Ergon Energy Demand Management Overview

Transcription

1 Ergon Energy Demand Management Overview Abstract: This document comprises an overview of Ergon Energy s proposed demand management activities for the regulatory control period 2015 to As well as the targets and expenditure forecast, this document contains a summary of activities, strategies, risks, drivers and operation of demand management throughout Ergon Energy s network. Keywords: Demand management, DM, embedded generators, demand management strategy

2 Table of Contents 1 Executive summary Background Document Purpose References Erg on Energy controlled documents Other documents Legislation, regulations, rules, and codes Definitions, acronyms, and abbreviations Definitions Acronyms and abbreviations Demand management What is demand management Demand Management drivers Understanding peak demand Demand management success Changing environment Demand management operational strategy Delivery via market enablement Demand response inceptive map Trade Alley Network Demand management process Demand management impacts Demand management forecast impact Strategic initiatives Demand Management Plan Network risk mitigation Forecast Demand Risk Mitigation Operational programs Broad-based and regional programs Smart network programs Demand Management innovation allowance Demand Management portfolio summary <Check this is the latest Process Zone version before use> Demand Management Overview

3 9.8 Demand reduction targets Payments to embedded generators Demand management forecast operating expenditure Forecast payments to embedded generators Summary AnnexA Annex B Demand management outcomes reports Ergon Energy processes <Check this is the latest Process Zone version before use> iii Demand Management Overview

4 1 Executive summary This document comprises an overview of Ergon Energy s proposed demand management activities for the regulatory control period 2015 to In total, we expect to invest $70.5 million of operational expenditure in demand management over the 2015 to 2020 regulatory control period consisting of: $46.2 million targeting a reduction in demand of 80MVA, $14.3 million of Demand Management Innovation Allowance (DMIA), strategic capability building and program management, and; a further $10 million to protect against an upswing in demand growth to a medium or high demand growth scenario. This document contains a summary of activities, strategies, risks, drivers and operation of demand management throughout Ergon Energy s network. Ergon Energy has a proven history in demand management, achieving strong results during the period and building our capability to deliver market based demand management as a business as usual approach. While historically we have focused on capital deferral, demand management is used to help achieve a number of other key business objectives such as optimisation of investment timing, management of network load risk and helping drive improved asset utilisation. As our focus is increasing on these other areas to increase the value of demand management a resulting in a change in approach is occurring requiring new and innovative capabilities. All of these objectives help us better manage our network and into the future, while putting downward pressure on the cost to customers. We also recognise that our customers needs and expectations are changing. Technology like solar photovoltaic is now far more common than at the start of this regulatory control period and we expect that by 2020 there will be a range of new customer technologies in use that we need to have the capability to support and interact with. Changes such as this have lead Ergon Energy to embark on a program of Effective Market Reform (EMR). EMR aims to enhance the linkages between network infrastructure capacity, network planning, demand management, market capabilities and customer choice by: Market Enablement enabling the market access to timely, appropriate information on the value of demand via appropriate market channels. Dynamic Planning forecasting and planning to further integrate customer demand capabilities into network planning analysis. Product Management development and enablement of product solutions for demand management, including new customers and new customer loads. Market Engagement use of third parties, aggregators, retailers and energy service suppliers to develop relationships with customers for the supply of demand services. Business Capability greater implementation of intelligent devices in the distribution network for both measurement and control We see these initiatives as critical in both meeting the needs of our network, but also better serving our customers and helping enable and develop the energy market in Queensland. Page 4 of 49 Demand Management Overview

5 Ergon Energy still considers demand management to be a key strategic capability for supporting the reduced capital works program forecast for the regulatory control period. The $70.5 million Demand Management Program will support a forecast $70-$200 million capital program reduction in real terms, as well as providing some risk mitigation against a future upswing in growth. Not only does the Demand Management Program support the capital reduction in forecast augmentation expenditure, it also supports a potential $600 million in capital reductions, available through to 2030, due to the implementation of the new safety net planning criteria. The safety net allows Ergon Energy to take a risk and outcomes based approach to managing the network, but requires the use of risk mitigation activities such as demand management to support it. This reduced investment in network assets from a combination of dynamic planning and demand management supports Queensland government initiatives such as The 30-Year Electricity Strategy and Queensland Plan as well as Ergon Energy s target of maintaining electricity price increases below inflation. Ergon Energy s current Demand Management Program consists of six main functions, which involve a range of activities that are evolving as part of the EMR strategic program. These are: 1. Committed works existing programs operational through the regulatory control period Planned programs programs forecast to commence in the regulatory control period Smart Network innovative use of new technologies in managing the network. 4. Demand Management Innovation Allowance (DMIA). 5. Forecast Demand risk mitigation against a medium to high demand growth environment. 6. Program management the ongoing management and maintenance of the programs Table 1 provides a summary of the proposal. Table 1- Forecast demand management investment Demand Management Portfolio Total ($'000) ($'000) ($'000) ($'000) ($'000) ($'000) Committed works 3,292 2,455 1,430 1,189 1,008 9,374 Contracting demand phase 1,892 1, ,777 Maintenance/operational phase 1,400 1,400 1, ,597 Planned programs 4,326 6,113 8,073 8,662 9,682 36,856 Network constraint targeted programs 2,246 3,333 4,493 4,482 4,802 19,356 Safety net risk mitigation 1,500 2,200 3,000 3,600 4,300 14,600 Broad-based and regional ,900 Smart Network Program - EMR 1, ,403 Demand Management Innovation Allowance 1,000 1,000 1,000 1,000 1,000 5,000 Program Management ,875 Medium/high growth demand scenario 1,000 3,000 3,000 3,000 10,000 Total 10,956 11,318 12,243 12,576 13,415 70,508 Page 5 of 49 Demand Management Overview

6 Table 2 highlights demand reduction targets, which are in line with the forecast decreasing peak demand growth and capital expenditure over the regulatory control period. Table 2 - Forecast demand reduction targets Additional Demand Targets Total Broad-based, regional and EMR Safety net risk mitigation Network constraint targeted programs Total Additional Demand In addition to the above demand management target we expect to target a further 20MVA of demand reductions if the demand growth were to return to the medium to high growth scenario bringing the demand target to 100MVA in this circumstance. Ergon Energy has demonstrated its commitment through our Demand Management Program 1, which has had significant successes such as: Successfully aiding in the forecast deferral of $644 million of capital investment Delivering the regulatory control period target of 122MVA, 12 months ahead of schedule and under budget. Contracting of demand via market engagement methodologies. Introducing use of Ergon Energy s Demand Response Incentive Map (DRIM) and Trade Ally Network (TAN) market mechanisms to support market enablement Ergon Energy Demand Management program will continue to evolve and will help deliver the results and build the capability to move us closer to our purpose of Providing safe, reliable, efficient and sustainable energy solutions, to support our customers and the Queensland economy. 1 see Demand Management Outcomes Report for a detailed review of the program to date. Page 6 of 49 Demand Management Overview

7 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; approximately 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. Ergon Energy s purpose is to provide safe, reliable, efficient, and sustainable energy solutions to support our customers and the Queensland economy. In order to fulfil its corporate purpose, Ergon Energy invests in electrical infrastructure to meet the growing needs of regional Queensland. This infrastructure investment must support the maximum energy demand of our customers, whenever and wherever it occurs. The maximum or peak demand that the infrastructure is designed to supply, typically occurs only for a few hours each year, resulting in significant investment in infrastructure that is rarely used. This utilisation of network infrastructure is inefficient and creates a situation whereby upward pressure is applied to electricity. 2.1 Document Purpose The purpose of this document is to outline the costs and targets for Ergon Energy s demand management activities, strategies, programs expected or forecasted to be undertaken in the regulatory control period Supporting documents for demand management activities, processes and strategies include: Demand Management Outcomes Demand Management Outcomes Demand Management Outcomes Demand Management Outcomes Ergon Energy Demand Management Final Report Demand Management Innovation Allowance Outcomes Report Demand Management Plan Demand Side Engagement Strategy 2013 Forecast Expenditure Summary Corporation Initiated Augmentation 2015 to 2020 Distribution Network Augmentation Plan Risk Exposure Distribution Network Augmentation Plan (DNAP) Embedded Generator Payments.xls - Page 7 of 49 Demand Management Overview

8 3 References 3.1 Ergon Energy controlled documents Document number or location (if applicable) Document name Document type Process Zone NA0009 Plan Network Investments Standard 3.2 Other documents Document number or location (if applicable) SharePoint Document name Demand Management Innovation Allowance Outcomes Report Document type Report SharePoint Demand Management Outcomes Report SharePoint Demand Management Outcomes Report SharePoint Demand Management Outcomes Report SharePoint Demand Management Outcomes Report SharePoint Demand Management Plan Plan SharePoint Demand Potential Reduction Review Review SharePoint Demand Side Engagement Strategy 2013 Strategy SharePoint Distribution Network Augmentation Plan (DNAP) Plan SharePoint Distribution Network Augmentation Plan Risk Exposure Report SharePoint Ergon Energy Demand Management Final Report Report SharePoint ov.au/ data/assets/p df_file/0009/78543/idc -report.pdf ov.au/ data/assets/p df_file/0009/78543/idc -report.pdf Forecast Expenditure Summary Corporation Initiated Augmentation 2015 to 2020 Independent Review Panel Report on Network Costs The Interdepartmental Committee (IDC) Report on Electricity Sector Reform Summary Report Report 4 Legislation, regulations, rules, and codes Nil Page 8 of 49 Demand Management Overview

9 5 Definitions, acronyms, and abbreviations 5.1 Definitions For the purposes of this strategy, the following definitions apply: Term Definition Augex 6sigma standard Description and Cost of Decentralised Energy (D-CODE) Model Augmentation Expenditure A set of tools or techniques for process improvement. A dynamic model that can be updated with information on the costs of various demand management activities 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. kva MVA Probability of Exceedance (PoE) Targeted/Network constraint demand management Time of Use Zone Substation A Kilo Volt Ampere is 1000 Volt Amps and is a unit of capacity of electrical plant 1,000,000 volt amps. A volt-ampere (VA) is the unit used for the apparent power in an electrical circuit. Equipment ratings are defined in MVA because this takes into account both real and imaginary power requirements. 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. forecast likely to be exceeded only once every two years). Initiatives that aim to address specific network constraints by reducing demand on the network at the location and time of the constraint. A tariff that has a differing charge that is dependent on the time of day. A site incorporating equipment that provides control and voltage transformation from the sub-transmission or transmission network to the distribution network. Page 9 of 49 Demand Management Overview

10 5.2 Acronyms and abbreviations The following abbreviations and acronyms appear in this strategy. Abbreviation or acronym Definition AER BCS B-S-T DANCE D-CODE DAPR DMIA DRIM EMR FLIC MVA RiT-D FY IDC NQ PoE SIFT TAN VCR NPV Australian Energy Regulator Benchmark Cost of Supply Base Step Trend forecasting model Dynamic Avoidable Network Cost Description and Cost of Decentralised Energy Distribution Annual Planning Report Demand Management Innovation Allowance Demand Response Incentive Map Effective Market Reform Forward Looking Incremental Cost 1,000,000 volt amps. Regulatory Investment Test Distribution Financial Year Interdepartmental Committee North Queensland Probability of Exceedance Substation Investment Forecasting Tool Trade Ally Network Value of Customer Reliability Net Present Value Page 10 of 49 Demand Management Overview

11 6 Demand management 6.1 What is demand management To fulfil our corporate purpose Ergon Energy invests in electrical infrastructure to meet the growing needs of regional Queensland. This means that the infrastructure investment must be efficient and support the maximum energy demand of our customers, whenever and wherever it occurs. The maximum or peak demand, that infrastructure is designed to supply, typically only occurs for a few hours each year resulting in significant investment in infrastructure that is rarely used. Maximum demand occurs when there is a large demand for energy from customers simultaneously on the network; typically, these events are driven by temperature or industrial expansion. While the overall system peak demand highlights the network wide impact of peak demand, Ergon Energy can experience localised peak demand events due to a 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, from; Toowoomba in the south east corner of Queensland with a peak demand driven by colder temperatures, to; Central Queensland driven by mining expansion and high summer temperatures, to; Cairns and Townsville in the tropics with extended hot humid temperatures being the primary driver. These vast distances coupled with ensuring that we meet our customers peak energy needs at all times, creates many challenges to prudently and efficiently building and maintenance our network infrastructure. The network risks and constrained network elements can best be addressed by several means: Network investment, build more network infrastructure to increase the capacity in the areas of network constraint and reduce the risk on these network elements. Invest in demand management, by working with our customers and reducing the peak demand, by permanent or temporary reduction in peak demand or shifting the demand, in the areas of network constraint enabling the need for network investment to be deferred. Invest in smart network solutions, introduce smart network alternatives such as dynamic ratings to gain more capacity and delay the need for network investment. Often, the optimal and most cost effective solution is a combination of the elements listed above, either in isolation, or in combination with network solutions to provide our customers safe, reliable, efficient, and sustainable energy in an efficient manner. Page 11 of 49 Demand Management Overview

12 6.2 Demand Management drivers Ergon Energy s demand management drivers can be summarised as follows: Capital deferment. By using demand management we can defer the need to invest in network infrastructure which in-turn provides an efficient use of capital. Investment timing. In some cases an investment decision is made on the basis of forward forecast of demand growth in an area. Forward forecasts always carry an element of risk due to the very nature of predicting the future. By using demand management, demand growth can be managed until the value of investing is better understood, thus optimising the timing of infrastructure investment. Management of Risk. A key change in our practices is in the area of network planning, with the implementation of the safety net and new security criteria, changing from strict N-1 planning criteria 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 minimum standards, helps reduce the need for infrastructure investment, whilst maintaining appropriate reliability and hence eases the upward pressure on energy costs, provided that the risks are appropriately managed. A reduction in outage costs. We aim to provide a safe, reliable energy supply to our customers. However, with a network as large as ours and the introduction of new risk based planning methods it is inevitable that some outages will occur. Using demand management reduces the economic impact of such network outages. 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 focus from pure peak demand management to asset utilisation is something that has occurred particularly in the last 12 months. 6.3 Understanding 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 capacity available. 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. Page 12 of 49 Demand Management Overview

13 ,., -.,... -.~.., ~:..._...,~",... ~... ~~...;...,...""'''',.. "' ~- QIQ..., :f::"'> '< Heat wave in Cairns causing peak demand issues Network element failure in Mackay causing peak demand issues Remaining network is under utilised, no peak demand issues Figure 1 Geographic peak demand The risks associated with geographical peak demand are further highlighted in Figure 2, demonstrating the growth forecast of zone substations. The differences in the growth rates highlight the risk of assessing only the network level growth rates and reinforces the need for demand management to reduce the peak to avoid network infrastructure in the high growth areas as well as to support an increase in energy use of assets that may be not fully utilised. Distribution of Annual Base Summer Growth Nu mbc: r < s s - 1 -o.s o o.s 1 t.s 2 z.s s s. s >4.5 Rate of Growth Figure 2 Demand growth by zone substation Page 13 of49 Demand Management Overview

14 While the geographical location of peak demand is one aspect, the other is the timing of the peak demand. Over the last decade, Ergon Energy's distribution network has experienced a significant increase in residential peak demand. More importantly, residential demand will generally make up a higher proportion of the load during critical evening peak periods 2. Figure 3 highlights that of the top 10% of system peaks events, approximately 40 events in total, occurring in Ergon Energy's network in , 22 of these peaks occurred in the early evening (1700 to 21 00) and the balance of 18 peaks occurred in the late afternoon (1400 to 1700); further all of these events occurred in summer. This demonstrates that even at a system level, the driving factors behind system peak demand are residential customers' usage behaviour and the lifestyle choices heavily impacted by cl imate. 12 Month Daily Maximum Demand Duration Curve top 10% peaks 2,450,000.., ,400, ,350, ,300, ,250, J... i-* ,200, t... l-+-l... l-+-l ,150, J... i-* * * Mid-day Lat e afternoon Othe r Evening 2,100, t... l-+-l... l-+-l... l :::-=---- 2,050, t... l-+-l... l-+-l... l+-...,... Figure 3 Top 10% maximum system peaks Demand management success Ergon Energy's future demand management activities are based on the success of demand activities to date. Ergon Energy reached the regulatory control period target of 122MVA in June 2014 a full 12 months ahead of target. The program has successfully aided in the forecast deferral of $644 million of capital investment highlighting the value of the program. Table 3 below shows the breakdown of this capital deferral for the regulatory control period Productivity Commission 2012, Electricity Network Regulatory Frameworks, Draft Report, Canberra. Page 14 of 49 Demand Management Overview

15 Table 3 - Capital forecast deferral Project Impact on demand (MVA) Deferred capital costs from demand management project ($'000 nominal) Deferral target FY Demand Total project demand Annualised NPV benefit Deferred capital value Years Mount Isa network demand management Project ,161 22,200 3 Cairns Northern Beaches ,452 83,100 3 Bohle Industrial Area ,129 75,700 2 Charleville 0 0 4, , St George ,470 85, Kingaroy , Malanda 0 0 3,281 16,404 5 Moranbah 1 9 1,082 29,507 2 South Mackay EMPower 0 0 1,725 24,827 3 Gordonvale / Meringa 0 0 2,260 13,815 3 Barcaldine Network Support , , Total , ,453 For a full description of the Demand Management Program s performance and outcomes, see the Demand Management Outcomes Report While the Demand Management Program has been successful to date, the program continues to strive for efficiencies and to expand the programs capabilities to offer value across all aspects of Ergon Energy operations. 6.5 Changing environment There are several external factors anticipated to affect Ergon Energy s demand management activities during the regulatory control period In the current regulatory control period 2010 to 2015, Ergon Energy has experienced some significant influences from external factors, such as: 3 Due to the high cost of the Network Alternative, it has always been the preferred approach to use embedded generation to manage security to the Barcaldine and Central West areas. The period of the contract is five years, after which time the local security requirements will be reviewed again, in line with the potential renewal of this contract Page 15 of 49 Demand Management Overview

16 The Queensland State Government reviews that aimed to enable more efficient delivery of electricity to consumers. These included the Interdepartmental Committee (IDC) on electricity sector reform 4 and the Independent Review Panel on network costs 5. The outcomes of these two reviews can be found on the Department of Energy and Water Supply website. the Queensland economy has experienced sofening during the financial year along with rising energy costs that have impacted the forward demand forecasts and reduced the forecasted system maximum demand growth rates. The continued adoption of new technologies by our customers, such as solar photovoltaic. Future technologies also present some significant risk to peak demand growth across Ergon Energy s territory, specifically: Residential energy storage. As the 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 us with a significant demand management tool. However, if customer energy storage is installed in such a way as to increase peak demand, it has the potential to significantly drive up infrastructure and hence energy costs for all customers. 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 an increase 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. The changing environment highlights the future risks 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, Ergon Energy will prepare for disruptive technology implementation and ensure that operational processes are in place to activate as required, to ensure any potential benefits are maximised. Ergon Energy will work with industry to develop a product management framework, including roadmaps for new products, which support technologies such as electrical vehicles and energy storage, and enable integration of the technologies into the network. 7 Demand management operational strategy Ergon Energy s demand management operation consists of four parts: 4 data/assets/pdf_file/0009/78543/idc-report.pdf 5 data/assets/pdf_file/0010/78544/irp-final-report.pdf Page 16 of 49 Demand Management Overview

17 1. New programs: The establishment of a new demand management project, including defining the requirements, measurement and verification policy, potential products of value, creation of a demand map, appropriate pricing of demand and stakeholder/supplier engagement including marketing. This aspect of the Demand Management Program occurs prior to broader market engagement and ensures that the foundations for the program are established and well defined. 2. Active programs: Once the program is active in the market the a range of activities are engaged including, active contracting of the demand, measurement and verification, monitoring the program to determine subscription levels, managing and monitoring market delivery channels and market delivery mechanisms, ensuring marketing campaigns are appropriate etc. This process will include an annual, or as needed review of the programs to determine any corrections required due to subscription levels, changing network circumstances, pricing adjustments, new opportunities etc. This ongoing program review ensures management of the network risks along with the Demand Management Program risks. 3. Operational programs: These programs no longer actively recruit new demand, the program supports an existing contracted demand supplier, generally a demand response, e.g. an embedded diesel generator. The demand is available at call by the network operators. In these circumstances the customer relationship, generation payments, contract management, and measurement and verification require ongoing maintenance to ensure program value. 4. Strategic programs: Development of new capabilities, knowledge, and systems is vital to the ongoing success and efficiency of the Demand Management Program. Strategic programs include the testing of new technologies, business models, operational systems and platforms for engaging the market and delivering demand solutions at a lower cost. While there are three main operational areas of demand management Ergon Energy are developing the systems and processes to ensure all operational areas adhere to a 6sigma standard to: 1. Define: Ensuring that the network constraint is accurately defined, including time, locations, duration, costs, values etc. 2. Measure: Ensuring the Demand Management Program has a valid measurement and verification plan and that the appropriate measurement devices are enabled in the field to ensure accurate reporting of the program. 3. Analyse: Reviewing the Demand Management Programs annual or frequently with key stakeholders, to ensure that the program still offers value and to determine if the program should be accelerated, decelerated or maintained, based on market activity, network risks and customer acceptance. Further ensuring that the demand contracted is fed back to network planning and forecasting to enable updates to the risks and forecasts. 4. Improve: Ensuring that value and learnings from the program will influence future programs to drive further value and efficiencies from the Demand Management Program. 5. Control: Enabling appropriate controls to ensure program maintenance as well as the flexibility to maintain a dynamic and active program for an efficient outcome. Page 17 of 49 Demand Management Overview

18 7.1 Delivery via market enablement 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 Demand Response Incentive Map (DRIM) and market engagement via the establishment and operation of the Trade Ally Network. 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 of 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. Working in partnership with research institutions and international technology providers such as the Guided Innovation Alliance within the Queensland University of Technology, ARENA and other parties to focus on key priorities for the electricity distribution sector. Developing internal capabilities to manage an active demand market and remove barriers for demand suppliers to access incentives and accelerate their demand management activities Demand response inceptive map The Demand Response Incentive Map (DRIM) 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 DRIM, example shown in Figure 4 - Tennyson DRIM, is in use with the South Mackay program, and published on Ergon Energy s external website. As can be seen the DRIM identifies, the exact location and timing of the constraint and any customer in the map catchment area can access incentives. Page 18 of 49 Demand Management Overview

19 Figure 4 - Tennyson DRIM The DRIM s main function is to inform the market: 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 suppling demand services, an increased 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 is developing the capability to expand and publish the DRIM map across Queensland, to highlight all the network areas of constraint and risk to provide better market information. Figure 5 provides an example of this. Page 19 of 49 Demand Management Overview

20 7.1.2 Trade Alley Network Figure 5 - DRIM map example 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 current consists of some 40 plus companies that range in capabilities from lighting experts to air conditioning design experts, and from power factor equipment suppliers to finance suppliers. 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, DRIM and the TAN create the foundation of a market-based solution for delivering demand management. Page 20 of 49 Demand Management Overview

21 7.2 Demand management process Underpinning Ergon Energy's current approach to demand management is the need to demonstrate prudent and efficient investment in our network. It involves active engagement with non-network providers to deliver efficient and cost effective non-network options as alternatives to network expenditure. The process whereby Ergon Energy engages demand management activities is defined in the standard internal procedure NA0009 and follows the same steps outlined in Figure 6. The application of the Regulatory Investment Test- Distribution (RiT-D) only occurs in projects where the project meets the RiT-D threshold specification requirements. While Ergon Energy's strategic direction for demand management is the creation of an active demand market, current regulatory arrangements still require us to perform a RIT-D to ensure any proposed network investment meets the RIT-D criteria. Parties Involved Identify network constraint locations Propose network investment solution Apply regulatory (RIT-D) test Ergon Energy Ergon Energy, NNA Solution Providers Ergon Energy, AER No OM solut1on 1dent1fied OM solution 1dentfied Develop OM solution including seeking funding Implement OM solution Ergon Energy, NNA Solution Providers Ergon Energy, Q/d Govt., Federal Govt., OM/A, NNA Solution Providers Ergon Energy~ NNS Solution Providers~ Customers Proceed with optimised network solution Ergon Energy Figure 6 - Ergon Energy's non-network implementation process In order to ensure that the Demand Management Program efficiently delivers demand management reductions, Ergon Energy commissioned several strategic studies to develop capabilities to quantify the size and cost of the demand management market in Queensland. The 'Demand Potential Reduction Review' was an innovative study produced by the University of Technology Sydney's Institute of Sustainable Futures. The output of the work provided estimates of technical and economically achievable demand reduction potential available to Ergon Energy across the service territory. The 'Demand Potential Reduction Review' provides Ergon Energy with a foundation to develop future Demand Management Programs by highlighting the size and economic cost of different demand management offers and interventions across the service territory. To determine the economic efficiency of demand management measures there are several benchmark costs estimates are available. The Forward Looking Incremental Cost (FLIC) is a measure used to define the value of demand reduction in the context of system-wide broad based measures. The FLIC is used to calculate the Benchmark Cost of Supply (BCS) which is the system wide benchmark cost for increasing network capacity. In simple terms the BCS is the average cost of adding 1 kva of additional demand to the network. Page 21 of49 Demand Management Overview

22 Dynamic Avoidable Network Cost (DANCE) is a benchmark cost for adding capacity in a constrained zone by evaluating the growth-driven network investment relative to the forecast increase in peak demand driving the proposed investment. DANCE defines a benchmark cost for the upper economic boundaries for Demand Management Programs. As with all benchmark costs they form the basis of financial analysis, but individual programs may differ due to local network design implications. Figure 7 provides an example of the application of the FLIC or BCS, and the DANCE combining to form the cost extremes for demand management, with the various intervention opportunity size and costs compared to the average network investment costs. Figure 7 - Demand Potential Reduction Review cost of measure for demand management example To support the Demand Potential Reduction Review Ergon Energy also commissioned the Description and Cost of Decentralised Energy (D-CODE) modelling tailored to use within our service territory enabling modelling of the cost of demand management programs and interventions. The D-CODE model is a dynamic model and can be updated with information on the costs of various demand management activities thus helping to tune the model over time to produce more accurate demand management forecasts in the future. Ergon Energy also commissioned the Ergon Energy Demand Management Final Report to perform a strategic review of the Demand Management Program 6 and to develop a gap analysis of demand management capabilities within Ergon Energy. The report delivered in April 2013 has helped us develop the foundations of the demand management strategies and program to date. Even with the recent changes in planning criteria and new direction for the Demand Management Program, the report contains the many initiatives and strategies that Ergon Energy is working towards. 6 Ergon Energy Demand Management Final Report as developed by DNV Kema Page 22 of 49 Demand Management Overview

23 This work enables Ergon Energy to implement prudent and efficient investments earlier in the demand management risk cycle, with higher confidence as to the size and cost of the demand intervention reducing the long-term likelihood of network investment in an area. 7.3 Demand management impacts The primary drivers for demand management within Ergon Energy over the current regulatory control period were: deferment of augmentation and hence the deferment of capital expenditure increasing the load under direct load control programs Deferment programs In the case of asset deferment programs Ergon Energy s business as usual practice is to fund the Demand Management Program from the savings gained from the deferral of capital. This practice captures any operating and capital expenditure trade-offs from using demand management at the business case stage. Any demand management program created to defer an asset links directly to a parent capital investment business case that highlights the capital and operational costs of delaying the investment and is captured in changes to the forward program of works. The business case process ensures examination of both the network and non-network options to ensure that the preferred option provides prudent and efficient investment. Using this process enables direct comparison of investment in a demand management program against other network investment options to ensure that the demand management solution provides the most efficient delivery of services. Broad based and regional Broad-based and regional programs differ from the deferment program by targeting the entire network in order to increase the demand reduction across the system or in a specific geographical location. Direct load control tariffs are a classic example of a broad based program. The benefit of these programs is that they can deliver demand management at a lower cost per unit but the disadvantage is the need to incentivise in locations where they are not of value. During the regulatory control period , Ergon Energy operated two significant broadbased programs, the Save-a-Bomb Pool Pump Program, and the North Queensland Load Harmonisation Program. The North Queensland Load Harmonisation Program aligned the timing of direct load control devices in Townsville with the rest of Queensland. Due to the history of load control in Townsville, and the types of devices that were connected to the load control tariffs it was difficult for Ergon Energy to operate the load control on a regular basis. Creation of the load harmonisation project aimed to align the devices on the direct load control tariffs and enable the switching of loads more frequently. This change in the network operation has affected load forecasts and load profiles for the Townsville area and resulted in changes to the maximum demand requirements, and hence impacted the forward forecasts. Page 23 of 49 Demand Management Overview

24 The Save-a-Bomb Pool Pump Program had strategic objectives as well as the simple intention of increasing the load under direct control. The strategic objectives included: Removing regulatory and technical barriers to enable connection of pool pumps to controlled tariffs. Engaging the pool services market and educating the market segment on the benefits of high efficiency pool pumps and connecting pool pumps to control tariffs. The program has been successful and changed the pool pump market to the extent that energy efficient pool pumps are now commonplace in pool shops throughout Queensland, pool pumps are connected to tariff 33 regularly, and some the restrictions concerning hardwiring of pool pumps have been removed. The Save-a-Bomb Pool Pump Program has had some significant strategic benefits and confirmed Ergon Energy s future strategic demand management direction by: proving Ergon Energy can influence and create and support a market for demand management outcomes creating a new standard of consumer and supplier awareness to support the long term value of behaviours that reduce demand creating an internal capability for targeting residential demand that can be applied within the network supporting the creation of incentive systems to enable Ergon Energy to apply these with other products and programs Demand management forecast impact Ergon Energy develops demand management projects in response to need, with a view to using demand management to defer or avoid capital expenditure in the short, medium, or long term by focusing the program on targeted areas of network risk. To appropriately capture and account for demand management activities within forecasting Ergon Energy uses the Substation Investment Forecasting Tool (SIFT) to forecast growth on a zone substation basis. The SIFT tool has the ability to accept demand management initiatives as a negative block load reduction that accounts for demand. There is a high level of complexity surrounding the type of demand activity and the long-term impacts these activities have on maximum demand and hence the forecasts. For example, a diesel generator will only be able to mitigate peak demand while the generator is under contract, whereas a load transfer to a controlled tariff will have much longer lasting demand reductions. Ergon Energy are developing more sophisticated feedback mechanisms to support SIFT enabling our forecasting teams to account for the targeted Demand Management Programs and the associated impact on forecasts. Page 24 of 49 Demand Management Overview

25 The implementation of the safety net and probabilistic based planning methodologies in Queensland enables Ergon Energy flexibility in assuming some risk in the network and managing to customer outcomes as opposed to specific network topologies. These changes have two opposing impacts on demand management: Reduced security levels result in higher asset loading at the time of augmentation. This increased loading results in an increased demand requirement for an equivalent demand management solution as well a typically reduced expenditure for comparison. An outcome based planning approach requires greater management of risk and contingencies, especially in the distribution network prior to an augmentation trigger being reached. The net result is an increased need for demand management to manage risk within the distribution network, increasing the number of demand management initiatives, reducing the size of each individual initiative and hence requiring a different approach to management and control. The change in the security criteria places greater focus on distribution management. Ergon Energy uses the Augex (Augmentation Expenditure) model to estimate forecast capital requirements for Sub-transmission and Distribution Capital expenditure. The estimated total augmentation requirement was $358 million (excluding overheads), compared to our proposed regulatory control period submission of approximately $314 million (excluding overheads). The Forecast Expenditure Summary Corporation Initiated Augmentation 2015 to 2020 discusses the inclusions and exclusions of this model in more detail, but results in approximately $45 million (excluding overheads) or around $70 million (including overheads) of capital expenditure removed from the forward program of works. This removal assumes increased use risk management initiatives via demand management. As mentioned above the security criteria changes transfer a portion of the network risk from sub-transmission to the distribution network resulting in a corresponding transfer of Augex costs. Overall, the changes to existing security criteria are forecast to save $600 million of capital expenditure by 2030 compared to the former criteria based on an Aurecon assessment in 2014, but this comes at the cost of increased operational response capability and risk management Referring specifically to the Distribution network, the initial forecast for the required program of work was $454 million excluding overheads. This has been reduced by $200 million to the proposed forecast of $248 million through higher levels of risk and corresponding risk management 7 in the distribution network 8. Demand Management in the Distribution network is different to the Sub-transmission network due to the more localised and faster growth rates, as well as the need to manage larger volumes of smaller quantities of demand in an effective manner. The impact of demand management on the Sub-transmission network is harder to define than for the Distribution network due to the changes in security criteria, load forecast and demand management evaluation since the initial program compilation in These changes resulted in major changes and reductions in the capital proposal, but the best estimate is that as part of the initial submission compilation proposed demand management programs impacted approximately $450 million of capital expenditure, about 50% of that draft program. Overall, based on the final submission, the level of capital expenditure reduction that the Demand Management Program supports over the regulatory control period is between $ million. 7 Ergon Energy s Distribution Network Augmentation Plan Risk Exposure 8 Forecast Expenditure Summary Corporation Initiated Augmentation 2015 to 2020 Page 25 of 49 Demand Management Overview

26 8 Strategic initiatives It is paramount that in addition to demand reduction Ergon Energy's Demand Management Program considers future network needs; helps manage risks within the network; and provides opportunities for improving asset utilisation. Traditionally the Demand Management Program has focused directly on deferring the need to augment the network by reducing peak demand. While that will still be a core function of future demand management, the program will need to consider a range of other issues to ensure that maximised asset utilisation while maintaining risk and customer reliability at acceptable levels, and returned overall value to our customers. The future success of the Demand Management Program will be dependent upon the creation of the strategic capabilities that enable the program to manage a higher number of demand initiatives effectively. The forecast higher numbers of demand initiatives are a result of the application of new security criteria transferring risk from the Sub-transmission network to the distribution network. 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. Ergon Energy are investing in a Demand Response Automation Server (DRAS), (see Figure 8- Demand Response Automation Server) which enables significant strategic capabilities to efficiently target, operate, measure, verify and control this increasing number of demand contracts. The DRAS will enable active demand management for Ergon Energy into the future allowing interactions with market participates in an automated seamless manner. As customers become more sophisticated in their energy use and new technologies, such as 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. 1'-~-----, I) ) 6---) \ J \.. Peak Demand Event DRAS Network Targeted Automated Contract Monitoring Measurement & Verification Figure 8 Demand Response Automation Server Page 26 of49 Demand Management Overview

27 The demand management strategic plan outlines programs designed to capture demand reduction potential identified through the Demand Potential Reduction Review. The strategic plan also contains recommendations on initiatives required to underpin effective Demand Management Programs and policy directions that Ergon Energy should pursue, such as: focusing on network areas of high value. focusing on products that offer the best MVA/$ return creating new cost analysis techniques for valuing demand creating market based demand activities researching and developing programs and partnerships with external organisations reviewing tariffs and conducting other internal systems and process reviews developing asset utilisation opportunities supporting risk mitigation minimising costs associated with customer reliability. 9 Demand Management Plan Ergon Energy s demand management plan for the regulatory control period comprises of five investment categories: 1. Committed programs projects which are already committed and will be in operation at the commencement of the regulatory control period , these programs consist of: a. Programs that are still actively recruiting new demand b. Programs that no longer recruit new demand and are operating existing demand under contract, e.g. contracted diesel generation. 2. Planned programs programs that are planned to commence in the regulatory control period based on the Base Step Trend (B-S-T) forecasting model with an uplift, these programs consist of: a. Network constraint and targeted programs including programs forecast to defer or avoid network assets. These programs are in line with the traditional application of the Demand Management Program and are in line with the B-S-T forecast. b. Network risk mitigation projects designed to use demand management to reduce network risks by managing load under control in an appropriate manner to manage network growth risks. The projects may be purely demand management or a hybrid solution of demand management and network investment to address network risks in an efficient manner and aligns to the step change in the B-S-T forecast program. c. Broad-Based and Regional - seeks to reduce demand on a system or regional basis and may include such initiatives such as increasing the number and range of appliances under load control on a broad basis and investigate the cost benefits of whole of network programs. 3. Smart Network initiatives that support reduced network investment via innovative network management schemes or customer signalling and interaction. 4. Demand Management Innovation Allowance (DMIA) initiatives funded under the Australian Energy Regulatory (AER) Demand Management Innovation Scheme (DMIS) to develop demand activity capability or knowledge. 5. Program management the costs associated with the ongoing maintenance of the programs, products and systems required to maintain the Demand Management Program. Page 27 of 49 Demand Management Overview

28 9.1 Network risk mitigation In order to extract the highest value from demand management activities Ergon Energy will be focusing the majority of the demand management activities on emerging network constraints, areas of network power quality issues, areas of network risk or areas where there is a high cost of customer unsupplied energy. These activities aim to minimise or eliminate the need for network augmentation over the short, medium, or long term. Analysis by Aurecon on the impacts of the safety net on Ergon Energy s feeder network indicate that over the next 15 years 45% of feeders are expected to exceed their 75% rating. This increase in risk to 2030 is likely to result in capital works increases without risk mitigation measures(aurecon Australasia Pty Ltd, 2014). Ergon Energy s reduced capital forecast for the Distribution Network Augmentation Plan and the risk exposure analysis highlight this increase in risk within the feeder network. As the augmentation capital program reduces expenditure, the Demand Management Program will increase the level of demand under control to help manage this increased risk. In the network constraint category, there are four main types of targeted demand management activities: 1. Identified network constraint where a network augmentation plan exists. These activities will follow the RiT-D rules where augmentation plans meet the RiT-D requirements. Generally, the use of demand management in these circumstances aims to enable appropriate timing of network investment by: a. deferring the investment for an efficient use of capital b. managing the potential growth risk to a point in time when the risk is better quantified c. ensuring that existing assets are operated at improved utilisation levels 2. Identified network risk. In these cases there may be an area where there is an identified mid to long-term risk of exceeding network capacity. In these cases, early intervention may enable the management of that risk, and influence future forecasts to the extent of mitigating the risk for a substantial time. Such cases may not have a credible network augmentation program due to timeframes and costs in which case using the Benchmark Cost of Supply will ensure the Demand Management Program uses capital efficiently. For cases of identified network risk, Ergon Energy s methodology will use the DRIM, the TAN, market engagement, and suppliers to support the creation of an active demand market. Ergon Energy expects that by enabling a demand market that targets areas of potential future constraints will ensure: a. lower costs demand management activities b. more certainty for energy services companies supping demand management products c. high visibility of emerging constraints and more risk coverage prior to network augmentation requirements. 3. Identified power quality issues. While demand management has traditionally targeted capacity constraint issues, there are instances in the Ergon Energy network whereby demand management may be able to provide voltage or power quality support. These instances require a range of different initiatives as capacity support may or may not resolve a power quality issue. Page 28 of 49 Demand Management Overview

29 4. Value of customer reliability The value of customer reliability (VCR) is a new methodology for valuing demand appropriately and instigating a Demand Management Program. The VCR calculations provide a straightforward methodology for valuing energy at risk, and comparing against the value of demand reduction to reduce the economic risk associated with unserved energy. As networks operate with higher utilisation, Ergon Energy envisages an active part for demand management in managing the risk associated with maintaining appropriate levels of network security and reliability. 9.2 Forecast Demand Risk Mitigation The Capital expenditure regulatory submission has been compiled on the basis of a low growth forecast for the forward regulatory control period This was felt to be the most appropriate scenario for the basis of the submission but does present some risk in the event that due to economic or weather related changes, peak demand again begins to grow. Were this to occur it would be preferable to use as much demand management as possible to manage any increases, rather than investing in network infrastructure. As a result, additional funding has been proposed in the Demand Management submission to cater for this risk. Low demand growth scenario Ergon Energy s control period augmentation expenditure is heavily influenced by the forecasted increase in maximum demand. For the control period Ergon Energy are forecasting a demand growth that is close to the low growth demand scenario as highlighted below in Figure 9 9. The economic factors impacting Ergon Energy s territory There is currently a downturn in commodity markets globally which have impacted the economic forecasts for Queensland and consequently the forecast for demand growth within Ergon Energy s supply territory. While these commodity prices are expected to remain depressed for some time there is a risk that the commodity market may undergo a resurgence, which will again drive up mining activities and impact the energy demand growth Forecast Expenditure Summary Corporation Initiated Augmentation 2015 Page 29 of 49 Demand Management Overview

30 Figure 9 - Ergon Energy total demand forecast maximum demand 2013 Ergon Energy s strategic goal of maintaining price rises below inflation has resulted in adopting the use of the low forecast, resulting in lower augmentation expenditure and an acceptance of increased risk within the network. The future risk for Ergon Energy is an inability to support a medium or high growth demand scenario without significantly impacting customer reliability, hence the consideration as part of the demand management program. As history has indicated, accurately predicating demand forecast is problematic, as demonstrated by both Ergon Energy s and the Australian Energy Regulator s forecasts for the regulatory control period in Figure 10. Page 30 of 49 Demand Management Overview

31 M aximum Demand-Actuals and Forecast 3,500, ,000 2,500,r... 3: ~ 2,000 1,500 1, <11- Maximum demand (MW)-AER forecast - Actual (MW) 50 POE Forecast with Demand Management included ,,---,--,--,---,,---,---,--,---,--~ YEAR Figure 10 - Maximum demand actuals versus Ergon Energy and AER forecast For the forecast, the different between a low, medium or high forecast as show in Figure 10, can be described as: Low forecast has a 90% probability of being exceeded. This is what the capital and hence demand management program has been based on. Medium forecast has a 50% probability of being exceeded and would result in capital expenditure being brought forward by two years. From a demand management perspective an additional two years of demand management deferrals would cost approximately an additional $22 million during the regulatory control period. High forecast has a 1 0% probability of being exceeded and would result in capital expenditure being brought forward by four years, resulting an approximately an additional $44 million of demand management requirement during the regulatory control period In balancing the probability and impact of this risk, Ergon Energy felt that an additional $10 million of demand management expenditure is appropriate, to use for risk mitigation in the event of an increase in the maximum demand to the medium forecast level. This is based upon the assumption that were a medium growth forecast to occur that at least 50% of this increase could be managed by demand management. 9.3 Operational programs These are programs that have reached an operational phase, with no expectation of there being new contracted demand in these areas. While there is no new demand to be contracted, the programs are still operational and will require ongoing program support and potentially customer payments. A classic example of such a program is the contracting of an embedded customer diesel generator. Once the demand is contracted and available for use in network operation, the program requires ongoing maintenance, measurement and verification, and operation. Page 31 of 49 Demand Management Overview

32 9.4 Broad-based and regional programs The use of incentive based system-wide demand management activities, such as the save a bomb pool pump program is reducing for Ergon Energy, in favour of programs targeting specific areas of network risk. This is primarily due to the difficulty in accurately valuing the costs and effectiveness of the system wide incentives across Ergon Energy s vast geographical network. Over the regulatory control period we forecast that tariff switching will deliver the majority of demand reductions for system wide activities. Over the regulatory control period Ergon Energy will apply learnings from broad-based activities in a much more targeted program roll-out to directly influence the risks in specific geographical areas. Currently Ergon Energy has no significant system-wide broad-based programs that will be operational at the commencement of the regulatory control period A review of broad-based (all of system), regional (large geographic area) and targeted programs will be performed determine the implications of the safety net, and the value of such programs. Future broad-based and regional programs are likely to focus on low cost high value activities as identified in the Ergon Energy Demand Management Final Report and the Demand Potential Reduction Review, and will include: consumer and market awareness campaigns of alternative tariffs such as off peak and time of use direct load control and interruptible load programs power factor correction programs that build strategic capabilities While there is no significant system-wide broad-based programs forecast, we intend to continue to monitor and investigate potential of system wide activities for appropriate opportunities. Of particular interest are non-incentive programs where-by Ergon Energy provides support and information to enable broad-based demand management such as the Your Power Queensland website. These programs are often lower cost and can provide high value. Ergon Energy will still perform residential demand management activities throughout the regulatory control period However, these activities will be targeted, levering the learnings from previous broad-based programs and applying them in a more focused manner. System-wide broad-based programs are generally difficult to value as they are applied across the entire distribution network, in areas where there is a capacity constraint, and in areas where no constraint exists, hence system-wide programs are: generally effective for mass market campaigns where the cost of customer recruitment needs to be low due to the low levels of demand gained per customer often used where there are a large number of customers, to engage and motivate the market used for residential peak demand issues due to low demand per customer and high volumes needed to achieve any significant demand reduction able by their very nature to impact system wide peak demand. Page 32 of 49 Demand Management Overview

33 This highlights a key challenge for Ergon Energy as: there is an overall softening of the growth of system level peak demand the maximum system peak demand days are primarily driven by a residential peaking load profile, i.e. early evening peak with the introduction of new planning methods there is a reduced need for investment in network augmentation, but a higher need for risk management The drive in efficiencies is focusing activities to specific areas of network risk These impacts create a divergence of business requirements: Required solutions for the residential peak demand growth which is generally best delivered in a broad based program of works. Reduced need and value in a broad based program, due to the flattening of the system peak forecasts (reducing demand in both constrained and not fully utilised areas) and development of new planning criteria. Ergon Energy will continue to monitor, examine, and test broad-based programs for their value; effectiveness and economic benefits prior to any extensive program roll out. 9.5 Smart network programs Smart network programs are designed to develop and test the benefits of operating a smarter network with a view to merging beneficial technology into business as usual over the longer term. Smart network solutions often use a range of technologies and aim to bring together network centric and demand side centric solutions into the one offering. Combining both network and nonnetwork offering into a single solution often provides efficient delivery of network utilisation improvement. As technology improves, Ergon Energy anticipates that new devices will become available, will enable higher levels of control and management over the network by the integration and use of demand side capabilities as standard operational practices for network management. To fully benefit from these emerging technologies Ergon Energy will need to understand the interactions of demand side capabilities, and to develop the systems and processes such that the technologies can seamlessly interact with the network. As well as the systems to leverage the developing demand side capabilities, Ergon Energy will need to support market development to remove barriers enabling these smart solutions to enter the network seamlessly. We will expand on the directions set in the Ergon Energy Demand Management Final Report and aim to close any capability or knowledge gaps in order to increase the efficiencies of the Demand Management Program. Page 33 of 49 Demand Management Overview

34 9.6 Demand Management innovation allowance The Demand Management Innovation Allowance (DMIA) is a valuable investment tool that enables the exploration of new technologies and is a means to develop capability and capacity for Ergon Energy s demand management activities. As such, the diversity of initiatives across the DMIA program reflects this commitment to lowering capital investments through finding alternatives for limitations driving network investments. The DMIA investment portfolio demonstrates a mix of projects exploring demand management opportunities to respond to capacity requirements; voltage management opportunities to respond to voltage fluctuations from photovoltaic customer take-up, and future knowledge and capacity building. Future DMIA projects are likely to focus on emerging risks and opportunities such as residential and commercial scale battery storage, integrated consumer energy management systems, and market led initiatives. Ergon Energy s DMIA program has progressed well over the regulatory period to date and has provided some valuable insights and knowledge as well as creating the opportunity to move innovation from concept to business as usual. The DMIA program continues to collaborate with innovation partners who are willing to contribute to DMIA projects and trials. Ergon Energy has found co-contributions are a useful way to lower Ergon Energy s innovation costs, share risks, and identify collaboration opportunities, share knowledge and capabilities and gain valuable insights into emerging markets. Table 4 provides a very brief description of DMIA activities undertaken throughout the regulatory control period. For a more detailed description, please see the Demand Management Innovation Allowance Outcomes Report Table DMIA project summary Name of project Residential AC Cleaning Maintenance Auto Demand Response Trial Chilled Water AC on SWER GUSS (REGUSS) Phase 2 Stockland North Shore Passive Air Cooling Trial (PACT) Smart Camp Feasibility Large Statcomm Description To evaluate the potential of an air conditioner cleaning product for use in demand reduction programs To evaluate the use of a demand response automation server for controlling and managing demand on a dynamic basis. This trial was successful and work is continuing for development of a BAU system. To investigate the use of small scale chilled water systems on SWER networks in small commercial environments. To develop capability and knowledge surrounding the use of energy storage and renewable energy systems for supporting peak demand, especially in SWER environments. Develop a range of engagement methods for actively working with customers and developers to consider peak demand in the building and purchasing of new homes. Trial passive air cooling systems for either direct or indirect cooling as a potential to reduce the peak demand created by thermal loads such as air conditioning. thermal Investigate the potential to work with mine camp developers and operators for reducing the camps impacts on peak demand. Evaluate the use of a large statcomm connected on the HV network for minimising the impacts of voltage rise from photovoltaic and enabling dynamic voltage control. Page 34 of 49 Demand Management Overview

35 Name of project Urban Statcomm SWER Statcomm Smart Voltage Regulator Validation (SVR) Solar Energy Management Systems Network Embedded Solar Thermal Cool Roof Trial RECESS Building Design Led Capacity QUT Super Conductor Customer photovoltaic Control LED Street lighting Description Evaluate the use of a large statcomm connected on the LV network for minimising the impacts of voltage rise from photovoltaic and enabling dynamic voltage control. Evaluate the use of a large statcomm connected on the SWER network for minimising the impacts of voltage rise from photovoltaic and enabling dynamic voltage control. Validate the capabilities for a smart voltage regulator to minimise the voltage rise impacts from photovoltaic installations on the LV network. Evaluate the use of desiccant cooling systems in a residential or small commercial environment as a potential low demand opportunity for climate control. Evaluate the potential of embedded solar thermal generation systems across the Ergon Energy network and develop an understanding of how they might be utilised in network constrained areas for peak demand support. Evaluate heat reflective paint for use in reducing the peak demand load from air conditioning. Develop a range of electrical contractor engagement methodologies for engaging the energy services market about demand, photovoltaic and other network related issues. This program was successful and is not operational. The investigated Design Led Innovation within a succinct project as a means of prototyping the internal business development requirements with a view to scaling across the business. The project identified, and reported on the barriers to the uptake of Design Lead Innovation within the business. Investigate the use of high temperature superconductors for enabling peak demand support and reducing the impacts of peak demand growth on the network. Investigate the use of customer owner inverters with smart VAR controls for reducing the voltage impacts on the network. Investigate the potential for LED street lighting to be utilised for peak demand reduction and develop an understanding of the barriers for deployment. Page 35 of 49 Demand Management Overview

36 9.7 Demand Management portfolio summary Table 5 summarises the key Demand Management Programs commenced in the regulatory control period, with a complete list of the projects and annual costs detailed. This includes the projects highlighted to continue into the regulatory control period. Table 5 - Summary of key demand activities Name of project Scope of program Location of program Pool Pump Program Rewards Based Tariff Energy Sense Communities Know Your Power QLD (YourPower Queensland) Network Demand Management Mt Isa Moranbah Security Of Supply South Mackay - Energy Sense Market Gordonvale Meringa Security Of Supply Malanda Ndemand management, Develop and deploy a range of initiatives surrounding encouragement of pool pumps to off peak tariffs or the installation of energy efficiency pool pumps. Create and deploy a program of education and awareness for the pool service industry to change business practices to encouraging pools to be connected to controlled tariffs and the adoption of energy efficient pool pumps. Gauge consumer behaviour towards time of use tariffs (particularly around trading off convenience against cost) to enable tariffs to be tailored to maximise both customer participation and return a net financial benefit to the networks Utilise a network constraint in order to develop a range of strategic capability surrounding smart grid technology, demand side solutions and traditional network solutions. Utilise the information to support future businesses cases and where appropriate implement the learnings into business as usual. Maximise the business learning's outcomes from the existing and planned smart network related initiatives within Ergon Energy that are currently not fully utilised. The Energy Sense Communities program included 34 sub projects that were all commenced with a view to supporting the overall ESC outcomes. Establish a single point of reference for energy information that would dispense free advice and customer education on a diverse range of energy / electricity issues and demand issues. Reduce enough peak demand to defer the proposed Sunset Substation by 3 years. Manage existing capacity constraint at Moranbah through customer embedded generation solution until a zone substation can be constructed and energised. Development of new market and customer engagement channels, incorporating the DRIM and TAN to reduce peak demand and optimise future network augmentation in the South Mackay area. Contract diesel generation in the Gordonvale area in order to relieve the pressure on the network surrounding Mt Peter. Support the mitigation of risk in the high growth area of Mt Peter. Mitigate the risks in the network in the Malanda area enabling a reduction in VCR, improved power quality and increased switching capacity in the Malanda network. Broad based Broad based Townsville Broad based Mt Isa Moranbah Mackay Gordonvale Malanda Page 36 of 49 Demand Management Overview

37 Name of project Scope of program Location of program Barcaldine Network Support Agreement, North Queensland Load Harmonisation Program Contract to renew the network support agreement for the Gas turbine at Barcaldine. Due to the high cost of the Network Alternative, it has always been the preferred approach to use embedded generation to manage security to the Barcaldine and Central West areas. The period of the contract is five years, after which time the local security requirements will be reviewed again, in line with the potential renewal of this contract. The program was to enable the alignment of the operational times of the controlled load tariffs in Townsville to be the same as the rest of Queensland. Due to historical use of controlled loads in Townsville there were many devices connected to the controlled tariffs that could not be switched on a regular basis without significant customer impact. The program aligned not only the operation of the controlled loads but also the types of loads that were connected to the controlled tariffs. Barcaldine Townsville Table 6 lists the programs that Ergon Energy forecasts to continue either in operation or in contracting of new demand at the commencement of the next regulatory control period. While currently these projects are forecast to be operational at the beginning of the regulatory control period , Ergon Energy reviews projects on an ongoing basis and will, if necessary, amend the programs in line with network risks. Table 6 - Summary of demand activities continuing into Name of project Likely Program actions Forecast project status Estimated costs ($ 000) Bohle Network Demand Management Continue project and recruit demand in line with demand targets and network conditions. Contracting demand 870 Cairns Northern Beaches Network Demand Management Monitoring of the greenfield risk in Cairns will determine the levels and type of demand management required for maintaining network risk levels. Contracting demand 400 Charleville Network Demand Management Continual review of the project and the network risk will determine the levels of demand management required. Contracting demand 750 St George Network Demand Management The St George project is continually reviewed to ensure the outcomes are still supply acceptable levels of benefit. Contracting demand 580 Your Power Queensland Website continually reviewed to ensure that value is derived from the content, project forecast to be in maintenance mode. Maintenance 400 Network Demand Management on SWER Continual review of SWERs and the associated risks is forecast to create an on-going range of SWER initiatives. Contracting demand 2,500 Page 37 of 49 Demand Management Overview

38 Name of project Likely Program actions Forecast project status Estimated costs ($ 000) Network Demand Management Mt Isa Moranbah Security Of Supply South Mackay - Energy Sense Market Gordonvale Meringa Security Of Supply Kingaroy network demand management, Malanda network demand management, Duaringa / Dingo network demand management, Barcaldine Network Support Agreement, Required demand expected to be contracted and only on-going maintenance, measurement and verification will be required. Required demand expected to be contracted and only on-going maintenance, measurement and verification will be required. Continual review of project in line with expected network augmentation completion dates will occur. Program forecast to be in maintenance mode with no new demand required. Activities will include continual review and monitoring of the market activities to support learnings for other projects. Required demand expected to be contracted and only on-going maintenance, measurement and verification will be required. Continual review of project in line with expected network risks and greenfield developments. Powerfactor correction actions across Kingaroy zone substation will be monitored to ensure that power factor is maintained. Generation forecast to be contracted with the program in operational phase and no new demand will be targeted. Generation forecast to be contracted with the program in operational phase and no new demand will be targeted.. Generation contracted with the program in operational phase and no new demand will be targeted. The Barcaldine network support agreement costs are not included in the demand management operational forecast expenditure. Maintenance 900 Maintenance 1,230 Maintenance 1,100 Maintenance 817 Maintenance 20 Maintenance 500 Maintenance 150 Maintenance 10,000 Ergon Energy s forecast Demand Management Program of works currently includes a range of projects that target both reduction in network risk and the deferral of network assets. In line with prudent and efficient use of capital, these programs will be evaluated, taking into consideration the new safety net and the value of customer reliability. In addition to the identified projects Ergon Energy are currently investigating the risk in the feeder network and will be instigating programs to actively manage feeder risk. These programs will be based on the Distribution Annual Planning Report (DAPR) outputs, and forward forecasts of feeder risks. While the program is not fully developed at the time of this submission, early investigations have highlighted there will be many opportunities to use demand management for feeder risk mitigation. Page 38 of 49 Demand Management Overview

39 Table 7 lists the areas of growing network risk where demand management is likely to form part of the suite of solutions that may commence in All projects will be managed through the Ergon Energy gated business case methodology to ensure the network risk justifies the investment in demand management in these areas under the new security of supply criteria. Table 7 - Areas of network risk and potential demand management activities Name of project Likely program actions Location North Mackay - Planella Cairns Northern Beaches Phase 2 Kingaroy Phase 2 Gracemere Harvey Bay Kunawarara Lower Burnett Continued residential growth in the Planella area highlight the need to manage the risk in the area and ensure that capacity will remain available and VCR can be managed. Cairns Northern Beaches area has significant greenfield growth risk combined with the Kamerunga zone substation capacity limitations is likely to result in further demand activities in this area. The primary risk in the Cairns Northern Beaches area is the proposed development of the Aquis hotel and casino complex which is forecast to commence construction within the next AER regulatory control period if it achieves the required approvals. Kingaroy power factor remains a constant watch program, if the need to continue to improve the power factor in this area arises a second program will commence to encourage the uptake of power factor correction. With the changes in tariffs to include a kva tariff it is likely that any future activities will involve awareness and education as opposed to direct customer incentives thus reducing the program cost. There is significant growth risk in the Gracemere area and an active investigation into possible solutions to the embodied demand risk. The area is being investigated for credible network and non-network solutions. The Harvey Bay area is a high growth area with significant risks, the area is supplied by a radial network which increases the levels of VCR and risk. With the removal of the network augmentation plans in the area demand management is likely to become a key risk mitigation tool in the area. On-going issues with the quality of supply in the Kunawarara are may require demand management activities to support power quality corrections. The augmentation projects for the lower Burnett have been removed from the control period forecast, however the risk associated with VCR remain as the Lower Burnett is a radial feeder. Demand management will be investigated for supporting the network and reducing the risk associated with reliability. North Mackay Cairns Kingaroy Rockhampton Maryborough Rockhampton Burnett Page 39 of 49 Demand Management Overview

40 Name of project Likely program actions Location Bundaberg Burnett Heads Warwick/Stanthorpe Western Townsville Emerald Feeder growth risk mitigation North Bundaberg has significant greenfield and brown field growth risk in the area. This combined with the potential for a return to business as usual after the floods highlight this area as a potential demand management risk mitigation area. Burnett Heads has growth risk associated with port development. The growth risk has implications on the feeder network and is a likely candidate for feeder based demand management activities in order to manage the risk. Continued risks associated with the risk of failure of the main supply route highlight Warrick as a key area of network risk. The likely solution is a combination of network and demand side opportunities which are continually being investigated and reviewed. Townsville continues to have general growth across the area. Ergon Energy has active programs in the Townsville area that have proven successful. As the north west develops there may be need to manage the growth risk to time any possible network augmentation appropriately. The central highlands area is one of risk due to the continued expansion of mining interests in the area. Emerald township has been growing rapidly over recent years to the point where there is developing risks on the supplying feeders. The DAPR highlights feeders that are likely to require augmentation in the next 2 years. However through the AER period there are a number of feeders that are likely to become constrained. Early intervention with a Demand Management Program can mitigate the growth risk and the need to perform network augmentation. These programs will be actioned on a case-by-case basis on the higher risk feeders, this program is akin to a targeted broad scale program. Bundaberg Burnett Warwick Townsville Emerald State wide Page 40 of 49 Demand Management Overview

41 9.8 Demand reduction targets For the regulatory control period , Ergon Energy is targeting an overall additional total reduction in demand of 80 MVA. During the regulatory control period there were two significant events that heavily affected Ergon Energy s Demand Management Program: 1. The North Queensland Load Harmonisation program delivered 39.9MVA of load reduction. This was a one off program to align the controlled tariffs in Townsville with the rest of Queensland, no other such opportunities are forecast to be achieved in the control period The load harmonisation project delivered a large block of demand reduction at low cost per MVA, hence future demand reductions are expected to have a higher cost per MVA resulting in a step in the B-S-T forecast. 2. The Townsville Network Demand Management pilot was in full operation and delivered 20MVA of demand reductions. This $7.7 million pilot was funded by the Queensland Department of Energy and Water Supply and enabled Ergon Energy to develop some of the key capabilities for demand management. This program delivered significant demand reductions that were not directly funded by Ergon Energy and the funding will not be available during the control period for which some of the B-S-T step increase can be attributed. Ergon Energy forecasts a final demand reduction of 135MVA over the regulatory control period, which includes 39.9MVA from the North Queensland Load Harmonisation Program, and 21MVA from Townsville Network Demand Management pilot reductions. Removing these two one-off programs from the overall net result leaves a demand reduction of 74MVA from capital deferral and other business as usual demand activities. There are three step changes forecast to affect the Demand Management Program over the regulatory control period , primarily due to the application of the safety net. 1. The number of zone substation and Sub-transmission constructions likely to be triggered are forecast to significantly reduce as the safety net application enables Ergon Energy to assume more risk. 2. There will be an increased need to cover the VCR risk that will build on the zone substations as the demand levels exceed the traditional N-1 security criteria. 3. The resulting reductions in Sub-transmission augmentation and increased demand levels will increase the risk in the distribution feeders requiring more risk levels 10 coverage. Therefore, the Demand Management Program expects to reduce the number of capital deferral programs due to the overall reduction in capital works and increase the number of risk mitigation programs. Table 8 gives an overview of the compilation of the Demand Management targets by year, in addition to this Ergon Energy are forecasting an additional 20MVA of demand reduction that will be targeted if the demand growth revert to a medium or high demand growth scenario. 10 Security Criteria Review Aurecon 2014 Page 41 of 49 Demand Management Overview

42 Table 8 Demand reduction targets Additional Demand Targets Total Broad-based, regional and EMR Safety net risk mitigation Network constraint targeted programs Total Additional Demand This is in addition to the pre-existing demand Ergon Energy is forecast to have under control at the commencement of the regulatory control period as summarised in Table 9. Table 9 Demand under management Total demand estimated to be under contract June 2014 MVA Existing demand under contract 21 Barcaldine 20 Total demand estimated to be under contract June Across the five-year program the largest share of demand reductions planned are from programs that target network constraint and risk locations, rather than broad-based programs. In addition to the forecast demand reductions, expectation is that there will be additional reductions due to other factors including the rising electricity costs, changing price signals, the influence of government policy and standards, and new customer connections. 9.9 Payments to embedded generators Payments made to non-network owned embedded generators over the regulatory control period, including actual payments and forecast payments for the financial year are detailed in spreadsheet Embedded Generators and in Table 12 Page 42 of49 Demand Management Overview

43 9.10 Demand management forecast operating expenditure Ergon Energy s demand management expenditure as shown in Table 10 is forecast to consist entirely of operating expenditure and to constitute $70.5 million of expenditure on a range of activities including demand management programs, strategic initiatives, operational programs, DMIA, demand forecast risk mitigation, and program management. Table 10 - Forecast demand management expenditure Demand Management Portfolio Total ($'000) ($'000) ($'000) ($'000) ($'000) ($'000) Committed works 3,292 2,455 1,430 1,189 1,008 9,374 Contracting demand phase 1,892 1, ,777 Maintenance/operational phase 1,400 1,400 1, ,597 Planned programs 4,326 6,113 8,073 8,662 9,682 36,856 Network constraint targeted programs 2,246 3,333 4,493 4,482 4,802 19,356 Safety net risk mitigation 1,500 2,200 3,000 3,600 4,300 14,600 Broad-based and regional ,900 Smart Network Program - EMR 1, ,403 Demand Management Innovation Allowance 1,000 1,000 1,000 1,000 1,000 5,000 Program Management ,875 Medium/high growth demand scenario 1,000 3,000 3,000 3,000 10,000 Total 10,956 11,318 12,243 12,576 13,415 70,508 Ergon Energy s forward forecast of demand management activities is forecast from the B-S-T model using a base year of , plus a step change to reflect forecast requirements for demand management operating expenditure across the regulatory control period. The Demand Management Program is forecast to offset the capital works program by $70-$200 million in real terms over the control period. The step change for the Demand Management Program is due to several factors: The application of the new security criteria which: o require Ergon Energy to manage the associated risk with lower (than traditional augmentation) costs afforded through demand management solutions o result in increasing risks in feeder network requiring increased levels of sophistication in the Demand Management Program. The need to increase the numbers of demand contracts requires investment in new systems, procedures and process in order to be able to efficiently manage the increases in demand opportunities. In order to efficiently manage the number of demand contracts and enable the management of the loads will require a range of automation systems to ensure that the feeder risks are managed appropriately. Page 43 of 49 Demand Management Overview

44 Ergon Energy s strategies are to enable market delivery of demand and to engage the market in network risks and issues. This market engagement model is a change in direction from the previous demand management activities and as such a range of capabilities will be developed in order to support market activities. The gradual erosion of existing excess capacity in the network over the regulatory control period combined with a reduced capital expenditure program will increase the network risks and hence need for demand management to support the operation of the network at higher levels of capacity. A focus on capital expenditure reduction increases the need for non-traditional solutions to managing the network risks resulting in increased expenditure in programs such as demand management. Over the regulatory control period Ergon Energy received $7.7 million of external funding from the Queensland Department of Energy and Water Supply to deliver 20MVA of demand reduction in Townsville. This funding expires in 2015 and will not be available for the control period. The North Queensland load harmonisation program delivered a significant demand reduction at a low cost per MVA due to the nature of the project. Over the next control period such low cost demand reductions are not expected to be available. Enabling the uptake of new technologies by our customers, such as electric vehicles and energy storage systems and a prudent and efficient manner. Protect against a medium to high forward forcast maximum demand growth forecast Forecast payments to embedded generators Ergon Energy forecast the following payments to non-network owned embedded generators for the regulatory control period This forecasting is for payments to embedded generators only and excludes forecast payments for other demand initiatives such as call off load, energy efficiency, or load shifting. Barcaldine is not included in the demand management financial reporting but is included in the summary of embedded generators. This forecast is subject to Ergon Energy s gated business case process and continual review of demand management projects to ensure that efficient value is being delivered. At any time, the demand management projects may be accelerated, slowed, or cancelled if a more efficient solution to risk mitigation exists. Table 11 - Forecast generator payment summary Forecast generator portfolio ($'000) ($'000) ($'000) ($'000) ($'000) Total ($'000) Forecasted generator payments, inc Barcaldine 4,356 4,419 4,153 4,366 4,522 21,816 Excluding Barcaldine 2,256 2,319 2,111 2,323 2,372 11,381 Existing contracts excluding Barcaldine 1,960 1,725 1, `6,597 Forecast new contracts ,384 1,564 4,784 Barcaldine* excluded from demand management budget 2,000 2,000 2,000 2,000 2,000 10,000 Page 44 of 49 Demand Management Overview

45 Table 12 - Forecast expenditure on embedded generators Forecast generator portfolio ($'000) ($'000) ($'000) ($'000) ($'000) Total ($'000) Forecasted generator payments, inc Barcaldine 4,356 4,419 4,153 4,366 4,522 21,816 Excluding Barcaldine 2,256 2,319 2,111 2,323 2,372 11,381 Existing contracts excluding Barcaldine 1,960 1,725 1, ,597 Forecast new contracts ,384 1,564 4,784 Barcaldine* excluded from demand management budget 2,000 2,000 2,000 2,000 2,000 10,000 Mt Peter Supply Reinforcement (Gordonvale) Dingo/Duringa Mt. Isa DR Alpha Malanda DR Moranbah DR South Mackay DR - Energy Sense Market Bohle Industrial area Page 45 of 49 Demand Management Overview

46 10 Summary Ergon Energy has created a successful and active Demand Management Program during the regulatory control period and considers demand management a credible option to network investment as demonstrated through the performance of the Demand Management Program to date, which has overachieved demand targets for the regulatory control period. Throughout the forthcoming regulatory control period and beyond we expect to expand and transform the Demand Management Program from a reactionary program dealing with deferment of already identified network augmentation plans, to a proactive program that actively seeks out and mitigates areas of network risk in an efficient manner. Proactively working with customers early in the risk cycle is seen as the least cost method for reducing the impacts of demand growth, helping to improve asset utilisation, and protecting against changes to maximum demand growth. Ergon Energy considers the regulatory control period as a significant and exciting time for the Demand Management Program with a change to demand operations from demand contractor, to market enabler. Over the next few years, Ergon Energy will roll out some key strategic investments in demand management aimed at creating an active and engaged demand market, including: releasing of a Queensland wide demand incentive map expanding the Trade Ally Network developing standardised products for demand management creating internet portals for demand suppliers to receive information on demand activities. The transformation and expansion of the Demand Management Program has enabled us to support a reduced capital works program and to support the increasing levels of risk forecast to develop within the Ergon Energy network. This enables the Demand Management Program to support a reduction of $70-$200 million in the augmentation program. Ergon Energy s Demand Management Program is transforming to serve the needs of our customer and support Ergon Energy s evolving business model. Page 46 of 49 Demand Management Overview

47 Annex A Demand management outcomes reports See attached demand management outcomes reports for a summary of the demand management activities that have occurred for the four years of the regulatory control period to date: Demand Management Outcomes Demand Management Outcomes Demand Management Outcomes Demand Management Outcomes <Check this is the latest Process Zone version before use> Page 47 of 49 Demand Management Overview

48 Annex B Ergon Energy processes Figure 11 NA Plan Network Investments Figure 12 NA Conduct annual planning review <Check this is the latest Process Zone version before use> Page 48 of 49 Demand Management Overview

49 Figure 13 NA Conduct regulatory investment test <Check this is the latest Process Zone version before use> Page 49 of 49 Demand Management Overview