Roadmap for Demand Response in the Australian National Electricity Market

Transcription

1 DRAFT Roadmap for DR in the Australian NEM Roadmap for Demand Response in the Australian National Electricity Market December 2006 The Australian Team International Energy Agency Demand Side Management Task XIII (Demand Response Resources)

2 DISCLAIMER The views expressed in this publication are those of the authors at the time of writing. They are the views of individual team members, and do not necessarily represent the views of the organisations which they represent. The Australian IEA DR Task XIII Team and its members do not in any way guarantee the accuracy of any information or data contained in this publication and accept no responsibility for any loss, injury or inconvenience sustained by any users of this publication or in relation to any information or data contained in this publication. No person should rely on any information or data contained in this publication without independently verifying its accuracy, currency, completeness and relevance for their purposes. All users of this publication should always obtain independent professional advice before making any investment or business decisions in relation to any information or data contained in this publication. Please note that all dollar figures expressed in this document are in Australian dollars (AUD) unless otherwise specified. Reference to government refers to the Australian Government, not to the state governments, which are described as such or delineated by state. For more information please contact Terry Jones, the Australian Task XIII Team s Country Expert, at Terry.Jones@csiro.au. Page 2 of 44

3 TABLE OF CONTENTS EXECUTIVE SUMMARY INTRODUCTION Background About Task XIII Reasons for Australian participation in Task XIII Demand Response defined The purpose of this Roadmap The Roadmap focal question Task XIII: Global work Valuation of DR in the NEM THE DEMAND RESPONSE ROADMAP Understanding Task XIII modelling outcomes...21 ABBREVIATIONS...23 APPENDICES...24 NOTES The Demand Response vision statement Roadmap timeline Factors influencing Demand Response in the NEM Major benefits of Demand Response in the NEM Roadmap challenges The way forward THE EMERGING DEMAND RESPONSE INDUSTRY An international perspective An Australian perspective THE VALUE OF DEMAND RESPONSE IN THE NEM Modelling results Page 3 of 44

4 EXECUTIVE SUMMARY The national electricity market The Australian national electricity market (NEM) is in a state of growth and development. It is expected that peak demand will continue to grow faster than total energy consumption. Subsequent deterioration in load factors, for both networks and generators, will create upward pressure on prices and may result in reduced reliability. Cross-subsidies across user groups with different load profiles are likely to become increasingly difficult to maintain. Changes in the regulatory environment and the rollout of smart meters in some, if not all NEM states will encourage the development of more cost reflective tariffs, which send better price signals to consumers at times of high system demand. Additionally, climate change, consumer income growth and technology changes, among other factors, are increasingly impacting on energy consumption. There have been growing concerns about the consequences of increasing peak demand growth in most Australian states, largely driven by the rapidly increasing penetration of residential air conditioning and the potential impact this can have on the security of electricity supply, the wholesale price of electricity and price volatility. It is expected that in the mid to long term tens of billions of dollars of investment will be required to maintain an adequate supply reserve and to address emerging network constraints. In short, the challenges are extensive and complex. Innovative solutions are needed. Demand Response where electricity demand is reduced at times when wholesale market prices are high or when system reliability is jeopardised, is a logical and economically viable way forward. The bigger picture It was unclear whether the Australian national electricity market was sufficiently capturing all of the existing Demand Response (DR) opportunities. This concern is shared by markets globally and in 2004 led to the International Energy Agency s Demand-Side Management Program instigating a project (Task XIII) to investigate and foster the wider take-up of Demand Response in competitive electricity markets around the world. The Australian Task XIII Team Australia s involvement in this international project enabled access to the best thinking, techniques and technology around the world. In applying this knowledge base to the Australian context, the Australian Task XIII Team has been able to test future scenarios, assess the value of Demand Response in the Australian national market and propose a way forward for government and industry. The Roadmap focal question The Australian Task XIII team defined a focal question upon which this Roadmap is centred: How can DR be employed in the NEM to provide improved competitiveness, efficiency and reliability and how will DR evolve in the NEM up to 2025? The vision for demand response As a result of the analysis undertaken through Task XIII, the vision for Demand Response in the national electricity market over the next two decades is that: By the year 2025, Demand Response can deliver around an additional 5% reduction in system peak demand, or approximately 2,800 MW of load reduction, compared to the current situation. Page 4 of 44

5 Demand Response will be a critical factor in the future management and efficient operation of Australia s electricity market. Achieving this goal will have significant system-wide benefits: based on a range of forecast assumptions, the net present value of system-wide market benefits (but excluding network related benefits) 2007 to 2025 is between $363 to $949 million, depending on the way in which supplyside resources are chosen and used. Major benefits The wider uptake of Demand Response will benefit the market in a number of ways because it can: improve system reliability. reduce transmission and distribution congestion and save and / or delay transmission and distribution capital expenditure. increase the security of supply by substituting voluntary load shedding for guaranteed load shedding. provide a means for avoiding the use of expensive fuels for meeting peak demand. defer or avoid the need for investment in peaking generation plant. provide a check on the market power of generators. reduce final prices to consumers by optimising use of all energy options. Understanding Task XIII modelling outcomes As part of Task XIII, the Australian team commissioned CRA International (CRA) to undertake a detailed economic analysis of the potential value of Demand Response in the national electricity market. The modelling compared the possible outcomes of the future national market with and without Demand Response. Four Demand Response programs were modelled based on three market scenarios from 2007 to The three scenarios modelled were: Least-Cost Base Case Scenario in which system requirements are assumed to continue to be met by supply-side resources and cost-effective Demand Response is deployed to provide increased system reliability (i.e. reduce unserved energy) and to reduce operating costs where operating costs are assumed to be represented by the short-run marginal cost (SRMC) of generators in the NEM. Market Bidding Scenario in which the same amount of Demand Response is deployed as in the base case scenario, but generators are assumed to bid strategically in the NEM rather than at SRMC. DR benefits come, as they did in the base case scenario, from improved reliability and reduced operating costs, but the proportion represented by operating costs increases significantly. Bidding strategically refers to the withholding of cheaper resources by offering part of the generation capacity in the market well above its marginal cost. Integrated Resource Planning Scenario in which the selection of supply and demand-side resources that minimise total system cost for meeting aggregate is made via a central planning function. Page 5 of 44

6 The four Demand Response programs modelled were: Callable Large Commercial & Industrial (Callable C&I) this program targets customers with at least 0.25 MW load reduction, either from load shedding or switching on standby generation. Residential Direct Load Control (DLC) - this program allows residential air conditioners to be cycled and pool pumps to be interrupted under the remote control of a utility. Eligible customers include households with ducted (central) refrigerative air conditioners or large split systems (input power of 2 kw or greater). Price Responsive Load for residential customers this program is based on a Critical Peak Pricing program, running in summer with potential market size being the same as households participating in the residential DLC program. Voluntary Load Reduction for small business customers (VLR) this program is similar to the callable C&I program but is targeted primarily at Small to Medium Enterprises. The modelling results indicate that Demand Response can provide substantial benefits to the national market under all three scenarios. Results of the net present value of benefits, using a discount rate of 8.8%, are shown in Table 1. Table 1: Summary of cumulative DR benefits 2007 to 2025 Scenario type Least Cost Base Case Market Bidding Scenario Total Net Present Value System Cost Savings Average Savings $/MW/Year $363 million $185,000 / MW / year $949 million $484,000 / MW / year IRP Scenario $555 million $283,000 / MW / year The modelling assumptions utilised by Task XIII are considered conservative and the results do not take into account: any savings that would accrue from deferral or avoidance of transmission or distribution system network augmentation. the value of greenhouse gas reductions or any other environmental impacts. any Demand Response impacts that could result from more cost-reflective price signals in retail contract or tariff structures and levels (other than the Price Responsive Load Program). The modelling indicated that the Callable C&I program represents approximately 85% of the DR potential. The rest of the programs are selected at varying levels in the model but in combination represent a less significant relative contribution to the overall DR resource. Of the NEM jurisdictions, New South Wales contributes the biggest share of Demand Response potential both in summer and winter (38% of total load reduction), followed by Queensland (28%), Victoria (23%), South Australia (8%) and Tasmania (3%). It is recognised that the rapidly increasing penetration of air conditioning in the residential and small to medium enterprise customer Page 6 of 44

7 segments, is the core driver of growing peak demand in most Australian states. The application of Direct Load Control, which focuses on residential air conditioning and pool pumps in the summer months, is strategically important in addressing this problem and is currently a topic of interest. The Task XIII modelling suggests that, despite its strategic importance, the residential Direct Load Control program contributes a comparatively small amount of potential (6%) to the overall value of Demand Response in the NEM. This is partly due to the relatively low market potential estimated for this product and partly due to its relatively high cost per unit of load reduction. If the cost of implementing Direct Load Control programs can be reduced, or if programs can achieve somewhat higher uptake rates than were assumed for this modelling, Direct Load Control could play a larger role, although it is still likely to deliver less load reduction than a Callable C&I program. DLC is generally more expensive that the marginal cost of reserve and is therefore not selected to full potential, whereas other DR options reach their full potential by This imbalance between the different programs is in part a product of the relatively small eligible population of both DLC and Load Responsive Price programs. It has been assumed that only customers with only larger air conditioning systems will be targeted for these programs, and that take-up amongst these customers will be moderately above the take-up in other jurisdictions 1. Of the remaining two programs modelled, Price Responsive Load and Voluntary Load Reduction, it is recognised that although the results indicated these programs represent a relatively small contribution to total Demand Response potential, these programs are cost effective and can provide important contributions to the NEM. A collaborative approach Governments (both state and federal), regulators and industry all have a role to play in facilitating the greater uptake of Demand Response in the national electricity market. The benefits of Demand Response are widely dispersed and require government and industry to work together to realise these benefits. Some of this work has already begun. For example, the Council of Australian Governments (COAG) has requested that the Ministerial Council on Energy (MCE) develop a national implementation plan for the roll-out of smart meters beginning in 2007, based on common technical standards agreed by COAG. A mandated roll-out of smart meters has already been agreed in Victoria and will commence in Specifications for the functionality associated with the smart meters will shortly be finalised and customer response trials to assess the level of residential responsiveness to different tariff structures will commence in Other promising developments include the Demand Side Management pilot programs in South Australia and the Commonwealth Government s Solar Cities trials which will include smart metering, load control and more cost-reflective pricing. The way forward A significant investment in the development of Demand Response capability in the NEM is necessary to ensure competitiveness, efficiency and reliability in the national market. Significant investment is needed in DR infrastructure to enable markets to communicate the value and cost of electricity supply. This shortfall is not due to the availability or its cost, but to Page 7 of 44

8 current market designs that fail to recognise and correct for the barriers that exist for the investment in such technology 2. The outcomes of the Australian Task XIII project have highlighted the significant and tangible benefits of Demand Response s role in the future management and efficient operation of Australia s electricity market. Enabling Demand Response will be best served within a market structure that understands and promotes the benefit of allowing peak pricing signals to operate effectively. To facilitate the development of Callable C&I DR programs further work is required to: Investigate ways to provide better transparency in the market for Demand Response resources this is especially the case for business consumers entering bilateral contracts, where there is an information asymmetry in favour of the retailers. Develop information tools to enable business consumers to better assess the Demand Response resource they have available to sell into the market. Identify opportunities to facilitate the use of standby generation in Demand Response programs, taking into consideration the existing limitations imposed by air quality requirements. Investigate the option of using appliance standards to facilitate Demand Response, either through standards relating to standby generation or a requirement for HVAC system controls to be suitable for participation in Demand Response programs. because they directly address the increasing penetration of residential air conditioning - a key driver for increased peak demand. A number of further actions could be taken to encourage the development of these products: Collate and disseminate key findings from current trials, including ETSA Utilities, Solar Cities, Sydney Demand Management & Planning Project and the Victorian smart meter trials this should be packaged both for industry stakeholders and the general public. Undertake detailed technical (end-use metering) and behavioural studies to obtain better data on the relationship between appliance use and peak demand and the loads that consumers are most likely to control under a CPP regime. Continued support for issues addressed by the A-HELP project to develop communication standards to facilitate direct load control of appliances and to investigate the feasibility of using appliance regulations to ensure that where relevant new products sold are already enabled for DLC. While the modelling undertaken for this project suggests that residential Direct Load Control and Critical Peak Pricing will play a relatively minor role in delivering value to the electricity market, these products still have a role to play due to their potential benefits in residential areas that have network constraints, their relatively fast response time, and Page 8 of 44

9 1. INTRODUCTION 1.1 Background This roadmap was developed by the Australian Team which participated in the International Energy Agency s Demand-Side Management Program s Task XIII on Demand Response Resources (Task XIII). This project is an international collaborative effort designed to help foster the development of Demand Response in competitive electricity markets around the world. The Australian Task XIII Team members, which funded Australia s involvement in this task and contributed to the preparation of the Team s outputs, including the development of this Roadmap, were (in alphabetical order): Australian Greenhouse Office CSIRO Energy Transformed Flagship Department of Infrastructure Victoria, Energy & Security Division EnergyAustralia Energy Retailers Association of Australia Electricity Supply Industry Planning Council of South Australia Origin Energy Sustainability Victoria A full list of the Australian team members is included in Appendix A. The Team would like to acknowledge the assistance provided by other stakeholders, including NEMMCO, Energy Response and Energy Users Association of Australia who provided assistance with the DR modelling project. 1.2 About Task XIII The International Energy Agency (IEA) is a collaboration of 26 countries with the purpose to promote the conditions, in the context of energy, for each of its member countries to make the fullest possible contribution to sustainable economic development. The IEA Demand-Side Management (DSM) program is an international collaboration working to clarify and promote opportunities for solutions to inefficiencies in the demand-side of the energy equation. Such solutions include load management, energy efficiency, strategic conservation and related activities. The Task XIII project is one of a number of current tasks of the IEA DSM program. There are eleven countries participating in the Task XIII project, namely Australia, Denmark, Finland, Italy, South Korea, Netherlands, Norway, Spain, Sweden, Canada and the USA. The project began in May 2004 and was completed in November 2006 when this Roadmap was launched at the final project workshop in Melbourne, Australia. 1.3 Reasons for Australian participation in Task XIII There have been growing concerns about the consequences of increasing peak demand growth in most Australian states, largely driven by the rapidly increasing penetration of residential air conditioning and the potential impact this can have on the security of electricity supply, the wholesale price of electricity and price volatility. Prior to the commencement of this project there was some uncertainty that the NEM was sufficiently capturing all existing DR opportunities. These issues are not limited to the NEM and, as such, the IEA DSM program instigated an international collaborative project to investigate and foster the wider take-up of DR in competitive electricity markets around the world. Involvement in an international project such as this one has enabled the Australian Task XIII Team access to the best thinking, and information on best practice techniques and technology (both current and Page 9 of 44

10 emerging) around the world. In applying this knowledge base to the Australian context, the Australian Task XIII Team has been able to test a number of future scenarios, assess the potential value of DR in the NEM and propose a way forward for government and industry. 1.4 Demand Response defined Demand-Side Management (DSM) refers to actions that either reduce the overall amount of energy (usually electricity) consumed or change the shape of the load curve by reducing load at times of peak demand or by shifting load into low demand (off-peak) periods. DR is one category of DSM, where electrical demand is reduced at times when wholesale market prices are high or when system reliability is jeopardised. This is achieved either by: shedding commercial and industrial loads switching on standby generation direct load control of certain appliances and equipment, or customer response to a higher price signal. Demand Response Resources (DRR) refers to the range of enabling technologies and retail products which, when combined, give electricity consumers the tools to reduce or defer their consumption during peak demand periods when prices are high or when they are otherwise financially motivated via an incentive payment (eg direct load control), demand-bidding or emergency DR type products. 1.5 The purpose of this Roadmap This Roadmap represents the culmination of the Task XIII project and is intended to inform the policy debate on the potential value and role of DR in the NEM. In particular, it presents the key results from modelling the economic benefits of a much wider uptake of DR and uses this as the basis for a vision statement and a proposed way forward to achieve this potential. It is also intended that this Roadmap will engage key stakeholders in the debate of supply-side verses demand-side options for developing the NEM and will potentially influence the future structure of the electricity market. 1.6 The Roadmap focal question The Australian Task XIII team defined a focal question upon which this Roadmap is centred: How can DR be employed in the NEM to provide improved competitiveness, efficiency and reliability and how will DR evolve in the NEM up to 2025? 1.7 Task XIII: Global work The project was managed by an Operating Agent (RETX) based in the USA. The project was split into eight key sub-tasks, with member countries contributing information so that a comprehensive picture of international best practice and technology and program trends could be established: Subtask 1 Country Objectives and Work Plan Subtask 2 DR Resource Base and Market Characterisation Subtask 3 Methodologies for assessing DR Market Potential Subtask 4 Methodologies for valuing DR Subtask 5 Role and value of enabling technologies, including the development of an international technology database Subtask 6 Priorities, barriers and solutions, including the development of an international DR program database Subtask 7 Develop DRR network methods Subtask 8 DR vision and Roadmap The Operating Agent, with input from participating country teams, developed a number of practical methodologies and tools for each member to apply to their market environment. The major outputs from the project are: Page 10 of 44

11 Market Overview Reports (Subtask 2) DR Program Benchmarking Report and tool (Subtask 3) Two reports on a methodology for valuing DR (Subtask 4) International DR Technology Database (Subtask 5) International Products Database and Guidebook on Barriers to DR and potential responses (Subtask 6) Web portal with resources from all participating countries (Subtask 7) Communications Plan and Complete Project Guidebook (Subtask 8) Key findings from Task XIII will be incorporated into a Guidebook on Demand Response, which will be made publicly available after completion of the project. 1.9 Valuation of DR in the NEM In order to estimate the value of DR in the NEM, the Australian team commissioned CRA to undertake an analysis of the value of implementing significantly more DR over the period 2007 to The methodology developed for the Operating Agent as part of Subtasks 3 and 4 was modified for application to the NEM and the potential impacts of four key DR products were modelled under a range of scenarios. This was the first time detailed system and economic modelling of DR was undertaken in the Australian context, the outcomes of which can be found in Section Task XIII: Australian work This Roadmap, incorporating key results from the Australian DR modelling project, is part of the final subtask and one of the project s major outputs. Using the benchmarking tool provided by the Operating Agent as part of Subtask 3 as a guide, a preliminary state by state assessment of the magnitude of potential DRR in Australia was conducted using Australian specific data, taking into account Australian market frameworks and investment signals. This data supplemented the more detailed economic modelling work commissioned by the Australian Task XIII Team. The team completed a survey of retail DR products currently available in the NEM, most of which related to residential or regulated time of use (TOU) tariffs, with little information available on commercial or industrial products (Subtasks 2 & 6). The appointed technology expert reviewed DR enabling technology available in Australia (Subtask 5), the summary details of which are included in Appendix B. Page 11 of 44

12 2. THE DEMAND RESPONSE ROADMAP For the DR market in Australia to expand significantly, industry needs to be informed and accept that a significant and plausible opportunity exists for the wider uptake of DR in the NEM. Recognition by governments, regulators and the market operator that DR has a legitimate and tenable place in the day-to-day operations of the NEM is also critical. Figure 2.1 Estimated additional peak demand reduction by DR Program 2007 to The Demand Response vision statement The vision for Demand Response in the national electricity market over the next two decades is that: By the year 2025, Demand Response can deliver around an additional 5% reduction in system peak demand, or approximately 2,800 MW of load reduction, compared to the current situation. MW Demand Response will be a critical factor in the future management and efficient operation of Australia s electricity market. Achieving this goal will have significant system-wide benefits: based on a range of forecast assumptions, the net present value of system-wide market benefits (but excluding network related benefits) 2007 to 2025 is between $363 to $949 million, depending on the way in which supplyside resources are chosen and used Legend: DR Programs modelled Voluntary Load Control - Summer Critical Peak Pricing - Summer Voluntary Load Control - All Year Critical Peak Pricing - All Year Direct Load Control - Summer Callable DR Large Commercial and Industrial - Summer Callable DR Large Commercial and Industrial - All Year 2.2 Roadmap timeline The following diagram illustrates the anticipated reduction in peak demand resulting from the wider deployment of DR in the NEM over the period from 2007 to 2025, including an initial ramp up phase from 2007 to More information on the uptake of DR programs modelled as part of the Task XIII project can be found in Section 4. Page 12 of 44

13 Roadmap for DR in the Australian NEM 2.3 Factors influencing Demand Response in the NEM A range of factors could influence the extent and rate of deployment of DR in the NEM over the next 20 years. These factors were identified from existing published information and the combined expertise of the Australian Task XIII Team Key influencing factors 1. Peak demand growth - peak demand will continue to grow faster than total energy consumption throughout the Roadmap period and the subsequent deterioration in load factors, for both networks and generators, will create upward pressure on prices and/or declining reliability, and will make DR increasingly more economically attractive. 2. Roll-out of smart meters - much wider deployment of smart metering in some or all NEM states will facilitate the introduction of more cost-reflective pricing and potentially lead to a more informed customer base. 3. Improved price signalling - the progressive removal of retail price regulation, as agreed by the MCE, will provide an increased ability for retailers to offer more innovative products and to assist in the removal of cross-subsidies Other influencing factors has the potential to create greater price volatility due to its intermittent nature. 7. DR technology innovation - technology changes on both the supply-side, through new supply options (e.g. distributed generation: fuel cells, pump storage) and the demand-side (e.g. new cooling technology options, next generation electricity storage developments, developments in load control technologies) are expected to become increasingly influential. Such innovation is expected to result in an increased array and reduced costs of DR related technology. 8. Income growth - will drive increased electricity consumption and increased consumer desire for comfort. Figure 2.2 Timeline of influencing factors for DR in the NEM Key Influencing factors MW 1 Peak demand growth 2800 MW 2 Roll out of smart meters Cost reflective pricing 2000 Other Influencing factors 4 Climate change Carbon signal (not in Task XIII modelling) Climate Change - a continued trend towards global warming will result in more frequent hot summer days, resulting in greater price volatility. 5. Carbon signal due to climate change factors, it is likely that future electricity prices will include a carbon price in some form. 6. Renewable electricity supply - significant increase in the quantity of renewable electricity supply in the generation mix 6 Renewable energy supply DR technology innovation 8 Income growth 0 MW Legend: Uptake of DR in the NEM Regulatory influences Market influences Socio-economic influences Page 13 of 44

14 2.4 Major benefits of Demand Response in the NEM The wider uptake of DR in the NEM will benefit the market in a number of ways. It is important to note the benefits differ depending on the way in which supply-side resources are chosen and used. For example, the DR modelling undertaken by CRA for the Australian Task XIII Team indicates that if supply-side resources are relied upon to meet energy, peak and system reliability requirements and DR is deployed as a means for achieving extra system reliability, then the majority of the savings flow from reduced unserved energy and operating cost savings. However in a least-cost, integrated resource planning market where decisions are made to minimise total system cost, capital cost savings feature prominently as the major component of benefits. The main benefits of increasing the uptake of DR in the NEM are that it can: improve system reliability - DR can reduce the threat of and/or need for Government intervention in the market to maintain power system reliability at politically and socially acceptable levels 3. reduce transmission and distribution congestion and can save and / or delay transmission and distribution capital expenditure 4. increase the security of supply by substituting voluntary load shedding for enforced load shedding 2. provide a means for avoiding the use of expensive fuels for meeting peak demand 1. defer or avoid the need for investment in peaking generation plant 1. provide a check on the market power of suppliers - DR can reduce the level of market power that could otherwise be exercised by generators under tight demand-supply conditions 1 and can act as a check on the market power of suppliers by reducing demand when customers find it more advantageous to reduce demand rather than pay the prices suppliers are asking for electricity 2. reduce final prices to consumers by optimising use of all energy options Roadmap challenges Key challenges which may inhibit the wider uptake of DR in the NEM have been assessed according to two major customer types. Refer to Appendix D for a more detailed discussion of these factors. Challenges for Commercial and Industrial Customers (C&I) Transactions costs for participating in DR programs Air quality limitations on the use of standby generation, especially in high density areas Lack of market based tools and customer awareness Lack of transparency to access the wholesale market Challenges for Residential and Small to Medium Enterprise (SME) Customers Lack of appropriate price signals Lack of market based tools and customer awareness Lack of market penetration of interval meters across the NEM Absence of technology based DR capacity and inter-operability for key appliances this increases the costs of implementing DLC programs as more work is required to identify appliances/equipment that are suitable to participate. Page 14 of 44

15 2.7 The way forward It is recognised that work being undertaken through the Ministerial Council on Energy, additional activity in specific jurisdictions, as well as the development of commercial DR aggregators will facilitate the wider uptake of Demand Response in the NEM. However, the vision set out in this Roadmap is unlikely to be achieved unless further steps are taken to facilitate the development of a DR market. Enabling Demand Response will be best served within a market structure that understands and promotes the benefit of allowing peak pricing signals to operate effectively. To facilitate the development of Callable C&I DR programs the relevant stakeholders need to: Investigate ways to provide better transparency in the market for Demand Response resources this is especially the case for business consumers entering bilateral contracts, where there is an information asymmetry in favour of the retailers. Develop information tools to enable business consumers to better assess the Demand Response resource they have available to sell into the market. Identify opportunities to facilitate the use of standby generation in Demand Response programs taking into consideration the existing limitations imposed by air quality requirements. Investigate the option of using appliance standards to facilitate Demand Response, either through standards relating to standby generation or a requirement for HVAC system controls to be suitable for participation in Demand Response programs. have a role to play due to their potential benefits in residential areas that have network constraints, their relatively short response times (DLC only) and because they directly address the increasing penetration of residential air conditioning - a key driver for increased peak demand. A number of further actions could be taken to encourage the development of these products: Collate and disseminate key findings from current trials, including ETSA Utilities, Solar Cities, Sydney Demand Management & Planning Project and the Victorian smart meter trials this should be packaged both for industry stakeholders and the general public. Undertake detailed technical (end-use metering) and behavioural studies to obtain better data on the relationship between appliance use and peak demand and the loads that consumers are most likely to control under a CPP regime. Continued support for issues addressed by the A-HELP project to develop communication standards to facilitate direct load control of appliances and to investigate the feasibility of using appliance regulations to ensure that where relevant new products sold are already enabled for DLC. While the modelling undertaken for this project suggests that residential Direct Load Control and Critical Peak Pricing will play a relatively minor role in delivering value to the electricity market, these products still Page 15 of 44

16 3. THE EMERGING DEMAND RESPONSE INDUSTRY 3.1 An international perspective DR primarily relates to electricity supply shortages driven by high system peak demand, which in most instances result from extreme weather events and/or significant generator outages. In most regions of the NEM, maximum system peak demand is caused by summer cooling requirements on hot summer days, whilst in Tasmania there is also a winter heating peak. When looking for comparable electricity markets internationally, it is necessary to look at countries that have similar climatic conditions in addition to similar electricity markets. In other words, looking at the drivers of peak demand which determines where potential solutions lie. Of the eleven countries participating in Task XIII, USA, Spain, Italy, South Korea and regions of Canada have hot summers with high air conditioning requirements, similar to that in Australia. South Australia for example has the peakiest electricity market in the world and the South Australian load profile closely resembles the shape of the Californian electricity market. Markets such as Norway, Sweden, Netherlands, Finland and Denmark have predominantly winter peaks. While the general approaches to DR used in these countries will be similar to that in countries with summer peaking markets, the electrical loads targeted for demand reduction are likely to be different, especially in the residential and commercial sectors. In Europe, Norway and Denmark are looking at DR mechanisms, such as direct load control (DLC) of residential electric heating, to manage winter loads. The European Distributed Energy Partnership (EU-DEEP) is working on the large-scale implementation of Distributed Energy (DE) resources in Europe. This is a comprehensive bottom-up approach to assess the potential for DR in European electricity markets by obtaining detailed information on the needs of different categories of end-users. This methodology is being applied to identify the most promising demand segments in the commercial, residential and industrial sectors. 5 The CRISP project, run by the Energy Centre of the Netherlands and funded by the European Union, is looking to introduce integrated systems targeted at synergy between demand and supply. The CRISP project examines how a more decentralised, future energy supply can be managed through an automated, intelligent system to achieve high reliability. This involves control and coordination on a massive scale including intermittent power supply such as wind, solar and microcogeneration 6. The Tempo tariff in France is a time-of-use tariff (TOU) active between November and March, which uses smart meters with prices that vary according to demand. The Tempo tariff allows customers to adjust their consumption either manually or by selecting a program for automatic connection and disconnection in response to day-in-advance notification by Electricity de France In the US, following the Californian crisis in 2000/01, characterised by a combination of extremely high prices and rolling blackouts, DR was considered as a matter of priority. Price instability and spikes lasted from May 2000 to September Rolling blackouts began in June 2000 and recurred several times in the following 12 months 10. The US Federal Energy Regulatory Commission in addressing the California crisis stated: Without a DR mechanism, the [independent system operator] is forced to work under the assumption that all customers have an inelastic demand for energy and will pay any price for power. There is ample evidence that this is not true. Many customers, Page 16 of 44

17 given the right tools, can and will manage their demand.... A working DR program puts downward pressure on price, because suppliers have additional incentives to keep bids close to their marginal production costs and high supply bids are more likely to reduce the bidder's energy sales. Appropriate price signals to customers thus help to mitigate market power as high supply bids are more likely to reduce the bidders' energy sales. Suppliers thus have additional incentive to keep bids close to their marginal production costs. Demand-side price-responsive bids will also help to allocate scarce supplies efficiently An Australian perspective From the inception of the NEM, DR was seen to be an important aspect of efficient market functioning, however, there is currently only approximately 400 MW of DR considered to be active 12. It was foreseen that customers would shape their consumption in response to price signals which in turn would provide significant benefits to the overall functioning of the NEM. For more information relating to DR and the NEM and to DR programs currently available in Australia, refer to Appendix E and F respectively. A report recently released by the National Electricity Market Management Company (NEMMCO) forecasts that demand for electricity will outstrip supply in NSW by NSW will be in the worst position, with South Australia facing power shortages by 2007 and Victoria following in In Australia, peak demand continues to grow at a faster rate than electricity consumption. Where the load shape is characterised by sharp peaks, as is the case in parts of Australia, a critical decision arises as to whether or not these short-lived periods of peak demand are sufficient on their own to warrant a significant investment in additional generation, such as peaking plant. Table 3.1 Australian electricity growth rates (NEMMCO Statement of Opportunities 2006) Region 10 year Energy Growth Rate 10% POE Summer Maximum Demand Growth Rate 10% POE Winter Maximum Demand Growth Rate QLD 3.5% 3.6% 3.5% NSW 1.7% 2.7% 2.0% VIC 0.8% 1.9% 1.3% SA 0.8% 1.6% 2.0% TAS 1.5% 1.6% 1.6% POE = Probability of Exceedence ABARE estimates that, in order to support Australia s forecast economic growth, approximately $30 billion will need to be spent on Australia s primary energy sector by This includes investment in base load and peak electricity generation, distribution and transmission systems, gas pipelines and renewable plant 14. Investment in demand-side options such as energy efficiency and DR have the potential to defer or offset the need for investment in at least some of the generation and supply infrastructure required to meet Australia s future electricity needs, with flow-on effects for energy security and the wholesale price of electricity. This was one of the issues addressed through the Task XIII modelling of the potential value of DR. The COAG statement of February 10, 2006 articulated further changes in energy market reform, in particular, the need to focus on changing consumption patterns. Recognising the role of smart meters in providing the platform for dynamic pricing and hence demand side response, COAG directed the MCE to develop a national implementation plan for the roll-out of smart meters beginning in There was also recognition of the need to introduce comprehensive measures to substantially improve demand management. Page 17 of 44

18 A comprehensive MCE work program has been implemented to identify effective demand side response mechanisms in the NEM including network owner incentives, the effective valuation of demand side responses and the regulation and pricing of distributed and embedded generation. The COAG statement noted: Demand management which is able to shift or reduce demand peaks can be an economically efficient substitute for building new network and generation assets. Demand management may be achieved through commercial initiatives in the electricity market. Improved demand responsiveness may also be achieved by creating financial incentives through the regulatory framework where regulatory arrangements do not adequately reward network owners for the avoided cost of new network assets. There is still further potential for demand management through the greater penetration of energy efficient appliances, lighting and buildings, particularly if these are combined with improved end user education and more accurate pricing. For customers, the benefits of these alternatives to more generation and network expansion include lower energy bills, better energy services, the improved utilisation of resources and fewer environmental costs 15. Page 18 of 44

19 4. THE VALUE OF DEMAND RESPONSE IN THE NEM In order to help assess the case for the much wider deployment of Demand Response, the Australian Task XIII Team commissioned CRA International to undertake an analysis of the value of an increased uptake of DR in the NEM. Other recent estimates of DR are contained in Appendix G. A DR valuation methodology based on electrical supply system modelling was developed by the Task XIII Operating Agent and was modified by CRA for application to the NEM. The approach taken, in summary, was to model DR alongside the supply-side, ensuring that the least cost plant is used to meet the required load. Four DR programs were modelled using three market scenarios from 2007 to The three scenarios modelled were: Least-Cost Base Case Scenario in which system requirements are assumed to continue to be met by supply-side resources and cost-effective Demand Response is deployed to provide increased system reliability (i.e. reduce unserved energy), and to reduce operating costs where operating costs are assumed to be represented by the short-run marginal cost (SRMC) of generators in the NEM. Market Bidding Scenario in which the same amount of Demand Response is deployed as in the base case scenario, but generators are assumed to bid strategically in the NEM rather than at SRMC. DR benefits come, as they did in the base case scenario, from improved reliability and reduced operating costs, but the proportion represented by operating costs increases significantly. Bidding strategically refers to the withholding of cheaper resources by offering part of the generation capacity in the market well above it s marginal cost. Integrated Resource Planning Scenario in which the selection of supply and demand-side resources that minimise total system cost for meeting aggregate is made via a central planning function. The four Demand Response programs modelled were: Callable Large Commercial & Industrial (Callable C&I) this program targets customers with at least 0.25 MW load reduction, either from load shedding or switching on standby generation. Residential Direct Load Control (DLC) - this program allows residential air conditioners to be cycled and pool pumps to be interrupted under the remote control of a utility. Eligible customers include households with ducted (central) refrigerative air conditioners or large split systems (input power of 2 kw or greater). Price Responsive Load for residential customers this program is based on a Critical Peak Pricing program, running in summer with potential market size being the same as households participating in the residential DLC program. Voluntary Load Reduction for small business customers (VLR) this program is similar to the callable C&I program but is targeted primarily at Small to Medium Enterprises. Refer to Appendix H for further information on the DR programs covered by the modelling. The modelling compared the possible outcomes for the NEM over the period 2007 to 2025 both with and without DR. The modelling methodology assumed that the benefits of Page 19 of 44

20 DR could be defined as the net change in total system costs derived from the with DR case, as compared to the without, where costs: include all costs associated with deployment of the DR, and can be disaggregated into the costs associated with capital investment, operating costs (both fixed and variable) and (expected) unserved energy (USE) 1. This section provides a brief overview of the CRA report. 4.1 Modelling results It is expected that the peak load reduction associated with each of the four programs in each NEM jurisdiction will increase over the modelling period (with a ramp up period between 2007 and 2013) and the estimated deployment of DR in 2025 is summarised in Table 4.1 below. Table 4.1 Estimated peak load reduction by DR program present value of benefits, using a discount rate of 8.8%, are found in Table 4.2 and Table 4.3 below. Table 4.2 Summary of DR benefits 2007 to 2025 Scenario type Least Cost Base Case Market Bidding Scenario Total Net Present Value System Cost Savings Average Savings $/MW/Year $363 million $185,000 / MW / year $949 million $484,000 / MW / year IRP Scenario $555 million $283,000 / MW / year Table 4.3 Summary of DR benefits by major item 2007 to 2025 NEM Summer Demand Response Potential: Demand Response QLD NSW VIC SA TAS Total MW Callable C&I ,289 Direct Load Control Price Responsive Load Voluntary Load Reduction Total by State, MW 758 1, ,770 Total by State, % 27% 39% 23% 8% 3% 100% NEM Winter Demand Response Potential: Demand Response QLD NSW VIC SA TAS Total MW Callable C&I ,580 Price Responsive Load VLR Total by State, MW ,770 Total by State, % 28% 38% 23% 8% 3% 100% The modelling results indicate that DR can provide substantial benefits to the NEM under all three scenarios. Results of the net $ millionsm 1,200 1, (138) (138) (143) Least Cost Base Case Market Bidding Integrated Resource Planning CAPEX Benefit OPEX Benefit USE Benefit 99 Page 20 of 44