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