments. Table 6: Demand Management Plan budget 2013/14 12 DM Portfolio Network Constraint & Targeted Program 2013/14 Operational Expenditure ($'000) 2013/14 Capital Expenditure (S'000) Total (S'000) Townsville Network Demand Management (NDM) Pilot Project 1,222-1,222 4 Mt. Isa DM Project Cairns Northern Beaches DM Project Bohle Industrial Area DM Project Ingham DM Project Charleville DM Project St. George DM Project Kingaroy DM Project Malanda DM Project Moranbah DM Project Mackay - Energy Sense Market Program 1,011-1,011 1 Blackwater DM Project Proposed Network Constraint & Targeted Initiatives 1,345-1,345 1 Broad-based & Residential Program Hot Water Supply DRED T Hot Water System Incentive T Peaksmart Air Conditioning Direct Load Control (DLC) Pool Pump "Save a bomb" Program Residential Brownfields SWER DM Program Proposed Broad-based & Residential Initiatives Smart Network Program C&I SME Business Models (BizBMod) Residential Business Models (ResBMod) Sustainable Residential Development (EDQ) QUT ARC Linkage Study Your Power QLD (Energy Information Portal) Proposed Smart Network Initiatives 1,485-1,485 Energy Conservation & Isolated Communities powersavvy 1,292-1,292 3 Demand Management Innovation Allowance 1,000-1,000 5 Energy Sense Communities Program Management ,2,4 Program Management Total 15,418-15,418 Funding Source 11 Except for very small investments in metering assets. 12 Funding Sources: 1 Regulated Non-network Alternative Operational Expenditure Allowance; 2 Australian Greenhouse Office and Ergon Energy; 3 Community Service Obligation; 4 Department of Energy and Water Supply; and 5 DMIA Ergon Energy Demand Management Plan 2013/