Ergon Energy Demand Management Plan

Transcription

1 Ergon Energy Demand Management Plan July 2015

2 Contents 1. Executive Summary Background Document Purpose Legislative compliance Introduction Demand Management Program Demand Management Summary Demand Management value Peak demand Power quality Reliability Changing Demand Management Environment Demand forecasting Probabilistic planning and Safety Net Existing challenges Emerging challenges Demand Management Strategy Demand side engagement capabilities Network Capacity Incentive Map Trade Ally Network Product development Demand response mechanism Demand Management Plan Demand Management Plan Maintenance programs Contracting demand programs Forecast future constraint programs Safety net programs Targeted broad-based programs Summary Appendix A. DM Project Summaries Appendix B. Definitions, acronyms and abbreviations Definitions Acronyms and abbreviations Ergon Energy Demand Management Plan

3 Table of tables Table 1 Demand management forecast operational expenditure... 4 Table 2 Demand management targets... 5 Table 3 Electricity Regulation 2006 requirements... 7 Table 4 - Demand management forecast expenditure Table 5 - DMIA forecast expenditure Table 6 - Demand management forecast demand Table 7 Maintenance programs Table 8 Contracting demand programs Table 9 - Network constraint forecast programs Table 10 - Network constraint forecast targets Table 11- Safety net potential program Table 12 - Safety net demand management forecasts Table 13 - Broad based and regional Table 14 - Broad-based and regional MVA targets Table of figures Figure 1 - Geographic peak demand Figure 2 - System demand forecast Figure 3 - Tennyson NCIM Figure 4 - Demand Response Automation Server Ergon Energy Demand Management Plan

4 1. Executive Summary The document represents Ergon Energy s Demand Management Plan for including our forecasted demand management targets for the regulatory control period (commencing on 1 July 2015 and ending on 30 June 2020). Ergon Energy remains committed to demand management as a key capability for avoiding the construction of network infrastructure through reducing network risks while supporting an increase in asset utilisation. This commitment is demonstrated by our delivery of 139MVA of demand reductions over the regulatory control period deferring $664 million of network investments. We also recognise that our customers needs and expectations are changing. Technology like solar photovoltaic is now far more common and we expect that by 2020 there will be a range of new customer technologies that we need to support and interact with. As our focus changes to support these emerging consumer choices as well as manage our network, our demand management program is developing new and innovative capabilities to help us better manage our network, interact with our customers and supporting downward pressure on energy costs. In order to manage network needs and our customers expectations we are forecasting an (operational expenditure) investment of $48.2 million in demand management over the 2015 to 2020 regulatory control period as listed in Table 1 and Table 2, consisting of: $22.3 million targeting an additional reduction in demand of 50.2MVA, $18.5 million supporting committed programs providing 41MVA of demand response, and; $7.3 million of Demand Management Innovation Allowance (DMIA) and program management. In the financial year we are forecasting an investment of $9.5M that consists of: $5.1 million to support the 41MVA of committed works, $2.9 million targeting 8.6MVA of new demand management contracts, and; $1.5 million of investment in DMIA, program innovations and program support. Table 1 Demand management forecast operational expenditure DM Portfolio Total Committed works 5,132 4,295 3,270 3,029 2,848 18,574 Contracting demand phase 1,892 1, ,777 Maintenance/operational phase 3,240 3,240 2,940 2,729 2,648 14,797 Planned programs 2,946 3,800 4,595 5,285 5,680 22,306 Network Constraint targeted programs 2,246 2,950 3,545 4,035 4,280 17,056 Safety net risk mitigation ,000 Broad-based and mass market ,250 Demand Management Innovation Allowance 1,000 1,000 1,000 1,000 1,000 5,000 Program Management ,375 Total 9,553 9,570 9,340 9,789 10,003 48,255 Ergon Energy Demand Management Plan

5 Table 2 Demand management targets Additional Demand Targets (MVA) Total Targeted Broad-based Programs Safety net risk mitigation Network Constraint targeted programs Total Additional Demand The forecasted demand management program targets are below the previous control period achievements due to two key reasons: 1. A lower growth forecast for the period compared to which results in lower capital expenditure and consequently lower demand management requirements; and 2. The implementation of the new probabilistic planning criteria and safety net measures resulting in higher levels of residual risk in the network and a shift in focus from Sub-transmission to distribution demand management programs. Other major changes reflected in the demand management program include: Continued Network Tariff Reform introducing new tariffs and price signals providing greater opportunity to work with customers to encourage demand management; Risk mitigation activities of actively working to reduce risk in growth areas prior to specific constraints occurring thus lowering the cost demand activities and reducing demand forecasts; The inclusion of Safety Net into the demand management program to ensure service levels can be maintained through managing outage impacts. The Safety Net is not specific about how these targets are to be achieved which enables far greater use of non-network solutions, particularly demand management and embedded generation; Implementation of several key capabilities to increase our capacity and reduce our demand management costs, including flexible incentive payment process (FIPP), the customer demand management portal (Portal), the network capacity incentive map (NCIM) and continued development of the trade ally network (TAN) concept; and, The development of a demand response automation capability to enable us to interact more freely with our end customers enabling higher levels of consumer participation in demand management activities. Across the 2015 to 2020 period we are expecting to see continual change within the usage and behaviours of Ergon Energy s customers and as a result how our organisation needs to respond in order to support their aspirations. Demand management will continue to play an active role in supporting both the network and the needs of our customers in this regard. Further details of the Demand Management program and future strategic plans are provided herein. Ergon Energy Demand Management Plan

6 2. Background Ergon Energy, as a Queensland Government-owned corporation, supplies electricity to around 700,000 customers across a vast operating area of over one million square kilometres around 97% of the state of Queensland from the expanding coastal and rural population centres to the remote communities of outback Queensland and the Torres Strait. We are all about delivering on our purpose 'to provide safe, reliable, efficient and sustainable energy solutions to support our customers and the Queensland economy'. To make this happen, Ergon Energy has around 4,500 employees and a $10.6 billion asset base. Ergon Energy's electricity network consists of approximately 150,000 kilometres of power lines and one million power poles, along with associated infrastructure such as major substations and power transformers. This is a vast coverage area and in order to fulfil its corporate purpose, Ergon Energy invests in electrical infrastructure and increasingly in demand management to meet the growing needs of regional Queensland. This investment must support the maximum energy demand of our customers, whenever and where-ever it occurs. The maximum or peak demand, typically only occurs for a few hours each year resulting in significant investment for a small duration of time. 2.1 Document Purpose This document is the Ergon Energy Demand Management Plan for , which aims to provide our stakeholders with details of our forecast demand management (DM) activities and insights into our expected demand management program over the next 5 years while meeting our legislative requirements. Its purpose is to: a) highlight the demand management activities planned by Ergon Energy including the defining of strategies, targets, budgeted programs and specific initiatives for the financial year ; b) inform the broader market of Ergon Energy s demand management objectives, goals and proposed programs for the financial year ; c) enable the market to participate in solving network load factor and localised network shortfall issues; d) inform Ergon Energy s regulatory submissions, with the next pricing proposal addressing the five year period starting July 2015; and, e) comply with Clause 127C(1) of the Electricity Regulation 2006 (Regulation) which requires that Ergon Energy prepare a Demand Management Plan for each financial year. Ergon Energy Demand Management Plan

7 2.2 Legislative compliance This Demand Management Plan satisfies the various regulatory requirements, as set out in the table below. Table 3 Electricity Regulation 2006 requirements Section Requirement Reference 127C(1) Ergon Energy must, for each financial year, prepare a Demand Management Plan. (this document) This document satisfies this requirement 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 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 5 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 in the plan. Each proposed initiative for must include a description of that initiative. Each proposed initiative for 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 must include Ergon Energy s performance targets for the initiative. Ergon Energy must on or before 30 April 2015 give the regulator a copy of the Demand Management Plan. Section 5 Section 5 Sections 6.1, 6.4 Sections 5.1, 5.2 Section 6.1 Section 8 Section 6.2, 6.3 Section 6.4 As agreed, Ergon Energy delivered a Preliminary Demand Management Plan by 30 April This report represents the revised Demand Management Plan (agreed to be delivered by 20 July 2015) following the AER s Preliminary Determination. Ergon Energy Demand Management Plan

8 3. Introduction To fulfil our corporate purpose Ergon Energy manages electrical infrastructure to meet the growing needs of regional Queensland. Where necessary, Ergon Energy invests in electrical infrastructure to ensure that our customers can access energy in an efficient manner, this includes taking into account embedded generation (including solar PV). In order to ensure that any infrastructure investment is prudent and efficient Ergon Energy examines many options surrounding any proposed investment, including demand management. Demand management - working with our customers to influence their energy usage in order to reduce or avoid the need for investment in infrastructure - has become a business as usual part of our approach. The three main drivers of infrastructure investment that demand management impacts are: 1. Peak demand - to ensure that the peak or maximum demand electricity needs of our customers can be met whenever and wherever it occurs; 2. Power quality ensuing that the quality of supply meets regulatory standards; and, 3. Reliability the measure of the continuous supply of electricity to a customer, or the number of outages that a customer may experience. Peak demand occurs when there is a large demand for energy from customers simultaneously on the network. Typically, these events are driven by temperature (heating/cooling) or large commercial and industrial customers. While the overall system peak demand highlights the network wide impacts and the economy more broadly, Ergon Energy can experience localised peak demand events due to localised temperature or economic conditions. These types of localised conditions are particularly noticeable across Ergon Energy s network due to the vast geographical size of the network and the wide variety of climatic zones the network covers. Power quality covers a range of network issues that impact the quality of the electricity delivered to our customers and can include power factor, voltage changes and harmonics. In cases, such as power factor, demand management can be a valuable economic alternative to a network solution, by increasing the efficiency of the energy used by the end customer. Reliability issues can occur for many reasons, network element failure, and vegetation or weather events such as the recent Tropical Cyclone Marcia. Demand management has a role to play in mitigating the risk associated with reliability in order to support a reduction in infrastructure investment. While customer attitudes to reliability have changed in recent years it remains a key component of our purpose. Supporting the reliable supply of electricity to customers, by improved fault restoration or reducing the impacts of a fault, is an increasing focus of our Demand Management program. Ergon Energy faces many challenges in ensuring that we meet our customers energy, power quality and reliability expectations in a prudent and efficient manner across the vast distances of our network. Our investment in demand management is one way that we can support our customers, manage our risk and efficiently invest in infrastructure. Ergon Energy Demand Management Plan

9 3.1 Demand Management Program Ergon Energy s future demand management activities are based on the success of demand activities to date. Ergon Energy achieved the regulatory control period target of 122MVA in June 2014 a full 12 months ahead of target and achieved 139MVA of demand reductions for the period. The program has successfully aided in the forecast deferral of $664 million of capital investment highlighting the value of the program. The performance of the Demand Management Program will be published in the Demand Management Outcomes Report on the completion of the financial year Demand Management Summary The demand management program is on target to deliver the forecast demand reductions for , highlights of the program from this financial year include: The South Mackay program, which utilised the NCIM (Network Capacity Incentive Map); Trade Ally Network (TAN) and market delivery mechanisms to achieve demand reductions. The program is significant as it underlines the success that this new method of interacting with the market can achieve and establishes the process for the future demand management program; The delivery of key demand management programs including, Gordonvale, St George, and Moranbah as well as Malanda and Kingaroy which are all well progressed in the implementation phase and expected to deliver their demand targets in the next three months; and The development of the portal and Flexible Incentive Payment Process (FIPP) system. These two systems will enable third parties to assist Ergon Energy to drive down the costs for managing payments for demand management and will not only simplify incentivising the market, but also support the mapping concept with easier communications channels to market. These successes pave the way for a successful demand management program over the next regulatory control period Demand Management value The value of demand management for Ergon Energy includes both direct investment deferral for short term value and longer term risk mitigation for longer term deferral, as summarised below. Capital deferment and investment timing. By using demand management we can manage load and defer the need to invest in network infrastructure optimising both investment and cash-flow. Investment decisions are made on the basis of forecast demand growth in an area. Forecasts always carry an element of risk, by using demand management these risks can be managed until the investment need is better understood, thus optimising the final solution. Management of risk. A key change in our planning practices is the change from N-1 planning to a risk based planning methodology. Traditionally the network has been designed to meet the maximum peak demand based on a set of design criteria or security standards, usually N-1. The use of a risk based methodology, combined with a safety net to ensure a minimum service standard, helps reduce the need for infrastructure investment whilst maintaining appropriate reliability. This approach is underpinned by a robust risk management and analysis approach in which demand management is an increasingly useful tool. Ergon Energy Demand Management Plan

10 A reduction in outage costs. We aim to provide a safe, reliable energy supply to our customers, but it is inevitable that some outages will occur. Demand management can reduce the economic impact of such network outages by reducing the amount of load impacted or amount of capacity available for restoration. Asset utilisation. As previously noted the distribution network is designed to meet the peak that only occurs for a few hours every year. Demand management is used to help reduce the peaks and fill the valleys by encouraging shifting of demand to lower network utilisation times. The end result is a network that is better utilised, creating more efficient use of the existing asset base and supporting the reduction in energy costs for consumers. The transition of the demand management program from pure peak demand management to asset utilisation is something that is evolving over time. Third-party value. As the demand management program expands and contracts demand for network management it creates opportunities and enables third parties to provide customers a mechanism to access value in the wholesale national electricity market. Enabling this value for third-parties and customers increases the overall value of demand management and decreases the costs for Ergon Energy to access demand management services in the future. While the above are all benefits that Ergon Energy can extract from demand management, there are three main categories which demand management will be used to support, defer or avoid, further investments. These categories are peak demand, power quality and reliability. 3.3 Peak demand Peak demand issues that trigger demand management activities generally occur in a geographic location and at specific times. These peak demand events are created by several factors coinciding, such as: location of energy use timing of energy use weather conditions, either locally or across the state economic conditions, either locally or across the state network elements and the network capacity available The key consideration with peak demand is ensuring that we have enough capacity to meet the demand when and where it occurs. This creates a level of risk in the forward planning of network investments as the network infrastructure must be in place and commissioned for any potential future peak demand event. The most significant impact on any demand management activities are the timing, location and duration of peak demand as demonstrated by Figure 1 - Geographic peak demand. Ergon Energy Demand Management Plan

11 Heat wave in Cairns causing peak demand issues Network element failure in Mackay causing peak demand issues Remaining network has, no peak demand issues Figure 1 - Geographic peak demand 3.4 Power quality Power quality issues that demand management may be able to address are generally broken into two broad categories: Power factor Voltage Several power factor projects have been delivered by Ergon Energy s demand management program in the past including the Kingaroy and Toowoomba programs. These programs were measured on the demand reduction (MVA reduction) values in order to support a reduction in network investment. Such programs in the future may be measured on their improvement in power factor and improvement in power quality rather than the straight MVA reduction. The introduction of kva tariffs is a large incentive and opportunity to engage with our customers to improve their power factor and costs, while supporting an improvement in our network performance. Apart from the power factor projects the demand management program has not directly performed any other voltage improvement projects to date. However as customers install more energy related technologies into their home, such as solar PV (photovoltaic), smart inverters and energy storage, there may be opportunities to work with our customers in improving power quality as part of future programs. While these two new demand investment opportunities may not deliver a direct capacity improvement measureable in MVA, they have the ability to support a reduction in capital expenditure, as such, provided they can be delivered with a positive net present value they will be considered for inclusion in future demand management activities. 3.5 Reliability Maintaining a high standard of reliability at an efficient cost is a high priority for Ergon Energy and our customers. Reliability in the simplest form is; how long and often an outage occurs at a customer s premise. High reliability comes at a cost of investment, typically in infrastructure or maintenance, which ultimately results in increases in the price of electricity. Reliability has been Ergon Energy Demand Management Plan

12 the subject of significant research by Australian Energy Market Operator (AEMO) and has resulted in the development of the Value of Customer Reliability (VCR). The VCR mechanism enables a methodology of measuring the economic impact of outages and therefore supports a measurable method to compare investment versus risk. Demand Management can be used to reduce the amount of priority load lost during an outage and provide additional network capacity for restoration after an event as an alternative to infrastructure. The demand management program over the coming years will explore opportunities to help improve reliability in areas where there is value for deferring network investment. The Safety Net implementation has already been a large part of this journey. 4. Changing Demand Management Environment There have been some significant changes to Ergon Energy s operating conditions over the past 12 months, with ongoing changes forecast over the coming regulatory control period. Ergon Energy are actively changing the demand management program, systems and processes in order to ensure the demand management program remains effective in this changing environment. 4.1 Demand forecasting Ergon Energy s infrastructure augmentation expenditure program is heavily influenced by the forecasted increase in customer maximum demand and the resulting network upgrade or investment requirements. For the regulatory control period Ergon Energy are forecasting a demand growth that is close to the low growth demand scenario as highlighted below in Figure 2, resulting in a low capital investment forecast for the coming period. This low capital investment forecast will be supported by our DM activities in order to maintain network risks at appropriate levels. Figure 2 - System demand forecast Ergon Energy Demand Management Plan

13 Forecasting plays the fundamental role of establishing demand growth therefore dictating network risks and potential investment areas. As demand management is a risk mitigation strategy, it needs to be appropriately captured within forecasting to ensure it is appropriately considered. In order to accurately account for demand management activities Ergon Energy s Substation Investment Forecasting Tool (SIFT) has the ability to accept demand management as a negative block load. In order for SIFT to accurately account for demand management activities the system must account for the complexity of demand management contracts e.g. comparing a single diesel generator contracted for 10 hours per annum over 3 years versus 1000 residential houses moving to tariff 33 for pool pump load control. Ergon Energy are developing more sophisticated feedback mechanisms to support SIFT enabling our forecasting teams to more accurately account for the demand management programs and the associated impact on forecasts. This will enable us to better predict the long term demand management program s impact on demand, which is especially important for programs that are broader in their application, such as residential PeakSmart air-conditioning programs. 4.2 Probabilistic planning and Safety Net The implementation of the Safety Net and probabilistic based planning methodologies in Queensland has moved planning activities from an input to an output based standard. This enables Ergon Energy flexibility in assessing risk in the network and managing customer outcomes as opposed to implementing specific network topologies. Probabilistic planning enables Ergon Energy to operate parts of the network at higher levels of utilisation and potentially over the traditional N-1 capacity threshold, taking into account the likelihood of a network failure, peak demand at that instance, the energy that cannot be supplied to customers and the time frame to repair a potential fault. These changes have two opposing impacts on demand management: The probabilistic planning allows for operation of the network over the traditional N-1 capacity threshold, reducing the level of redundancy. Typically the lower levels of redundancy in the network occur at the lower voltages (11kV and 33kV distribution elements), which has resulted in the need for the demand management program to focus on localised network elements with very specific and reliable solutions. An outcome based planning approach requires greater management of risk and contingencies. Demand management is a very effective risk mitigation activity for load based network risk. As the need for demand management to manage risk within the distribution network increases so too will the number of demand management initiatives, reducing the size of each individual initiative and driving new approaches to contracting and managing the demand. In order to ensure that the risk of probabilistic planning does not result in significant outages to our customers Ergon Energy operates within the safety net which is a minimum outage time during a contingency event. Demand management interventions, including embedded generation, are playing an increasing role in meeting safety net provisions. Ergon Energy Demand Management Plan

14 4.3 Existing challenges Key risks that have been identified in past Demand Management Plans are still applicable for the demand management period. During this time Ergon Energy expects to see a continued growth in: PV installations. As incentives have reduced over recent times the installation of PV systems has decelerated. However the growth of PV systems in residential environment remains strong with the average size of systems increasing; Air-conditioners. While air-conditioning systems are starting to reach saturation levels throughout our supply territory there is still growth in the air-conditioning market, with a 8% forecast of customers purchasing an additional air-conditioner and 3% of customers purchasing their first air-conditioner over the next 5 years. An added risk to this has been a decrease in the percentages of customers using inefficient temperature setting, from 53% to 46% on the hottest summer day; 1 and As mentioned in section 3.3, localised growth continues to be a key contributor to the demand management program with localised growth resulting in constraints on various network elements. 4.4 Emerging challenges The two main emerging challenges and opportunities for Ergon Energy are the increased consumer interest in residential energy storage (residential battery systems) and rate of electric vehicle uptake. Both of these challenges are still emerging and although they are not forecast to significantly impact Ergon Energy in the coming 12 months, they pose such a risk and opportunity that strategies need to be in place to ensure our customers can access these technologies in an appropriate manner. Residential energy storage - As the Solar Bonus Scheme Feed in Tariff reduces, we expect to see an uptake in consumers installing energy storage devices such as batteries, representing a significant opportunity and risk. The opportunity is to encourage consumers to install batteries that mitigate the network peak demand thus providing a significant demand management tool. If customer energy storage is installed in such a way as to minimise peak demand, it has the potential to significantly drive down infrastructure investment and hence energy costs for all customers; and Electric Vehicles - While the uptake of electric vehicles is slow and is expected to remain so for the immediate future, electric vehicles present such a significant risk that they require consideration early in the adoption cycle. Electric vehicles have the potential to create localised increases in peak demand, therefore we must have strategies to encourage customers to connect and charge electric vehicles in a way that improves network utilisation and hence has a downward pressure on customer prices. 1 Colmar Brunton. (2014). Queensland Household Energy Survey. Brisbane: Colmar Brunton. Ergon Energy Demand Management Plan

15 This changing environment highlights the future risks and opportunities for Ergon Energy across the distribution network that require management, together with implementation of new business processes such as asset utilisation improvement and new risk based planning methodologies. Rather than responding reactively to disruptive technologies, we are preparing for disruptive technology adoption ensuring that operational processes are in place to activate as required, to maximise any potential benefits. 5. Demand Management Strategy Ergon Energy s demand management strategy over the coming regulatory control period builds on the previous demand management strategy and aims to increase the capabilities of demand management to enable further support of reduced network risks. Our strategy is to engage earlier in the risk cycle with low cost proactive demand management programs and create the opportunity for customers to engage earlier with us to ease network risks. As the demand profile in an area grows and the risk increases the demand management program will increase activities and incentives to increase the demand benefits. This process continues as the network solution is developed, whereby the demand management program value can increase to include direct asset deferral and offer customers higher incentives. This continual demand management process will enable our forecasting teams to develop an understanding of the impacts of demand management programs; our planning teams to increase knowledge of the demand capability embedded in an area; our customers to realise longer term value from demand activities; and, finally our market supplier s surety over the length and time of available incentives. This type of demand management is expected to increase the numbers of service providers, customers and products used in the delivery of demand management. 5.1 Demand side engagement capabilities Ergon Energy s vision for delivering demand management is through market enablement. The energy services market continues to grow and in the future, we expect the energy services market to be able to deliver demand opportunities efficiently. The market enablement mechanism is already in the pilot phase with the EmPower South Mackay project, and includes a number of initiatives such as NCIM and market engagement via the establishment and operation of the TAN. We are also investing in initiatives to support market delivery enablement and to increase the size and activity of a demand management market by Developing preapproved products that can be actively used by the market to supply demand management solutions; Investing in systems and processes to reduce the barriers for customers and suppliers to participate in the demand management market; Examining regulatory arrangements and working with regulators and governments on barriers that may be removed to enable a more active demand market; Working with other demand purchasers, retailers, aggregators, and transmission companies to ensure the full value of demand management is available for customers; Ergon Energy Demand Management Plan

16 Working in partnership with research institutions and international technology providers such as the Guided Innovation Alliance within the Queensland University of Technology, ARENA and others to focus on key priorities for the electricity distribution sector; and, Developing internal capabilities to manage an active demand market and remove barriers for demand suppliers to access incentives and accelerate their demand management activities Network Capacity Incentive Map The network incentive capacity map (NCIM) is a market communication tool that engages the market to identify the value, location, and metrics related to a Demand Management Program of works. The NCIM, example shown in Figure 3 - Tennyson, is in use with the South Mackay program, and published on Ergon Energy s external website. As can be seen the NCIM identifies, the exact location and timing of the constraint and any customer in the map catchment area can access incentives. Figure 3 - Tennyson NCIM The NCIM s main function is to inform the market of the location of a program the timing of the program the economic value of the program the metrics around the program Informing the market should enable an increased number of vendors supplying demand services an increase in competition driving down cost to supply innovation in the market, once the market is established and informed high levels of engagement with third parties Ergon Energy Demand Management Plan

17 Ergon Energy is developing the capability to expand and publish the NCIM map across Queensland, to highlight all the network areas of constraint and risk to provide better market information Trade Ally Network The Trade Ally Network (TAN) is an active group of preapproved suppliers of services or products that can support demand management products or services. The purpose of the TAN is to ensure there is a ready-made market of appropriately qualified vendors and suppliers that can offer products to a customer base. Using already developed market capabilities reduces the need for Ergon Energy to duplicate these services and capabilities to achieve demand reductions. The TAN are provided with information, collateral and other marketing support tools to help them seek, find, and engage with customers willing to undertake demand reduction initiatives. Currently the TAN consists of over 40 companies that range in capabilities from lighting experts to air conditioning design experts, to power factor equipment suppliers, to finance companies. This relationship enables a capable market; provides suppliers with opportunities for business development, and enables customer choice. Frequently customers have pre-existing relationships with TAN members that further reduce barriers for customer participation in demand markets. The combination of dynamic planning, NCIM and the TAN create the foundation of a market-based solution for delivering demand management. 5.2 Product development In order to support our demand partners and customers we are developing a range of standardised products for which there will be a defined range of requirements to enable the product to be eligible for incentive payments. This will enable our TAN partners to develop their own systems, process and products to further create value for our customers and ensure that the demand management program continues to deliver benefits. These standardised products will be supported by FIPP which, when combined with the NCIM, portal and TAN enables us to efficiently and quickly process incentive payments. Products for development will vary over time as market forces and customer requirements change, but the following list of 10 product areas will be our key focus over the period: 1. Air Conditioning Peak Smart; 2. T33 controlled loads (pool pumps, HW storage etc); 3. T12 (non-control price signal tariff); 4. Call Off Load; 5. Customer Embedded Generation; 6. Network Embedded Generation; 7. Power Factor Correction; 8. C&I Demand Management; 9. SWER delivery mechanism; and 10. Customer IES. Ergon Energy Demand Management Plan

18 Effective development and management of these products will be instrumental in ensuring effective market deliver of demand management. 5.3 Demand response mechanism The future success of the Demand Management strategy will be dependent upon the creation of the capabilities that enable the program to manage a higher number of demand initiatives effectively. The increase in distribution network demand management programs is forecast to increase the numbers of customer contracts and demand programs, and to decrease the average size of contracted demand. As this demand gets contracted there will be an increasing requirement to automate the management of the contracted demand, therefore Ergon Energy have invested in a Demand Response Automation Server (DRAS), (see Figure 4 - Demand Response Automation Server). The DRAS enables significant strategic capabilities to efficiently target, operate, measure, verify and control this increasing number of demand contracts automatically. The DRAS will enable active demand management for Ergon Energy into the future by allowing interactions with market participants in an automated seamless manner with clear interface rules. As customers become more sophisticated in their energy use and new technologies, such as when batteries evolve, the interactions Ergon Energy has with our suppliers of demand become more complex. The DRAS forms part of our future of demand management and will be integrated with other network management tools allowing Ergon Energy to interact with our customers on a regular basis to actively shape the demand profiles of the network. Figure 4 - Demand Response Automation Server Ergon Energy Demand Management Plan

19 Ergon Energy Demand Management Plan

20 6. Demand Management Plan We have developed our Demand Management Plan for based on our Australian Energy Regulator (AER) proposal for the regulatory control period. The AER s final determination will have significant influence on all aspects of Ergon Energy s operational and capital expenditure including demand management activities. Not-withstanding the uncertainty surrounding the final funding for the regulatory control period, Ergon Energy are forecasting a total demand management expenditure of $43.2M as detailed in Table 4, including Demand Management Incentive Allowance (DMIA) (Table 5). Table 4 - Demand management forecast expenditure DM Portfolio Total Committed works 5,132 4,295 3,270 3,029 2,848 18,574 Contracting demand phase 1,892 1, ,777 Maintenance/operational phase 3,240 3,240 2,940 2,729 2,648 14,797 Planned programs 2,946 3,800 4,595 5,285 5,680 22,306 Network Constraint targeted programs 2,246 2,950 3,545 4,035 4,280 17,056 Safety net risk mitigation ,000 Broad-based and mass market ,250 Program Management ,375 Total 9,553 9,570 9,340 9,789 10,003 43,255 In addition to $43.2M of demand management activities Ergon Energy forecast a DMIA expenditure of $1M per year over the 5 years as detailed in Table 5. While DMIA is separate to the demand management expenditure, it is administered and managed by the demand management program as it provides a key resource for Ergon Energy to conduct research and investigation into innovative techniques for managing demand. Although budgeted for separately, DMIA is highlighted in this Demand Management Plan for completeness. Table 5 - DMIA forecast expenditure Demand Management Innovation Allowance Total ($'000 ) DMIA forecast expenditure 1,000 1,000 1,000 1,000 1,000 5,000 Ergon Energy Demand Management Plan

21 Ergon Energy forecast expenditure over the period will result in an additional 50.2MVA of demand reductions across Ergon Energy s coverage area as detailed in Table 6 in addition to the 41MVA of committed demand that was contracted in the period. Table 6 - Demand management forecast demand Additional Demand Targets (MVA) Total Targeted Broad-based Programs Safety net risk mitigation Network Constraint targeted programs Total Additional Demand Demand Management Plan Ergon Energy s Demand Management plan includes the following programs forecast to continue into or commence in : Maintenance programs - programs which are no longer contracting new demand but which have demand under management, e.g. contracted diesel generator; Committed works - programs which are forecast to commence or continue into ; Forecast future constraint programs, programs which are forecast to commence based on constraint identification; Safety net programs - aligning with the application of the new safety net planning criteria; Broad based and regional programs - supporting a reduction in forecast network risk by mitigating the demand growth in an area; Smart network programs - creating future strategic capabilities for the demand management program; and, Program management - which includes a range of activities, such as measurement and verification, reporting, feasibility studies and other activities not directly associated with a program. Ergon Energy Demand Management Plan

22 6.2 Maintenance programs Maintenance programs are programs where the demand targets have been reached and the existing demand is available to Ergon Energy under a continuing contract. Such programs include demand response contracts through customer or network embedded diesel generation. Our current maintenance and contracting programs support approximately 41MVA 2 of contracted demand. Table 7 Maintenance programs Maintenance/operational phase Total 3 Mt Peter (Gordonvale) Dingo/Duringa Mt. Isa DR Alpha ,000 Malanda DR Moranbah DR ,230 Barcaldine 1,840 1,840 1,840 1,840 1,840 9,200 Total 3,240 3,240 2,940 2,729 2,648 14, Contracting demand programs Contracting demand programs are programs that will be continuing to contract demand or commencing operation in the coming control period. This may consist of programs that already have a level of demand under contract and will be continuing to contact additional demand or programs transferred from previous smart network programs. Table 8 Contracting demand programs Contracting demand phase Total Your Power QLD ESC Bohle Industrial Area EmPower Mackay ,133 Cannonvale ,068 Kingaroy Power Factor Mackay North ADMD Phase 2 Calculator Total 1,892 1, ,777 2 Forecasted as at the end of FY 2014/15 at the time of Demand Management Plan creation 3 Forecast expenditure does not include any expenditure previously incurred 4 Alpha is currently under review, the forecast is based on previous operational costs. 5 Includes feeders of Blacks Beach, Rural View, Eimeo and Bucasia as listed in Preliminary Demand Management Plan Ergon Energy Demand Management Plan

23 6.4 Forecast future constraint programs Ergon Energy s forward planned programs of work for and beyond are subject to change as network needs and demand changes across our network. With the added implications of the new planning criteria, Safety Net and the AER determination Ergon Energy will continue to revise the forward programs of works to ensure that the program continues to provide value. The forecasted network constraint program is detailed below in Table 9. It contains a list of network risk areas where demand management is likely to form some part of the solution for easing the network risk. Many of these areas contain some elements of network risk related to safety net, reliability and capacity and the solutions will continue to be developed in conjunction with new planning standards. Table 9 - Network constraint forecast programs Forecast programs Total North Mackay ,600 Charleville ,600 Ooralea Gracemere ,698 Charters Towers Alpha Harvey Bay ,000 Feeder program ,250 Single Wire Earth Return ,255 Others ,445 1,985 2,005 7,283 Total 2,246 2,950 3,545 4,035 4,280 17,056 The others that are currently under review for inclusion in the demand management program include, among others: Charlton, Tukura, Broxburn, Kunawarra, Bundaberg Port, Yarranlea, Hervey Bay (Pialba), Bargara, Avoca, Kingaroy, Emerald, Lower Burnett, Burnett Heads. These sites all have varying network influences on the risk that is in the area and will be reviewed in line with the application of the new planning criteria. 6 Includes feeders of Blacks Beach, Rural View, Eimeo and Bucasia as listed in Preliminary Demand Management Plan 7 Charleville may include the surrounding towns of Charleville, Quilpie, St George and Cunnamulla, however it is dependent on the application of Safety Net. Ergon Energy Demand Management Plan

24 The forecast demand reduction targets for the above programs are detailed below in Table 10. Table 10 - Network constraint forecast targets Forecast demand reduction (MVA) Total North Mackay Charleville Ooralea Gracemere Charters Towers Alpha Harvey Bay Feeder program Single Wire Earth Return Others Total Safety net programs The forecast financial expenditure on safety net demand management is listed below in Table 11. The safety net expenditure does not include any site preparation for embedded generation nodes and specifically considers only the operational costs of demand management for supporting safety net. Safety net was developed for low probability high impact events and we are forecasting that in any one year, on average, we would only expect one significant safety net event which would require the deployment of safety-net generation support. While our forecast safety net risk exposure supported by demand management is 16.6MVA, one safety net event per year would result in a forecasted deployment of 6.5MVA of demand management over the 5 years. It is important to note that safety net is a new planning and operational standard as such Ergon Energy will continue to revise the program in line with prudent operating practice. Table 11- Safety net potential program Total Safety net forecast expenditure Safety net risk mitigation ,000 The demand forecast for demand requirement to support safety net is listed below in Table 12. Table 12 - Safety net demand management forecasts Safety forecast demand reduction (MVA) Total Safety net risk mitigation Ergon Energy Demand Management Plan

25 6.6 Targeted broad-based programs Our targeted broad based regional programs are detailed below in Table 13. These programs are based on supporting our existing constraint and targeted programs and where possible, the two programs will work in unison. The targeted broad based programs follow on from previous broad based and residential programs, with future programs aiming to include small to medium business as well as residential programs. Table 13 - Broad based and regional Forecast program expenditure Total Demand mapping Tariff Switching Peak smart ,300 Education Total ,250 The new MVA targets for the broad-based and regional programs are shown below in Table 14. The education program does not have any specific targets as they are focused on community engagement and education of customers, suppliers and the general market. These program are considered important to enable broad based programs, however it is hard to quantify the exact demand savings associated with an educational program as such no specific demand reduction is forecast. Table 14 - Broad-based and regional MVA targets Targeted Broad based demand targets (MVA) Total Tariff switching PeakSmart Total Ergon Energy Demand Management Plan