Power from the People
Inquiry into distributed generation
Final Report July 2012
© State of Victoria 2012
This final report is copyright. No part may be reproduced by any process except in accordance with the provisions of the Copyright Act 1968 (Cth), without prior written permission from the Victorian Competition and Efficiency Commission.
ISBN 978-1-922045-14-0 (paperback) ISBN 978-1-922045-15-7 (PDF)
Disclaimer
The views expressed herein are those of the Victorian Competition and Efficiency Commission and do not purport to represent the position of the Victorian Government. The content of this final report is provided for information purposes only. Neither the Victorian Competition and Efficiency Commission nor the Victorian Government accepts any liability to any person for the information (or the use of such information) which is provided in this final report or incorporated into it by reference. The information in this final report is provided on the basis that all persons having access to this final report undertake responsibility for assessing the relevance and accuracy of its content.
Victorian Competition and Efficiency Commission GPO Box 4379 MELBOURNE VICTORIA 3001 AUSTRALIA
Telephone: (03) 9092 5800 Facsimile: (03) 9092 5845 Website: www.vcec.vic.gov.au
An appropriate citation for this publication is:
Victorian Competition and Efficiency Commission 2012, Power from the People: Inquiry into Distributed Generation, final report, July.
About the Victorian Competition and Efficiency Commission
The Victorian Competition and Efficiency Commission (VCEC), which is supported by a secretariat, provides the Victorian Government with independent advice on business regulation reform and opportunities for improving Victoria’s competitive position.
VCEC has three core functions:
• reviewing regulatory impact statements, measuring the administrative burden of regulation and business impact assessments of significant new legislation • undertaking inquiries referred to it by the Treasurer, and • operating Victoria’s Competitive Neutrality Unit.
For more information on the Victorian Competition and Efficiency Commission, visit our website at: www.vcec.vic.gov.au
Disclosure of interest
The Commissioners have declared to the Victorian Government all personal interests that could have a bearing on current and future work. The Commissioners confirm their belief that they have no personal conflicts of interest in regard to this inquiry.
27 July 2012
Mr Kim Wells MP Treasurer of Victoria 1 Treasury Place MELBOURNE VIC 3002
Dear Treasurer
VCEC Inquiry into Feed-in Tariff Arrangements and Barriers to Distributed Generation
In accordance with the terms of reference received by the Commission on 13 January 2012, we have pleasure in submitting the Commission’s final report Power from the People.
Yours sincerely
Deborah Cope Dr Matthew Butlin Presiding Commissioner Chair
Terms of reference
Inquiry into Feed-in Tariff Arrangements and Barriers to Distributed Generation
I, Kim Wells MP, Treasurer, pursuant to section 4 of the State Owned Enterprises (State Body – Victorian Competition and Efficiency Commission) Order (‘the Order’), in conjunction with Michael O’Brien MP, the Minister for Energy and Resources, hereby direct the Victorian Competition and Efficiency Commission (‘the Commission’) to conduct an inquiry into feed-in tariff arrangements and barriers to distributed generation.
Background
Victoria currently has in place a number of programs that are designed to reduce greenhouse gas emissions and facilitate an adjustment towards a low emissions economy.
These programs include feed-in tariff schemes such as the standard feed-in tariff scheme for customers with installations up to 100kW capacity and the premium and transitional feed-in tariff schemes applying to eligible customers with solar inverter systems up to 5kW capacity. In the context of the implementation of a national carbon price, it is appropriate that the Commission undertakes a review of Victoria’s feed-in tariff schemes.
Addressing any state and local regulatory or other barriers to the uptake of low emissions generation, including co-generation and tri-generation, is also important to ensure that any transition to low emissions generation occurs as smoothly and as cost-effectively as possible.
Scope of the inquiry
In this inquiry, the Commission is required to:
(1) Assess the design, efficiency and effectiveness of feed-in tariff schemes, including market-based gross feed-in tariff schemes, in the context of a national carbon price. (2) Prove a recommendation as to whether existing feed-in tariff arrangements should be continued, phased-out or amended. Where phase-out of existing arrangements is proposed, the appraisal should give consideration to whether any transitional arrangements may be necessary. Any changes to existing arrangements would not be applied retrospectively. (3) Identify and State and/or local regulatory and other barriers to the development of a network of distributed renewable and low emission generation in Victoria, including co-generation and tri-generation.
TERMS OF REFERENCE VII In conducting this inquiry, the Commission should have regard to:
• recent reports by the Australian Energy Market Commission on planning and connection arrangements for distributed energy generation; • reviews currently being undertaken by the Victorian Government; and • relevant reports by Commonwealth forums and bodies such as the Productivity Commission.
Inquiry Process
In undertaking this inquiry, the Commission is to have regard to the objectives and operating principles of the Commission, as set out in section 3 of the Order. The Commission must also conduct the inquiry in accordance with section 4 of the Order.
The Commission is to consult with key interest groups and affected parties, including representatives of end-use electricity consumers, and may hold public hearings. The Commission should also draw on the knowledge and expertise of relevant Victorian Government departments and agencies.
The Commission is required to produce a draft report for public consultation, ahead of a final report to the Government within 6 months of receipt of this reference.
KIM WELLS MP Treasurer
Received: 13 January 2012
VIII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GEENRATION Contents
Terms of reference VII Contents IX Abbreviations XIII Glossary XV Key Messages XIX Summary report XXI Recommendations XLI 1 Introduction 1 1.1 Background to the inquiry 1 1.1.1 What is distributed generation? 2 1.1.2 What are feed-in tariffs? 2 1.2 Context and why this inquiry is important 3 1.3 The Commission’s approach 4 1.4 Inquiry process 5 2 Distributed generation in Victoria 7 2.1 The Victorian electricity industry 7 2.1.1 Market for distributed energy 8 2.2 Regulation of distributed generation in Victoria 14 2.2.1 Regulation of the NEM 15 2.2.2 Delay of the NECF in Victoria 17 2.2.3 Connecting to the distribution network 19 2.2.4 Selling exported electricity 25 2.2.5 What do these arrangements mean for the inquiry? 29 2.3 Policies for distributed generation and renewable energy 35 2.3.1 Commonwealth policies 35 2.3.1 State policies 37 2.4 Future trends 38 2.4.1 Cost trends 38 2.4.2 Improved metering technology 41 2.5 Conclusions 42 3 Issues raised by participants 43 3.1 Introduction 43 3.1.1 Issues raised in response to the draft report 44 3.1.2 Connecting to the network 44 3.1.3 Selling electricity 51 4 Commission’s framework 57 4.1 Introduction 57 4.2 The value of distributed generation 58 4.2.1 Output value 58 4.2.2 Network value 62 4.3 Realising the value of distributed generation 64 4.3.1 Role of the market 64 4.4 Improving the efficiency of transactions 69 4.5 Equity considerations 70 4.6 Addressing terms of reference 71 5 Network value 72 5.1 Introduction 72 5.2 How material is network value?
CONTENTS IX 5.3 Market power concerns 74 5.3.1 Better information 75 5.4 Network reinforcement costs 80 5.4.1 Information and transparency 80 5.4.2 Sharing costs 81 5.4.3 Who benefits from reinforcement 81 5.4.4 The Commission’s view 82 5.5 Regulatory incentives 83 5.6 Recovering network value 85 6 Connecting generators to the distribution network 87 6.1 Context 88 6.2 Benefits of medium-scale distributed generation 91 6.3 Barriers to medium-scale distributed generation 91 6.4 Right to connect and export 94 6.5 Process: cost, timelines and uncertainty 101 6.6 Cost savings from improved medium-scale connection process 110 7 Facilitating connection of household-scale distributed generation 111 7.1 Barriers to household-scale connection raised by stakeholders 112 7.1.1 Specific connection barriers 114 7.2 Timeliness of household-scale connection 117 7.2.1 Connection process timeframes mandated by regulation 118 7.2.2 Stakeholder feedback on the timeliness of connection 121 7.3 Why does the Victorian connection process work the way it does? 122 7.3.1 The Victorian electrical safety system 122 7.3.2 Rationale for a retail feed-in tariff contract 123 7.4 Opportunities for improvement raised by stakeholders 123 7.4.1 One connection process for all Victorian DNSPs 124 7.4.2 No requirement for connection approval by the DNSP 124 7.4.3 Removing the obligation that distributed generation customers enter into a separate FiT contract 125 7.4.4 Introducing meter contestability 126 7.4.5 Remove the retailer from the installation, connection and metering process 126 7.4.6 Online connection process 127 7.4.7 Improving information 128 7.5 The Commission’s view 129 7.5.1 Process improvement 1: remove retailer from the physical installation, connection and metering arm of the connection process 129 7.5.2 Process improvement 2: require retailers to combine their supply and FiT (export) contracts 130 7.5.3 Supporting recommendations 133 7.5.4 Implementation of process improvements and supporting recommendations 133 7.6 Cost savings from improved household-scale connection process 135 7.6.1 Savings arising from the Commission’s recommendations 136 8 Selling electricity 139 8.1 Overview of Victorian feed-in tariff schemes 139 8.2 Reconsideration of Victorian FiT objectives 141 8.2.1 Objective of reducing greenhouse gas emissions 141 8.2.2 Industry support 144 8.2.3 Providing a ‘fair and reasonable’ price 146 8.3 Barriers to establishing fair and reasonable FiTs 147
X POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 8.3.1 Is there competition within the Victorian electricity retail market? 147 8.3.2 Structural issues 153 8.3.3 Information and transaction costs 154 8.3.4 Limitations on time of use and locational pricing 156 8.3.5 Conclusion 157 8.4 Impacts of other policy settings on medium-scale distributed generation 158 9 Future Victorian feed-in tariff arrangements 163 9.1 Design, efficiency and effectiveness of feed-in tariff schemes 166 9.1.1 The value of distributed generation 166 9.1.2 Participants’ views 172 9.1.3 Market-based feed-in tariffs 179 9.1.4 Eligibility 180 9.1.5 Gross or net metering 183 9.1.6 Information provision 185 9.1.7 Billing arrangements 187 9.1.8 The Commission’s view 187 9.1.9 Terms of Reference 1: The Commission’s summary view 188 9.2 Implications for existing Victorian feed-in tariff schemes – Terms of Reference 2 189 10 Transitional arrangements 195 10.1 Introduction 195 10.2 What actions has the Commission recommended? 195 10.2.1 Future feed-in tariffs arrangements 195 10.3 Implications for current PFiT and TFiT customers 196 10.3.1 PFIT customers 196 10.3.2 TFIT customers 196 10.4 Implications for current PFiT customers 197 10.4.1 Non-retrospectivity 198 10.5 Implications for future customers 200 10.5.1 Closure of the TFiT scheme 200 10.5.2 New customers on the proposed new FiT 202 10.6 Impact on distributed generation customers and industry 202 10.7 Managing the transition 204 10.7.1 Information provision 204 10.7.2 Role of the ESC 205 10.7.3 Role of CAV and EWOV 205 Appendix A: Consultation 207 A.1 Introduction 207 A.2 Submissions 207 A.3 Roundtables 211 A.4 Stakeholder consultations 213 Appendix B: Regulation of the electricity sector 215 B.1 Victorian regulation 215 B.2 Regulatory framework after commencement of the NECF 216 B.3 Connecting to the distribution network 216 B.4 Selling electricity generated 238 References 257
CONTENTS XI
Abbreviations
AEMC Australian Energy Market Commission AEMO Australian Energy Market Operator AER Australian Energy Regulator AMI Advanced metering infrastructure ASP Accredited service provider ATA Alternative Technology Association B2B Business to business CA Connectional applicant CAV Consumer Affairs Victoria CEC Clean Energy Council CEFC Clean Energy Finance Corporation CES Certificate of Electrical Safety CFCL Ceramic Fuel Cells Limited CO2-e Carbon dioxide equivalent COAG Council of Australian Governments DAPR Distribution Annual Planning Report DG Distributed generation DMEGCIS Demand Management Embedded Generation Connection Incentive Scheme DMIS Demand Management Incentive Scheme DNSP Distribution network service providers DPI Department of Primary Industries DSP Demand-side participation DSPR Distribution System Planning Reports DUOS Distribution use of system EDC Electricity Distribution Code EEC Energy Efficiency Council ERAA Energy Retailers Association of Australia ESAA Energy Supply Association of Australia ESC Essential Services Commission ESCOSA Essential Services Commission of South Australia ESV Energy Safe Victoria EWOV Energy and Water Ombudsman Victoria EWR Electrical Works Request FiT Feed-in tariff IPART Independent Pricing and Regulatory Tribunal
ABBREVIATIONS XIII ISF Institute for Sustainable Futures JEN Jemena kW Kilowatt kWh Kilowatt hour LCOE Levelised cost of electricity LGC Large-scale Generation Certificate LRET Large-scale Renewable Energy Target MCE Ministerial Council on Energy MEFL Moreland Energy Foundation Ltd. MEI Melbourne Energy Institute MOE Merit order effect MW Megawatt MWh Megawatt hour NECF National Energy Customer Framework NEL National Electricity Law NEM National Electricity Market NEO National Electricity Objective NER National Electricity Rules NERL National Energy Retail Law NERR National Energy Retail Rules PC Productivity Commission PCA Property Council of Australia PFiT Premium feed-in tariff PV Photovoltaic REBS Renewable Energy Bonus Scheme REC Renewable Energy Certificate RET Renewable Energy Target RIT-D Regulatory Investment Test for Distribution ROI Return on investment SCCC Select Committee on Climate Change SCER Standing Council on Energy and Resources SCF Solar Connection Form SEG Small embedded generator SEIA Solar Energy Industry Association SFiT Standard feed-in tariff SIR Service Installation Rules SRES Small-scale Renewable Energy Scheme STC Small-scale Technology Certificate
XIV POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION SV Sustainability Victoria TFiT Transitional feed-in tariff TFP Total factor productivity TNSP Transmission network service providers TOR Terms of reference TOU Time of use TUOS Transmission use of system UE United Energy UFWA Union Fenosa Wind Australia UK United Kingdom VEEC Victorian Energy Efficiency Certificate VEET Victorian Energy Efficiency Target VRET Victorian Renewable Energy Target
ABBREVIATIONS XV
Glossary
Australian Energy Market Manager and operator of the National Electricity Market, Operator and coordinator of market planning Australian Energy Markets Rule maker and adviser to Ministers on development of Commission energy markets Australian Energy Enforcer and monitor of compliance with the National Regulator Electricity Rules; responsible for economic regulation of electricity transmission and distribution networks in the National Electricity Market Capacity • Generator capacity The full-load sustained output of a generator under ideal conditions. Capacity often exceeds output as output is limited by weather conditions, equipment failure and maintenance • Network capacity The power limit (in megawatts) a network can support Carbon price Commonwealth tax on carbon production (initially fixed at $23 per tonne before shifting to a market-determined price) Certificate of Electrical Required for all electrical installation work undertaken by a Safety registered electrician under the Electrical Safety Act (1998) Co-generation The simultaneous production of electricity and heat from the same fuel source Connection A physical link between a distribution system and a customer’s premises to allow the flow of electricity Consumer Electricity purchaser and user Cost benefit analysis An analytical tool used to assess the benefits and costs of a project, decision or government policy to determine feasibility Default clause Proposed feed-in tariff clause in the retail supply contract activated when the retailer is notified that the supply customer has met all the preconditions for connecting distributed generation Distributed generation Small- to medium-scale electricity production by households, business and community groups, predominantly for on-site use or to supply people and organisation close by. Generators may be stand-alone or connected to the distribution network and may export excess electricity into the grid Distribution network Links the transmission system to electricity consumers through distribution lines that carry low voltage electricity Distribution network Operator and manager of the distribution network service provider Efficient and fair Proposed price paid to small-scale renewable or low- emissions distributed generators based on the wholesale price of electricity adjusted for reduced system losses
GLOSSARY XVII Electrical Work Request Paperwork completed by a Registered Electrical Contractor to notify a retailer and distribution network service provider that electrical work has or will occurred and the distribution network service provider is required to complete the work and/or change the metering Electricity The flow of electrical power or charge Essential Services Economic regulator of Victorian essential utility services Commission supplied by the electricity, gas, ports and rail freight industries. Equity Fair distribution of assets and resources throughout society Fair and Reasonable Mandated condition on the price paid to customers supplying electricity under the SFiT. Interpreted by the Essential Service Commission to mean no less than the retail price of electricity Fault-level limit The maximum current that can flow through a network in the event of a short circuit. Exceeding the fault level limit increases the risk to the reliability and safety of the distribution system Feed-in tariff Price paid (by retailers) per unit of electricity exported to the grid by small to medium distributed generators (from renewable or low-emissions sources) • Gross feed-in tariff Price paid for total electricity produced, regardless of whether it is used on-site or exported into the grid • Net feed-in tariff Price paid for electricity exported into the grid • Premium feed-in tariff Net feed-in tariff (of at least 60 cents per kWh) available to customers with solar photovoltaic systems of five kilowatts or less. The scheme began in late 2009 and closed in late 2011, although payments to subscribers will continue to 2024 • Standard feed-in tariff Net feed-in tariff available to customers with specified renewable energy generators up to 100 kilowatts capacity. Tariff level must be ‘fair and reasonable’ and the scheme has no prescribed end date • Transitional feed-in Net feed-in tariff (of at least 25 cents per kWh) available to tariff customers with solar photovoltaic systems of five kilowatts or less. The scheme began in 2012 and will run until 2016, but can be ended early at the Minister’s discretion Generator A unit that generates electricity. Definitions of generators by size vary, and the Commission uses the following capacity limits as a guide only: • Small-scale or 100 kilowatts or less. ‘Household-scale’ includes distributed household-scale generators owned by small business and community generator groups • Medium-scale Greater than 100 kilowatts and less than five megawatts generator • Large-scale generator Greater than five megawatts • Precinct-scale A unit whose primary purpose is to sell electricity to generator surrounding building only using a local grid
XVIII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Greenhouse gas Atmospheric gas that traps radiation emitted by the Earth. Increasing levels of greenhouse gases (such as carbon dioxide) have caused the atmosphere and Earth’s surface to heat up Industry assistance Government support to encourage the innovation and development of an industry, achieved by stimulating the demand for products of that industry or reducing its costs Kilowatt or megawatt Measure of real electrical power, or energy rate of production or demand (one megawatt equals 1000 kilowatts) Kilowatt hour or megawatt Measure of energy consumption or use (one megawatt hour hour equals 1000 kilowatt hours) Licence condition An obligation imposed by the Essential Services Commission on a Victorian electricity industry licensee as a condition of their retail, distribution, generation or transmission licence Low-emissions generation Energy produced from technologies that produce 50 per cent, or less, of the emissions intensity of electricity generation in Australia Market-based pricing Unregulated pricing determined by supply and demand. In an efficient and competitive market, market price will equal market value Market failure The inefficient allocation of goods and services by a free market Market power The ability of a business to raise prices without losing customers to its competitors National Electricity Market The market for the supply of electricity to retailers and end- users in all states and territories except Western Australia and the Northern Territory National Energy Customer National consumer protection framework for the retail sale Framework of electricity and gas Network reinforcement Investment in network infrastructure to maintain network performance and reliability under increased load density Peak demand A historically high point in electricity price resulting from strong consumer demand. It is estimated that 10 per cent of distribution network capacity is built to meet peak demand which occurs 1 per cent of the time Photovoltaic Power generated by converting solar radiation into electricity using semiconductors. Photovoltaic generation uses solar panels composed of solar cells containing a photovoltaic material (commonly crystalline silicon)
GLOSSARY XIX Price reset Victorian distribution network service providers (DNSPs) are required to comply with distribution pricing determinations made by the Australian Energy Regulator (AER). Pricing determinations are made on a five yearly basis, and prescribe the allowed capital and operational expenditure for each DNSP. DNSPs are required to submit to the AER annual pricing proposals, outlining proposed prices to take effect from the commencement of the regulatory year of the regulatory control period. A DNSP’s allowed prices are therefore ‘reset’ on a five yearly basis Renewable energy Energy produced from naturally replenished sources including solar, wind, marine, geothermal, hydro-electricity and bioenergy Retailer Interface between the electricity wholesale market and customers that sells electricity to the customer and manages customer transfers, connections, billing, complaint handling, and service information. Victorian retailers with 5000 or more customers are required to offer feed-in tariffs Rule change request Under the National Electricity Law (NEL), the Australian Energy Market Commission (AEMC) has power to make rule changes to the National Electricity Rules (NER). Generally, any person (the proponent) can make a written rule change request to the AEMC. The AEMC will consider the request, undertake consultation and make a Draft Rule Determination. Following further consultation, the AEMC will make a Final Rule Determination and, if relevant, amend the NER Smart meter Device that measures two-way electricity flow and communicates this information to electricity distributors. By the end of 2013 each Victorian house and business will have one installed System load The demand in megawatts or megawatt hours placed on the total network generation system — equal to the demand created by network-connected consumers plus distribution and transmission losses Thermal capacity The more power sent through a line or transformer, the higher the temperature of the equipment. The equipment is designed for temperature tolerances based on power levels Transmission network Transports electricity from generators to the distribution network and large end users through high voltage transmission lines Tri-generation The simultaneous production of heat, cooling and electricity Voltage level The amount of electrical pressure necessary to transfer electricity. Transmission lines carry high voltage electricity long distances, before the voltage level is decreased for compatibility with the distribution network, and decreased again for customer use Wholesale electricity Exchange between electricity producers and retailers market whereby the output of all generators is aggregated and instantaneously scheduled to meet demand in the most cost-effective way
XX POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Key messages Spending by Victorian households and businesses on distributed generation (such as solar panels and co-generation) has grown sharply over the past three years, stimulated by government policies and the desire to offset rising power costs, diversify sources of electricity supply and reduce greenhouse gas emission. The carbon tax is a further major addition into this mix. Distributed generation faces barriers from inefficient installation processes and inefficient and unsustainable pricing of electricity fed into the network. Victoria has three feed-in tariff (FiT) schemes that pay small domestic and commercial distributed generators for the electricity they produce. The Commission considers Victoria’s FiTs should be market-based as soon as practical so they are sustainable, predictable and free from cross subsidies. It recommends: • the premium FiT (closed to new entrants) continue for existing customers until 2024 as previously announced • the transitional FiT (TFiT) be closed to new entrants by 30 September 2013 or once the 75 MW capacity is reached (as currently legislated), whichever occurs first. Existing customers would receive a TFiT until 2016 as previously announced. The standard FiT (SFiT) also be closed by 30 September 2013 • a new net FiT scheme be established to replace SFiT that requires Victorian electricity retailers with more than 5000 customers to offer an efficient and fair FiT to all small low-emissions or renewable distributed generators (100 kW or less) until 31 December 2016. This price would be based on the wholesale price of electricity (which includes the carbon tax) adjusted for reduced system losses • following a transition period, the price for energy from distributed generators would be set through the retail electricity market from 1 January 2017. Advice to the Commission suggests the efficient and fair market price for 2013 to be, at a minimum, in the range of 6 to 8 cents per kWh (compared with 25 cents currently for TFiT). This minimum range is consistent with rates announced in New South Wales, Queensland, South Australia and Western Australia over the past year. Distributed generation may have significant network value in deferring or reducing investment in network capacity. However, no reliable estimates of this value currently exist. Moreover, this value cannot be efficiently captured through a FiT. The Commission recommends the Victorian Government investigate whether, and how, the Australian Energy Regulator’s price reset process could be used to identify and permit payments from distribution network service providers (DNSPs) to distributed generators based on the network value. Connecting household-scale generation is complex and the process imposes unnecessary regulatory burdens on retailers, installers and consumers. The cost of this regulatory burden could be reduced by around $3-4 million per year by: • having a default FiT in retail supply contracts, avoiding the need to sign a separate FiT contract; and households dealing directly with DNSPs rather than retailers, avoiding the double handling of paperwork. Medium-scale generators have most potential to reduce network costs and greenhouse gas emission. But there are significant barriers to connecting medium-scale generators. National regulatory change is needed to remove these barriers. The Victorian Government could advocate for national reform. If national changes are not forthcoming, then the Victorian Government could assess the net benefits of implementing State-based improvements.
KEY MESSAGES XXI
Summary report
In this inquiry the Commission has been directed to look at the policies that relate to distributed electricity generation using low-emissions and renewable technologies. More specifically the terms of reference require the Commission to:
• assess the design, efficiency, effectiveness of feed-in tariff (FiT) schemes • recommend any changes to current FiT arrangements (although any changes to existing arrangements are not to be applied retrospectively) • identify state and/or local and other barriers to the development of a network of distributed renewable and low emissions generation.
The Commission received 200 submissions, 100 short submissions and comments and 844 proforma submissions through Environment Victoria. The Commission has addressed the issues raised in the submissions in the final report. The Commission thanks those people and organisations that participated in its consultation process and made submissions to the inquiry before or after the release of the draft report. The Commission appreciates the quality of the submissions, reflecting the thought and effort which has been put into their preparation.
The structure of this summary report differs from the final report as it addresses issues of most concern to participants first (those relating to FiTs) and considers connection issues later.
What is distributed generation?
There is no definitive definition of distributed renewable or low-emissions generation. For the purposes of this inquiry, the Commission is focussing on generation with the following characteristics:
• the electricity is generated by households, businesses or community groups who primarily intend to use the electricity on-site or to supply people or organisations close by, and includes co-generation and tri-generation systems • the generator is connected into the electricity grid through the distribution network, not the transmission network. In some cases the system may be stand alone • electricity in excess of the needs of the generator owner may or may not be sold (exported) into the grid • the electricity could be from renewable sources such as solar, wind, bio-gas or waste, but may also be low-emission fossil fuels such as natural gas • the total amount of electricity generated is small- to medium-scale.
The Commission’s definition was generally supported by many participants (chapter 1).
What are feed-in tariffs?
FiTs are the price of electricity exported to the network by small- and medium-scale low-emission and renewable electricity generators, all of which are distributed generators. Victoria currently has three regulated FiTs that apply to either small-scale solar alone or small-scale renewable generators. All retailers with more than 5000 customers are required to offer these tariffs.
SUMMARY REPORT XXIII Premium FiT (PFiT) — introduced in 2009 and closed in December 2011, PFiT is paid to customers generating electricity using solar photovoltaic (PV) systems of 5 kW or less. Customers are paid 60 cents per kWh until 2024 for net exports of electricity fed into the electricity network. The level of the PFiT was set according to the amount needed to pay back the cost of the solar PV system over 10 years. At that time solar panels were considerably more expensive than they are currently.
Transitional FiT (TFiT) — commenced in January 2012 following the closure of PFiT, TFiT has similar eligibility criteria to PFiT but sets the FiT at 25 cents per kWh until 2016. The tariff was set at the level needed to pay back over six years the cost of an average household solar PV system in late 2011, and reflects the significant fall in the capital cost of household-scale PV generators since the inception of the PFiT. It is open to new applicants until 2016 but may be closed earlier if a cap of 75 MW of installed capacity is reached, the cost of the scheme on other energy users exceeds $5 per year per customer or the Minister for Energy and Resources thinks earlier closure is appropriate.
Standard FiT (SFiT) — introduced in 2004 as part of the Electricity Industry Act for electricity generated from wind generators, the SFiT was extended in 2007 to cover all renewable electricity generators up to 100 kW capacity. The scheme has no specified end date and requires eligible retailers to pay a Fair and Reasonable price for the surplus electricity fed into the grid. Although not mandated in legislation, guidance from the Essential Services Commission (ESC) is that ‘fair and reasonable’ is interpreted that the price paid to customers supplying electricity from distributed generation should not be less than the price they pay the retailer for electricity bought from the network.
Why this inquiry is important
Interest in installing distributed generation in Victoria has been growing because distributed generation has a role to play in reducing greenhouse gas emissions, offsetting rising power costs and contributing, on a competitive basis, to a diverse and efficient electricity sector. However, there are concerns about unnecessary barriers to installing and using distributed generation and how electricity fed into the network will be priced. These barriers are preventing the adoption of distributed generation when it is an efficient investment decision for households and businesses.
This inquiry also has been conducted in a context of changing Commonwealth policy regulating electricity markets, including processes for connecting distributed generation and consumer protection, and climate change. In addition, other jurisdictions have been changing their FiT policies (chapter 1).
Wider policy developments
The Commonwealth Government has policies either in place or about to be implemented that will reduce carbon emission and make installing distributed generation more attractive, including:
• a fixed carbon price of $23 a tonne since 1 July 2012, moving to a market-determined price after three years • the Clean Energy Finance Corporation, with a mandate to encourage and leverage private investment in renewable energy and clean technology projects • a target that 20 per cent of Australia’s electricity supply will come from renewable energy by 2020 (supported by assistance that includes subsidises for small-scale renewable energy).
XXIV POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The distributed generation industry itself is now more viable, without the need for industry support measures and subsidies. Moreover, it is growing more rapidly than expected indicating that it is able to compete and secure a place in the electricity generation network into the future.
The widening scope of Commonwealth policies affecting distributed generation and the maturing of the sector raise questions about the continued relevance of previous State policy objectives for distributed generation. Other jurisdictions have faced similar questions and have reformed their FiTs and related policies. Four Australian states have already substantially reduced FiTs:
• In 2012 New South Wales’ Independent Pricing and Regulation Tribunal (IPART) reviewed New South Wales’ FiTs for small-scale solar PV systems, recommended removing the obligation for retailers to offer a gross FiT (of 20 cents per kWh) and suggested that a fair and reasonable net tariff would be in the range of 5.2 to 10.3 cents per kWh. • South Australia’s price regulator, ESCOSA, also made a price determination in 2011 for net FiTs applying to small-scale solar PV and concluded that retailers must pay a minimum FiT of 7.1 cents per kWh in 2011-12, increasing slightly in subsequent years. DNSPs will pay an additional 16 cents per kWh until 30 September 2016. This change reduces the FiT by approximately 27 cents per kWh. • In May 2011 Western Australia halved its net FiT from 40 cents to 20 cents per kWh and has subsequently closed the scheme. • In June 2012 Queensland announced it was reducing its net FiT from 44 cents to 8 cents per kWh from 9 July 2012.
The changes announced in other states contrast with Victoria’s TFiT and SFiT which respectively set FiTs of at least 25 cents per kWh and the retail price.
Distributed generation in Victoria
Distributed generation currently occupies a specific segment in the broader electricity market. The installation and production of distributed generation involves electricity retailers, technology producers and installers, small- and medium-scale generators, and energy DNSPs. Distributed generation is a diverse sector of the electricity market, with a wide range of energy sources and producers, ranging from micro size (households) to medium size. The installation and operation of distributed generation is made more complex by a slew of standards, regulations, policy and legislation imposed by various levels of government.
The extent of distributed generation
Figure 1 shows the capacity of solar PV installed annually, and highlights the impact of the PFiT (introduced in late 2009). The take up of household-scale solar PV has been significantly greater than anticipated by the previous Victorian Government. In the Victorian Climate Change Whitepaper - The Action Plan published in July 2010, the Victorian Government noted that PFiT installations ‘have recently been growing at 1 MW per month and are expected to reach over 40 MW by 2014’ (DPC 2010, p.15). By the end of 2011 households had installed an estimated 150 MW (CEC 2011a, p.32) and are expected to install approximately 250 MW by 2013-14 (ACIL Tasman 2011a, p.42). The Commission considers that the growth in the uptake of PV solar indicated in Figure 1 is not sustainable (chapter 2).
SUMMARY REPORT XXV Figure 1 Annual installed and cumulative capacity of PV in Victoria (MW)
150
100
50
0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Cumulative installed capacity Annual capacity installed
Note: 2011 data based on first eight months of the year only Source: CEC 2011a, pp.32, 34.
While exact figures on market characteristics depend on definitions of distributed generation, Energy Supply Association of Australia (ESAA) figures for June 2010 suggest ‘embedded and non-grid generation’ account for 7.2 per cent of Victoria’s installed capacity (approximately 5.7 per cent from renewable distributed electricity generation and 1.6 per cent from non-renewable distributed generation) (table 1; (ESAA 2011, pp. 18, 20)). Figures on distributed generation capacity are published annually and, as such, the data presented in table 1 are likely to be out of date. Policy changes, such as closing the PFiT scheme, increased the installed capacity of distributed generation in 2011 (figure 1) and hence the data in the table underestimates solar’s current contribution to generation.
XXVI POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Table 1 Capacity of embedded and non-grid generation in Victoria – June 2010 Non-hydro renewable All embedded/non-grid MW MW embedded/ non-grid Natural gas 133 Black liquor 55 Waste gas 45 Landfill gas 40 LPG 0.6 Sewage gas 22 Hydro 103 Solar 75 Non- hydro renewable 619 Wave 0.2 Wind 428 Solar hot water 131,000 units Total 900 Total 619
Notes: Embedded generators are those connected directly to the distribution network, with no direct connection to the transmission network; solar hot water is not included in total. Sources: (ESAA 2011, pp. 20-21; CEC 2011a.
The majority of embedded generation capacity, by volume, is from medium-scale generators, which include wind farms, biomass, gas, hydro and some solar generation. The capacity factor for distributed generation technologies (actual annual generation divided by potential annual generation) varies depending on technology, system design, location and end-user requirement. There are around 30 co-generation facilities in Victoria but they produce a significant amount of electricity (DPI 2012d). While data depend on definitions and sources, non-renewable co-generation accounted for around 478 MW of Victoria’s electricity capacity in 2010 (ESAA 2011, p. 21; CEC 2012a).
The Commission’s framework
Policies affecting distributed generation, including FiTs, are aimed at achieving a number of objectives (chapter 2). These objectives are reflected in the different views participants presented in submissions to the inquiry and during consultations. Submissions to the inquiry and the Commission’s research indicate that there are several broad lenses through which participants view policies for distributed generation and its place in the National Electricity Market (NEM):
• efficiency — investing in distributed generation when it is the most efficient option and being rewarded for the value of the electricity it generates and any broader network benefits without imposing additional costs on other electricity users (that is, without cross subsidies) • fair return — those who invest in distributed generation want a ‘fair return’ on their investment and this may be reflected in an expected ‘pay-back period’ • environmental concerns — investing in distributed generation is primarily driven by environmental concerns such as reducing greenhouse gas emission and should be stimulated so that the share of electricity generated from distributed generation grows as quickly as is practicable.
For the reasons outlined in this report the Commission considers that distributed generation can contribute to reducing greenhouse gas emissions in Victoria and is often a sound commercial decision for many individuals and businesses. However, these outcomes need to be achieved on an efficient economic basis that avoids, as
SUMMARY REPORT XXVII far as possible, cross subsidies from one group of customers to another (especially where these cross subsidies are likely to be regressive).
The electricity industry is a complex market which is regulated — heavily in some areas — and much of this regulation is changing or under review.
The Commission’s response to its terms of reference reflect its view that the primary policy objectives for distributed generation policy should also fit within the broader NEM objectives which are:
To promote efficient investment in, and efficient operation and use of, electricity services for the long term interests of consumers of electricity with respect to – a) price, quality, safety, reliability, and security of supply of electricity; and b) the reliability, safety and security of the national electricity system. (National Electricity Law s 7)
The Commission’s response to its terms of reference is therefore guided by five core principles:
• Incentives reflecting economic value — through efficiently working markets that capture the value of the output of distributed generation and capture the additional efficiency to the network of incorporating distributed generation among investment options. • No cross subsidies — for both equity and efficiency reasons policies for disturbed generation should be subsidy free so that one consumer group is not financially supporting another. • Efficient assignment of policy instruments — the most efficient policy instrument should be used to address a particular issue. • Technology neutrality — policy affecting distributed generation should not discriminate among technologies. • Efficient and predictable processes — connection and other processes should not be unnecessarily burdensome, red tape should be minimised, and processes should be timely and predictable.
Given the context and in applying the principles it is important to understand what is the value of distributed generation, who benefits from these values, and whether the market is capable of delivering those values, and if not, whether barriers can be removed to improve market outcomes (chapter 4).
Value of distributed generation
In economic terms, the Commission has distilled the benefits of distributed generation into two broad types of value:
• output value, which translates into a unit price • network value, which translates into an incremental investment/capital value. Output value
The output value of distributed generation is the value of the electricity produced by the distributed generator. Participants have variously argued that the electricity produced by distributed generation has value arising from:
XXVIII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • The wholesale price of electricity including avoided system losses — distributed generation has an output value based on the wholesale price of electricity because output from distributed generation reduces the amount of electricity that must be purchased on the wholesale electricity market. • Avoided network charges — electricity retailers are required to pay for the use of the transmission and distribution network in the form of transmission use of system (TUOS) and distribution use of system (DUOS) charges. Because distributed generators use only a small part of the network, if any, some argue that the price they receive for exported electricity should reflect avoided network charges. • Pollution and greenhouse gas reduction — electricity produced by low-emission and renewable distributed generators has value because of the value of greenhouse gas reductions (which would have been produced if electricity had have been generated by more emission-intensive technologies). • The merit order effect — the merit order refers to how available sources of electricity are ranked in the marketplace in deciding which will be called on to supply into the wholesale electricity market. Sources of electricity supply are ranked in ascending order according to the price at which they are offering to supply electricity. Usually the suppliers with the lowest marginal costs bid into the market at the lowest price and are the first to be brought online to meet demand. The plants with the highest marginal costs who offer to supply at the higher prices are the last. Distributed generators that supply intermittently based on weather, such as wind and solar generators, are automatically dispatched into the market when they produce. Therefore, introducing new distributed generation with low marginal costs of production can reduce the average wholesale price by displacing high marginal cost gas-generated electricity with lower marginal cost renewable electricity when it is available. Network value
The network value of distributed generation is the difference between upgrading the network sooner, and upgrading it later, taking into account the costs that a distributed generator may impose on the network (ACIL Tasman 2012c, p.vii). The value of distributed generation to the wider distribution network therefore comprises positive and negative elements:
• Deferral of network augmentation costs — the network value of distributed generation stems from electricity being generated close to the customer and therefore not needing to be transported through all of the network. Reducing the demand on the network may defer the need for network augmentation if the network is constrained. However, the value of the distributed generation is driven by its capacity to support the network at the time the network is constrained (which is at times of peak demand) and hence the value is partly technology dependent. • Costs of network reinforcing — connecting distributed generation may require additional expenditure to reinforce the network to allow safe and reliable connection.
Realising the value of distributed generation
Realising or capturing the full value of distributed generation is key to ensuring there are appropriate, efficient incentives for distributed generation to play a role in Victoria’s electricity sector. In the Commission’s view the market is generally the best mechanism to identify and realise value. However, there may be times when markets fail to function effectively and additional regulation or government intervention is needed to ensure efficient outcomes.
SUMMARY REPORT XXIX There are two key elements necessary for realising the value of distributed generation:
(1) there must be payment based on the value of the electricity produced (both network value and output value) (2) the distributed generator must be connected to the network.
These two transactions are the focus of the remainder of the report.
Recovering the output value
The Commission considers that appropriately determined FiTs are the best way to recover the output value of electricity produced by distributed generators.
Ensuring access to an efficient and fair price for exported electricity (particularly for households and small businesses) is the most relevant objective underpinning any future FiT arrangements. This is consistent with COAG national FiT principles and the objectives of the NEM. Efficient and fair FiTs are also consistent with the Commission’s five core principles, in particular that incentives reflect economic value and that there are no cross subsidies.
The Commission notes, however, that there are varying views about what constitutes an appropriate price. The Commission’s assessment of FiTs (chapter 8) concludes that the wholesale price of electricity and reduced network losses should be included in any FiT (which includes the value of reduced greenhouse gas emissions captured through the carbon tax). The Commission sees no argument for including merit order effects in FiTs paid to distributed generators (chapter 9).
Barriers to an efficient market-determined feed-in tariff
The most common view among distributed generation proponents was that retailers are far less responsive to distributed generation than in competing for customers without distributed generation. For example, unlike the process for changing retailers to supply electricity, the processes for signing up to a FiT is complex and lengthy. Distributed generation proponents, particularly in areas not subject to regulated FiTs, have found it difficult to negotiate a FiT for electricity fed into the network. These experiences raise questions about whether market behaviour reflects that which would be expected in a competitive market (that would set ‘efficient and fair’ FiTs chapter 8) or that retailers have business models that do not get value from distributed generation.
The underlying causes of these difficult, complex and lengthy processes are likely to include:
• information and transactions costs • market power issues and vertical integration • limitations on time-of-use and locational pricing • uncertainty of the regulatory environment, coupled with the transition to a national regime.
While on its own none of the above factors constitutes a market barrier big enough to prevent competitive outcomes from emerging (as long as adequate consumer protection, transparency and information is provided), taken together they are likely to be a significant short term barrier.
XXX POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Several of the changes in the NEM that are underway or have been foreshadowed are likely to reduce these barriers, as would the Commission’s recommendations on connecting distributed generation, if accepted. Other aspects could be addressed through consumer protection, reasonable access to information and maturing of the market. Accordingly, a market-based FiT is likely to provide the most efficient outcome in the long term. However, there are important transition issues and in the short term moving too rapidly to market determined FiTs may cause unnecessary disruption and hinder the transition to a fully competitive market. Observation of energy markets in Victoria and other states (particularly New South Wales) over the transition period would provide further evidence on how the FiT markets are performing and whether there is any justification for further measures to improve market outcomes.
Proposed future Victorian feed-in tariff arrangements
The terms of reference require the Commission to, in part, ‘assess the design, efficiency and effectiveness of feed-in tariff schemes, including market-based gross feed-in tariff schemes, in the context of a national carbon price’. The Commission’s view on this element of the terms of reference may be summarised as follows:
• With the advent of the carbon tax, the energy value for distributed generation output is best captured through a wholesale-based price (which includes the carbon tax) adjusted for network losses that is set by the competitive market. A well-specified FiT recovers this value. • FiT schemes should:
− be based on such market prices, and for the immediate future be part of a transition to a fully market-based approach for pricing electricity from distributed generation − include the ability to compare market-based offers on a well-informed and comprehensible basis (for example, through a FiT comparator website) − at least for the short- to medium-term provide an indicative benchmark range (consistent with the methodology outlined by ACIL Tasman 2012) with periodic updates until market FiTs are reasonably established − not be mandated to exceed such a market-based price, because this would mean cross subsidies from customers without distributed generators to customers with distributed generators − be technology neutral so that the most efficient choices among generation technologies can be made − be confined to ‘household-scale’ distributed generation of 100 kW or less, as larger-scale producers are better placed to compete in the market and are likely to have access to alternative mechanisms for selling/exporting electricity to the grid.
• Adopting time-of-use pricing is desirable, because it provides a stronger economic signal to distributed generators of the value of production when overall electricity demand is high. • While there are arguments in favour of gross FiT schemes, there is likely to be significant costs in replacing recently installed smart meters and changing retailers’ supporting infrastructure and computer systems to be able to adopt such schemes. The retention of net FiTs is also consistent with recent changes in other jurisdictions. Therefore, while not ruling out such schemes if they were to arise in the marketplace as a result of competition, the Commission sees no clear value in mandating them.
SUMMARY REPORT XXXI The second element of the terms of reference directs the Commission to ‘provide a recommendation as to whether existing FiT arrangements should be continued, phased-out or amended. Where phase-out of existing arrangements is proposed, the appraisal should give consideration to whether any transitional arrangements may be necessary. Any changes to existing arrangements would not be applied retrospectively’.
There was considerable debate among participants about the structure and method of calculating future FiTs. The Commission has presented and considered the various views in some detail in the body of the report (chapter 9). To avoid confusion, specifically in relation to the criteria used by the ESC, the Commission has adopted ‘efficient and fair’ to characterise FiTs that are based on and reflect the wholesale price of electricity.
Taking into consideration all this input, the Commission recommends:
• the PFiT (closed to new entrants) continue for existing customers until 2024 as previously announced • the TFiT be closed to new entrants by 30 September 2013 or once the 75 MW capacity is reached (as currently legislated), whichever occurs first. Existing customers would receive a TFiT until 2016 as previously announced. The SFiT also be closed by 30 September 2013 • a new net FiT scheme be established to replace SFiT that requires Victorian electricity retailers with more than 5000 customers to offer an efficient and fair FiT to all small low-emissions or renewable distributed generators (100 kW or less) until 31 December 2016. This price would be based on the wholesale price of electricity (which includes the carbon tax) adjusted for reduced system losses • following a transition period, the price for energy from distributed generators would be set through the retail electricity market from 1 January 2017.
That the Essential Services Commission:
• publish information on the likely range of minimum wholesale market-based net feed-in tariffs which would be consistent with an efficient and fair offer — updated at regular intervals and published until 31 December 2016. The estimate by ACIL Tasman at May 2012 suggested a range of between 6 and 8 cents per kWh for 2013 would be consistent with the Commission’s recommendation. • From 1 October 2013 to 31 December 2016 consider the extent to which new FiT offers are consistent with efficient and fair criteria, defined to reflect a wholesale-base value of electricity (the output value, including reduced system losses).
Feed-in tariff transition arrangements
The transition needs to be well understood so there are no surprises for those involved, and they understand what is going to happen, when it will happen and what are the implications of the changes (chapter 10). Experience from the process and attention to detail of the closure of the PFiT has shown the importance of minimising adverse impacts during the transition on:
• installers and electricity businesses — minimising the creation of boom and bust cycles on distributed generation installation • customers — minimising uncertainty and ensuring maximum provision of information
XXXII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • electricity businesses — minimising the impact of a last minute rush of customers wanting to connect.
A time line for implementing the Commission’s recommendations is provided in table 2.
Table 2 The Commission’s recommendations: key events and dates Event Dates Notes Close TFiT to new 30 September 2013 or when customers 75 MW capacity is reached Close current SFiT to new 30 September 2013 or when Legislation required customers TFiT closes Establish new FiT 1 October 2013 or Legislation required. ESC to (market-based) immediately after current consider whether new SFiTs SFiT closure are consistent with an efficient and fair criteria — redefined to reflect a wholesale plus value of electricity Publish information on From 1 October 2013 until minimum FiTs considered 31 December 2016 to be efficient and fair Market-based FiTs to 1 January 2017 apply Current SFiT customers To receive a FiT as per All customers contract made prior to 30 continue to get 1for1 September 2013 (or date of until 31 December SFiT closure) until 31 2016. Afterwards December 2016 payment depends on type of contract. Current TFiT customers Continue on current TFiT As specified in current contract until 31 December legislation 2016 Current PFiT customers Continue on current PFiT As specified in current contract until 31 October legislation 2024
Source: Commission analysis.
However, the design of TFiT and its underpinning legislation inevitably means that, based on the PFiT experience, some intending participants may be disadvantaged when the scheme is closed.
Implications for current premium and transitional FiT customers
As noted above, if the Commission’s recommendation on future FiT arrangements is accepted by the Victorian Government, customers currently receiving the PFiT would continue to receive this FiT until it is contracted to end on 1 November 2024. The key transition issue is to ensure this information is communicated to existing PFiT customers. The Commission notes several participants misunderstood its draft recommendation and thought their PFiT would be terminated early.
SUMMARY REPORT XXXIII At the expiry of their PFiT contract these customers would be free to select a new FiT with retailers based on retailer’s ‘efficient and fair’ offers at the time.
Customers currently receiving the TFiT would continue to receive that tariff for their contract period (31 December 2016). At the expiry of their contract these customers would be free to select a new FiT with retailers based on retailer’s ‘efficient and fair’ offers at the time. The Department of Primary Industries (DPI) should ensure that this information is disseminated to existing TFiT customers to minimise uncertainty and unnecessary anxiety.
The completion date of 31 December 2016 is specified in legislation and is presumably directly (or indirectly) incorporated in each customer’s TFiT contract. The Commission recommends the closure process, when it occurs, be modelled on that for the PFiT scheme, together with any lessons from that closure. In particular as part of the closure process there should be:
• information provided to customers so that they understand the process and timelines • timely monitoring to identify any problems in enough time to take remedial action • a strong explicit role given to the Energy and Water Ombudsman and Consumer Affairs Victoria so that where problems arise for customers they have a right of redress and the numbers of customers affected is known.
Implications for current standard FiT customers
The implications of the Commission’s recommendations for current SFiT customers are more complex than for TFiT and PFiT customers. For one thing, the legislative underpinnings and closure mechanisms are different. Closing or amending SFiT would require amendments to the Electricity Industry Act 2000 (Vic) and associated regulation. In addition, interpreting non-retrospectivity is not straight forward as the provisions of SFiT contracts vary among retailers. Some allow for changes to the way the FiT is calculated, while others lock in a rate for a particular period. It proved impossible for the Commission to determine the number of customers currently receiving SFiT and hence the number affected by the Commission’s recommendations. The data are not readily available and retailers themselves were unable to provide robust data.
The Commission recommends simultaneously:
• closing SFiT to new customers • establishing a new market-based FiT for renewable and low-emission distributed generation.
It is highly desirable, although not necessary, that the timing of these changes coincide with the recommended closure of TFiT to new entrants.
The different legislative underpinning for TFiT and SFiT make coordination challenging. As the Electricity Industry Act must be amended to close or amend the SFiT scheme, time needs to be allowed for this process. In contrast, the TFiT scheme can be closed by notice published in the Government Gazette. Changes to the Electricity Industry Act would also be required to extend the proposed new FiT to cover renewable and low-emission technologies. The Commission is not in a position to assess how quickly necessary changes to the Electricity Industry Act could be achieved. It has assumed that 30 September may be reasonable, or sooner to coincide with an earlier closure of TFiT. In the following discussion references to 30 September 2013 (and 1 October 2013) should also be taken as referring to an earlier date if this is practical. It would be highly
XXXIV POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION desirable, although not essential, for the closing of TFiT and SFiT and opening the new FiT to occur simultaneously.
In making recommendation 9.1 the Commission considered two options to implement its recommended future FiT arrangements that would also meet the terms of reference requirement that the Commission’s recommendations do not apply retrospectively. The Commission notes there may be other practical implementation options. See chapter 10 for more detail on the transitional arrangements.
Option 1: close the SFiT and open a new FiT
Under option 1, the SFiT would close to new customers from 30 September 2013 and a new market-based FiT scheme for all small low-emissions or renewable distributed generators (100 kW or less) would open on 1 October 2013. Existing SFiT customers would be unaffected by the scheme closure and continue to receive a fair and reasonable price in accordance with their existing SFiT contract until the 31 December 2016. The SFiT scheme would close for existing SFiT customers on 31 December 2016.
Option 2: have two classes of SFiT customers
Under option 2, the SFiT would remain open but there would be two classes of SFiT customers from 30 September 2013:
• Class A would be existing SFiT customers — these customers would continue to receive a fair and reasonable price in accordance with their existing SFiT contract until 31 December 2016. • Class B would be new SFiT customers, who enter into the SFiT scheme from 1 October 2013. The Class B SFiT would apply to all small low-emissions or renewable distributed generators (100 kW or less).
The ESC would amend its Methodology for Assessment of Fair and Reasonable Feed-in Tariffs and Terms and Conditions (ESC 2008), so that:
• Class A SFiT customers would continue to receive a ‘one-for-one’ price • Class B SFiT customers would receive an a wholesale-based price.
The Commission was advised that both options 1 and 2 would require amendments to the Electricity Industry Act and associated regulation. The Commission considers that its recommended future FiT arrangements could not be implemented by the Victorian Government without legislative change. Given this, the Commission considers that option 1 is preferable being clearer and more certain for customers and industry. Implications for future customers
New customers (following the closure of TFiT and SFiT (if the government were to choose this option) entering an arrangement to receive a FiT for electricity exported into the grid will be eligible to receive the ‘efficient and fair’ market rate offered by retailers. The Commission considers it likely that different retailers would offer different rates and conditions and it will be up to each customer to explore their options and decide on the offer that best suits their needs.
The Commission has suggested that a price comparator website be established to make the process of comparing retailer offers easier. The website should be available by the end of the transition period recommended by the Commission and provided by the Victorian Government if it is not available from the private sector or the Commonwealth.
SUMMARY REPORT XXXV Under the Commission’s recommendation the offers made by retailers will be available to all distributed generation technologies and not favour a particular technology.
In addition, once on the market-based FiT is established the Commission expects that there will be more certainty for distributed generators as there will be no need to make substantive changes in scheme design once implemented. The FiT rate will vary depending on market rates but this is no different to other contractual arrangements (such a mortgages) which allow for floating rates.
There are many indications that FiTs, while a focus in the past, will not necessarily drive future investment in small-scale distributed generation. Other factors that drive the attractiveness of these investments are strengthening, such as the impact of the carbon tax and lower technology costs.
The main benefit to solar customers will continue to be the avoided cost of the electricity produced and used by the customer. For example, an average householder would save between $383 and $615 in 2013 depending on the size of their PV system. Between 97 and 83 per cent of this saving is the value of electricity displaced from the grid by the householder’s own generation (as the system size increases, a greater proportion of the electricity is exported) (chapter 9).
Special issues for medium-scale distributed generation
Medium-scale distributed generators were also concerned about their ability to sell excess generated electricity. These concerns are known to the Australian Energy Market Commission and several national processes are seeking solutions to the identified problems. The difficulties are, however, even more complicated for precinct-scale projects where the complexities of electricity generation can be compounded by State planning and local regulation, including infrastructure for distributing heating (and cooling).
Precinct-scale projects involve a number of parties, often including but not limited to: proponents of large-scale urban renewal land development, local government, businesses, community groups, utilities (electricity, gas and water), building designers, architects and alternative technology proponents.
Given the complexities associated with precinct-scale developments the Commission is not in a position to recommend specific solutions. The Commission however, does see merit in the Victorian Government sponsoring a combined approach to identifying, evaluating and addressing some of these issues, especially the regulatory framework governing precinct proposals. The Commission has recommended that, to inform future policy development, and assist in the efficient consideration of distributed generation options, the Victorian Government facilitate precinct-scale development(s) by:
• selecting an appropriate precinct scale project, or projects, and bringing relevant interested parties together in a project facilitation group • taking the new precinct development and thoroughly examining the regulatory and other barriers to distributed generation including the net benefit of reducing or removing those barriers • subject to the outcome of this assessment, taking action to remove the barriers, including through necessary changes to legislation and regulation • documenting the results and disseminating the information to government, industry and community organisations to inform future precinct scale distributed generation projects and policy directions (electricity, planning etc.).
XXXVI POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Recovering the network value
Recovering the network value and paying it to the proponents of distributed generation is important to ensure there are incentives for the efficient incorporation of distributed generation into Victoria’s electricity system. However, recovering this value is not easy. No reliable estimates of this value currently exist — at least in the public domain. The size of the network value is difficult to determine because it will be both time and location specific, but in constrained areas of the network it is likely to be large (chapter 5).
If there were an effective market for identifying and realising network value, the Commission expects that distribution businesses would plan measures, including for distributed generation, to address identified localised system constraints where such investment would have a net benefit. The distribution businesses and the proponents of distributed generation would have sufficient information to assess the costs and benefits of proposed distributed generation to the network and the proponent.
The rules on how any necessary network reinforcement costs should be shared, and who pays, would be clear and efficient. Areas where network investment could be avoided by distributed generation (or demand side responses more generally) would be identified and payments made available to proponents of such investments. If distributed generation projects arose outside this planning and required investment to be brought forward, the rules on how such projects would be charged would also be clear and predetermined.
However, the Commission concluded there are two major barriers to the market identifying and realising network value:
• distribution businesses are regional monopolies and therefore do not face competition • regulatory incentives reinforce the traditional approach of investing in the existing network rather than delaying augmentation through encouraging additional distributed generation.
The Commission identified three areas where there is scope to improve current arrangements and put industry participants in a better position to make an informed decision about the value of proposed investment in distributed generation:
• improving information on the location and value of network constraints • increasing transparency and clarity on how network reinforcement costs are determined and shared • recovering the network value and paying it to distributed generators.
Better information about where there are network constraints would help and there are national processes underway to make more information available. It will be necessary to wait until the process is complete to determine if any additional information is required to be published.
Improved information would also help proponents of distributed generators to understand the need for, and likely cost of, any network reinforcement required to enable the connection of a distributed generator. However, the issue of how reinforcement costs are shared among current and future users of the network remains. There was concern that a single distributed generator who ‘tripped’ the requirement to reinforce the network would bear the full cost while subsequent users would free ride on this investment without bearing any cost.
SUMMARY REPORT XXXVII To clarify the circumstances and conditions in which network reinforcement costs can be spread across new distributed generators and other users, the Commission has recommended that the Victorian Government:
• make a submission seeking the development of principles for cost sharing to the Australian Energy Market Commission’s (AEMC) consideration of the Proposal to amend the National Electricity Rules for connecting embedded generators. This submission would be prepared by DPI in consultation with the Australian Energy Regulator (AER), DNSPs and distributed generator proponents • advocate to the AER that it prepares and provides guidance on cost sharing arrangements for the connection of distributed generators before the next round of network distribution pricing determinations expected in 2015.
Recovering the network value is key to ensuring there are appropriate incentives to invest in distributed generation where it is most valued. Possible options for addressing this network value, include:
• recognising that there is a value but doing nothing because of the difficulty and possible transactions costs involved in identifying, calculating and sharing it • improving information about network constraints and reinforcement costs to reduce DNSPs market power and leaving market participants to optimise the network • estimating the value and spreading it across all distributed generators through FiT payments.
However, none of these options is particularly effective in identifying the network value and ensuring it is paid to the distributed generation proponent. Advice provided to the Commission by ACIL Tasman suggested that the network value of distributed generation is in the nature of a local specific capital value that is unrelated to the quantity of energy generated, and is not easily incorporated into the FiT payment. The Commission’s view is that the network value is appropriately dealt with outside the FiT payment.
Another option is to use the AER’s price reset process to consider the value of any network benefits from distributed generation and then to require DNSPs to make payments based on this value. The payments could be made available to proponents of large distributed generators, retailers (to pass on to relevant distributed generators), or aggregators who may be responsible for a number of distributed generators that have an appreciable effect on the network.
DNSPs are already required to provide the AER with estimates of the need for and cost of network investment as part of the price reset process. Those requirements could be modified to include providing estimates of the network costs and benefits of distributed generation (or demand side responses more broadly). This information would be the basis for identifying the areas of the network where the network benefits of distributed generation would be positive and setting up how payments would be made to proponents bringing forward proposals that would realise those benefits.
The Commission therefore recommends that the Victorian Government, through DPI, investigate whether, and how, the AER’s price reset process can be used to:
• identify the network value of distributed generation • require distribution businesses to make available payments based on that value.
XXXVIII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Subject to that investigation producing a practical solution, and in the absence of any other relevant developments, the Commission recommends the Victorian Government prepare and submit a rule change proposal so it could be considered by the AEMC prior to the next price reset process in 2015.
Connection issues
Efficient connection processes are critical to ensuring that there is appropriate investment in distributed generation as part of Victoria’s electricity sector. The connection processes for both medium- and household-scale distributed generation are more complex and costly than they need to be. There is very limited performance information on the efficiency and timeliness of the connection process — in stark contrast to processes in other sectors, such as planning approvals.
The Commission makes a distinction between the processes for connecting medium-scale and household-scale distributed generation because of the different issues involved.
Connecting household distributed generation
The current household connection processes causes problems for consumers, retailers, installers and DNSPs. The problems arise from complicated and time consuming processes, multiple handling of paperwork and a lack of information on the process. There are significant cost savings from reforming connection processes for household- scale distributed generation. These savings come from reducing administrative burdens and ‘bringing forward’ the benefit of producing electricity sooner (chapter 7).
Reducing the administrative burden and delay involved in processing contracts, double handling by retailers of paperwork and reducing paperwork errors could reduce administrative burdens in Victoria by $3m to 4m per year. Time savings, and the ‘bring forward’ depend on whether the individual has errors in their application which delay connection. The estimated ‘bring forward’ of revenue is minimal for those that do not experience errors now ($5), whereas for those who do not experience errors under the improved connection process but would have under the previous process have additional revenue of $95. These ‘bring forward’ savings are important at the individual level but are not significant in aggregate (for details of the calculations see chapter 7).
The Commission consulted extensively after the draft report on the connection process to identify where the problems arise and how they could be addressed. The Commission identified and recommends the following improvements:
• remove the need for separate supply and export contracts with retailers and include a default FiT in retailer’s standard supply contracts • allow households to deal directly with DNSPs rather than retailers.
These reforms would address concerns about delays in the connection process, unnecessary red tape burdens and minimise double handling of paperwork.
In addition DPI should work with the sector to improve information provided to customers on their role and the role of other parties in the connection process, the likely retail and installation costs, and on the progress of their connection application — to ensure information is available to all parties and delays can be identified and addressed early.
SUMMARY REPORT XXXIX In the event that industry is unable to reach agreement by 31 December 2013 — on improving process visibility and removing the retailer from the installation, connection and metering processes, then the Commission recommends the Victorian Government assess the costs and benefits of mandating the reforms.
Many participants argued in favour of online application and tracking systems to improve information flows and reduce delays. While the Commission concluded mandating the establishment of such systems would be difficult, it considers that its recommendation that customers deal directly with DNSPs would increase incentives to improve the system.
Medium-scale connection
Depending on location and operation, medium-scale generators offer several advantages in network support and electricity supply to the owner and other parties in the electricity system:
• greater potential for network savings and lower cost than small-scale renewables because of economies of scale • contribution to national emission reduction targets and improved green building ratings which improve rental returns for building owners • low transaction costs with less than 100 medium- to large-scale plants making up 295 MW of installed capacity and around 50 000 small-scale PV installations making up around 75 MW of installed capacity in Victoria in 2010 (CEC 2011). • co- and tri-generation plants can switch on at full capacity or switch off unlike solar PV which cannot guarantee maximum production when the network is constrained and the electricity spot prices peak (Dunstan et al 2011, p. 12).
The net benefits of medium-scale generation will vary by location and operation and achieving many of these benefits requires connection to the network. Many participants expressed concerns to the Commission about significant barriers to connecting medium-scale generators (chapter 7).
The areas where participants argued there was scope to improve the efficiency of the medium-scale distributed generation connection process are in the areas of:
• The right to connect and export — there are network access barriers for medium-scale distributed generators with ambiguity around standards and no obligation on DNSPs to provide an automatic right to connect and export electricity, subject to the necessary standards and costs being met • Improved process, timelines and uncertainty — the connection process was raised by many participants as a source of uncertainty and delay and therefore a barrier to distributed generation. Areas for improvement are: providing more information on the connection process, standardising the connection process, better information exchange between the proponent and DNSPs, quicker connection times and a better negotiation/arbitration process.
Several of these areas fall within the accountability of the NEM and the AER. Some can be addressed by the Victorian Government. To address these issues the Commission has recommended that, to facilitate efficient connection of medium-scale distributed generators up to 5 MW, the Victorian Government support initiatives that:
• clarify minimum technical standards and cost sharing arrangements that would support a right to connect and export
XL POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • improve information on the connection process and the exchange of information between the DNSP and the distributed generator early in the connection process, including by publishing Sustainability Victoria’s guide to distributed generation connection in Victoria • standardise connection processes • improve engagement between DNSPs and distributed generators • specify and reduce timelines.
In the first instance, the Commission recommends the Victorian Government, through DPI, indicate to the AEMC its support for those aspects of the ClimateWorks, Seed and PCA Proposal to amend the National Electricity Rules for connecting embedded generators that progress the above objectives. The Commission also recommends DPI advise the AEMC accordingly, during the AEMC’s consultation on the rule change proposal.
Should these issues not be resolved through the national rule change process by June 2013, the Commission recommends the Government adding a licence condition requiring DNSPs in Victoria to establish such standards and rights.
SUMMARY REPORT XLI
Recommendations
The six recommendations are listed in the order they appear in the report, and need to be understood in the context of the discussion in respective chapters.
Recommendation 5.1 That to clarify the circumstances and conditions in which network reinforcement costs can be spread across new distributed generators and other users, the Victorian Government:
• make a submission seeking the development of principles for cost sharing to the Australian Energy Market Commission’s consideration of the Proposal to amend the National Electricity Rules for connecting embedded generators. This submission be prepared by the Department of Primary Industries in consultation with the Australian Energy Regulator (AER), distribution network service providers and distributed generator proponents • advocate to the AER for appropriate guidance on cost sharing arrangements for the connection of distributed generators before the next round of network distribution pricing determinations expected in 2015.
Recommendation 5.2 That the Victorian Government, through the Department of Primary Industries investigate whether, and how, the Australian Energy Regulator’s price reset process can be used to:
• Identify the network value of distributed generation • Require distribution businesses to make available payments based on that value.
Subject to the investigation producing a practical solution, and in the absence of any other relevant developments, the Victorian Government prepare and submit a rule change proposal so it could be considered by the AEMC prior to the next price reset process in 2015.
Recommendation 6.1 That, to facilitate efficient connection of medium-scale distributed generators up to 5 MW, the Victorian Government support initiatives that:
• clarify minimum technical standards and cost sharing arrangements that would support a right to connect and export • improve information on the connection process including publishing Sustainability Victoria’s guide to distributed generation connection in Victoria • improve exchange of information and engagement between the distribution network service provider and distributed generator early in the connection process • standardise and simplify connection processes and incorporate more reliable timeframes.
In the first instance, the Victorian Government, through the Department of Primary Industries (DPI), indicate to the AEMC its support for those aspects of the ClimateWorks, Seed and PCA Proposal to amend the National Electricity Rules for connecting embedded generators that progress the above objectives. DPI should make the AEMC
RECOMMENDATIONS XLIII aware of this view during the AEMC’s consultation process on the rule change proposal.
Should these issues not be resolved through the national rule change process by June 2013, the Government, subject to a positive cost benefit assessment, use Victorian regulatory instruments such as adding a licence condition requiring distribution network service providers in Victoria to establish such standards and rights.
Recommendation 7.1 That to facilitate the connection of all renewable and low-emissions distributed generation (100 kW or less) under the new feed-in tariff (FiT) scheme contemplated by recommendation 9.1, the Victorian Government:
• amend the Electricity Industry Act 2000 (Vic) (EI Act) to require that Victorian retailers with more than 5000 customers include a default FiT clause in all their retail supply contracts, which is activated — unless the customer has instructed otherwise — when the retailer is notified by the distribution network service provider (DNSP) that the supply customer has met all the physical and technical preconditions for connecting distributed generation. Retailers and customers would be free to agree on a FiT outside this default offer. The default FiT offer would give effect to the new FiT specified in recommendation 9.1.
That the Victorian Government require the Department of Primary Industries (DPI) to:
• increase the information available to household-scale distributed generation customers — about the customer’s role and the role of other parties in the new FiT connection process, and the likely retail and installation costs — by being proactive in the provision of upfront independent information that:
– outlines the impact of recommended process improvements – identifies which party is accountable for each step in the connection process and who bears the risk for any resulting cost and delay – clearly indicates to the customer the risk of not being informed
• in conjunction with Consumer Affairs Victoria and the Energy and Water Ombudsman Victoria identify, and respond to, ongoing systemic process problems • initiate a process with Victorian retailers and DNSPs to establish an industry agreement on processes that:
– improves visibility of the connection process, so that customers are informed about the progress of their application and can determine if, and where, their application has stalled at any stage in the connection process – allows for the installer to submit the Electrical Work Request and Certificate of Electrical Safety directly to the DNSP, and amend the Solar Connection Form to require customers to fill in the name of their supply retailer.
In the event that industry is unable to agree by 31 December 2013 on improving process visibility and removing the retailer from physical installation, connection and metering process, the Victorian Government, subject to a positive cost benefit assessment, amend the EI Act to:
• create a deemed electricity distribution licence condition that DNSPs vary their Use of System Agreements with applicable retailers to implement these process reforms
XLIV POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • impose a distribution licence condition that Victorian DNSPs amend the Solar Connection Form to add in a new box for customers to fill in the name of their supply retailer.
Recommendation 8.1 That, to inform future policy development, and assist in the efficient consideration of distributed generation options, the Victorian Government facilitate precinct scale development by:
• Selecting an appropriate precinct scale project, or projects, and bringing relevant interested parties together in a project facilitation group. • Taking the new precinct development and thoroughly examining the regulatory and other barriers to distributed generation including the net benefit of reducing or removing those barriers. • Subject to the outcome of this assessment, taking action to remove the barriers. • Documenting the results and disseminating the information to government, industry and community organisations to inform future precinct scale distributed generation projects and policy directions (electricity, planning etc.).
Recommendation 9.1 That, to improve the efficiency and effectiveness of the operation of feed-in tariffs (FiTs) in Victoria, the Victorian Government:
• close the Transitional FiT to new entrants, either by 30 September 2013 or once the 75 MW capacity is reached (as currently provided in legislation), whichever occurs first – those customers currently eligible to receive a Premium FiT (which is now closed) or TFiT to continue to receive this tariff until the end of the contracted period • close the Standard FiT to new entrants at the same time as closing TFiT, or as soon as practical thereafter. Ensure that current SFiT customers continue to receive a feed- in tariff not less than the tariff agreed to prior to the date of closure to new entrants, until 31 December 2016 by continuing the ESC ‘Fair and Reasonable’ guideline until 31 December 2016. The ESC guideline to be rescinded with effect from 1 January 2017. • establish a new net FiT scheme simultaneously with the closure of SFiT to new customers, to require that Victorian electricity retailers with more than 5 000 customers offer ‘efficient and fair’ prices for electricity exported to the grid by all small low-emissions or renewable distributed generators (100 kW or less) until 31 December 2016. Define low-emissions technology as generators that produce 50 per cent or less of the emissions intensity of electricity generation in Australia • establish market-based FiTs from 1 January 2017 to apply to all new participants for electricity supplied by distributed generators through the retail electricity market • allow market-determined arrangements based on gross payments by mutual agreement • ensure a FiT comparison website is operational by 31 December 2016 (the end of the transition period), provided by the Victorian Government if a Commonwealth or private site is not available.
RECOMMENDATIONS XLV That the Essential Services Commission:
• publish information on the likely range of minimum wholesale market-based net feed-in tariffs which would be consistent with an efficient and fair offer —updated at regular intervals and published until 31 December 2016. The methodology adopted by ACIL Tasman suggests (at May 2012) a range of between 6 and 8 cents per kWh for 2013. • From 1 October 2013 to 31 December 2016, assess, on referral from the Minister for Energy whether new FiT offers are consistent with the ‘efficient and fair’ criterion, defined to reflect a wholesale-based value of electricity (including network system losses).
XLVI POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 1 Introduction 1.1 Background to the inquiry
Investment in distributed electricity generation is increasing in Australia and internationally as technology prices fall and distributed generation is an increasingly valued part of the electricity network. This partly reflects policy incentives favouring distributed energy, especially solar.
Electricity generated by renewable and low emission technologies plays a role in reducing greenhouse gas emission and ensuring a diverse and competitive electricity sector. In many cases installing distributed generation capacity makes commercial sense to the household or business installing the capacity. Distributed generation enables them to offset their electricity costs by using their own power in place of purchasing it from a supplier (import replacement) and they may earn additional income by selling unused power into the grid.
While people invest in distributed generation for a range of reasons, proponents are concerned that there are unnecessary barriers to its use and about how electricity fed into the gird will be priced.
A key consideration for households is the economic return they receive from the electricity charges they avoid by generating their own electricity, combined with the price paid for the electricity they export. Many households also invest in distributed generation because they want to make a personal contribution to reducing greenhouse gas emissions.
For larger distributed generation projects, timeliness and cost of the connection process are key concerns, as these costs along with the above mentioned economic return affect the project’s viability. Businesses, such as building owners and developers, may also use distributed generation to improve the attractiveness of their buildings through improved environmental performance of their buildings or their operations more broadly, or to produce heat and/or cooling as well as electricity (co-generation and tri- generation).
The prices paid per unit for the electricity sold by distributed generators are referred to as feed-in tariffs (FiTs). Some FiTs are regulated and set at rates intended to encourage the installation of renewable generators, including photovoltaic (PV) cells, on homes and other buildings and to reduce greenhouse gas emissions. Businesses may also install renewable or low emissions generation that is not covered by FiT schemes, but the price paid for their unused electricity fed into the grid is usually determined by negotiation with an electricity retailer.
The introduction of a national carbon tax combined with other Commonwealth climate change policies, improves the incentives to generate electricity with renewable and low emission technologies. The terms of reference for this inquiry require consideration of the policies that relate to distributed energy generation, including the carbon tax, in relation to:
• assessing the design, efficiency, effectiveness and future of FiT schemes and to recommend any changes to current FiT arrangements • identifying barriers to connecting distributed renewable and low emission technologies into the distribution system.
INTRODUCTION 1 Most other Australian jurisdictions, including New South Wales, South Australia, Western Australia and Queensland, have recently reviewed and changed the way state household (mainly solar) FiTs are regulated, and are substantially reducing their FiTs to levels that are similar to the Commission’s draft and final recommendations.
The narrative begins with some key definitions of distributed generation and feed-in tariffs.
1.1.1 What is distributed generation?
The terms of reference direct the Commission to look into regulatory and other barriers to the development of a network of distributed renewable and low emission generation in Victoria. There does not appear to be a standard definition of distributed generation, however, and reports that analyse distributed generation (or embedded generation) use varying definitions. This inquiry focuses on electricity generation with the following characteristics:
• the electricity is generated by households, businesses or community groups who primarily intend to use the electricity on-site or to supply people or organisations close by, and includes co-generation and tri-generation systems • the generator is connected into the electricity grid through the distribution network, not the transmission network. In some cases the system may be stand alone • electricity in excess of the needs of the generation owner may or may not be sold (exported) into the grid • the electricity could be from renewable sources such as solar, wind, bio gas or waste, but may also be low emission fossil fuels such as natural gas • the total amount of electricity generated is small to medium scale.
The Commission defines medium-scale as greater than 100 kW and generally less than 5 MW. Medium-scale includes co-generation and tri-generation plants, and diesel backup generators, in factories, shopping centres, office blocks and hospitals with capacity often between 1 and 5 MW. It can also include renewable energy generators such as wind and biomass plants. Small- or household-scale distributed generation is defined by the Commission as 100 kW or less and is currently dominated by solar PV in the 1.5 to 5 kW range. The dominance of solar PV in household-scale distributed generation could change as technology changes because it also includes batteries in electric vehicles, fuel cells and micro wind turbines. The terms of reference direct the Commission to focus on low emissions and renewable distributed generation, including co-generation and tri-generation.
The Commission’s definition was generally supported by participants. The Clean Energy Council (CEC) noted that:
The CEC is generally comfortable with the characteristics of distributed energy systems and low emissions generation proposed by the Commission. However, the combined definitions of both distributed and embedded generation require consideration in this case. While used broadly to define generation which is not centralised, ‘distributed generation’ has no clear definition. Conversely, ‘embedded generation’ is defined in the National Electricity Rules (rules) as being a generator “connected within a distribution network and not having direct access to the transmission network. (sub. 76, p. 1)
Similarly, Ceramic Fuel Cells Limited noted that it agrees with the proposed qualitative criteria for defining distributed and low-emission generation and:
2 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION … particularly that the energy is generated by households, businesses or community groups who primarily intend to use the energy on-site or to supply people or organisations close by, and includes cogeneration systems; and that the total amount of energy generated is small to medium scale. (sub. 41, p. 9)
1.1.2 What are feed-in tariffs?
A FiT is a price paid per unit of electricity either ‘fed in’ to the grid (distribution network) or generated by small to medium distributed generators. FiT arrangements provide for customers to enter into a contract with their electricity retailer to receive payments for the electricity generated by small-scale renewable generators at their premises.
FiTs may be either net or gross and may be set by policy or determined by the market. Under a net FiT, a price is paid for any electricity that goes into the grid from the premises, and so the customer is paid only for the surplus electricity generated. Under a gross FiT the customer is paid for every unit of electricity generated, regardless of whether it goes into the grid or is used at the premises, and the customer then pays separately for all the electricity the customer uses including that supplied from the grid. All regulated FiTs in Victoria are net, and apply to small scale distributed generation.
In Victoria, there are three Victorian Government policies that regulate FiTs under the Electricity Industry Act 2000 (Vic):
• the general feed-in tariff scheme, also known as the Standard Feed-in Tariff (SFiT) scheme, established in 2004 • the Premium Solar Feed-in Tariff (PFiT) scheme introduced in 2009 and now closed to new customers • the Transitional Solar Feed-in Tariff (TFiT) scheme, which replaced the PFiT.
All electricity retailers with 5000 customers or more are required to make offers to eligible customers under these three policies. Electricity retailers with fewer than 5000 customers can choose to make offers under these policies, in which case the relevant statutory requirements apply.
The details of these policies are discussed further in chapter 2 and appendix B.
1.2 Context and why this inquiry is important
TFiT (and previously PFiT) is regulated to encourage the installation of PV cells and increase the amount of electricity generated by PV renewable technologies. A wider range of renewable technologies is eligible for SFiT. Recently, however, the Commonwealth legislated to tax carbon emissions. The Commonwealth’s Clean Energy Future legislation, among other things, imposed a fixed carbon price of $23 a tonne from 1 July 2012, moving to a flexible price after three years.
The Commonwealth also has a target that 20 per cent of Australia’s electricity supply will come from renewable energy by 2020. This target is supported by other assistance, some of which is targeted specifically at small-scale renewable energy. Since January 2011 households, small businesses and community groups installing small-scale renewable energy technologies have been eligible to receive financial credits in the form of small-scale technology certificates. Additional credits are available to encourage further the installation of small-scale renewable generators, such as roof-top PV or wind generators (DCCEE 2011).
INTRODUCTION 3 At the state level, the previous Victorian State Government legislated to cut greenhouse gas emissions to 20 per cent below 2000 levels by 2020. However, in March 2012, on the advice of an independent review, the current state government decided to abolish the target.
The introduction of a price on carbon has led the Council of Australian Governments (COAG) to argue that subsidies, including policies such as FiTs, should be discontinued. South Australia and New South Wales recently held inquiries to establish the future framework for setting ‘fair and reasonable’ FiTs in their jurisdictions. Following these inquiries their FiT rates are moving quickly to wholesale price based regimes. Western Australia and Queensland have also recently changed their FiT arrangements and the new FiT rates are much lower than those previously offered. The terms of reference for this inquiry note that:
In the context of the implementation of a national carbon price, it is appropriate that the Commission undertakes a review of Victoria’s feed-in tariff schemes.
More generally, the introduction of a price on carbon will increase the price of electricity, and so improve the competitiveness of electricity generation from renewable and low emission sources. However, there may be regulatory or other barriers that hinder the response to this increased incentive to distributed renewable or low emission electricity generation. As noted in the terms of reference:
Addressing any state and local regulatory or other barriers to the uptake of low emissions generation, including co-generation and tri-generation, is also important to ensure that any transition to low emissions generation occurs as smoothly and as cost-effectively as possible.
The electricity market is being increasingly regulated nationally, with responsibility for more elements transferring to the national jurisdiction. For example, economic regulation became national on 1 January 2009 (chapter 2) and the process for transferring consumer regulation to the national regulator is well advanced. In this context Victoria has limited powers over distributed generation and actions taken by Victoria need to be consistent with national approaches.
This inquiry investigates the barriers that apply to renewable and low emissions distributed generation.
1.3 The Commission’s approach
The starting point for answering the terms of reference is to understand is the value of distributed generation and how it can be realised. If the value of distributed generation can be realised market participants will face appropriate incentives to invest in such generation.
The Commission then considered the barriers to distributed generation achieving its potential within the National Electricity Market and the role FiTs should (or could) play in the policy framework. A key consideration is whether market failures or other barriers prevent participants from responding to market signals (mainly efficient prices) in a way that results in electricity being supplied as efficiently as possible. Removing these barriers in a way that reinforces choice and competitive incentives could help increase the efficiency of investment in and use of network and generation infrastructure.
Efficient FiTs (policy or market determined) play an important role in providing market signals to drive investment and the use of different forms of distributed generation. An
4 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION important question is what is the role of FiTs in reducing greenhouse gas emissions in the context of other state and national climate change policies.
In the absence of a policy role for FiTs in dealing with greenhouse gas emissions, the Commission considers that FiTs should provide efficiency-based incentives for the installation of distributed generation in Victoria’s electricity system where the benefits of this form of generation outweigh the costs. These incentives should not require cross subsidies from one class of customer to another, especially where those cross subsidies are regressive.
The Commission has also examined whether any transition arrangements are necessary in moving from the current regime to its recommended regime.
1.4 Inquiry process
The inquiry was advertised in the press and by circular to those organisations and individuals that the Commission considered likely to be interested. The terms of reference and inquiry particulars were listed on the Commission’s website (www.vcec.vic.gov.au). In February 2012, the Commission released an issues paper and invited submissions to the inquiry.
On 28 June the Treasurer granted the Commission a two week extension to the reporting date for the final report (the due date became 27 July 2012). The Commission took the unusual step of seeking an extension because:
• There had been an extremely high level of interest in the Draft Report which resulted in over 100 submissions and many requests for meetings. These submissions and meetings contributed a substantial body of material to be assessed, a significant proportion of which proved to be new.
• In addition, the Victorian Government decided in June 2012 to delay the previously foreshadowed timing of Victoria’s adoption of the National Electricity Consumer Framework (NECF). The analysis and some of the advice in the Draft Report was based on a start date for NECF in Victoria of 1 July 2012 and required some reconsideration in the light of this change.
During the inquiry, the Commission met with a large number of individuals and organisations — including community groups, consumer representative groups, industry experts, businesses, government agencies, and State and Commonwealth regulators — to identify and assess the relevant issues . The Commission also ran a short Victorian Electricity Retail Business Survey to help analyse current and future Victorian feed-in tariff arrangements. In preparing its draft report the Commission held three roundtables, and received 86 individual submissions from interested parties, including businesses, unions and private individuals. The Commission also received 718 proforma submissions supporting the retention of FiTs sent via the Environment Victoria website and a further 126 proforma submissions where the submitters had added additional comments. After the release of the draft report the Commission held an additional three roundtables and received 114 submissions. Also 100 short submissions and comments on the draft report were received and published on the Commission’s website. Detailed information about the consultation process is available in appendix A.
The Commission engaged ACIL Tasman in March 2012 to advise on the advantages and disadvantages of different methodologies for valuing electricity from distributed generation and model one of these methodologies. The ACIL Tasman report is available on the Commission’s website (www.vcec.vic.gov.au).
INTRODUCTION 5 The Commission thanks those people and organisations that participated in its consultation process and made a submission to the inquiry both before and after the release of the draft report. The Commission appreciates the quality of the submissions, reflecting the thought and effort which has been put into their preparation.
The Commission took account of the Charter of Human Rights and Responsibilities Act 2006 (Vic) and considers that this report is consistent with the human rights set out in the Charter.
6 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 2 Distributed generation in Victoria 2.1 The Victorian electricity industry
The market structure for electricity in Victoria can be defined by interactions through physical electricity flows and financial transactions between market participants (figure 2.1). The key participants in the Victorian electricity industry are summarised in box 2.1.
Figure 2.1 Market structure
physical electricity flows transmission network distribution network physical electricity flows
dispatch orders AEMO generators schedules retailers consumers wholesale market supply offers electricity settlement payments
feed-in tariff electricity settlement payments
financial contracts electricity payments
Source: Commission analysis.
Box 2.1 Electricity industry key participants The key participants in the Victorian electricity industry are: • Generators — produce and supply electricity to the transmission or distribution system. Most of the generation capacity in Victoria is privately owned. The major companies are AGL Energy, International Power, TRUenergy, and Alinta Energy. • Transmission network service providers (TNSPs) — transport electricity from generators to distribution network service providers and large end users through high voltage transmission lines to substation transformers that lower the voltage for distribution. The Victorian TNSP in the National Electricity Market (NEM) is owned and operated by SP AusNet. • Distribution Network Service Providers (DNSPs) — link the transmission systems to end users (including households) through distribution lines that carry low voltage electricity. In Victoria DNSPs are CitiPower, Powercor, Jemena, SP AusNet and United Energy. Each DNSP is responsible for a defined region.
DISTRIBUTED GENERATION IN VICTORIA 7 Box 2.1 Electricity industry key participants (cont.) • Retailers — act as an interface between the electricity wholesale market and customers. They manage customer transfers, connections, billing, complaint handling, and service information. They also deliver a range of Commonwealth and state programs, including community service obligations, energy efficiency schemes, hardship schemes and renewable and other electricity generation schemes. Retailers operating in Victoria include: AGL, Australian Power and Gas, Click Energy, Dodo Power and Gas, Energy Australia, Lumo Energy, Momentum Energy, Neighbourhood Energy, Origin Energy, Powerdirect, Red Energy, Simply Energy and TRUenergy. Retailers are not constrained to operate in a particular region and are free to compete for customers. • Consumers — purchase and use electricity. These assets and businesses physically operate in Victoria and are governed by the rules of the NEM which is a wholesale market for the supply of electricity to retailers and end-users. The NEM consists of five interconnected regions (essentially Queensland, New South Wales, Victoria, South Australia and Tasmania). The NEM is operated by the Australian Energy Market Operator (AEMO) under the National Electricity Law and Rules. Source: Commission analysis.
2.1.1 Market for distributed energy
The Victorian electricity market has historically been shaped by large brown coal generation in the La Trobe Valley, with large transmission lines to distribution networks. This network reflects system design decisions made in the 1920s and a legacy structure that has been adapted over the ensuing years. Since privatisation, smaller gas fired generators have increasingly played a part in the electricity market and, more recently, large-scale wind and small-scale solar capacity have grown. The growth of renewable technology reflects a number of factors including increased climate change awareness and a response to a number of government incentives.
Distributed generation is currently a specific segment in the broader electricity market. The installation and production of distributed generation involves electricity retailers, technology producers and installers, small- and medium-scale generators, and distribution network service providers (DNSP). Distributed generation is a diverse sector of the electricity market, with a wide range of energy sources and producers, ranging from micro size (households) to medium size. The installation and operation of distributed generation is made more complex by a number of standards, regulations and policy imposed by various levels of government.
While exact figures on market characteristics depend on definitions of distributed generation, such generation already appears to play a measurable role in the Victorian electricity market. The Institute for Sustainable Futures (ISF), however, suggests that while Australian distributed generation is growing in absolute terms, it has shrunk as a proportion of installed capacity over the past five years (Dunstan et al. 2011, p. 42).
Small-scale distributed generation
Victorian small-scale distributed generators include homes, businesses and community groups that produce electricity primarily for their own use. Most small-scale generators use solar photovoltaic (PV) technology. Many Victorian electricity retailers are active in the small-scale solar market, having published offers under the standard, premium and transitional feed-in tariff schemes (SFiT, PFiT and TFiT). Electricity retailers with more than
8 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 5000 customers are required to offer feed-in tariffs (FiTs), and have to do so using a variety of packages and terms and conditions (DPI 2012f). The number of PFiT customers and installed capacity (kW) in the various Victorian electricity distribution networks is shown in table 2.1.
Table 2.1 Premium solar feed-in tariff scheme uptake
SP Jemena Powercor CitiPower UED Total Ausnet Number of PFiT 29 771 8 029 29 436 3 533 17 479 88 248 Customers Installed capacity (kW) 60 130 15 618 60 733 6 078 32 697 175 256
Source: DPI 2012a.
As well as retailers, the small-scale solar sector also comprises producers and installers of solar panels. There are significant numbers of solar PV cell and panel producers worldwide, many of which sell their products in Australia. Several electricity retailers also supply and install solar systems, including to customers who purchase their electricity from other retailers. This includes selling a range of system configurations with different panels and inverters, arranging finance, arranging installation by licensed accredited installers, organising applications for appropriate government rebates, and providing advice and assistance for the installation of appropriate meters by the relevant distributers (Origin 2011; TRUenergy 2011). In Australia, all installed solar PV cells and panels must be certified and approved to AS/NZS5033 standards. These guidelines are set by Standards Australia. The Clean Energy Council (CEC) runs an industry accreditation program,1 and more than 3000 accredited installers of PV systems are certified and trained Australia wide.
To be eligible for the Commonwealth rebates and Renewable Energy Certificates (RECs), solar PV systems must be designed and installed by accredited CEC installers. Each installation must have a completed report before the system has been commissioned and RECs can be applied for up to 12 months after installation.
The market for non-solar, small-scale distributed generation operates in a similar fashion. While the PFiT and TFiT are limited to solar (under 5 kW), the SFiT applies to renewable energy sources provided the system is less than 100 kW (table 2.7). Again, Commonwealth rebates and RECs are issued where an accredited system is installed.
Medium-scale distributed generation
Medium-scale distributed generation encompasses customers such as hospitals, office blocks and manufacturers. Many medium-scale generators produce electricity primarily for private use, although some export their excess electricity into the grid, and, for others, selling electricity is their primary focus. Medium-scale distributed generation includes a wide variety of energy sources including renewable and non-renewable energy and encompasses co-generation and tri-generation facilities (which respectively generate heat and electricity, or heat, cooling and electricity simultaneously).
1 See http://www.solaraccreditation.com.au for more details.
DISTRIBUTED GENERATION IN VICTORIA 9 Larger distributed generators can be expensive and the connection process can be long and costly. Most businesses interested in installing distributed generation will therefore engage an electrical contractor to oversee the process. The contractor assesses the business energy requirements and capacity to generate electricity, and determines the feasibility of a generator through consultation with a number of parties. These include local and international technology manufacturers and accredited installers. Once the project is approved the contractor engages the relevant DNSP to establish a connection to the electricity grid.
Take up of distributed generation
While exact figures on market characteristics depend on definitions of distributed generation, Energy Supply Association of Australia figures for June 2010 suggest ‘embedded and non-grid generation’ account for 7.2 per cent of Victoria’s installed capacity (approximately 5.7 per cent from renewable distributed electricity generation and 1.6 per cent from non-renewable distributed generation) (table 2.2; (ESAA 2011, pp. 18, 20)). Figures on distributed generation capacity are published annually and, as such, the data presented in table 2.2 are out of date. Policy changes, such as the PFiT scheme closure, are known to have increased the installed capacity of distributed generation in 2011 (figure 2.2). The majority of embedded generation capacity, by volume, is from medium-scale generators, which includes wind farms, biomass, gas, hydro and some solar generation.
The capacity factor for distributed generation technologies (actual annual generation divided by potential annual generation) varies depending on technology, system design, location and end-user requirement. The approximate capacity factors for various types of renewable and non-renewable electricity generation in Victoria are presented in table 2.3
Table 2.2 Capacity of embedded and non-grid generation in Victoria — June 2010
Non-hydro renewable All embedded/non-grid MW MW embedded/ non-grid Natural gas 133 Biomass - black liquor 55 Waste gas 45 - landfill gas 40 LPG 0.6 - sewage gas 22 Hydro 103 Solar 75 Non- hydro renewable 619 Wave 0.2 Wind 428 Solar hot water 131 000 units Total 900 Total 619
Notes: Embedded generators are those connected directly to the distribution network, with no direct connection to the transmission network; solar hot water is not included in total. Sources: ESAA 2011, pp. 20-21; CEC 2011a.
10 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Table 2.3 Approximate capacity factor of renewable technologies Victoria
Energy type Capacity factor a (per cent) Gas (open cycle gas turbine) 2-90 Hydro-electricity 15 b Solar (utility-scale photovoltaic) 20-22 Wave and tidal 25-30 Wind 30 Geothermal 80-90 c Brown coal 80-90 Biomass - d
Notes: a The approximate capacity factor is the ratio of the annual generation to the maximum possible generation if the system operated at full power every hour of the year; b capacity factor depends on rainfall and dam storages; c capacity factor is theoretical. In practice it has been significantly lower; d capacity factor varies depending on site and fuel type — DPI suggests direct combustion has an approximate capacity factor of 2035%, while co-generation and thermal-only bioenergy systems have an approximate capacity factor of 85% or higher. Sources: VAGO 2011, p.3; DPI 2012b.
Importantly, the ISF notes that:
In absolute terms, installed DG [distributed generation] capacity has increased in Australia by about 20% between 2006 and 2010 … however this has not kept pace with the national average increase in installed capacity. (Dunstan et al. 2011, p. 42)
Unfortunately, a lack of data makes it difficult to assess the uptake and system impact of small-scale distributed generation. While solar PV installations are well documented it would be useful to understand what proportion of small-scale distributed generation they account for. Furthermore it would be useful to track the impact of various FiT schemes on the uptake and impact of non-solar distributed generation. This would help assess the extent to which FiTs detract from the uptake and impact of other distributed generation technologies in favour of solar PV.
Figure 2.2 shows the capacity of solar PV installed annually, and highlights the impact of the PFiT (introduced in late 2009). The take up of household-scale solar PV has been significantly greater than anticipated. In the Victorian Climate Change Whitepaper - The Action Plan published in July 2010, the previous Victorian Government noted that PFiT installations ‘have recently been growing at 1 MW per month and are expected to reach over 40 MW by 2014’ (DPC 2010, p.15). In the four years to 2011, the cumulative installed capacity of solar PV across Australia increased more than 100-fold. While the cost of PV units declined over this period ‘this extraordinary growth [in installed capacity] has been pump-primed by what has been widely acknowledged as excessively generous subsidies provided by multiple levels of government’ (T Nelson et al. 2012, p. 1).
DISTRIBUTED GENERATION IN VICTORIA 11 Figure 2.2 Annual installed and cumulative capacity of PV in Victoria (MW)
150
100
50
0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Cumulative installed capacity Annual capacity installed
Note: 2011 data based on first eight months of the year only. Source: CEC 2011a, pp.32, 34.
Although there are only around 30 co-generation facilities in Victoria they produce a significant amount of electricity — substantially more than the household production (DPI 2012d). While data depend on definitions and sources, non-renewable co- generation accounted for around 478 MW of Victoria’s electricity capacity in 2010 (table 2.4).
Table 2.4 Co-generation capacity in Victoria — 2010
MW Brown coal 195 Natural gas 124 Waste gas 45 LPG 0.6 Bioenergy 113 Total 478
Note: the 195 MW Morwell brown coal co-generation power station is classed as a ‘principal power station’ and does not appear in table 2.4. Sources: ESAA 2011, p. 21; CEC 2012a.
12 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Pricing electricity
The retail price of electricity reflects three elements — the wholesale price of electricity, network tariffs and retail services. Future retail prices will also be affected by capital change and investment in the network. According to the Australian Energy Regulator (AER), the average electricity bill reflects a cost breakdown of 42 per cent wholesale costs, 47 per cent network costs and 11 per cent retail costs (AER 2011d, p. 2)2.
Wholesale electricity price
Within the National Electricity Market (NEM), exchange between electricity producers and consumers occurs within a pool in which output from all generators is aggregated and scheduled to meet demand. Wholesale electricity trading is conducted in a spot market in which supply and demand are matched instantaneously. At five-minute intervals, generators bid to supply the market a specific amount of electricity at a specific price. AEMO determines the most cost-effective generators to meet demand and dispatches them into production. The cost to supply the last megawatt of electricity to meet demand (within the five minute period) is deemed the ‘dispatch price’ and applies to all generators in production, regardless of their original bid. The ‘spot price’ of Victorian electricity for a 30 minute trading interval is the average of the previous six dispatch prices.
The Rules set a maximum spot price (market price cap) at $12 500 per MWh. This is the maximum price generators can bid into the system, and automatically triggers AEMO to request customer electricity supply be interrupted to maintain supply and demand balance. The Rules also limit the minimum spot price (market floor price) at minus $1000 per MWh (that is, the generator pays to have their electricity dispatched). Market non- scheduled small generators are said to be ‘price takers’ in the NEM. That is, while they cannot set the spot price, they receive it for any electricity exported into the grid.
AEMO determines the liabilities of all market participants daily and settles trade transactions in the NEM weekly. NEM financial settlement operates on a four week delay. The settlement price for generators and market customers equals the amount of energy consumed or supplied multiplied by the spot price and any loss factors (AEMO 2010a).
Network tariffs
Network tariffs recover the cost of transporting electricity from generator to customer. This takes places through the transmission network (high voltage power lines that transport energy long distances) and the distribution network (lower voltage power lines that deliver electricity to homes and businesses). Network tariffs are regulated by the AER and include the cost of:
• maintaining, replacing and extending infrastructure • metering • operating the network business (including labour, material and compliance with reliability and safety standards) • financing the installation of new equipment • complying with government legislation (AER 2011d, p. 3).
2 Based on the average customer bill in the Australian states where network prices are set by government.
DISTRIBUTED GENERATION IN VICTORIA 13 Retail services
Retailers purchase wholesale electricity in the NEM, pay the owners of distribution and transmission networks to transport electricity, and bill customers for their electricity use. Retail services include customer information and billing; and the costs of these services include:
• running customer service centres, advertising and selling electricity contracts • complying with government legislation (AER 2011d, p. 3).
Unlike other states, the price of Victorian retail services is unregulated and electricity prices are directly determined by retailers.
All customers must install equipment that monitors their consumption and measures electricity use. This equipment is provided by local network service providers and is registered and audited by AEMO. Currently, under the National Electricity Rules (NER) there is no obligation for decentralised generators to install remotely-read interval meters. Where these are not used, generators may not receive accurate settlement statements as actual output may not be incorporated into the settlement cycle until revision (up to 30 weeks after billing).
2.2 Regulation of distributed generation in Victoria
Regulation of the electricity sector in Victoria is complex, comprising a combination of national and State-based regulation. The trend in recent years has been towards an increasingly national regulatory framework with the economic package of national reforms completed in 2008.3 The non-economic package of national reforms was intended to commence on 1 July 2012, by creating a single national framework for energy distribution networks and retail markets — that is the supply and sale of energy to retail customers. This reform process is known as the National Energy Customer Framework (NECF). These reforms have significant implications for distributed generators wishing to connect to the distribution network. Since publication of the draft report, the Minister for Energy and Resources announced that the Victorian Government will not implement the NECF in Victoria on 1 July 2012. On 13 June 2012, the Minister noted that ‘the Victorian Government had consistently stated that it would only agree to implement the National Framework if key Victorian consumer protections were retained’ (O’Brien 2012b). In an earlier statement, the Minister also raised concerns about the Australian Energy Regulator (AER) being adequately funded to administer jurisdictional-specific matters that Victoria intends to retain under the NECF (O’Brien 2012c). The delay of the NECF in Victoria is discussed in section 2.2.2.
This section provides an overview of:
• the regulatory framework governing the NEM (section 2.2.1) • delay of the NECF in Victoria (section 2.2.2) • connecting to the distribution network (section 2.2.3) • selling (exporting) electricity generated (section 2.2.4) • how regulation of the electricity sector impacts distributed generation and the implications of these arrangements for the inquiry (section 2.2.5).
3 The AER assumed national responsibility for DNSP price determinations on 1 January 2008, with the exception of Western Australia (MCE 2009, p.4).
14 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION A more detailed discussion of the framework regulating distributed generation in Victoria can be found in appendix B: Regulation of the electricity sector.
2.2.1 Regulation of the NEM
Current regulatory framework
The NEM is the wholesale market for the supply of electricity to retailers and end-users in all states and territories except Western Australia and the Northern Territory. The regulatory framework for the electricity market in Australia is governed by the Council of Australian Governments (COAG) and is developed under the guidance of Standing Council on Energy and Resources (SCER). The AER regulates the NEM. The AEMC makes rules in response to requests for rule changes, usually from NEM participants. The AEMO manages and operates the NEM and coordinates planning of the market. Appeals — in relation to price determinations made by the AER in accordance with the NER — are considered by the Australian Competition Tribunal.
The NER are made under the National Electricity Law (NEL). The NER are maintained and developed by the AEMC and enforced by the AER. The lead legislation for the NEL is the National Electricity (South Australia) Act 1996 (SA). This legislation is applied in Victoria by the National Electricity (Victoria) Act 2005 (Vic).
The current national regulatory framework for distribution and transmission is supplemented by Victorian legislation. The Electricity Industry Act 2000 (Vic) (EI Act) includes a licensing regime for those generating electricity for supply or sale, and the Victorian FiT arrangements for the PFiT, TFiT and SFiT schemes. The Victorian Essential Services Commission (ESC) administers the licensing framework and is the retail regulator in Victoria. The high-level structure of the current Victorian electricity sector is outlined in figure 2.3.
Regulatory framework after commencement of the NECF
The NEL and NER are complemented by the NECF, which was intended to commence in all Australian jurisdictions except Western Australia and the Northern Territory on 1 July 2012. However, it has been delayed in the majority of participating jurisdictions including Victoria. The NECF regulates the sale of energy to retail customers through the National Energy Retail Law (NERL) and National Energy Retail Rules (NERR). It also amends existing national regulation, including introducing chapter 5A into the NER, which regulates electricity connections for retail customers (including embedded generators). The lead legislation for the NERL— the National Energy Retail Law (South Australia) Act 2011 (SA) — came into operation on the 1 July 2012 by proclamation of the Governor of South Australia. Components of the NECF which are of relevance to the inquiry include:
• the NERR • the National Energy Retail Regulations • amendments to the NER, including a new chapter 5A for electricity retail connections (JIG 2012b, pp.2–3).
The legal architecture of the NECF allows jurisdictions to implement it at different stages. Participating states and territories must apply the NECF via jurisdictional implementing legislation before the NECF will commence in their jurisdictions.
DISTRIBUTED GENERATION IN VICTORIA 15 Figure 2.3 Victorian electricity regulatory structure
Council of Australian Governments (COAG)
Standing Council on Energy & Resources
Australian Energy Australian Energy Australian Energy Market Operator Market Commission Regulator (AER) (AEMO) (AEMC) Economic regulator of System operator and transmission and Rule maker and adviser planning distribution networks
Australian Competition & Consumer Commission (ACCC)
Participants & Consumers
AER currently administers for Essential Services Australia the economic regulation Commission (ESC) of: Licensing and service • transmission network service standards providers (TNSPs) • distribution network service providers (DNSPs) In Victoria the ESC currently regulates: Under the NECF the AER will also • transmission, distribution, generation regulate: and retail licensing • non-economic regulation of • non-economic regulation of DNSPs retailers (including retailer and retailers authorisations and exemptions, Under the NECF the ESC will: sale to retail customers and • no longer licence or regulate retail consumer protection) retailers but will still assess referred • non-economic regulation of retail feed-in tariff terms and DNSPs, including supply to retail conditions customers and new distributed • no longer regulate DNSPs but will generation connections retain responsibility for transmission, distribution and generation licensing
Source: Commission analysis.
16 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 2.2.2 Delayed commencement of the NECF in Victoria
The NECF will be applied in Victoria by the National Energy Retail Law (Victoria) Bill 2012, currently before the Victorian Parliament. Clause 2 of the Bill provides that it will commence on a day to be proclaimed (Explanatory Memorandum 2012, p.1; O’Brien 2012a, p.1447). Although the Victorian Government has confirmed that the NECF will not commence on 1 July 2012 as planned, at the time this report was finalised a new commencement date had not been announced.
The implementation of the NECF has also been delayed in some other participating jurisdictions. Bulletin No. 5 of the Joint Implementation Group, which is responsible for coordinating the implementation of the NECF by participating jurisdictions, confirmed that:
• Tasmania, the Australian Capital Territory and the Commonwealth will apply the NECF from 1 July 2012 (‘first applying jurisdictions’) • South Australia, Queensland, New South Wales and Victoria will not apply the NECF on 1 July 2012 (‘later applying jurisdictions’) (JIG 2012b, p.1).
Bulletin No. 5 also clarified that:
• the NECF can commence in the first applying jurisdictions ahead of the lead legislator jurisdiction (South Australia) • retailers located in later applying jurisdictions will continue to governed by state- based retail licensing frameworks until the NECF is applied • DNSPs located in later applying jurisdictions will be required to operate under existing jurisdictional regulatory arrangements and national economic regulatory requirements (the NEL/NER) until the NECF is applied • as each of the later applying jurisdictions apply the NECF, the AER will assume responsibility under the relevant jurisdictional implementing legislation for that applying jurisdiction (JIG 2012b).
A SCER Meeting Communique, dated 8 June 2012, stated that: … Victoria will undertake further work with the AER regarding the administration of certain key state specific retail regulations. In the meantime, Victoria, New South Wales and Queensland agreed to explore opportunities to align state retail and consumer protection arrangements with the NECF. (SCER 2012, p.2)
The New South Wales Government announced that commencement of the NECF has been deferred in New South Wales until 2014, to allow time for the Government to ensure that consumer information protection measures are satisfactory (Hartcher 2012). The Victorian Minister for Energy and Resources has since stated the Victorian Government will ‘explore opportunities to align state retail and consumer protection arrangements with the national framework where it does not result in lower standards’ and that Victoria will work with other jurisdictions to implement the NECF ‘as soon as practicable’ (O’Brien 2012b).
ESC Interim Guidance Statement
On 27 June 2012, the ESC released an Interim Guidance Statement on its approach to retail energy regulation from 1 July 2012. The ESC stated that:
DISTRIBUTED GENERATION IN VICTORIA 17 Businesses operating under a Victorian licence are required, and will continue to be required to comply with the licence conditions and with current codes and guidelines issued under the relevant Industry Acts (collectively, ‘the Victorian framework’). Retailers will remain obligated to monitor their compliance with relevant obligations and to promptly report material breaches of these obligations to the Commission … In recognition of the Victorian Government’s commitment to exploring opportunities to align state retail and consumer protection arrangements with the National Framework, the Commission intends to harmonise, where possible, its regulatory framework and the proposed National [Energy Customer] Framework. We will liaise with the Department of Primary Industries to determine the parameters of such a harmonisation process. (ESC 2012c, p.1)
Some of the key ESC retail and DNSP licence conditions, Codes and Guidelines relevant to distributed generation are summarised in box 2.2. Victorian retailers and DNSPs will be required to comply with these requirements until the NECF is applied in Victoria. Retail Codes and Guidelines are enforced by the ESC. Although the ESC is currently responsible for distribution licensing, the AER is responsible largely for the enforcement of DNSP Codes and Guidelines.4
Box 2.2 Victorian regulation of distributed generation The Essential Services Commission (ESC) licences Victorian electricity retailers and distribution network service providers (DNSPs). The ESC also administers the non- economic regulation of Victorian electricity retailers and DNSPs. Key sources of State-based regulation relevant to distributed generation are outlined below. Retailers: • electricity retail licence conditions, including the feed-in tariff provisions in the Electricity Industry Act 2000 (Vic) which are currently enforced as retail licence conditions • Electricity Retail Code (ESC 2012b) DNSPs: • distribution licence conditions • Electricity Distribution Code (ESC 2012a) • Electricity Industry Guideline No. 14: Provision of Services by Electricity Distributors (ESC 2004b) • Electricity Industry Guideline No. 15: Connection of Embedded Generation (ESC 2004a) Retailers and DNSPs: • Use of System Agreements between retailers and DNSPs • Electricity Customer Metering Code (ESC 2011a) Sources: Victorian electricity licence conditions; ESC Codes and Guidelines.
4 The AER assumed responsibility for the economic regulation of Victorian DNSPs on 1 January 2009 under the National Electricity (Victoria) Act 2005 (Vic) (NEVA) Pt 4. The ESC remains responsible for administering the non-economic components of ESC Codes and Guidelines (AER 2012i). There is no definition of ‘economic’ functions in the NEVA. As such, there is no definitive list of the ESC responsibilities transferred to the AER.
18 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 2.2.3 Connecting to the distribution network
The process for connecting connection applicants (CAs) to the distribution network will change with the commencement of the NECF. Currently there is one connection process under chapter 5 of the NER for distributed generators, which is supplemented by Victorian regulation (including licence conditions, Codes and Guidelines). However, small embedded generators are able to connect through a separate small embedded generator State-based connection process.
With the commencement of the NECF, the majority of State-based obligations imposed on DNSPs — contained in distribution licences, ESC Codes and Guidelines — will be replaced or replicated by national regulation. These Victorian regulations will largely become redundant and will be repealed. Therefore, after the implementation of the NECF, the NER chapter 5 connection process will only be supplemented by a minimal number of State-based requirements that the Victorian Government has decided to retain. At this stage, it is unclear which State-based regulation — relevant to new embedded generator connections — will be retained after the NECF is applied in Victoria.
After commencement of the NECF, there will be two separate processes under the NER for connecting distributed generation to the distribution network:
• a process for registered generators or generators exempt from registration by AEMO under chapter 5 • a process for retail customers (including generators who do not intend to participate directly in the NEM and instead intend to sell electricity through a direct contract with a retailer) under chapter 5A.
Each connection process sets the rights and obligations for those seeking connection to the distribution network and specific sizes/types of generators may be excluded from, or find it more difficult to access, one or other of these connection processes. There are various fees and charges associated with connecting distributed generators to the distribution network applied by DNSPs. These costs vary depending on the size/type of generator being connected and type of connection. With the commencement of the NECF, fees and charges will be regulated nationally by the AER through the NER.
Connecting distributed generation under chapter 5
To be connected under chapter 5, registration as a generator is required unless AEMO grants an exemption from registration (NEL, s 11; NER, cl 2.2.1). A Standing Exemption exists for generating systems with a nameplate rating of less than 5 MW (AEMO 2010b, p.36). In certain circumstances, AEMO may also exempt generators less than 30 MW from registration on a case-by-case basis.
Generator classification has significant implications for participation in the NEM. Registration as a ‘market generator’ is required to sell electricity in the NEM through the spot market. The consequences of generator classification for distributed generators wishing to export excess electricity generated are discussed in section 2.2.4.
Connection under chapter 5 is a negotiated process. The DNSP ‘must use reasonable endeavours’ to provide the access arrangements sought by the CA, ‘subject to those arrangements being consistent with good electricity industry practice’ (NER, cl 5.5(e)). However, there is an automatic right of connection if automatic access standards outlined in sch 5.2 are met. These automatic access standards apply to larger registered generators. Generators of less than 5 MW capacity must negotiate the terms of a connection agreement, including technical standards, with their DNSP on a case-
DISTRIBUTED GENERATION IN VICTORIA 19 by-case basis. Connecting under chapter 5 is a long and complex process, even for large-scale distributed generators that meet automatic access standards. Connecting for small and medium-scale distributed generators under chapter 5 is very uncertain, as the CA would need to negotiate technical standards on an individual basis.
Supplementary Victorian regulation
Victorian regulation contains supplementary requirements and protections for distributed generation proponents connecting under NER chapter 5. These additional requirements will be largely replaced under the new NER chapter 5A and therefore repealed once the NECF is applied in Victoria. They include:
• Electricity Industry Guideline No. 15, cl 2.1 requires DNSPs to negotiate generator access arrangements in ‘good faith’ with embedded generator proponents (ESC 2004a, p.2) • a Victorian distribution licence condition that DNSPs offer connection services to embedded generators within 65 days of request or when the DNSP receives all the information ‘reasonably require[d] to make the offer, whichever is the later’ (cl 7.1 and 11.1) • a specific connection agreement is not required for ‘small embedded generators’, defined as embedded generators of 2 kW or less and/or embedded generators that meet Australian Standard AS4777. DNSPs and embedded generators may enter into a small embedded generator standard connection agreement under cl 3.2 of the Electricity Industry Guideline No. 15: Connection of Embedded Generation (ESC 2004a). Clause 3.2 requires DNSPs to have a ‘fair and reasonable’ standard connection agreement for ‘small embedded generators’ that the AER has approved.5 If requested by a customer or retailer, DNSPS must make a small embedded generator standard connection offer within 65 business days ‘adapted only to reflect the particular circumstances of the small embedded generator’ CA (cl 3.2.5). Distribution planning and reporting
DNSPs are required to consider the impacts of connecting distributed generation as part of their distribution network planning. The national network planning and development framework is supplemented by State-based planning and reporting regulatory arrangements. In Victoria, the Electricity Distribution Code (ESC 2012a) requires that DNSPs publish annual distribution system planning reports (DSPRs) that plan for the next five calendar years (cl 3.5). A DSPR must cover:
• historical and forecast demand • feasible options for meeting forecast demand, such as opportunities for embedded generation and demand management • availability of contributions from the DNSP to embedded generators to reduce forecast demand and defer or avoid augmentation of the distribution system.
5 The Commission understands that the AER does not intend to seek Victorian DNSPs to submit their terms and conditions for small embedded generators under Guideline No.15 for approval unless there is evidence that the current arrangement is not working (see box B.2 for a description of the AER’s approach to approving small embedded generator standard connection agreements).
20 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Connecting distributed generation under chapter 5A
The new chapter 5A connection process is designed primarily for retail customers seeking to buy electricity, but it will also apply to distributed generators wishing to connect to the distribution network and sell electricity directly to a retailer. Chapter 5A provides for three types of connection service for ‘retail customers’.
(1) A basic connection service which will cover retail customers, including those who are micro-embedded generators (but not larger embedded generators). DNSPs must have a model standing offer for basic connection services that has been approved by the AER. Micro-embedded generators are not defined in chapter 5A according to generator size. The NER merely state that a micro EG (micro-embedded generator) connection is ‘of the kind contemplated by Australian Standard AS 4777 (Grid connection of energy systems via inverters)’ (cl 5A.A.1). (2) A standard connection service which can cover the terms and conditions for different classes of connection services or different classes of retail customers (including non-registered embedded and micro-embedded generators). DNSPs can choose to prepare a model standing offer for such services and have it approved by the AER. (3) A negotiated connection contract which covers services that are not subject to a basic or standard connection standard offer, or where a basic or standard connection service is sought but the CA elects to negotiate the terms and conditions of the connection agreement. The terms and conditions for such services are negotiated and if agreement cannot be reached the dispute can be arbitrated by the AER. The DNSP must use its 'best endeavours' to make a negotiated connection offer within 65 business days. A CA is an applicant for a connection service that is a retail customer (including an embedded generator), a retailer or other person acting on behalf of a retail customer, or a real estate developer.
Table 2.5 summarises the current connection process for distributed generators in Victoria, which is governed by the NER chapter 5 connection process and supplemented by State-based regulation. Table 2.6 summarises the connection processes after the NECF commences in Victoria, which will be governed by chapters 5 and 5A of the NER. See appendix B for a detailed discussion on the connection processes for distributed generators under chapters 5 and 5A of the NER.
DISTRIBUTED GENERATION IN VICTORIA 21 Table 2.5 Current connection process for distributed generators in Victoriaa
Source Applies to Connection Right to connect? NER chapter 5 • Registered generators — various Negotiated — Yes for larger generators — if (supplemented by combinations of: • NER cl 5.5 outlines access automatic access standards are met Victorian – scheduled, semi-scheduled and arrangements for embedded (NER, sch 5.2) regulation) non-scheduled generators wanting to connect to No — if CA wishes to negotiate any – market and non-market the distribution network. DNSPs must access standards or if the generator is ‘use reasonable endeavours’ to • Generators exempt from exempt or eligible for exemption from provide access arrangements registration, automatic access registration: sought by CA (cl 5.5(e)) standards do not apply and there is no – generators <5 MW (must meet • DNSP must provide CAs with automatic right to connect under NER Standing Exemption criteria) ‘reasonable information’ and chapter 5 – other generators <30 MW on a negotiate generator access case-by-case basis (includes However, DNSPs must offer connection arrangements in ‘good faith’ (ESC services to embedded generators generators >5 MW and <30 MW Guideline No. 15, cl. 2) within 65 days or when the DNSP capacity which export <20 GWh • DNSP and embedded generators receives all the information ‘reasonably in any 12 month period) must ‘negotiate in good faith’ to require[d] to make the offer, whichever reach connection agreement, if is the later’ (distribution licence such an agreement is sought condition (cl 7.1 and 11.1)) (Distribution Code, cl 7.1.2) Under the National Electricity (Victoria) • DNSPs must be able to receive Act 2005 (Vic), the AER can resolve supply from a connected disputes on whether the terms and embedded generator in conditions of Victorian DNSPs’ accordance with a connection embedded generation connection agreement (Distribution Code, offers are ‘fair and reasonable’ cl 7.1.1)
22 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Table 2.5 Current connection process for distributed generators in Victoria a (cont) Source Applies to Connection Right to connect? Victorian ‘Small embedded generators’ — Under the Distribution Code, a specific Yes — if requested by a customer or regulation: defined as: connection agreement is not required retailer, DNSPS must offer an approved b • distribution • embedded generators of 2 kW or for small embedded generators. standard connection within 65 business licence less and/or Each DNSP must, however, keep a days ‘adapted only to reflect the particular circumstances of the small conditions • embedded generators that meet register for all embedded generators connected to its distribution network (cl embedded generator’ CA (ESC • ESC Guideline Australian Standard AS4777 Guideline No. 15, cl 3.2.5) No. 15 7.9) and inform all registered small embedded generators of their rights • Electricity and obligations at regular intervals (on Under the National Electricity (Victoria) Distribution initial connection and at least every 3 Act 2005 (Vic), the AER can resolve Code years thereafter)(cl 9.1.3A) disputes on whether the terms and conditions of Victorian DNSPs’ DNSPs and small embedded embedded generation connection generators may enter into a ‘fair and offers are ‘fair and reasonable’ reasonable’ standard connection agreement for ‘small embedded generators’ that the AERc has approved under ESC Guideline No. 15, cl 3.2
Notes: a Additional Victorian technical and safety standards in the Electricity Distribution Code (ESC 2012a) cl 7.2. to 7.9 also apply. b The ESC had determined that a specific connection agreement between DNSPs and small embedded generators is not required. See Final Decision: Network Connection Arrangement for Small Embedded Generators (ESC 2007).c Responsibility for approving small embedded generator standard connection agreements transferred from the ESC to the AER on 1 January 2009. The Commission understands that the AER does not intend to seek Victorian DNSPs to submit their terms and conditions for small embedded generators under Guideline No.15 for approval unless there is evidence that the current arrangement is not working (see box B.2 for a description of the AER’s approach to approving small embedded generator standard connection agreements). Sources: Commission analysis of chapter 5 NER and State-based regulation (Victorian distribution licence conditions; ESC Electricity Distribution Code (ESC 2012a) and Electricity Industry Guideline No. 15: Connection of Embedded Generators (ESC 2004a), Dispute Resolution Process: Customer Connection to Electricity Networks (AER 2011b).
DISTRIBUTED GENERATION IN VICTORIA 23 Table 2.6 Connection process for distributed generators after the NECF commences in Victoriaa
NER Applies to Generator type Connection Right to connect? Chapter 5 • Registered generators Various Negotiated — cl 5.5 Yes — if automatic access standards are combinations of: outlines access met (sch 5.2) • Generators exempt from registration: • scheduled, arrangements for – generators <5 MW (must meet embedded generators Standing Exemption criteria) semi-scheduled No — if CA wishes to negotiate any and wanting to connect to access standards or if the generator is – other generators <30 MW on a case- non-scheduled the distribution exempt or eligible for exemption from by-case basis (includes generators network. DNSPs must registration, automatic access standards >5 MW and <30 MW capacity which • market and ‘use reasonable do not apply and there is no automatic export <20 GWh in any 12 month non-market endeavours’ to provide right to connect. period) access arrangements sought by CA
Chapter 5Ab Retail customers who are Generator size not Basic connection Yes — DNSP must offer basic connection micro-embedded generators specified but must service (model within 10 business days (excludes meet Australian standing offer) registered standard AS4777 generators) Retail customers Not specified Standard connection Yes — DNSP must offer standard (includes non-registered embedded service (model connection within 10 business days but generators and micro-embedded standing offer) only if the DNSP provides a relevant generators) model standing offer (DNSPs may, but are not required to, provide model standing offers) • Connection is neither basic nor Not specified Negotiated Unclear — DSNP must use its ‘best standard connection service, or connection contract endeavours’ to make a negotiated connection offer within 65 business days. • Basic or standard connection service is The AER has the power to arbitrate when sought but CA elects to negotiate terms agreement cannot be reached and conditions
Notes: a The Commission understands that some Victorian-specific supplementary regulation will be retained under the NECF. b Chapter 5A will largely replace the State-based regulation that supplemented embedded generator connections prior to the commencement of the NECF in Victoria. Sources: Commission analysis of chapters 5 and 5A NER.
24 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 2.2.4 Selling exported electricity
National regulation
Under the NER, Victorian distributed generators wishing to sell electricity exported to the distribution grid currently have two options.
(1) Sell through the NEM at spot prices: each generating unit that receives payment from AEMO for sent out electricity must be registered as a ‘market generator’, regardless of generating unit size. This would include generators of less than 5MW capacity that would otherwise be eligible for an exemption from registration under the Standing Exemption (although the Commission understands it is rare for this to occur in practice). Substantial registration and participant fees apply. (2) Sell through a private bilateral agreement outside of the NEM, generally for an agreed fixed price: applies to registered ‘non-market’ generating units and generating systems exempt from registration. All sent out generation must be purchased in its entirety by a local retailer or customer located at the same connection point. A ‘connection point’ is the agreed point of supply established between a DNSP and distributed generator.
In the future, there may be a third option for distributed generators wishing to sell surplus electricity generated. AEMO recently submitted a rule change to the AEMC to introduce a new category of market participant into the NER called a 'small generation aggregator'. If approved, it would allow a small generation aggregator to have market responsibility for the participation of multiple generating units in the NEM and would only require a single registration. Separate registration of each of the small generating units would not be required, significantly reducing costs and improving access to the market. This would allow aggregated generators to enter and sell in the NEM more easily (AEMC 2012c, pp.1–5). On 5 July 2012, the AEMC published a draft rule determination on the Small Generation Aggregator Framework. The AEMC’s draft rule broadly reflects that rule change requested by AEMO (AEMC 2012g, p.2). However, registered small generation aggregators would not be eligible for the simpler chapter 5A connection process (part of the delayed NECF) and would instead have to connect through chapter 5.
Victorian regulation
Licensing
The EI Act prohibits the generation of electricity for supply or sale unless the generator is licensed or has been exempted from the requirement to hold a generation license (s 16(1)). Under s 17 of the EI Act, the Governor in Council can make an Order in Council exempting a person from the requirement to obtain a generation licence. An Exemption Order exists for distributed generators with a capacity of less than 30 MW (ESC nd, p.1; Order in Council 2002).
Once the NECF is applied in Victoria and the regulation of electricity retailers is transferred to the AER, distributed generators wishing to sell their generation will be subject to a national retailer authorisation and exemption framework. Under the NECF, a retailer authorisation is required to sell energy unless a retailer exemption has been granted. Victorian distributed generators who ‘onsell’ their generation will need to obtain a retail exemption under the AER’s Exempt Selling Guideline (AER 2011f). Distributed generators who wish to onsell electricity within a private embedded network would also usually need to obtain an exemption from the requirement to register as a network service provider with AEMO (AER 2012h).
DISTRIBUTED GENERATION IN VICTORIA 25 Victorian feed-in tariff schemes
In Victoria, certain types of distributed generators connected to the distribution network are able to sell surplus electricity exported to the distribution grid through FiT schemes under Division 5A of the EI Act.
There are three FiT schemes operating in Victoria and each has specific eligibility criteria restricting the size of generator, type of technology and type of customer that can participate.
(1) Premium feed-in tariff (PFiT): started on 1 November 2009 and ended on 29 December 2011. The PFiT scheme is closed to new applicants. (2) Transitional feed-in-tariff (TFiT): started on 1 January 2012 and is currently open to new applicants. The TFiT scheme will run for 5 years from its commencement date until 31 December 2016. The scheme can be closed to new applicants by the Minister for Energy and Resources under certain discretionary triggers specified in the EI Act (s 40FEA). (3) Standard feed-in-tariff (SFiT): open to new applicants. Unlike the PFiT and TFiT schemes, there is no end date.
Electricity retailers with more than 5000 customers are obliged to offer a regulated FiT. The PFiT and TFiT schemes are funded by a DNSP ‘pass through’ model. DNSPs apply the appropriate FiT credits to licensed electricity retailers’ network bills for PFiT and TFiT generation conveyed along the distribution network in their distribution area. Licensed electricity retailers must pass through the FiT credits applied by the DNSP in the form of a credit (as a statutory minimum) against the bills of their PFiT and TFiT customers. The AER regulates the distribution charge that licensed retailers pay to DNSPs. The AER will allow for the costs associated with the PFiT and TFiT schemes when approving the annual distribution network tariffs applied to retail customers’ network bills. This means that the PFiT and TFiT are funded by all distribution network customers.
Licensed retailers with more than 5000 customers are required to fund the SFiT scheme, by paying or crediting the SFiT customer for generation exported to the distribution grid (DPI nd, p.1). As a consequence, retailers presumably fund SFiT payments by smearing the costs among their retail customer base. There is no regulated process for how Victorian retailers must fund the SFiT scheme.
Currently, Victorian distributed generators receiving a FiT are exempt from the requirement to obtain a licence by the Exemption Order. After commencement of the NECF, the State-based retail licensing regime will be replaced by a national retailer authorisation and exemption framework. The retail licensing provisions under the EI Act will be repealed, and current licence conditions that regulate FiTs will become direct statutory obligations under an amended EI Act. Under the proposed National Energy Retail Law (Victoria) Bill 2012 (as currently drafted), there will be no change to the substance of the Victorian FiT arrangements after commencement of the NECF in Victoria. The only change will be to the mechanism by which FiT obligations are imposed on Victorian electricity retailers with more than 5000 customers.
Role of the Essential Services Commission
Licensed electricity retailers are required to publish the terms and conditions of their FiT offers. The EI Act provides that the Minister for Energy and Resources may refer a matter to the ESC for assessment where the Minister has concerns that the terms and conditions of a licensed retailer’s PFiT or TFiT offers are not ‘fair and reasonable’, or the price, terms and conditions of a licensed retailer’s SFiT offer are not ‘fair and
26 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION reasonable’ (ss 40I and 40J). Where licensed retailers have published their FiT offer terms and conditions, the Minister can only make a referral before published terms and conditions take effect — that is within two months of publication. The Minister can make a referral at any time where licensed retailers have failed to publish their FiT offer terms and conditions.
The ESC assesses whether the referred terms and conditions are fair and reasonable and reports its assessment to the Minister (s 40J(1)). On receiving the ESC’s report, the Minister may declare (by notice published in the Government Gazette) that:
• the ESC recommended or determined PFiT and TFiT terms and conditions apply to the licensed retailer named in the declaration • the ESC recommended or determined SFiT prices, terms and conditions apply to the licensed retailer named in the declaration (ss40M, 40MA and 40MAB).
Table 2.7 summarises the FiT schemes that operate in Victoria. See appendix B for a more detailed discussion of the Victorian FiT arrangements.
DISTRIBUTED GENERATION IN VICTORIA 27 Table 2.7 Victorian feed-in tariff schemes
Feed-in Generator Other terms and Applies to Technology Tariff tariff size conditions Premium FiT • householders claiming Solar PV 5 kW or less 60 cents per kWh statutory • consistent with (closed to one solar PV at principal minimum statutory minimum new place of residence, or conditions applicants) • persons (such as small • ‘fair and Transitional businesses and 25 cents per kWh statutory reasonable’ where FiT community minimum terms and (open to organisations) occupying conditions are not new one or more properties statutory minimum applicants) (other than as a place of conditions residence) that claim • average cost per one solar PV at each customer of property and consume electricity per year 100 MW hours or less per arising from the TFiT year. scheme cannot exceed $5. Standard FiT • generation companies, Small renewables: Less than A ‘fair and reasonable’ price: Terms and conditions must be ‘fair and (open to or • wind 100 kW • ESC guidance states that this reasonable’. new • persons generating • solar (excludes means the rate offered to the applicants) solar PV of customer must be not less than electricity for supply or • hydro sale. 5 kW or less) the rate the customer pays to • biomass buy electricity from the retailer • other (but only if • range of offers from 18.99 to specified in an 26.39 cents per kWh available Order in as of 19 June 2012.a Council).
Notes: a A number of Victorian electricity retailers’ published standard FiT offers were specified as ‘one-for-one’ and Dodo’s standard FiT offer was the ‘peak electricity rate’. Sources: Commission analysis of Division 5A of the Electricity Industry Act 2000 (Vic).
28 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION 2.2.5 What do these arrangements mean for the inquiry?
The regulatory framework governing the Victorian electricity sector, and distributed generation in particular, has significant implications for the growth of distributed renewable and low-emission generation in Victoria. Although the electricity sector is increasingly nationally regulated, some areas of Victorian-specific regulation — such as the FiT schemes — will remain after the commencement of the NECF in Victoria. In reviewing how the framework applies to distributed generation, the Commission has found that the regulation is complex, and has identified aspects that are inconsistent and where the rationale for regulating similar activities differently is unclear. The Commission’s conclusions about the regulatory framework relate to connecting and selling after the NECF is implemented in Victoria.
The regulatory framework is complicated
The present electricity framework will change once the NECF is implemented in Victoria and many current state-based regulatory responsibilities are transferred to the AER, significantly reducing the amount of State-based regulation and the role of the ESC. However, Victoria regulation will continue to govern distribution, transmission and generation licensing, and FiTs.
Under the NECF, a distributed generator can potentially be required to enter into four separate contractual arrangements, each of which is subject to separate terms and conditions:
• a contact for retail services with a retailer governed by the NERL Part 2 • a contract with a DNSP for initial connection services governed by the NER chapter 5 or 5A • a (deemed) contract with a DNSP for ongoing ‘energisation’ services governed by the NERL Part 3 • a Victorian FiT contract with a retailer who is retailing to Victorian customers, governed by the EI Act Division 5A.
The regulation that governs these contractual arrangements distinguishes between categories of customer and/or types of generator. These categories are not consistent. This complicates the connection process for distributed generators wishing to connect and export electricity to the distribution network. It may be difficult for prospective distributed generation customers to work out the connecting and selling options applicable to their particular generator size and technology type. For example, a household-scale distributed generator would be able to connect under chapter 5A of the NER but only solar PV systems of 5 kw or less capacity can apply for the TFiT scheme. Other household-scale renewable distributed generators would need to apply for the SFiT scheme, and non-renewable and low-emission generators are ineligible for Victorian FiT schemes and would need to investigate other selling options. They may be able to negotiate a private export agreement with their local retailer or customer located at the same connection point. However, if they cannot reach a private agreement or wish to export to the NEM, household-scale distributed generators would need to register with AEMO and connect through chapter 5 of the NER.
Similarly, the NERL contains important consumer protections that govern the retail supply contract and certain connection services provided by the DNSP. However, the consumer protections regulating the relationship with retailers are restricted to supply contracts with ‘small customers’. These protections do not extend to retail FiT (export) contracts or distributed generators connecting under chapter 5 of the NER. A distributed generation customer may need to assess:
DISTRIBUTED GENERATION IN VICTORIA 29 • the need to enter into up to four separate contracts to connect and sell their exported generation • the sources of regulation that govern each of the contractual arrangements • their rights and obligations under each of the contracts • their relationship to the retailer and DNSP under each of the contracts.
The regulatory framework is, in some respects, inconsistent and discriminatory
Processes for connecting distributed generation to the distribution network and for receiving a regulated FiT for exported surplus electricity generated contain detailed and inconsistent generator eligibility criteria. Only certain types/sizes of generators and/or types of technology can connect under chapter 5, would be able to access the new chapter 5A simplified connection process, and participate in a Victorian FiT scheme to sell electricity. In addition, individual DNSPs have their own requirements and procedures.
• To connect under chapter 5, a generator must be registered or exempt from registration by AEMO under the NER chapter 2. A Standing Exemption exists for generators of less than 5 MW capacity. • Connection services for distributed generators under chapter 5A would be restricted to specific types of retail customers that are not registered with AEMO. Micro-embedded generators would be guaranteed connection through a basic connection service. Other embedded generators would only be guaranteed connection through a standard connection service if a DNSP chooses to provide a model standing offer for that particular class of connection service or retail customer. • The PFiT and TFiT schemes are reserved for solar PV systems of up to 5 kW capacity. The SFiT scheme applies to specified small renewable energy generating facilities of less than 100 kW capacity (greater than 5 kW and less than 100 kW for solar PV systems).
As a result of the various size thresholds and eligibility criteria that have emerged over time, the rationale for why some generators — and not others — have access to certain regulated rights is unclear and can conflict across the different areas of regulation.
Registration is a high entry barrier to participation in the NEM
Any distributed generator wishing to sell through the NEM at spot prices must be registered as a ‘market generator’ with AEMO, regardless of the size of the generator. Registered generators would be unable to connect through the new simpler processes in chapter 5A and must therefore connect under the chapter 5 process. Similarly, the proposed new category of registered participant — a ‘small generation aggregator’ — would also need to connect under the more complicated chapter 5 process.
• The registration process is designed for larger generators and, therefore, can be complex and time consuming. AEMO has advised that it may take a proponent up to three months to prepare the documentation necessary for registration (AEMO 2011c, p.4). • The chapter 5 connection process is generally lengthier, more costly and uncertain than the process under chapter 5A. There will be no mandated statutory timeframe within which a DNSP must make an offer to connect. In addition, registered generators are subject to significant registration and participant fees.
30 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION • Electricity sold outside the NEM must be purchased in its entirety by a retailer or customer located at the same connection point. Non-registered distributed generators can therefore only sell their exported generation to market participants through a retailer (AEMC 2012f, p.174).6 Although distributed generators may enter into a private agreement with their retailer, retailers are not obliged to purchase electricity in this way. Small-scale distributed generators in Victoria therefore often rely on State-based FiT schemes to sell surplus electricity generated.
Connection and selling regulation do not cater for all distributed generators
Certain customers, generator types/sizes and forms of technology are restricted, excluded from or find it more difficult to access current connecting and selling arrangements.
• An automatic right to connect exists for larger generators (with a capacity of 5 MW or greater) that meet the automatic access standards under chapter 5. Similarly, micro-embedded generators will have an automatic right of connection through a basic connection service under chapter 5A. However, other small to medium-scale generators would only be guaranteed an automatic right of connection if DNSPs choose to provide a relevant model standing offer for standard connection services under chapter 5A. • Generators unable to connect through a basic or standard connection service under chapter 5A would need to negotiate their connection arrangements with a DNSP under chapter 5 or 5A. Connecting through a negotiated connection contract under chapter 5A is a more complex process than simply accepting a basic or standard connection service model standing offer. Negotiating access under chapter 5 is even more time consuming, costly and difficult for a CA. Table 2.8 summarises the connecting options available to distributed generators after the NECF commences in Victoria. • Non-renewable and low-emission generation, and renewable generators with a capacity of 100 kW or greater, are excluded from participating in the Victorian FiT arrangements. These larger distributed generators are restricted to selling through the NEM at spot prices, or through a private bilateral agreement outside of the NEM with a retailer or customer located at the same connection point. Table 2.9 summarises the selling options available to various distributed generator types/sizes and forms of technology. • New solar PV systems of 5 kW or less are currently eligible for the TFiT if they meet specific customer eligibility criteria. Householders may only claim one solar PV system on a property that is their principal place of residence. TFiT is also available to people that occupy one or more properties (other than as a place of residence), claim only one solar PV system at each of those properties, and their annual electricity consumption is 100 MWh or less. For example, small businesses and community organisations. If these criteria are not satisfied, new customers with solar PV systems of 5 kW or less are unable to access a regulated FiT. For example, the TFiT could not be claimed for the electricity generated from solar panels on a holiday home. This, however, does not preclude retailers from offering an unregulated FiT if they choose to do so.
6 Although larger distributed generators can onsell their electricity within a private embedded network if they are granted a retail exemption and a network exemption.
DISTRIBUTED GENERATION IN VICTORIA 31 Table 2.8 Connecting options for distributed generation after the NECF commences in Victoriaa
Small to medium generators Medium generators Micro to small generators <100 kW 100 kW to 5 MW >5 MW to <30 MW Chapter of Chapter 5A (when the NECF is Chapters 5 and 5A (when the NECF is applied in Victoria) the NER applied in Victoria)b Registration No Under chapter 5A (when the NECF is applied in Victoria): no with AEMO Under chapter 5: yes — registration or Under chapter 5: yes — registration or required? exemption from registration is required. A exemption from registration is required Standing Exemption applies for generators <5 MW Type of Basic connection service, Under chapter 5A (when the NECF is applied in Victoria): connection standard connection service or standard connection service or negotiated connection contract negotiated connection contract Under chapter 5: negotiated Automatic Yes — for basic connection Under chapter 5A (when the NECF is applied in Victoria): right to services a DNSP must provide a Yes — if a DNSP provides a model standing offer for a relevant standard connection connect? model standing offer. service. Yes — for standard connection Unclear — for negotiated connection contracts a DNSP must use its ‘best endeavours’ to services if a DNSP provides a make a negotiated connection offer, AER has the power to arbitrate when agreement model standing offer for a cannot be reached relevant standard connection Under chapter 5: Under chapter 5: service. No — there are no automatic access Yes — if automatic access standards are Unclear — for negotiated standards for generators of <5 MW. Access met connection contracts a DNSP standards must be negotiated on a must use its ‘best endeavours’ to No — if connection applicant wants to case-by-case basis. DNSP to ‘use make a negotiated connection negotiate any of the access standards. reasonable endeavours’ to provide access offer, AER has the power to DNSP to ‘use reasonable endeavours’ to arrangements sought by the CA arbitrate when agreement cannot provide access arrangements sought by the be reached CA
32 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION Table 2.8 Connecting options for distributed generation after the NECF commences in Victoriaa (cont) Small to medium generators Medium generators Micro to small generators <100 kW 100 kW to 5 MW >5 MW to <30 MW Statutory Yes — for basic and standard Under chapter 5A (when the NECF is applied in Victoria): timeframe connection services a DNSP has Yes — for standard connection services a DNSP has 10 days to make a model standing mandated? 10 days to make a model offer. Expedited connection is available. standing offer. Expedited No — for negotiated connection contracts a DNSP must use its ‘best endeavours’ to make connection is available. negotiated connection offer within 65 days No — for negotiated connection Under chapter 5: contracts a DNSP must use its ‘best endeavours’ to make a No — preliminary program of milestones agreed between parties negotiated connection offer within 65 days Cost of Subject to AER Connection Under chapter 5A (when the NECF is applied in Victoria): subject to AER Connection connecting Charge Guidelines — covers Charge Guidelines — covers extension assets and shared network augmentations extension assets and shared Under chapter 5: Under chapter 5: network augmentations • fees and charges specified in chapter 5 • fees and charges specified in chapter 5 — covers ‘negotiated use of system — covers ‘negotiated use of system charges’ for extensions and charges’ for extensions and augmentations augmentations • DNSP and CA must ‘negotiate in good • DNSP and CA must ‘negotiate in good faith’ to reach agreement on connection faith’ to reach agreement on connection charges charges • registration and participant fees apply to • registration and participant fees apply to registered generators registered generators • exempt generators (excludes generators • exempt generators must pay a <5 MW subject to the Standing registration fee Exemption) must pay a registration fee Notes: a The Commission understands that some Victorian-specific regulation relevant to embedded generator connections will be retained under the NECF .b Although it is unlikely to occur in practice, micro-embedded generators will also be technically able to apply for connection under chapter 5 of the NER. Source: Commission analysis.
DISTRIBUTED GENERATION IN VICTORIA 33 Table 2.9 Mechanisms for selling output from distributed generation (Victoria)
Technology Micro to small generators Small to medium generators Medium generators 5 kW or less <100 kW 100 kW to 5 MW >5 MW to <30 MW Solar Solar PV only: Standard FiT • Registered generators can • Registered generators can • Premium FiT (>5 to <100 kW) sell through the NEM at spot sell through the NEM at spot (closed to new prices prices customers) • Non-market and exempt • Non-market and exempt • Transitional FiT for generators can sell through a generators can sell through a new customers private agreement outside private agreement outside the NEM to a local retailer or the NEM to a local retailer or Wind Standard FiT Standard FiT customer located at the customer located at the Hydro same connection point same connection point Biomass • Distributed generators • Distributed generators wishing to ‘onsell’ generation wishing to ‘onsell’ generation Other forms of renewable within a private embedded within a private embedded energy if specified in an network usually need to network usually need to Order in Council obtain a retail exemption obtain a retail exemption and a network exemption and a network exemption Low-emission • No FiT regulated schemes exist for these forms of technology Non-renewable • Registered generators can sell through the NEM at spot prices • Non-market and exempt generators can sell through a private agreement outside the NEM to a local retailer or customer located at the same connection point • Distributed generators wishing to ‘onsell’ generation within a private embedded network usually need to obtain a retail exemption and a network exemption
Notes: Technically, distributed generators eligible to participate in a Victorian FiT scheme and household-scale low-emission and non-renewable distributed generators have the option of selling electricity under national regulation (as registered generators through the NEM; as non-market or exempt generators through a private agreement outside the NEM to a local retailer or customer located at the same connection point; or by ‘onselling’ their electricity within a private embedded network). However, it is unlikely that household-scale distributed generators would choose these options in practice. Source: Commission analysis.
34 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION 2.3 Policies for distributed generation and renewable energy
In the past distributed generation policies have formed part of a broader policy framework designed to reduce greenhouse gas emissions and facilitate an adjustment towards a low emissions economy. This framework comprises state and national policies, programs and legislation. Contributing to the complexity, a number of programs overlap, and there is little sense of overarching policy rationale.
The Commonwealth emissions trading scheme, renewable energy target (RET) and Clean Energy Finance Corporation (CEFC) are Australia’s main policy measures for reducing carbon emissions. These policies increase the cost of carbon-intensive energy and subsidise low-emissions technology, thus making low-carbon energy a more attractive alternative.
2.3.1 Commonwealth policies
The Commonwealth Government published its Clean Energy Plan in July 2011. The Plan details the Commonwealth’s climate change strategy as well as households’ transition to clean energy, and investment in low-emissions technology. The Commonwealth proposed four key drivers of a transition to clean energy:
(1) introducing a carbon price (2) promoting innovation and investment in renewable energy (3) encouraging energy efficiency (4) creating opportunities in the land sector to cut pollution (Commonwealth Government 2011, p. 17).
Carbon price
The cornerstone of the Clean Energy Plan, the carbon tax was introduced on 1 July 2012. The carbon price is initially fixed at $23 per tonne, and will increase by 2.5 per cent per year in real terms (for three years from 1 July 2012). Following this, the price will be determined by the market through an emissions trading scheme with the Government capping the number of permits issued each year. In its Clean Energy Plan the Commonwealth Government stated a carbon price would create incentives for business to ‘find the cheapest and most effective way of reducing carbon pollution, rather than relying on more costly approaches such as government regulation’ (Commonwealth Government 2012a). Under the carbon pricing mechanism large co- generation plants (those that produce 25 000 tonnes or more of CO2-e (carbon dioxide) in any financial year) are liable as direct emitters. Retailers who supply smaller plants with natural gas are liable for the emissions produced and therefore factor the carbon tax into their gas prices (Clean Energy Regulator 2012d, p.10) Renewable Energy Target
The Renewable Energy Target (RET) scheme is a market-based measure to increase the share of electricity consumption derived from renewable energy resources. The current RET replaces the Victorian RET and mandatory RET with a commitment that 20 per cent of Australia’s energy will come from renewable sources by 2020. The Commonwealth Government predicts the scheme will generate approximately $20 billion of investment in renewable energy by 2020 (Commonwealth Government 2011, p. 64).
The RET encourages distributed generation by providing payments to households and other small producers of renewable energy. Under the RET scheme, tradeable
DISTRIBUTED GENERATION IN VICTORIA 35 Renewable Energy Certificates (RECs) are created by eligible renewable energy sources, based on the amount of electricity they produce or displace. RECs are then traded (sellers and purchasers directly negotiate the price), with electricity retailers and electricity wholesale purchasers mandated to surrender their RECs into their holding account each year in proportion to their acquisitions of electricity.
From 2011 the RET has been separated into two components: the Large-scale Renewable Energy Target (LRET), and the Small-scale Renewable Energy Scheme (SRES) (Clean Energy Regulator 2012a, p. 6).
Large-scale Renewable Energy Target
The LRET supports the deployment of renewable energy projects. The most common examples of these are wind farms, commercial solar, and geothermal power stations. The target also extends to energy produced by ocean waves and tides, and biomass.
In accordance with the target, accredited renewable energy power stations generate renewable large-scale generation certificates (LGCs). One LGC is equivalent to 1 MWh of renewable energy generated above the power station’s baseline. LGCs are traded in the LGC market with prices determined by supply and demand. Liable entities are required to surrender a prescribed number of LGCs to the Office of the Renewable Energy Regulator annually (Clean Energy Regulator 2012a, pp. 7–10).
Small-scale Renewable Energy Scheme
The SRES was designed to support the installation of small renewable energy systems. These are most often rooftop PV panels or solar water heaters, but can include wind turbines, micro-hydroelectric systems and heat pump water heaters.
The scheme assists households, small businesses and community groups by reducing the upfront cost of installing these systems. Under the SRES, small-scale technology certificates (STCs) are generated for eligible installations. Installers can claim a set number of STCs based on electricity generated or displaced over the system’s lifetime (where one STC is equivalent to 1 MWh of electricity). These certificates are tradeable and the government legislates their demand by mandating that liable entities surrender a prescribed number of STCs quarterly (Clean Energy Regulator 2012a, pp. 11–14).
Solar credits
Solar credits work in conjunction with STCs. Solar credits provide additional support for the installation of small-scale solar units by increasing the number of STCs created for eligible installations. Solar credits apply to the first 1.5 kW of installed capacity for systems connected to the main electricity grid, and up to the first 20 kW of installed capacity for off-grid systems (Clean Energy Regulator 2012a, p. 12).
Clean Energy Finance Corporation
As part of its Clean Energy Plan, the Commonwealth announced the creation of, and $10 billion investment in, the CEFC. The Government predicts transforming the Australian energy sector will require $100 billion in renewable energy, and additional investment in new manufacturing technologies and improving energy efficiency. The Commonwealth Government believes it plays ‘an important role in facilitating and coordinating investment in technologies that financial institutions may not be familiar with’(Commonwealth Government 2012b, p. 4). The CEFC therefore, aims to leverage private funding for renewable energy and clean technology, as well as remove barriers to funding large-scale renewable energy projects.
36 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The Report of the Export Review Panel clarified the CEFC’s focus. The CEFC will allocate its funding into two streams — at least 50 per cent to renewable energy, and the remainder to low-emissions and energy efficiency. The term ‘renewable energy’ is not prescriptive and will adapt in response to technological evolution. The fund’s direct investment in energy efficiency will focus on large-scale projects, while small-scale projects may be funded indirectly if aggregated through a third party. Co-generation units are eligible for funding as either energy efficiency projects or low-emissions technology. Although it acknowledges demand management is distinct from energy efficiency, the Report argues demand management lowers the cost of transitioning to clean energy by reducing network upgrade costs and deferring investment in new generation. Technologies associated with demand management will therefore be funded from the energy efficiency stream (Commonwealth Government 2012c, pp. 13–16).
2.3.2 State policies
Under the Climate Change Act 2010 (Vic) s 5(i), Victoria set an emissions reduction target of 20 per cent by 2020 (based on 2000 levels). In light of the Commonwealth’s Clean Energy Act 2011 (Cth) and the introduction of a carbon price, a recent review found that separate state-based targets were unnecessary (DPC 2011, p. 14). A number of state-based renewable energy policies initiated under the Victorian Act have been aligned with national schemes and emissions reduction targets.
Victorian Energy Efficiency Target
The Victorian Energy Efficiency Target (VEET) is intended to be an energy saving initiative. It commenced in 2009 and is legislated to continue in three-year phases until 2030. The scheme aims to:
• reduce greenhouse gas emissions • encourage the efficient use of electricity and gas • encourage investment, employment and technology development in industries supplying goods and services which reduce the use of electricity and gas.
Under VEET, large electricity retailers are liable to surrender a specific number of energy efficiency certificates annually. These Victorian energy efficiency certificates (VEECs) each represent one tonne of abated greenhouse gas and are created when accredited entities help consumers make energy efficiency improvements to their homes. The revenue generated through the sale of VEECs allows accredited entities to offer consumers special benefits, thus reducing the cost of undertaking energy efficiency improvements.
Currently, VEECs are created for around 30 prescribed energy efficiency enhancements. These range from installing high efficiency hot water systems, to draught proofing and purchasing high efficiency appliances (ESC 2012d).
Large-scale solar feed-in tariff
In 2010, the then Victorian Government announced an extension of the solar feed-in tariffs to include large-scale solar generation (DPC 2010, p.15). This announcement was not implemented.
DISTRIBUTED GENERATION IN VICTORIA 37 2.4 Future trends
2.4.1 Cost trends
Cost estimates for renewable energy are based on a number of factors. Fundamentally, they rely on learning curves (experience curves) which map the relationship between knowledge and experience in production, and technology costs. While these curves provide useful trendlines, a number of other factors influence costs. These include government policy, supply and demand, and broader market dynamics. As the bulk of renewable energy technology components are produced overseas, international trends have the greatest impact on technology price. The following describes some cost trend forecasts for renewable energy.
The past decade has seen a substantial increase in the installed capacity of solar PV cells. As the international industry has grown, cost has decreased along a common learning curve — with cost reductions of approximately 22 per cent for every doubling of cumulative capacity. Cost strayed from this curve from 2003 to 2008 due to a supply bottleneck and market dynamics (MEI 2011, p. 2).
The Melbourne Energy Institute (MEI) argued that increased production capability, improved supply chains and economies of scale will reduce costs further. It contended that China’s massive increase in production capability will continue to reduce prices, while an increase in silicone production capacity will alleviate supply constraints (MEI 2011, p. 2)(figure 2.4).
Figure 2.4 Solar PV cost projections
Notes: Levelised Cost of Energy (LCOE); Direct normal irradiation = 2445 kWh/m2/yr; Electric Power Research Institute (EPRI) and Australian Energy Market Operator (AEMO) costs projections based on Australian data; European Photovoltaic Industry Association (EPIA) and International Energy Agency (IEA) cost projection based on international data. Source: MEI 2011, p. 2.
38 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Wind energy capacity has also doubled every three years over the past decade. Capital costs have generally followed the expected learning curve (MEI 2011, p. 3). However, supply chain bottlenecks and commodity constraints slowed price reductions. A shift to more large-scale (and automated) production has alleviated this slow down recently.
MEI contended that economies of scale and industry expansion internationally will continue to deliver modest cost reductions for wind technology. It also suggested that incremental technological improvements will potentially reduce costs significantly (figure 2.5).
Figure 2.5 Wind power cost projections
Notes: Levelised Cost of Energy (LCOE); Electric Power Research Institute (EPRI) and Australian Energy Market Operator (AEMO) costs projections based on Australian data; Global Wind Energy Council (GWEC) and International Energy Agency (IEA) cost projections based on international data. Source: MEI 2011, p. 3.
As concentrating solar thermal power is still a relatively new technology, sources suggest it has a significant cost reduction potential. This cost reduction should be driven by known technical improvements, economies of scale and industry learning (MEI 2011, p. 4). It is expected that concentrating solar thermal power cost will follow a similar learning rate to those observed for solar PV and wind power (figure 2.6).
DISTRIBUTED GENERATION IN VICTORIA 39 Figure 2.6 Concentrating solar thermal power cost projections
Notes: Levelised Cost of Energy (LCOE); Direct normal irradiation = 2445 kWh/m2/yr; Australian Energy Market Operator (AEMO) costs projections based on Australian data; US Department of Energy (USDoE), European Solar Thermal Electricity Association (ATK) and International Energy Agency (IEA) cost projections based on international data. Source: MEI 2011, p. 4.
The CSIRO modelled the price of key technologies under various carbon price paths. Figure 2.7 demonstrates the long run marginal cost of these technologies under the highest and lowest carbon prices. The first carbon price path would lead to a 5 per cent reduction in Australian emissions below 2000 in 2020. The second would lead to a 25 per cent reduction in Australian emissions below 2000 in 2020. Both assume Australia meets its commitment to 20 per cent energy from renewable sources by 2020.
40 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Figure 2.7 Long run marginal cost ($ per MWh 2009) of technologies in 2050
Notes: a pulverised fuel; b carbon capture and storage Source: Hayward et al. 2011, pp. 29, 32.
The lower carbon price path produced a greater diversity of technology choices (including black and brown coal combined cycle plants). Under a higher carbon price path black coal became far less affordable which led to a greater diversity of renewables in the long term (Hayward et al. 2011, p. 52).
2.4.2 Improved metering technology
By the end of 2013, the Victorian Government plans to roll-out smart meters to all Victorian homes and businesses. Smart meters will measure and record electricity usage throughout the day and communicate this information to electricity DNSPs. The intent is to provide customers with more accurate and detailed information about their electricity use. This increased awareness is expected to lead to reductions in electricity use.
Furthermore, the increased information smart meters provide should make it easier for consumers to compare the prices offered by competing providers. The introduction of smart meters is expected to lead to customers switching from fixed to flexible pricing. Making consumers aware of the large fluctuations in electricity price is expected to shift electricity consumption as consumers seek low cost, low demand periods.
Smart meters are also capable of measuring two-way electricity flow. Thus, households or businesses that generate electricity will not need to install a new meter (but may need to have their meter reconfigured) to be credited for the electricity they export into the grid (DPI nd).
DISTRIBUTED GENERATION IN VICTORIA 41 2.5 Conclusions
Distributed generation is a relatively new part of Victoria’s electricity industry and, as such, does not always fit neatly into Victoria’s traditional electricity market. Although it currently accounts for only a small portion of Victoria’s energy generation, decentralised energy capacity is increasing. Furthermore, changes to government policy and consumer choices, together with a reduction in technology prices are expected to encourage further installation of distributed generators.
Some government policies encouraging distributed generation have increased its uptake. But without substantial analysis, it is difficult to determine how successful and cost effective these have been. Many of these policies favour specific technologies and an observed increase in the uptake of one technology may mask a shift from other renewable electricity sources.
If decentralised generation is to continue to grow, it is important to consider the current state of the sector and, where possible, simplify entry to and participation in it. Complex regulatory arrangements governing the installation, generation and sale of electricity are tolerable by large electricity companies; however they may not be to smaller distributed generators. Distributed generation is diverse and many generators are managed by households or small businesses with little knowledge of electricity regulations.
42 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 3 Issues raised by participants 3.1 Introduction
The Commission has consulted extensively with participants to understand the issues affecting the persons and organisations involved in dealing with distributed generation. The issues raised by participants ranged from very specific technical issues to wider concerns about the operation and regulation of the electricity industry in Victoria and nationally.
Previous Commission work also highlighted relevant issues. For example, participants in the Commission’s 2009 inquiry into Victoria’s environmental regulations claimed examples of barriers to investment in distributed generation systems included:
• complex network connection and access requirements (for example, requirements for detailed network connection studies) added substantially to overall project costs • existing market rules of electricity distribution did not adequately set price signals that reflect the security and competition benefits that come from clean electricity generation • possibly excessive technical performance standards must be met for renewable generators to be registered • existing structure of the electricity market discouraged energy efficiency more generally. For example, retailers had an incentive to sell more electricity, while distribution network service providers (DNSPs) were rewarded for approved capital spending and had little incentive to encourage energy efficiency • electricity distribution businesses had been set up on the basis of centralised electricity generation — distributed generation was difficult to accommodate in a system set up for one-way flows of electricity and the network reinforcement needed to connect distributed generation could be costly • planning application and approvals processes added complexity, cost and time risk (VCEC 2009, pp.375 –376).
This chapter summarises the issues raised across the sector in the context of this inquiry (substantive issues and possible recommendations to deal with them are explored in subsequent chapters). The Commission’s previous work suggested that the issues would be wide ranging and, therefore, to focus the analysis and help structure the discussion, the Commission has categorised the issues raised by participants into two groups:
• connecting to the network • selling power from distributed generators into the grid — including how to recover the energy value and network value of distributed generation.
Whilst the classification is intended to aid the discussion of issues, the Commission notes in practice there is some overlap between the issues and a particular issue may fit into both groups. For example, feed-in tariff (FiT) issues may also incorporate elements of the connection process. That said, the two group classification is consistent with the views of many inquiry participants. For example, Exigency argued that:
The key barriers to establishing distributed generation could be simply summarised as revenue certainty and grid connection on reasonable terms. (sub. 4, p. 3)
ISSUES RAISED BY PARTICIPANTS 43 The Commission has also identified, where possible and relevant, where issues differ according to size of the market participant and location.
3.1.1 Issues raised in response to the draft report
In its draft report, the Commission made four draft recommendations covering:
• measures to facilitate connection of medium-scale distributed generators • measures to deal with network reinforcement costs • measures to facilitate connection of household scale distributed generation • measures to improve the efficiency and effectiveness of the operation of FiTs in Victoria.
There was broad support among participants for the Commission’s recommendations to reduce the barriers to connection at both the medium and household scale and support for the need to clarify the allocation of network reinforcement costs.
Most of the submissions received on the draft report commented on the Commission’s draft recommendation on FiTs. Submissions canvassed views such as:
• The Commission’s market-based rate was too low, did not provide incentives to install distributed generation, and did not take into account the effect or network benefits of distributed generation. Others supported a market-based rate based on the energy value. • Some expressed concern about the ability of the market to provide ‘fair and reasonable’ FiTs: in particular the market power held by retailers and DNSPs. • Some participants emphasised that existing contractual arrangements must be honoured and it would be unfair to change the FiT for those who currently have an agreement with a retailer. • There was some agreement that there were potential network benefits from distributed generation but taking them into account was difficult. Some participants argued that an amount should be included in the FiT to reflect the network value of distributed generation.
The following section outlines issues raised throughout the inquiry, both before and after the release of the draft report.
3.1.2 Connecting to the network
The most commonly raised immediate barrier to investing in more medium-scale distributed generation was the process for connecting these systems into the electricity network. Technical standards must be met and contractual arrangements must be in place before distributed generation, such as a co-generation or tri-generation system, can be connected to a DNSP’s network. These are required to ensure the DNSPs meet their safety and reliability of supply obligations. There is little information available on the average time taken to connect to the network and so it is difficult to assess the relative performance of different DNSPs.
The National Electrical and Communications Association observed that:
The Commission rightly identified connection issues as a major barrier to distributed generation. This is not a surprise to NECA as our members have
44 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION identified connection issues for all electrical work as a significant frustration and expense to their business. (sub. DR174, p. 3)
Participants were also critical of the complexity of the process for connecting small-scale generators. For example, Ann Scally reported her experiences:
I am a small business owner and have spent considerable time and effort negotiating and liaising with electricity retailers, solar installers, inspectors and relevant government authorities in order to install a PV system for FiT, all of which I have a record of. The whole process has been stressful and staggeringly unprofessional—especially in regard to electricity retailers who have proved to be most ineffectual. (sub. DR131, p. 1)
Connection costs, performance standards for distributed generators, conditions and the negotiation timeframes can have a major impact on the financial viability of embedded generation projects. These costs are project specific, depending on various characteristics and location of the proposed distributed generation. In addition, local land planning rules may play a part in limiting embedded generation projects.
The Commission has structured the discussion by identifying the critical issues raised by participants at each stage of considering whether, and how, to connect distributed generation. This involves consideration of:
• information on where distributed generation is needed • the right to connect • costs of connection (including process simplification, timelines and uncertainty) • dispute resolution • regulatory issues • technical issues.
In some cases these issues varied depending on the scale of the distributed generation. There was a clear distinction between medium-scale and household scale distributed generation systems. These differences are reflected in the Commission’s later analysis and recommendations.
Information, network plans and opportunities for distributed generation
In response to the draft report, participants argued that there was a lack of public and accessible information on where distributed generation could contribute to the network’s performance, including where there were network constraints on adding further distributed generation.
The in-principle benefit of distributed generation in deferring network investment is installing it in areas where the network is at, or close to, capacity. However, some participants argued that there was insufficient information about the location of network constraints. In addition, there are some parts of the network where increasing distributed generation is impractical without additional investment because it would contribute to already high fault levels.
There are, in principle, several ways of addressing the constraints in distribution capacity. Making the information on system constraints more widely available to interested parties may encourage more targeted proposals for the installation of distributed generation. Proponents of distributed generation projects can more readily identify those locations where connecting further distributed generation is likely to be
ISSUES RAISED BY PARTICIPANTS 45 difficult. Proposals may also be more likely to proceed as market participants are more aware of and, therefore, able to share the benefits of the savings from deferred network augmentation. Network owners would therefore face positive incentives to encourage and accept distributed generation connection.
The constraints and opportunities in the network can be highly localised. For example, the Commission was told that some parts of the network in the Melbourne CBD were constrained while other areas were not. This means that information needs to be sufficiently detailed to allow location specific assessments of the network impact of distributed generation. Origin Energy noted that greater transparency and more information:
… will greatly assist distributed generation proponents target their proposals and create localised network system benefits. (sub. DR196, p. 3)
Right to connect for small and medium generators
Some participants argued that there are no incentives for DNSPs to connect distributed generation to the network. In the Clean Energy Council’s (CEC) view:
There is presently no incentive for a DNSP to process a connection application; rather it is an obligation of the DNSP’s Distribution Licence. In conjunction the introduction of a generator has the effect of reducing the DNSP’s revenue from energy delivered, whilst increasing complexity (and hence cost) of their network assets. (sub. 76, p. 6)
This apparent lack of incentive to connect distributed generation to the network has led a number of participants to suggest that there should be an automatic right to connect to the network. For example, WattSource argued that:
It [the right to connect] should be automatic for every person, household and business (no negotiations, no approvals, no special contracts) so power companies have access to renewable energy at competitive wholesale prices from small, medium and large contributors around the nation. (sub. 2, p. 1)
The Property Council of Australia (PCA), Seed Advisory and ClimateWorks have also argued for automatic connection rights for distributed generation that meets predetermined technical standards (ClimateWorks et al. 2011). Ceramic Fuel Cells Limited argued:
The simplest and most efficient solution would be to adopt a “install and notify” process for small scale generators, without needing prior approval from the network operator. (sub. DR135, p. 1)
The Mildura Development Corporation argued that
The ability for the distributor to automatically reject distribution generators from connecting onto the distribution network is anti competitive and is not a publicly auditable process. … There should be no difference between connection requirements of a user of electricity and a generator of electricity of the same size. (sub. DR177, pp. 2-3)
The issue is complicated because some distributed generation technologies (and scale of activity) already have an automatic right of connection. For example, small-scale solar systems have an automatic right to connect through the standard and transitional feed-in tariff schemes. Despite the right to connect a number of participants noted that the process can be cumbersome and time consuming because of the paper work and
46 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION number of agents involved. The Energy and Water Ombudsman Victoria noted, for example, that:
Delays in the application of FiTs sometimes occurred because customers did not know that several forms needed to be completed. (sub. 48, p. 2)
There are also concerns that the right to connect solar PV may be restricted because distribution businesses are said to be limiting PV systems in some constrained parts of the network. In Queensland, for example, some distribution businesses claim they are limited to only allowing 30 per cent penetration of solar PV in particular urban areas and only 10 per cent penetration in some regional areas. Penetration of PV is much greater in these areas of Queensland than it is in Victoria but it is still causing concern that:
… distributors are considering limiting the output of micro-generators where the network has a lot of PV installed instead of upgrading the network. (Mike Reeves, sub. DR130, p. 3)
AGL observed that while the connection of individual small-scale distributed generators are unlikely to have significant network impacts:
AGL acknowledges however that issues will arise where there is a significant penetration of like technologies, which may in aggregate create technical issues. (sub. DR193, p. 2)
For medium-scale distributed generation, participants such as Jemena (sub. 79), suggested that connection should be subject to consideration of any technical and commercial issues and may therefore not necessarily be automatic. In some cases it may be appropriate to refuse connection of distributed generation. CitiPower and Powercor expressed a similar view:
… one of the principal concerns for the Businesses in connecting medium sized DG relates to network fault levels. Connecting medium scale embedded generators can result in the network fault levels exceeding safe working levels, or a decline in reliability to other network customers. (sub. DR184, p. 6)
Costs of connection
The costs incurred in connecting to the distribution network were cited by many participants as a barrier to further distributed generation. These costs include the direct financial cost involved in connecting to the network and the time taken to complete the process — but most of the participant comments focused on the process and on the time taken from requesting connection to it being done.
Participants suggested that the time taken to negotiate and effect a connection for a distributed generation unit varied from a few months to several years. In addition, in some cases the negotiations were not completed and connection did not occur.
Some participants were concerned that a lack of information on the connection process added to uncertainty and made the process more costly as they needed to search out information.
This perceived problem is compounded by different DNSPs having different requirements and processes to connect distributed generation. It was argued that the different processes did not reflect technical or locational issues - for example, Ironbark Sustainability (sub. 50, p. 9).
ISSUES RAISED BY PARTICIPANTS 47 Groups such as the PCA claimed that, despite the national regulatory changes, barriers to connecting small- to medium-scale distributed generation will persist (ClimateWorks et al. 2011, p. 11). In particular, while the proposed national changes establish automatic access standards for micro generators, other small to medium generators do not have similar rights (ClimateWorks et al. 2011, p. 36). The PCA Seed Advisory and ClimateWorks have proposed a rule change to the AEMC to address these barriers. The CEC questioned, however, whether a uniform set of performance standards is credible and practicable. It argued that, even with the rule change, problems will remain and further amendments to chapter 5A of the national electricity rules are needed.
In response to these issues several participants, for example, the Moreland Energy Foundation (sub. 75), have also argued for standardised and predetermined processes to ensure the timely and cost effective connection of distributed generation to the network.
Participants also commented on the direct financial and administrative costs of connection, especially with the connection of medium-scale distributed generators. Erwin Boermans of Comfortid.com (sub. 1, p. 1) suggested that a major barrier to connecting renewable power sources to the grid was the ‘extreme connection fees charged by grid monopolist’ owners and the ‘very high priced generator-permits for medium or large scale solar’. The Warburton Community Hydro Project argued that the connection process ‘remains a costly financial, technical and regulatory challenge’ (sub. 69, p. 4).
Gerard Noonan was of the view that in the case of household solar there should be no additional connection charges at all because:
Households are already paying for their connection to the network by the service to property charge. (sub. DR115, p 1)
The Renewable Energy Solutions Australia Holdings (sub. 78) also raised the cost of connection as being an issue. The costs of meeting technical requirements as a condition of connection are discussed in the later section on technical issues.
Dispute resolution
The need for an effective dispute resolution mechanism was raised by some participants (for example, the Clean Energy Council, sub. 76, Energy Efficiency Council, sub. 200, p. 11). There was concern that current dispute resolution process through Australian Energy Regulator (AER) arbitration were not being used because distributed generation proponents were concerned that it may impact on the willingness of DNSPS to work with them in the future. This reflects the real or perceived view held by many inquiry participants, that differences in market power among consumers, retailers, and DNSPs had implications for both connecting to the network and selling electricity (discussed in the next section).
Regulatory issues
The industry is subject to extensive regulation, and many participants suggested that the existing regulatory framework can act as a barrier to connecting distributed generation. There are two broad groups of regulatory issues, arising from:
• electricity regulation (such as technical standards, incentives facing industry participants and licensing arrangements) • non-electricity specific regulation (such as council planning approvals and heritage regulation.
48 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Electricity sector specific regulation
Many of the regulatory issues relate to the requirement to meet technical standards (discussed in the following section) but some participants have claimed that additional requirements have been added by retailers and DNSPs. For example, Ironbark Sustainability argued that:
In this context, incentives for efficient DG [distributed generation] may be viewed as a secondary objective of regulation, with the localised nature of DG posing challenges for the regulations. The regulations are often not conducive to ease of installation of DG and provide substantial market impediments through metering, connection and pricing requirements. DBs [distribution businesses] are obliged to meet minimum technical standards for connection, detailed in the Victorian Electricity Distribution Code, however they can also add additional requirements effectively resulting in no standard process for gaining approval to connect cogeneration systems to the electrical network across the network providers. (sub. 50, p. 9)
Aspects of the regulation of network investment have also been questioned. It has been argued that there is a lack of incentive for networks to connect distributed generation. In particular the current regulatory environment rewards investment in network assets rather than in network performance, and does not recognise the potential role of distributed generation which may reduce the need for such investment (CEC, sub. 76). Such a view is consistent with the AER‘s more general views that there is a systemic bias towards inflated expenditure estimates, disincentives for efficient investment and process biases in favour of the service provider that can lead to excessive payment by users (AER 2011h).
The AEMC Power of Choice review also raised concerns over the impact of current regulatory arrangements on the incentives faced by network owners:
… the current economic regulation arrangements may fail to provide the right incentives for distribution network businesses to explore demand side solutions as an alternative to network investment. (AEMC 2012f, p.135)
The DNSPs currently have weak incentives to minimise the cost of delivering electricity and choose between network investments and other possibly more efficient solutions.
Regulatory issues also arise when distributed generators are required to be licensed as generators. In Victoria the Electricity Industry Act 2000 (Vic) (EI Act) supplements the national electricity regulatory framework, regulating matters that include licensing people who generate electricity for supply or sale, or who transmit, distribute, supply or sell electricity.
Non-electricity sector specific regulation
Other regulatory issues including planning concerns, especially around the construction of new distributed generation in particular areas, were also raised in submissions. The construction of new wind farms has been one such issue in Victoria. Union Fenosa Wind Australia (UFWA) observed that:
The Victorian government and councils should remove or reduce planning laws that are particularly onerous, and are not based on economic, scientific or environmental criteria. The recent changes to the Victorian planning laws for utility scale wind farms that apply noise, setback and right of veto powers that are significantly above criteria for all other
ISSUES RAISED BY PARTICIPANTS 49 developments are not in the interests of the Victorian community. UFWA respects the right of the Victorian government to apply rigid objective criteria for development but the same criteria should be consistently applied to all developments i.e. the criteria for noise, visual amenity and setback should apply to all developments including small and large scale generation, and others such as coal mines, gas wells, sewerage facilities, piggeries, and farming facilities that have far more relaxed planning requirements. (sub. 71, pp. 4-5)
Other local government regulations can also be a barrier to the installation of distributed generation. For example, the National Electrical and Communications Association noted that:
In some cases, such as those residents who live in a heritage overlay area, they are required to seek planning approval from their local Council to install a solar PV system on their premises. This has created another barrier to the installation of distributed energy. (sub. 37, p. 5)
Kathryn Miller and Matthew Thomas stated that:
We also agree that planning regulations in heritage overlay areas are a barrier to connection by imposing an additional cost (either financial or in terms of risk). Either the distributed generator incurs the expense and delay of obtaining a planning permit; or the distributed generator installs the system and runs the risk of being in breach by not having a planning permit. Moonee Valley City Council has attempted to deal with this problem by providing an exemption to the heritage overlay for PV systems. This attempt was defeated by the Department of Planning and Community Development. (sub. DR190, p. 10)
Technical standards
Technical performance standards need to be addressed when considering whether to connect additional distributed generation to the network. These arise because the connection of distributed generation can impact on the reliability and performance of the electricity network. Jemena (JEN) stated that:
… connection of medium and large scale rotating equipment to the distribution network generally contributes to the fault level energy that flows into the network when a localised network fault occurs … The Electricity Distribution Code issued by the Essential Services Commission of Victoria requires that embedded generators (DG) design and operate their plant so as not to cause fault levels on the distribution network to increase above specified levels. Additionally, the NER [National Electricity Rules] advises fault levels which should not be exceeded for sub-transmission systems. While supportive of renewable energy initiatives, JEN by necessity has a stronger commitment to safety and reliability of electricity supply. (sub. 79, p. 7)
Similarly, the Energy Supply Association of Australia argued that:
… the process to connect to a Distribution Network Service Provider’s (DNSP) network is to ensure the safety and reliability of supply. This should remain the primary concern of a regulatory process. Rather than being a barrier to distributed generation, this process is essential to maintain the integrity of the system. (sub. 74, p. 3)
50 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Some participants suggested the technical issues are overstated and used as a barrier to connect distributed generation. For example, Ironbark Sustainability observed that:
In some cases DBs [distribution businesses] require the installation of prohibitively expensive equipment in the distribution network to accommodate increased fault levels. (sub. 50, p. 9)
The Mildura Development Corporation noted that:
Currently there are significant issues with distributed generators connecting to the electricity distribution network being scrutinised for technical issues such as power factor and maximum demand that similarly size users of electricity are not required to prove. (sub. DR177, pp. 2-3)
It may not always be clear to the proponent of the distributed generation whether these requirements are justified. Some distributed generators that were required to pay for network augmentation, criticised the reluctance of distribution businesses to provide a cost breakdown with sufficient detail to show the distributed generator what they were being asked to pay for (Senergy 2011, pp. 3-4). Professor Alan Pears also noted the asymmetrical treatment of electricity consumers and those generating electricity, and argued that:
… any small consumer is free to install energy consuming equipment that causes significant impacts on local power quality (such as low Power Factor equipment), increases pressure on local network capacity, creates harmonics or causes power surges. Dealing with these kinds of problems is seen as the ‘normal’ business of the electricity supply industry, and the costs of doing so are smeared across all customers. Yet, if similar impacts are caused by a small distributed generator, the electricity supply industry can insist on expensive remedies. (sub. 44, p. 2)
This point has some validity but is outside the terms of reference for this inquiry. The issue that the Commission must address is the extent to which the technical requirements are justified on the grounds of safety and network stability or are being used as an unnecessary barrier to the introduction of distributed generation. In addition, the Commission must consider how the necessary technical (safety and network stability) requirements can be addressed at least cost.
3.1.3 Selling electricity
Issues about selling electricity raised by participants often focused on the price paid and the way it was calculated. However, participants also raised other matters, which are discussed below and expanded on in chapters 5 and 6. The issue of how to recover the network value of distributed generation, and whether this should be through a FiT or other mechanism, was also raised by participants.
Export price
A number of participants, especially households with solar PV installations, argued that there should be an automatic right to sell their excess electricity and that retailers should be obliged to buy that electricity. For example, the Energy Innovation Co-operative argued that:
There does need to be a ‘requirement’ or ‘obligation’ on retailers to offer a FiT for renewable energy generators. We have already heard of retailers
ISSUES RAISED BY PARTICIPANTS 51 refusing to offer contracts to wind farms, and even to the very small (just above 5 kW) solar pv generators. (sub. DR160, p. 8)
For medium-scale distributed generation some submissions also argued that ‘distributors must be required to take the energy being produced’ (Sandra and Alan Dinsdale, sub. DR151, p. 1, and Anne-Marie Gibson, sub. DR155, p. 1)
The price paid for generated and/or exported electricity is a key concern for many participants in this inquiry. Those participants wanting to encourage distributed generation, often solar, argued for higher FiTs, while others argued for unregulated or market-based tariffs. Still others argued in favour of a ‘fair and reasonable’ tariff that is sustainable, but definitions of ‘fair and reasonable’ differed.
The principal existing objectives for ‘premium’ FiTs are to encourage the uptake of zero-emission generation to reduce greenhouse gas emissions and encourage industry development. Many submissions argued that FiTs should continue to be set at a level that encourages the development of distributed generation.
Stewart Kerr stated a view held by many participants that:
I think that the feed in tariff paid to small household generators of renewable energy should be based on encouraging the sector to grow, in the manner of a start-up subsidy. (sub. DR94, p. 1)
Similarly, Peter Anzo argued that:
I believe an appropriate level is an averaged wholesale cost with an additional amount for the equivalent transmission/distribution costs, in total an export price in the range of 22 to 30c per kWh would assist in promoting a healthy solar industry, and provide a monetary benefit to help recoup installation and maintenance costs to the systems owners. (sub. DR91, p. 1)
Another participant, Graham Scarlett argued that:
The Government needs to support this fledgling industry for many years till it generates enough momentum so that it is so cheap that support is no longer needed. I suggest the VCEC turn their thinking around and recommend a generous FiT, approximately 40 cents above retail rates and indexed to future rises in retail electricity prices. Such a scheme should exist for the next 20 years. (sub. DR97, p. 1)
Jill Dumsday (sub. 3), reflected the views of a number of participants when she argued that a premium FiT was necessary to ensure that households recoup the capital cost of installing solar panels within a reasonable period. A shorter payback period was regarded as a major incentive to install solar panels. John Speelmeyer was also concerned that FiTs should allow adequate rate of return on investment in solar panels. He stated that:
… I believe that it is paramount to continue to offer a reasonable and of fair value rate which will ensure that the return on investment is in the current timeframe of 6-7 years. Any cut to the SFIT regime before that 6-7 year pay back will have a materially detrimental impact on the industry who needs to have ROI certainty in order to invest in solar (and other renewable generation). This
52 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION impact cannot be underestimated and must not be ignored. (sub. DR158, p. 1)
Similarly, Alex Dupleix argued that:
Most people have and will purchase systems purely based on business principles; they demand to see a payback. And a period of earnings once the system has paid for its self. (sub. DR152, p. 1)
In contrast to the view of many participants that FiTs are meant to encourage the uptake of low emissions generation technology, the Alternative Technology Association (sub. 73, p. 1) argued that it is a ‘misconception that the objective of FiT policy is primarily one associated with the delivery of emissions reduction’, contending:
… the primary objective of a well designed and structured FiT mechanism is to correct market failure — and to capture costs benefits and other potential benefits (e.g. carbon) of a particular policy choice, where the market alone cannot realise those benefits, or indeed is actively preventing them from occurring. (sub. 73, p. 2)
Similarly, Exigency argued that:
Any change to feed-in tariff structures should address free-rider issues, including the use of the distribution network as a back-up supply. (sub. 4, p. 2)
If there are market failures then some participants considered that the case for government intervention and the setting of regulated FiTs is strengthened. Jemena argued that:
… regulated feed-in tariffs are not an efficient way of achieving the FiT objectives. However, JEN would support a level of regulation if it can be demonstrated that competitive prices are not being offered or are below the value of energy in the market … (sub. 79, pp.5-6)
Regardless of the justification used, if FiTs are to be regulated, submissions have suggested a number of different methodologies that could be used to calculate the FiT. Some of the more commonly suggested approaches include:
• economic/market-based price • payment of a ‘fair and reasonable price’ or a price that reflects the value of distributed generation • paying a ‘one-for-one’ price based on the retail price of electricity • payment based on the estimated return needed to payback investment in distributed generation technology • payment of a premium tariff.
Other issues raised in submissions in relation to regulated FiTs include:
• Should FiTs be calculated on a gross or net basis? • Should FiTs be calculated in such a way as to treat generators of a different size or type differently? • Over what time frame should regulated FiTs be held constant to provide certainty for investment decision-making?
ISSUES RAISED BY PARTICIPANTS 53 Some participants have suggested that regulation is not needed and FiTs should be market-based, for example AGL argued that:
It is critical that the tariff paid by retailers to embedded and distributed generators be determined by the market. Regulating such a tariff would be a significant retrograde step in relation to microeconomic reform of Australia’s energy markets. (sub. 72, p. 1)
Others questioned the ability of the market to determine appropriate FiTs. For example, the City of Whitehorse argued that:
We do not believe that the electricity market is currently sufficiently competitive to offer Feed-in tariffs which reflect: • The costs of production of competing sources of electricity • The reduced burden on the transmission and distribution networks • The reduction in carbon and other emissions associated with distributed electricity generation • Existing subsidies and other forms of financial support provided to electricity generators and network operators which distort electricity pricing from that of a true free market • Avoiding excessive burden on retail and commercial customers through excessive subsidies to distributed generation electricity generators (ie excessive feed-in tariffs). (sub. DR169, p. 1)
Market determined FiTs may still need to be assessed to ensure that they are ‘fair and reasonable’ and there may need to be regulation to ensure that generators, especially smaller generators, are covered by adequate consumer protection.
Regardless of how FiTs are determined participants were concerned that there had been too many changes in the past and this contributed to uncertainty. For example, Lorraine and William Anthony argued that:
Government bodies keep changing the rules and it is difficult to now make an informed decision. We will be unable to commit to any future schemes that would benefit the environment and the future for our children and grandchildren. (sub. DR179, p. 1)
Many participants (for example, Mark Oscar sub. DR144 and Jailal Lalji sub. DR162) were concerned that they had entered an agreement to receive a FiT (such as the PFiT) for a specified period and that this period should be honoured until the expiry of the contract.
These particular comments are a matter of concern as the draft report emphasised that existing contracts would be honoured are part of the terms of reference requirement that no changes would be applied retrospectively. The Commission addresses this and other transition matters in chapter 10.
Recovery of contribution to network value
As well as producing electricity distributed generation also has value because it can lead to deferral of network augmentation in areas where the network is at or near capacity. The network value of distributed generation is very location and time specific (chapter 5).
54 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Participants had different views on how this value could be captured and paid back to distributed generators to provide an incentive to invest in distributed generation in areas where it has the most value. However, the location and time specific nature of the network value mean that it is difficult to calculate and to identify those to whom it should be paid.
One option for taking account of this value suggested by participants, for example, the Clean Energy Council (2012), is to include an amount for the network value in the FiT and pay it to all distributed generators. Another option is to estimate the value of the network benefits and make direct payments to those distributed generators responsible for delaying necessary augmentation of the network.
The nature of network value and how it can be recovered is discussed in chapter 5.
Billing and administrative arrangements
Billing and administrative arrangements are of particular concern to smaller distributed generators, such as households with solar PV panels. Concerns were raised regarding the amount of paper work required to enter into an agreement with an electricity retailer and problems with delays and lost paperwork. How distributed generators were paid for the power they exported was also a concern for some households.
A number of participants, for example, Lois Knight (sub. DR119), argued that the process for determining what FiT would be offered was complex and difficult to navigate.
In relation to the paper work burden imposed on those wanting to set up distributed generation, AGL noted that:
The current Victorian feed-in tariff schemes place an unnecessary level of administrative burden on retailers and customers. (sub. 72, p. 4)
Peter Dewez argued that, in his experience with household solar:
Energy companies need to clean up their acts in paying out customers where appropriate, streamlining and automating the process as far as possible … the process is ad hoc, cumbersome and slow. (sub. DR110, p. 1)
The Energy and Water Ombudsman Victoria noted that on the basis of complaints received one of the main consumer concerns related to:
Incorrect or confusing information about the solar process, or about the billing of FiTs [which] had often been provided to customers by their electricity retailer, distributor or solar installer. (sub. 48, p. 2)
In relation to a larger co-generation project, BRT Consulting stated that:
The administration charges are greater than the off peak feed in tariff and therefore costs to sell energy. (sub. 8, p. 2)
Billing issues were raised by a number of participants. Seng Tan submitted that:
After installing solar PV, I had to change to a new electricity tariff plan. The new plan consists of peak/offpeak tariffs and FiT. This billing practice is confusing and does not provide customer’s ability to assess whether he/she is better off switching to the new electricity tariff. Because of the lack of clarity, I requested my supplier to re-instate my previous tariff plan and
ISSUES RAISED BY PARTICIPANTS 55 would like to forgo FiT. However this is not a viable choice as I would have to incur costs to disconnect from the feed. Thus the issue with current billing practice is the lack of transparency to enable customer to evaluate • Whether the household electricity bill is more or less under the new tariff plan? • To what extent is the purported savings (via FiT) paying off the capital costs of the solar PV? (sub. DR113, p. 1)
Similarly, Kathryn Miller and Matthew Thomas stated that:
Since the agreement has begun, we have had numerous billing issues, including delayed bills (we did not receive a bill until six months after the new meter was installed); overly complicated processes for receiving payments; and lengthy call centre delays. (sub. DR190, p. 10)
Another billing issue is how those producing distributed generation are paid for their power exported into the grid. This is an issue of particular concern to smaller household producers who may be concerned about whether they are paid directly for their electricity or offered a credit on their account. Depending on their personal circumstances, some consumers may prefer payments, while others may prefer an amount to be credited. For example, Elizabeth Walsh submitted that:
… my company only gives a credit and now I am struggling to get them to return my emails regarding direct credit 'to' my account just as they take direct credit 'from' my account. They frustrate customers with over half hour waits which suggests they are deliberately avoiding confrontation with customers-appalling. (sub. DR96, p. 1)
Other conditions or constraints
Other issues related to selling electricity produced by distributed generation include:
• difficulties in distributed generators receiving payment of any benefits they bring to the electricity network, including scope to aggregate smaller generators to enhance seller bargaining power and to provide more scope to argue for compensation for delaying network enhancement • the complexities around to whom the distributed generator can sell its electricity. For example, a distributed generator cannot sell directly to a neighbour without obtaining a retail licence or meeting the associated consumer protection regulations (and incurring the associated costs of that application) (ClimateWorks et al. 2011, p.30)
56 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 4 Commission’s framework 4.1 Introduction
Policies affecting distributed generation, including feed-in tariffs (FiTs), are aimed at achieving a number of objectives (chapter 2). These objectives are reflected in the different views of participants presented in submissions to the inquiry and during consultations. Submissions to the inquiry and the Commission’s research indicate that there are several broad lenses through which participants view policies for distributed generation and its place in the National Electricity Market (NEM):
• efficiency — investing in distributed generation when it is the most efficient option and being rewarded for the value of the electricity they generate and any broader network benefits without imposing additional costs on other electricity users (that is without cross subsidies among consumers) • fair return — those who invest in distributed generation want a ‘fair return’ on their investment and this may be reflected in an expected ‘pay-back period’ • environmental concerns — investing in distributed generation is primarily driven by environmental concerns such as reducing greenhouse gas emission and should be stimulated so that renewable technologies are encouraged and the share of electricity generated from distributed generation grows as quickly as is practicable.
For the reasons outlined in this report the Commission considers that distributed generation can contribute to reducing greenhouse gas emission in Victoria and is often a sound commercial decision for many individuals and businesses. However, these outcomes need to be achieved on an efficient economic basis that avoids, as far as possible, cross subsidies from one group of customers to another (especially where these cross subsidies are likely to be regressive).
The electricity industry is changing, including the recent introduction of the carbon tax. It is also a complex market which is regulated — heavily in some areas — and much of this regulation is changing or under review.
It is against this context of differing views on the objectives of distributed generation policy and a changing market and regulatory environment that the Commission must address its terms of reference, which require it to:
• assess the design, efficiency, effectiveness and future of FiT schemes • recommend any changes to current FiT arrangements • identify barriers to connecting distributed renewable and low emission technologies into the distribution system.
The Commission’s response to its terms of reference reflect its view that the primary policy objectives for distributed generation policy should also fit within the broader national electricity market objective which is to:
To promote efficient investment in, and efficient operation and use of, electricity services for the long term interests of consumers of electricity with respect to – a) price, quality, safety, reliability, and security of supply of electricity; and
b) the reliability, safety and security of the national electricity system. (National Electricity Law s 7)
COMMISSION’S FRAMEWORK 57 The Commission’s response to its terms of reference is therefore guided by a number of core principles:
• Incentives reflecting economic value — through efficiently working markets that capture the value of the output of distributed generation and capture the additional efficiency to the network of incorporating distributed generation among investment options. • No cross subsidies — for both equity and efficiency reasons policies for distributed generation should be subsidy free so that one consumer group is not financially supporting another. • Efficient assignment of policy instruments — the most efficient policy instrument should be used to address a particular issue. • Technology neutrality — policy affecting distributed generation should not discriminate among technologies. • Efficient and predictable processes — connection and other processes should not be unnecessarily burdensome, red tape should be minimised, and processes should be timely and predictable.
Given the context, and applying the principles it is important to understand the value of distributed generation, who benefits from these values, and whether the market is capable of delivering those values, and if not, whether barriers can be removed to improve market outcomes. If problems remain regulation may be an option as long as the benefits of regulation outweigh its costs. In considering changes to regulation the Commission has considered equity and transitional issues.
This chapter further develops the Commission’s analytical approach to be adopted in subsequent chapters. It considers:
• the value of distributed generation • improving the efficiency of transactions • equity considerations • how the Commission has addressed its terms of reference.
4.2 The value of distributed generation
The first element of the Commission’s approach identifies the value of distributed generation. The second element considers how this value can be realised. This is critical to understanding the incentives facing market participants to invest in distributed generation where it has the most value.
In economic terms, the Commission has distilled the benefits of distributed generation into two broad types of value:
• output value, which translates into a unit price • network value, which translates into an incremental investment/capital value.
4.2.1 Output value
Participants (variously) argued that the electricity produced by distributed generation has value arising from:
• the wholesale price of electricity including avoided system losses
58 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • forgone market fees • avoided network charges • pollution and greenhouse gas reduction • the merit order effect.
These values may be reflected in the FiT offered to distributed generators for energy that they export to the network.1
Many participants argued for at least a one-for-one FiT equal to the retail price of electricity. One participant proposed the relevant comparator price is the premium ‘green’ price paid by consumers who wish to offset fully the greenhouse gas emissions of their electricity consumption.
Wholesale price of electricity
Distributed generation purchased by electricity retailers has an output value based on the wholesale price of electricity because output from distributed generation reduces the amount of electricity that must be purchased on the wholesale electricity market.
The wholesale price of electricity in Victoria is determined on the NEM (which includes Victoria, New South Wales, Queensland, South Australia, Tasmania and the Australian Capital Territory). The spot market balances electricity supply and demand and the price of electricity is set on a half hourly basis. ACIL Tasman state that:
… the wholesale spot price of electricity in Victoria is typically between $10 per Megawatt hour (MWh) and $30 per MWh. However, when demand is very high, price can rise as high as $12,500 per MWh (the market price cap). When demand is low, price can fall as low as -$1,000 per MWh (the market floor price). (ACIL Tasman 2012c, p.16)
The value of the electricity produced by distributed generators will therefore depend on the time of day it is produced.
There are also distribution losses as electricity is transported: the further it is from the point of generation to use the greater the loss. The CSIRO argued that distributed energy generation improves system efficiency due to:
… the reduction of network losses by generating energy close to the point of consumption, or improving the utilisation of a fuel by capturing more of the energy available as occurs through co-generation and tri-generation. (CSIRO 2009, p. 18)
To take account of this AEMO publishes loss factors for various locations in Victoria (transmission loss factors are calculated by AEMO while distribution system losses are calculated by the DNSPs and provided to AEMO). The delivered price of electricity includes these loss factors. Distributed generation, being consumed closer to the point of generation, helps avoid these system losses.
Some participants (for example Professor Alan Pears sub. DR192) suggested that the output value of distributed generation is equal to the retail price, not the wholesale price of the electricity. This view is explored further in chapter 9.
1 Some participants argued that FiTs should apply to all the electricity generated (a gross tariff) not just the electricity exported (a net tariff). The Commission’s views on gross and net tariffs are discussed in chapter 9.
COMMISSION’S FRAMEWORK 59 Market fees
The Alternative Technology Association (sub. 73, p. 4) argued that there are ancillary savings in the form of avoided market fees that add value to the output of distributed generators. Table 4.1, prepared by ACIL, shows the market and ancillary services fees that retailers (and other market customers) are required to pay in Victoria to AEMO on a per MWh basis. The table also provides an estimate of their size.
Table 4.1 Estimated market and ancillary services fees
Fee category $ per MWh General fees 0.12 Allocated fees 0.14 FRC establishment 0.02 FRC operations 0.04 NTP 0.04 Smart metering 0.02 Consumer advocacy panel 0.01 Average Victorian ancillary services fees 0.21 Total 0.60
Source: ACIL Tasman 2012, p. 80.
AEMO levies market and ancillary service fees on wholesale electricity purchases. Distributed generation reduces the amount of electricity a retailer needs to buy on the wholesale market and hence it avoids the associated market and ancillary service fees. However ACIL Tasman noted that:
… AEMO’s costs are mainly fixed, so as the total volume of energy each retailer buys falls the allocation process will cause the fee rates themselves to increase over time. (ACIL Tasman 2012c, p.B–12)
In the long run, therefore, these fees are not avoided but are reallocated proportionately to usage, meaning the customers without distributed generation pay an increasing proportion of the fees.
Network charges
Electricity retailers are also required to pay for the use of the transmission and distribution network in the form of transmission use of system (TUOS) and distribution use of system (DUOS) charges. These charges are not levied on electricity purchased from distributed generators.
As a greater share of electricity supply is generated by distributed generation and used on site, network charges will need to be shared across a smaller volume of electricity on the wholesale market. However, distributed generators still have access to the network but the value of this service is not recognised explicitly in current pricing mechanisms.
This issue is much broader than distributed generation. Similar issue arise with growing energy efficiency and growing peak demand accompanied by lower network utilisation. Therefore, the Commission considers that ongoing recovery of network costs
60 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION needs to be recognised but the issue should be addressed through broader regulatory and price reform. It is beyond the scope of this inquiry.
Pollution and greenhouse gas externalities
Electricity produced by low-emission and renewable distributed generators also has a social (but not private) value because of the value of reducing greenhouse gases (which would have been produced if electricity had have been generated by more emission intensive technologies).
ACIL noted that:
From 1 July 2012 a carbon trading scheme will be implemented under the Commonwealth Government’s Clean Energy Future policy. Subject to certain criteria, the carbon trading scheme will require greenhouse gas emitters, such as electricity generators, to pay for their emissions. The carbon price is an additional cost incurred by the electricity generators, which will be reflected in higher bids into the NEM. To the extent that the electricity generators are able to pass through the carbon price to customers, the carbon price will be incorporated in the wholesale electricity price from 1 July 2012. (ACIL Tasman 2012c, p.18)
The carbon tax, and hence the private value it sets for greenhouse gas reductions, will therefore be reflected in the market determined wholesale electricity price. The carbon tax will also be reflected in the retail price of electricity and therefore the cost of electricity avoided by those using distributed generation.
The merit order effect
The merit order refers to how available sources of electricity are ranked in the marketplace in deciding which will be called on to supply into the wholesale electricity market. Sources of electricity supply are ranked in ascending order according to the price at which they are offering to supply electricity. Usually the suppliers with the lowest marginal costs bid into the market at the lowest price and are the first to be brought online to meet demand. The plants with the highest marginal costs who offer to supply at the higher prices are the last. Distributed generators that supply intermittently based on weather, such as wind and solar generators, are automatically dispatched into the market when they produce. Therefore, introducing new distributed generation with low marginal costs of production can reduce in the average wholesale price by displacing high marginal cost gas-generated electricity with lower marginal cost renewable electricity when it is available.
An as yet unpublished study by the Melbourne Energy Institute described the merit order effect (MOE)2:
In electricity markets that use a merit order dispatch system, generation capacity is ranked by the price that it is bid into the market. Demand is then met by dispatching electricity according to this rank, from lowest to highest bid. The last capacity dispatched sets the price received by all generation, ensuring the lowest cost provision of electricity. A consequence of this
2 The study has not yet been published as it is undergoing a peer review process. However an abstract is available on the institute’s website: http://energy.unimelb.edu.au/index.php?mact=News,cntnt01,detail,0&cntnt01articleid=112&cntnt01returnid =22
COMMISSION’S FRAMEWORK 61 system is that significant deployments of low marginal cost electricity generators, including renewables, can reduce the cost of electricity.
The Institute stated that:
… In this analysis we calculate the likely reduction of wholesale prices through this merit order effect on the Australian National Electricity Market. We calculate that for 5GW of capacity, comparable to present per capita installation of photovoltaics in Germany, the reduction in wholesale prices would have been worth in excess of A$1.8 billion over 2009 and 2010, all other factors being equal. We explore the implications of our findings for Feed-in Tariff policies, and find that they could deliver savings to consumers, contrary to prevailing criticisms that they are a regressive form of taxation.
The MOE is not unique to distributed generation or the electricity market. In other competitive markets innovation and the introduction of lower cost supplies will lower the average market price faced by producers and consumers of the good or service. Its existence does not necessarily imply a case for government intervention.
4.2.2 Network value
Distributed generation can have the following effects on the network and the network operator:
• causing additional costs, both operational and capital expenditure • entailing network benefits, such as increased reliability, smaller incremental cost than centralised energy supply solutions and relieving network constraints • replacing or deferring network investments (Bauknecht & Brunekreeft 2008, p.480).
ACIL Tasman (2012) suggested that the network value of distributed generation arises when capacity from a distributed generator enables a planned network augmentation to be deferred. This presumes there is an identified network expansion plan (at a local level) and that network owners have actively considered the possible impact of distributed generation.
The network value of distributed generation is the difference between upgrading the network sooner, and upgrading it later, taking into account the costs that a distributed generator may impose on the network. The network value of the distributed generator would be zero (or negative) in areas where the network is not constrained (ACIL Tasman 2012c, p.vii).
The value of distributed generation to the wider distribution network therefore comprises positive and negative elements:
• deferral of network augmentation costs
• costs of network reinforcing.
Deferral of network augmentation costs
The network value of distributed generation stems from electricity being generated close to the customer (or other customers) in areas where the network is constrained. Electricity therefore does not need to be transported through all of the network, and may defer the need for network augmentation. However, the value of the distributed generation is driven by its capacity to support the network when it is constrained (at
62 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION times of peak demand) and hence the value is partly technology dependent. ACIL Tasman notes:
… the network value of distributed generation is likely to vary significantly from place to place due to the local nature of network constraints. It is also likely to vary significantly for different generation technologies as the certainty with which they can be relied upon to generate electricity during times of peak demand varies. It is only efficient to use distributed generation for its network value if the cost of doing so is less that the (avoided) network solution. (ACIL Tasman 2012c, p.25)
It is difficult to estimate the size of the network value because it depends on the location of the generation, whether it is of sufficient capacity to delay the need to invest in the network and whether it can be relied on at the time it is needed (chapter 5).
The network value is therefore both time and location specific and can be significant. However, as noted above it must be balanced against the additional costs that may be required to support the connection of distributed generation.
Costs of network reinforcing
Connecting distributed generation may require additional expenditure to reinforce the network to allow safe and reliable connection of distributed generation. Jemena argued that:
It should be noted that connection of medium and large scale rotating equipment to the distribution network generally contributes to the fault level energy that flows into the network when a localised network fault occurs. Distribution networks are designed with a maximum fault level limit. Exceeding the network’s designed fault level limit will increase the risk to the reliability and safety of the distribution system. (sub. 79, p. 7)
Additional investment may be required to accommodate the connection of distributed generation to ensure fault levels do not exceed safe levels and compromise system reliability.
The costs of accommodating distributed generation may be significant when compared with other project costs, especially for smaller projects. For example, Ironbark Sustainability observed that:
In some cases DB’s [distribution businesses] require the installation of prohibitively expensive equipment in the distribution network to accommodate increased fault levels. (sub. 50, p. 9)
COMMISSION’S FRAMEWORK 63 ClimateWorks argued that: … if it is established that there is not enough network capacity, the costs of network augmentation are not transparent and are often prohibitively expensive – costing more than the cogeneration system itself. (ClimateWorks et al. 2011, pp.24–25)
Other participants were concerned that it was the distribution business that determined what reinforcing or additional capital work was required. For example, the Clean Energy Council provide an example where:
A mega-watt rated distributed generator proponent was required by the DNSP to install two separate voltage control schemes. With a total cost in the millions one of these schemes is expected to remain redundant leaving the proponent holding significant stranded assets. (sub. DR197, p. 13)
Net network value
Overall, the network value of a proposed distributed generation project can be positive, zero or negative depending upon the relative sizes of any network augmentation savings (which in themselves are time and location specific) and the costs of any required network reinforcing.
4.3 Realising the value of distributed generation
Realising or capturing the full value of distributed generation is key to ensuring there are appropriate incentives to ensure that distributed generation plays a role in Victoria’s electricity sector. In the Commission’s view the market is generally the best mechanism to identify and realise value. However, there may be times when markets fail to function effectively and additional regulation or government intervention is needed to ensure efficient outcomes.
4.3.1 Role of the market
The Commission considers that an efficient electricity system should take account of the full value of distributed generation and this value should be reflected in price signals and other incentives faced by market participants. An effectively functioning market will enable market participants to identify and realise the value of distributed generation. The Commission’s starting point is therefore that well-functioning competitive markets are the best means of achieving efficient outcomes that ultimately protect the long-term interests of consumers (and society more generally) (box 4.1).
64 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Box 4.1 Market-based prices Market-based price signals and the actions of market participants will result in an efficient take up of distributed generation and development of the electricity network. In such circumstances the case for government intervention is weak. In competitive markets potential sellers of electricity will negotiate the conditions and price under which their exported electricity will be purchased. Those considering installing distributed generation will be able to assess the benefits (energy costs saved and returns from selling excess electricity) and make an informed decision as to the desirability of installing generation capacity. The buyers will offer a price which reflects the value of the electricity to them. If the market is well-functioning the price offered will be economically efficient. Price signals will guide investment in generation and the development of network assets. Source: Commission analysis.
Efficient outcomes are predicated on the market functioning effectively. If there are any ‘market failures’, market outcomes may not be efficient, the value of distributed generation not revealed and there may be scope for government intervention. That said, even in the presence of market failures it is necessary to consider whether the cost of intervention outweighs the benefits. The existence of market failure is not in itself sufficient to justify government intervention and regulation.
The Commission considers that the potential market failures relevant to this inquiry include:
• significant disparities in market power • when a party to a transaction has incomplete information or less information compared with another party (information asymmetries or deficiencies) • when the parties to a transaction do not account for the full effects of their actions on others (spillovers or externalities) • high transactions costs where it is difficult for dispersed parties to combine to negotiate joint benefits.
Market power of participants
Market outcomes will not be efficient if there is a significant asymmetry of market power where one or more of the participants is able to exercise market power during price negotiations. An electricity service provider (such as a distribution business) with market power is able to charge a higher price for the services it sells (compared with the price that would be offered in a competitive market) to the detriment of the buyer of those services. It also leads to an inefficient use of resources between generators, distributed generation, and transmission and distribution infrastructure.
Several participants expressed concern that retailers and distribution businesses have market power and that regulation of FiTs and connection was therefore warranted. For example, the Australian Solar Round Table noted that one of the problems that FiTs are intended to address is that:
The market for power from distributed and embedded generation is distorted by an imbalance of market power. A small number of players dominate the market. (sub. 56, p. 9)
COMMISSION’S FRAMEWORK 65 The Dandenong Ranges Renewable Energy Association argued that the electricity market:
… is not perfect and can be manipulated by vested interests. Protections need to be put in place so that solar households cannot be treated unfairly. (sub. DR114, p. 1)
Similarly, Professor Alan Pears also asserted that the network operators have market power and that this can distort the role of distributed generation (sub. 44, p. 2).
If monopoly distribution businesses exploit their market power they could adversely affect those seeking to connect to the distribution network. The distribution businesses may have little incentive to allow the connection of distributed generation and the proponents of distributed generation have no alternative distribution network to approach for connection. The monopoly power of distribution businesses may also affect the ability of distributed generation proponents to recover the network value of their investment in distributed generation (chapter 5).
At face value, the potential market power of monopoly distribution businesses is likely to be much higher than retailers who operate in a more competitive market where entry by new businesses is possible. However, some retailers (although not all) also own generation assets. This may affect their incentives to encourage more distributed generation when that generation competes with their own generation businesses especially when merit order is being determined. Any market power available to retailers may affect the FiT offered to those exporting their excess electricity into the grid. The ability of retailers to do so is considered in chapter 8.
To address market power concerns some participants argued for mandated FiTs, not just general guidance on what might be a ‘fair and reasonable’ FiT.
Incomplete information
Markets work best when market participants have sufficient information to make decisions that best reflect their individual circumstances and priorities. Information is important — to help those making long-term decisions about whether to invest in distributed generation.
The Commission has identified a number of information issues affecting different parties, including information on the:
• process for connection and receiving a FiT • costs and benefits of distributed generation • opportunities for distributed generation.
Information is also required to ensure an efficient connection process for distributed generation. Distributed generation proponents argue they need access to information on where the distributed generation is most highly valued and the nature of any network constraints that raise the cost of the project. In addition, some participants argued that there was a lack of information on the connection process itself and what information was expected from distributed generation proponents (chapter 6).
Moreland Energy Foundation Limited (MEFL) argued that there is a need for certainty and that:
Without a feed-in tariff, a person or business considering investment in a distributed energy system cannot be certain that they will receive the true
66 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION value of the electricity produced by their system over the life of the system. A feed-in tariff can provide this certainty, with appropriate mechanisms for adjustment of the feed-in tariff rate. (sub. 75, p. 3)
However, in practice it is not possible to offer a certain return to investors, and nor is there a general presumption among private sector investors that they will receive a certain return on their investment.
There are also concerns that the availability of information and ability to understand and use it may vary according to the size and sophistication of the entity installing distributed generation. For example, MEFL argued that:
Nor is there any guarantee without regulation that the characteristics of feed-in tariffs provided voluntarily by market participants will be useable by the significantly smaller, less sophisticated, less knowledgeable and less well-resourced distributed generation owners. (sub. 75, p. 8)
Many small potential investors in distributed generation, such as households and small businesses, have limited access to information. However, those with the information on the opportunities for distributed generation are monopoly distribution businesses who have limited incentives to make the information available to distributed generation proponents. Information issues relating to recovering the network value of distributed generation are discussed in chapter 5.
Lack of information as such does not always justify government intervention in the operation of the market. In some cases, information concerns can be overcome by private intermediaries, for example, in the case of financial services, loan and insurance comparison services provide information to consumers to help them make informed decisions.
Spillovers and externalities
Spillovers and externalities occur when the activities of one agent in the market affect another in ways that are not taken into account by the market. For example, in the absence of any tax on pollution a producer will not take into account the cost of pollution in production decisions.
Many of the participants that supported policies encouraging distributed generation argued that this support was justified because of environmental externalities, in particular reducing greenhouse gas emission (for example, P, D and D Marcuccio, sub. DR164 and Sally McIlroy, sub. DR171). The role of distributed generation in reducing greenhouse gasses and the implications of the introduction of the carbon tax are discussed in chapter 8.
Ironbark Sustainability identified one of the market failures resulting in a barrier to distributed generation as:
Savings related to avoiding upgrades to the grid (ie, DG systems may not require investment in poles and wires) are not captured in the current regulatory environments, meaning DG providers accrue the risks but none of the savings. (sub. 50, p. 12)
It has also been argued by some participants that more distributed generation benefits electricity users by reducing reliance on a small number of larger generators. Such participants argued that continuity of electricity supply can be vulnerable to the failure of a large generator. Ironbark Sustainability argued that a benefit of distributed generation is that:
COMMISSION’S FRAMEWORK 67 DG provides the opportunity to reduce the negative consequences from potential outages of escalations in energy costs. A large number of smaller units using varied energy sources represents a lower output at risk per installation, as opposed to outages at centralised plants that have massive output at risk, for example, through accident, terrorism, maintenance. (sub. 50, p. 10)
Overall, the existence of spillovers and externalities and resulting market failures may justify additional support for distributed generation. For example, United Energy stated that:
Incentive schemes are required to encourage distributed generation because in general distributed generators don’t receive a financial reward that reflects the full benefits they provide to the network and wider community. (sub. 77, p. 1)
During consultations, John Daley of the Grattan Institute noted another form of externality relating to the development of new electricity generation technologies. He argued, consistent with a recent paper published by Grattan Institute3, that there is a ‘first mover’ disadvantage for those trying to introduce new generation technologies. Early movers of new technologies face costs, particularly in technology development, regulatory development and finance, that are higher than the costs of subsequent entrants, but because electricity is a commodity, first movers do not recover additional revenues. He also argued that in its first few years, any form of carbon pricing is likely to lack long-term credibility, and consequently emissions will be under-priced in the short term, leading to under-investment in lowest cost, longer term technologies.
High transactions costs
The costs of negotiating individual contracts and arrangements can be a problem for households and owners of smaller distributed generation units. Transaction costs can also affect the willingness of retailers and distribution businesses to connect small-scale distributed generation if they have to deal with a large number of potentially diverse and geographically spread suppliers. These costs may mean that transactions that would have been mutually beneficial to all parties, including the community as a whole, do not take place — representing a market failure.
Regulating FiTs and the terms and conditions of connection and supply can reduce the transactions costs faced by both the seller and buyer of electricity. This point was recognised by the Australian Solar Round Table which argued that FiTs address a number of problems including ‘transaction costs of the individual transactions’ (sub. 56, p. 9).
The overall time taken for connection can also impose significant transactions costs on those wanting to connect distributed generators to the network. For example, some inner city distributed generators can take up to 12 months for a connection, and in some cases as long as two years if the connection is complex (ClimateWorks et al. 2011, p.23). Ceramic Fuel Cells Limited noted that the connection of its fuel cells averaged 40 days but could be much longer (sub. DR135, p. 2).
3 (Wood & Edis 2012).
68 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Role of the market: summary
The Commission considers that a well-functioning market for electricity and an absence of regulatory barriers would provide the most efficient and effective mechanism for revealing the value of distributed generation. However, the Commission is aware that market failures may prevent the full value of distributed generation being revealed and creating incentives for efficient investment in distributed generation.
In the Commission’s view, to the extent that these market failures are valid, addressing them, when the benefits of intervention outweigh the costs, would make decisions on the connection of distributed generation and investment in the network more efficient.
Dealing with market failures involves revealing the value of distributed generation and embedding efficient price signals — this is complex and involves sending efficient, information rich price signals to all participants in the market to encourage market players to reflect the value of distributed generation in their actions. The value of distributed generation among industry participants differs:
• to retailers — the value of distributed generation is their savings from buying less electricity on the wholesale market — the output value of distributed generation. This value should be reflected in the price of electricity per unit exported. Competitive prices should reflect the opportunity cost of electricity generated by different types of generation and not subsidise or favour any particular technology. • to DNSPs — the value of distributed generation results from the value of any capital expenditure to augment the network avoided as a result of distributed generation (the network value of distributed generation). But, must also include the cost of any network reinforcement necessary for the connection of distributed generation. • to distributed generators — the value of energy produced and exported to the grid as well as the value of the energy consumed on site and any payments received for other values (such as the network value of distributed generation).
4.4 Improving the efficiency of transactions
Efficient connection processes are critical to ensuring that there is appropriate investment in distributed generation as part of Victoria’s electricity sector. Removing unnecessary regulatory burdens and simplifying the connection process would help distributed generation — both at medium- and household-scale — to be an important part of the electricity sector.
The Commission makes a distinction between the processes for connecting medium-scale and household-scale distributed generation because of the different issues involved. In the case of medium-scale connection the areas for improving the efficiency of the connection process are:
• improving information on connection processes • providing an automatic right of connection providing minimum standard technical criteria are met • ensuring a right to export electricity to the grid • establishing a standard connection process to the network • improving engagement by Distribution Network Service Providers (DNSPs) in the connection process, including providing information earlier on network constraints and technical requirements
COMMISSION’S FRAMEWORK 69 • requiring specific reported timelines, including limits on how information requests can impact on overall timelines.
Improvements to the connection of household-scale generators include:
• requiring a default FiT to be offered • combining retailer’s supply and FiT contracts • providing information to customers on their role and the role of other parties in the connection process, the likely retail and installation costs, and on the progress of their connection application • providing paperwork directly to DNSPs rather than retailers.
The Commission explores these issues and makes recommendations to improve the connection processes in chapters 6 and 7
4.5 Equity considerations
There are conflicting views about the impact of FiTs on public welfare, which is a matter the Commission is required to consider under its Order in Council.
A number of submissions to the inquiry and some academic papers suggest that schemes such as the Premium FiT (PFiT), which set a FiT price above competitive market levels, result in regressive outcomes. For example Nelson, Simshauser and Kelley (2011) argued the extra costs associated with PFiT schemes result in above market costs that are passed on to all electricity customers as higher electricity prices. In effect, distributed generators are cross subsidised by other electricity consumers.
Furthermore, those authors argued this cross subsidy is regressive because higher income households can afford distributed energy systems and therefore capture the benefits. By contrast, lower income consumers who cannot afford these systems incur higher costs. This outcome is bolstered by the restriction that various distributed generator rebates only apply to those consumers who hold the title deed to property. Consequently, less affluent consumers (such as renters) have less access the benefits. Nelson, Simshauser and Kelley (2011) also present some quantitative evidence, based on the NSW FiT schemes and AGL data, to support the theory.
In addition, in South Australia the Essential Services Commission of South Australia (ESCOSA) has estimated that:
The current distributor funded FiT scheme provides generous subsidies to existing customers with solar PV, particularly those who are eligible for the 44c/kWh amount. While the Commission supports the decision to phase out the distributor funded scheme for new customers, it notes that the scheme may cost all South Australian energy customers around $90m per annum, which adds around $65 to the average annual household energy bill. (ESCOSA 2012, p.48)
Grosche and Schroder’s (2011) evaluation of the German FiT schemes concludes that while FiTs are regressive, the redistributive effects are quantitatively small. The Alternative Technologies Association (sub. 73) also supported the view that provided the overall cost of the FiT scheme is low, and that the broadest base of electricity consumers are levied, the final cost to average consumers should remain insignificant.
In contrast to these views, other participants have argued that FiT schemes can have a positive impact on welfare through the merit order effect (MOE). In addition, the
70 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION potential for distributed generators to improve the cost-effectiveness of the electricity network (for example through reduced transmission losses or need to augment the network) can also facilitate lower electricity prices. Beyond Zero Emissions (sub. 64, p. 5) asserted that increasing the amount of renewable energy on sale lowers the average price per unit of electricity because it counteracts the effects of peak demand. However, this conclusion would only be valid if cost savings were not possible from other demand reductions that do not require subsidies.
Other commentators have argued that as renewable energy sources tend to be more expensive than the non-renewable alternatives the effect is to increase the total cost of producing power. They argued that the MOE shifts costs among market participants but does not lower the overall cost of electricity. For example Nelson, Simshauser, and Kelley (2012) concluded that:
… the result is nothing more than a short term wealth transfer from existing electricity producers to consumers and a long run increase in overall costs leading to a loss of consumer (or taxpayer) welfare. (sub. 72, p. 4)
The Commission understands the nature of the MOE but is not persuaded that it justifies a subsidy through a higher FiT. The MOE and its implications for future FiTs is discussed in more detail in chapter 9.
Another equity consideration is that under current regulatory arrangements, distributed generators pay less for their ongoing access to the network, including meeting the costs of ongoing maintenance of the existing network. As the amount of distributed generation increases over time the cost of network access will be spread across a smaller number of customers. These customers will therefore be disadvantaged relative to those with distributed generation.
In the Commission’s view, the equity impact of FiTs will depend on pricing policies and the nature and extent of any resulting subsides to particular groups. To the extent there are subsidies to particular groups, the risk of negative welfare effects increases as the penetration of distributed generation increases. An efficient distributed generation model that is free of cross subsidies will have positive long-term benefits for all energy users.
4.6 Addressing terms of reference
The terms of reference require the Commission to:
• assess the design, efficiency, effectiveness and future of FiT schemes (TOR 1) • recommend any changes to current FiT arrangements (TOR 2) • identifying barriers to connecting distributed renewable and low emission technologies into the distribution system (TOR 3).
Based on its research and information from participants (chapter 3) the Commission considers that there are two main transactions involved in establishing distributed generation:
• connection processes (chapters 6 and 7) • establishing efficient prices for the electricity produced by distributed generation (chapters 8 and 9).
COMMISSION’S FRAMEWORK 71 The first dot point addresses TOR 3, while the second dot point addresses TOR 1 and TOR 2. Issues in recovering the network value of distributed generation (part of TOR 3) are discussed in chapter 5.
Markets work best when transactions can be undertaken efficiently by informed market participants. In particular, the Commission considers that distributed generation policies should be designed and implemented to be consistent with a number of core principles:
• Incentives reflecting economic value — through efficiently working markets that capture the value of the output of distributed generation and capture the additional efficiency to the network of incorporating distributed generation among investment options. • No cross subsidies — for both equity and efficiency reasons policies for distributed generation should be subsidy free so that one consumer group is not financially supporting another. • Efficient assignment of policy instruments — the most efficient policy instrument should be used to address a particular issue. • Technology neutrality — policy affecting distributed generation should not discriminate among technologies. • Efficient and predictable processes — connection and other processes should not be unnecessarily burdensome, red tape should be minimised, and processes should be timely and predictable.
The Commission considers its approach is consistent with the objectives of the national electricity market. Appropriate transitional arrangements are also critical to ensure the Commission’s recommended regime it put in place with minimal disruption to consumers and those in the industry. Past changes, particularly in other parts of Australia, have resulted in uncertainty and ‘boom and bust’ conditions for the industry. The Commission wishes to avoid a repetition of this in the future.
In chapter 10 the Commission discusses the implications of its recommendations on current PFiT, TFiT and SFiT customers as well as for future customers. It considers how to manage the transition including through providing information, and the roles of the Essential Services Commission, Consumer Affairs Victoria and the Energy and Water Ombudsman of Victoria.
72 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 5 Network value 5.1 Introduction
Enabling the network value of distributed generation to be captured by distributed generators is an important driver of efficient investment and installation of distributed generation technologies of all sizes. If network vale can be identified, captured and paid to those parties providing distributed generation, positive net network values can provide incentives to connect distributed generation in areas where it has the biggest benefits in reducing the cost of the network. Network costs are a major driver of retail electricity prices (ACIL Tasman 2012c).
Positive network values signal areas where the existing network is close to, or at capacity, and investment in distributed generation would allow additional investment in the network to be deferred or avoided. Those able to connect distributed generation in these congested areas of the network would receive a greater financial incentive to do so than those proposing to connect in areas where the network value may be zero or negative because of the investment required to reinforce the network to accommodate distributed generation.
Identifying and realising the network value of distributed generation is more difficult than identifying the output value of exported electricity because network value is location and time specific. In addition, it relies on distributed generation being able to guarantee production when it is needed by the network. Furthermore, network value is a capital value rather than a value based on per unit of output.
If there were an effective market for identifying and realising network value the Commission expects that distribution businesses would plan measures, including for distributed generation, to alleviate identified localised system constraints where such investment would have a net benefit. The distribution businesses and the proponents of distributed generation would also be able to access sufficient information to assess the costs and benefits of the proposed distributed generation to the network and the proponent.
The rules on how any necessary network reinforcement costs should be shared, and who pays, would be clear, efficient and equitable. Areas where network investment could be avoided by distributed generation (or demand side responses more generally) would be identified and payments made available to proponents of such investments. If distributed generation projects arise outside this planning and require investment to be brought forward the rules on how such projects would be charged would also be clear and predetermined.
In these circumstances each party would be in a position to make an informed decision about the value of proposed investment in distributed generation.
Such a system would allow distributed generation to be planned into the network and charges and payments to be defined up front as part of the Australian Energy Regulator’s (AER’s) five yearly price reset when regulated distribution charges are determined. This system would avoid the problem of one distributed generation project bearing the full cost of any necessary network reinforcement.
However, the current market is unlikely to deliver this sort of outcome because distribution businesses are regional monopolies and therefore do not face competition, and the way they are regulated reinforces the traditional approach of meeting future demand by investing in the capability of the existing network. The Commission
NETWORK VALUE 73 considers these issues and possible recommendations to address them in the remainder of the chapter.
5.2 How material is network value?
The value of deferring additional investment in the network is both time and location specific, and where the network is constrained the value may be significant. Based on a range of estimates on the network value of distributed generation ACIL Tasman reported that:
In a recent report to the AEMC, Ernst and Young noted that the network value of reducing growth in peak demand is complex and recommended “exercising extreme caution in using any (general) measure of value”. Ernst and Young considered that there was sufficient precedent for using “rules of thumb” of between $90 and $300 per kVA per year for deferred network expenditure. (ACIL Tasman 2012c, p.87)
Another estimate found similar values:
Similarly, in the context of the Victorian Advanced Metering Infrastructure program, Oakley Greenwood calculated the value of reduced growth in peak demand at $200 per kW, although this included the value of deferred investment in generation, so is greater than the network value. (ACIL Tasman 2012c, p.87)
In very constrained networks the value of deferring can be very high. For example, in the very constrained parts of the Sydney network:
… there are potential avoidable network costs of up to and beyond $1000 per kVA of peak demand reduction per year. If such a peak lasted, say 10 hours per year, this represents a potential avoidable cost of $1000/10 hours or about $100 per kWh. (Dunstan et al. 2011, p.11)
In terms of what this means for a distributed generation in Victoria, ACIL Tasman noted that:
If it is assumed that the network value is in the order of $150 per kW, and a 2.5 kW solar PV system defers a planned network augmentation by three years, the network value is $375 per year for the three years for which the augmentation is deferred. (ACIL Tasman 2012c, p.83)
Currently there is little information about the nature, location and value of network constraints. This situation clearly limits the capacity of market participants to identify and value opportunities to relax these constraints and/or defer investments in the network. That said, the ACIL Tasman findings suggest that network value, if it could be realised and made available to the proponents of distributed generation, is likely to provide a material financial incentive for those in constrained parts of the network to invest in distributed generation.
5.3 Market power concerns
Local distribution businesses have monopoly power, and access to information on where the network is constrained or is reaching capacity (hence where network value is greatest) and on the need for, and cost of, any network reinforcement necessary to support the connection of distributed generation. This is a significant information asymmetry.
74 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Market power concerns can be reduced by putting distributed generation proponents in a better negotiating position. Increasing their negotiating position through the use of aggregators (being considered in the AEMO Small Generator Aggregator Framework rule change) would help by providing distributed generation proponents a degree of countervailing power (AEMO 2011). However, issues remain, the two key ones for this inquiry are:
• provision of better information • increased clarity on the size and sharing of reinforcement costs.
5.3.1 Better information
Many inquiry participants argued that information on network capacity by location could help reveal areas where network values are likely to be higher and inform better siting of investment in distributed generation. Such information would assist with negotiation thereby improving the functioning of the market and reduce connection costs. Distributed generators can benefit from information on where their projects are needed or can be tolerated in the network and where there are network constraints to their further addition. The lack of such information could be a significant barrier to efficient distributed generation investment and active demand management, and makes it more difficult for distributed generators to negotiate with monopoly distribution businesses.
Many participants, for example Ironbark Sustainability, sub. 50 and the Clean Energy Council, sub. DR200 suggested that regulators should require the publication of better information about network constraints and other issues that may render certain locations unsuitable for new connections. The Energy Efficiency Council recommended the publication of:
Annual maps of the costs and benefits of connecting cogeneration at different points on the grid, including potential payments for offsetting infrastructure investment. The pre-emptive analysis of the costs and benefits of connecting to the grid at different points would provide greater information transparency, opening up competition in the market. (sub. DR200, p. 11)
In the UK, distribution network service providers (DNSPs) submit information strategies for regulatory approval (ACIL Tasman 2011b, p.30). Ironbark Sustainability suggested maps of network constraints could reduce barriers to distributed generation (sub. 50, p. 14). The Institute for Sustainable Futures prepared maps that identify network constraints that can help inform where distributed generation could result in savings from deferred network investment (SV 2012). However, these maps are not available on the Sustainability Victoria website. In addition, the ISF report does not contain information on fault levels, the main driver of distributed generation connection costs in Melbourne.
Exigency’s submission argued that:
• Publication of network performance data (capacity constraints, quality of supply) would simultaneously support regulatory oversight of prudent network expenditure and enable the market to proactively devise non-network solutions. • The process of consideration of non-network solutions by DNSPs could be made more transparent, for the benefit of energy market efficiency overall. (sub. 4, p. 3)
NETWORK VALUE 75 The Clean Energy Council proposed that transparency could be improved by compelling the DNSPs to provide information in sufficient detail to inform negotiation (sub. DR197). The CEC suggested that any new arrangements should take account of the fact that DNSPs are monopoly businesses (CEC, sub. 76, p. 6).
CitiPower and Powercor (sub. DR 184) and United Energy (sub. DR 199) claimed that such information is already available (discussed in the following section).
The AEMC is currently considering a rule change request from the Ministerial Council on Energy on the Distribution Network Planning and Expansion Framework (AEMC 2011a). The proposed rule change includes a requirement for DNSPs to publish a Distribution Annual Planning Report (DAPR) that would detail peak demand, forecast augmentation of the network and, of particular relevance to distributed generation:
… forecasts of any factors that may have a material impact on the network, including factors affecting: (A) fault levels; (B) voltage levels; (C) other power system security requirements; and (D) ageing and potentially unreliable assets. (AEMC 2011a S5.8(2)(v))
In June 2012, the AEMC published a draft rule determination and is seeking submissions on it by 9 August 2012. The AEMC states that:
The Commission considers that the draft rule will contribute to the achievement of the National Electricity Objective by establishing a clearly defined and efficient planning process for distribution network investment. This will support the efficient development of distribution networks. The draft rule will also provide transparency to, and information on, distribution business planning activities and decision making processes. This will assist market participants in making efficient investment decisions and enable non-network providers to put forward credible non-network options as alternatives to network investment. (AEMC 2012d, p.1)
The submission process for the draft rule determination will provide an opportunity for affected interested parties to comment on the value of the draft change from the perspective of removing barriers to the connection of distributed generation.
The Commission’s view
The Commission considers improved spatial information on network constraints and fault levels would improve contestability through fairer negotiation which would help reveal the network value of distributed generation, and better siting of investment leading to reduced connection costs. The information would allow distributed generator proponents to make judgements about likely connection costs and manage the risks of pursuing projects that are less likely to proceed. Information can support proponents to make informed decisions and to negotiate more effectively with DNSPs.
The MCE’s proposed Distribution Network Planning and Expansion Framework rule change request is expected to improve transparency and lead to better long-term planning to accommodate distributed generators (box 5.1). It would also require DNSPs to more actively engage with distributed generators.
76 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The AEMC noted ‘that the proposed content of the DAPR would maintain the core of existing jurisdictional requirements’ (AEMC 2012d, p.30) and the aim is to reduce inconsistency across jurisdictions.
In response to the AEMC’s consultation paper, Seed Advisory asserted:
Guidance should be provided to ensure that DAPRs appropriately reflect existing and well-based anticipations about future projects in the five years covered by each DAPR. This guidance could include: • Requiring the DNSP to provide information on the basis for projections of estimated embedded generating units and outputs… • Requiring the DNSP to discuss the methodology on which estimates of capacity in sections of the network have been based… • Requiring the DNSP to discuss the methodology on which estimates of system security issues, design fault levels and the requirement for voltage regulation have been based … (Seed Advisory 2011, p.2)
Other participants considered that sufficient information already exists and that additional information requirements would impose unnecessary burdens on electricity companies. For example, CitiPower and Powercor claimed:
In relation to information and planning, Victorian DNSPs have for more than ten years produced annual planning reports for their distribution assets and transmission connection assets. The Essential Service Commission of Victoria (ESCV) ensured through various amendments to the Electricity Distribution Code over time that the detail provided in these reports is the most detailed in Australia and publicly available from DNSP websites. The current annual planning reports already place a significant work load on the Businesses taking many months of preparation, review and co-ordination with other parties. The Australian Energy Market Commission’s (AEMC) proposed Distribution Network Planning and Expansion Framework further increases the detail required in each report. The Businesses question how much further information can practically and cost effectively be included in these reports. Further, the Businesses would note the Distribution Network Planning and Expansion Framework Rule changes have been subject to detailed consultation over many years and the Businesses would expect the AEMC has reviewed and considered the same issues identified by stakeholders in the current review. (sub. DR 184, p. 6)
Similarly, United Energy stated that information provision is required by Victorian regulation:
… distributors have, for the past 10 years, published distribution system planning reports which must set out, among other information: (a) the historical and forecast demand from, and capacity of, each zone substation; (b) a description of feasible options for meeting forecast demand including opportunities for embedded generation and demand management; (c) where a preferred option for meeting forecast demand has been identified, a reasonably detailed description of that option, including estimated costs; and (d) the availability of financial contributions from the distributor to embedded generators or customers to reduce forecast demand and defer or avoid augmentation of the distributor’s distribution system. (sub. DR 199, p. 3)
NETWORK VALUE 77 Distributed generation of all scales is likely to grow (chapter 2) and pressure to reduce the growth of network costs will increase. This will make it increasingly important that distribution businesses and regulators have good information on the constraints in the network and where network investment is needed and where it could be avoided.
Distributed generation projects that address network needs are more likely to be identified and brought forward if regular information is produced in sufficient detail and made available to the market. The red tape risk is that DNSPs are required to produce information they would not otherwise need for their own planning for areas that are not of interest to the proponents of distributed generation.
Patricia Boyce from Seed Advisory questioned the value of information currently provided through the distribution code:
The information required by the Distribution Code is answering the wrong question from the perspective of embedded generators not primarily interested in demand side management. The requirements of the Victorian and other state Annual Planning Reviews have been strongly influenced over time by Demand Side Management proponents and, as a result, the information focuses on the requirement for network augmentation, the planned timing and costs of that augmentation and the potential for a DSM proponent to receive payments from the network from identifying an alternative solution. The material is focussed on the network’s own requirements, but the underlying customer facing information is not provided and, I would judge, would be difficult to derive without an intimate knowledge of the network.
As a customer, you’d want to know:
• How to map your project’s location to a zone sub-station, so as to identify whether or not, at first glance, there appear to be capacity issues at the zone sub-station that would serve your project; • Whether the underlying projections for energy demand at the zone sub- station already allow for your project proceeding; • Whether there’s any fault level headroom in the location you’re planning to build and, if so, how much; • For what areas of the network there is effectively a choice of zone substation, giving the project proponent the opportunity to consider alternative connection routes. (Boyce 2012)
Additional information will be available to the proponents of distributed generation as a result of the rule change (box 5.1).
78 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Box 5.1 AEMC’s draft determination: reporting requirements The AEMC’s Draft Determination on the Distribution Network Planning and Expansion Framework proposes the publication of the following information: • forecasts for the forward planning period, including at least: – a description of the forecasting methodology used, sources of input information and the assumptions applied; – load forecasts for: - transmission-distribution connection points; - sub-transmission lines; - zone substations, - total capacity; - firm delivery capacity for summer periods and winter periods; - peak load (summer or winter and the number of hours per year that 95 per cent of peak is expected to be reached); - power factor at time of peak load; - load transfer capacities; and - generation capacity of embedded generating units; • forecasts of future sub-transmission lines, transmission-distribution connection points and zone substations, including for the latter two asset categories: – location; – future loading level; and – proposed commissioning time (estimate of month and year); • forecasts of any factors that may have a material impact on its network, including factors affecting: – fault levels; – voltage levels; – other power system security requirements; and – ageing and potentially unreliable assets. Source: AEMC 2012.
There was a strong consensus among the participants that were investing in distributed generation projects that information is important and current levels of information are inadequate. But there was disagreement and differing emphasis on where in the process that information should be provided. Information can be provided up front through distribution system planning reports. Location specific information tailored to specific projects seems best provided during connection negotiations. The need for information can be reduced by setting predetermined standards that allow for automatic connection.1 The AEMC is considering a rule change request which, among other things, would set connection standards. These avenues for information provision are not mutually exclusive. They form a continuum and if more information is available at one stage the need for information at other stages can be reduced.
1 Information provided during connection negotiations and through predetermined standards is discussed in chapter 6.
NETWORK VALUE 79 If the framework and other process do not deliver the level of specificity needed the Victorian Government could:
• Undertake and release specific work on network constraints and augmentation needs • Seek a further rule change • Require distribution businesses to provide information through state requirements.
The Commission therefore considers it prudent to wait until the rule changes are finalised and then assess the extent to which gaps remain in the information provided. While the Commission considers that access to information is a significant barrier to distributed generation it is not in a position, at this stage of the process, to recommend the approach Victoria should take if the results of the rule changes are inadequate.
5.4 Network reinforcement costs
A network may need to be reinforced to accommodate the connection of distributed generation. However, given the monopoly position of the network providers, four questions arise:
• are the quoted costs of reinforcement and augmentation appropriate? • how does the proponent know this? • who benefits from the reinforcement? • how are the costs shared among distributed generation proponents?
5.4.1 Information and transparency
A lack of transparency makes it difficult for distributed generators to evaluate the appropriateness or competitiveness of the cost estimates and distributed generators’ share of the costs of network augmentation. Bauknecht and Brunekreeft (2008, p.489) argued that in theory the form of regulation used for distributed generation, 100 per cent cost pass through, gives DNSPs incentives to shift costs of system augmentation, which would happen regardless, onto distributed generation customers. The MCE in 2006 and the AEMC in 2012 identified that this is a problem in practice.
Augmentation of existing network assets may provide benefits to other network users, creating difficulties in assigning these costs. Furthermore, DG may provide other benefits to network users, for example, through improved system security. Quantifying and assigning these benefits is difficult. (Ministerial Council on Energy Standing Committee of Officials 2006, p.26) … in relation to augmentations, it is difficult to distinguish the causes of the increased need of augmentation in a meshed network. (AEMC 2012f, p.173)
Distributed generators claimed that the information provided by the DNSPs is often insufficient to do due diligence on estimated network costs (Synergy 2010, p. 22). The Energy Efficiency Council argued there are ‘uncertain and often unjustifiable costs for connecting to the grid’ (sub. DR200, p. 11). Additional concerns raised by participants are discussed in chapter 6.
80 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 5.4.2 Sharing costs
Determining how to share reinforcement costs among distributed generation proponents is also problematic. Where a network is constrained, a distributed generator may have to pay the full cost of network reinforcement that would accommodate several distributed generation projects and other demand growth:
Requiring non-registered DG [distributed generator] proponents to possibly pay for costs of augmenting the shared network will affect the incentives for DG projects, especially in Victoria. Currently DG projects in that state are only liable for shallow connection costs (i.e., direct connection assets and extensions)… The incremental DG project application that leads to the available fault level headroom/capacity being breached will be asked to meet the full costs of the required shared network augmentation. (AEMC 2012f, p.270)
The DNSPs consider this problem is complex:
There are no easy ways to remove the fault level barrier problem although long term planning should aim to reduce fault levels to make allowance for future distribution generation. (UE sub 77, p. 5)
Where network reinforcement does occur, there is no mechanism to charge subsequent distributed generation projects for their share of the reinforcement. For example, the Energy Efficiency Council argued there are:
Inequitable rules about who pays for network upgrades to facilitate cogeneration. Currently, the last cogeneration unit that wants to connect to the grid before an upgrade is required to pay the full cost of the upgrade, despite the fact that other units may connect before or after the upgrade. In contrast, the cost of upgrades to the grid to address rising energy demand are generally smeared across all energy users. (sub. DR200, p. 11)
5.4.3 Who benefits from reinforcement
Another aspect of the incremental network reinforcement cost is identifying who benefits and which activities have produced the need for that investment. Growth in demand, for example, also naturally leads to the need for increased fault level capacity. As electricity demand increases due to population growth, more energy- intensive appliances and changing land use (such as higher density housing), new substations are required to accommodate increased energy from the transmission network and this requirement increases the fault levels on the distribution network. The AER considers that, in general, the beneficiary of network augmentation to accommodate a distributed generation project is the distributed generator and that these increased costs should not be recovered from customers through network charges (AER 2011c, p.64). The AEMC considers treatment of this issue will have a significant impact on distributed generation: … the effectiveness of [the AER’s proposed connection] arrangements will depend upon how they are applied in practice, including the net benefit test and whether DNSPs offer constraint reduction services, and the transparency of connection cost estimates. (AEMC 2012f, p.174)
There is also an issue that if a distributed generator does pay for investment required to connect to the network this may open the way for other distributed generators to connect without incurring any of the costs.
NETWORK VALUE 81 However, while distributed generation can impose costs on the network there are potential network benefits including increased reliability, smaller incremental cost and deferred network investment. These benefits depend on highly localised characteristics and timing of distribution network investment. While the AER does recognise where there are ‘demonstrable benefits’ to other users and the negotiation process offers an opportunity to share these benefits, the onus of proof is on the distributed generator proponent (AER 2011c, p.64).
In terms of regulatory incentives for distributed generation specifically, even if the overall benefits of a project are positive, additional network costs can represent a disincentive for network operators to connect the distributed generator. Consistent with this view, the AEMC concluded that the incentives for DNSPs to engage in demand side participation, which includes distributed generation, may not be optimal: ‘the current arrangements may fail to provide the right incentives even if it is efficient to do so’ (AEMC 2012f, p.135). The AEMC also concluded DNSPs have strong incentives to concentrate on security concerns, and weak incentives to connect distributed generation (AEMC 2009b, p.28).
5.4.4 The Commission’s view
The Commission considers that the lack of guidance and clarity around regulatory mechanisms to recover network reinforcement costs presents a significant barrier to connecting distributed generation to the electricity network in Victoria.
There have been attempts to clarify how reinforcement costs will be shared but they have been unsuccessful. For example, CitiPower proposed a levy on distributed generators for the 2011-15 price determination. The cost was to be recovered partly through a charge on embedded generators and partly from all customers (standard control service). In rejecting the proposal the AER argued the service should fully recover fees from distributed generators (alternative control service) and requested CitiPower to provide further information to support the fee (ACIL Tasman 2011b, p.20).
AER was of the view that this service should be an alternative control service rather than a standard control service on the basis that the works to maintain fault levels were attributed to specific connections rather than recognising that an efficient solution requires works to be undertaken in the shared network. (ACIL Tasman 2011b, p.20)
This process illustrates that there is no agreed framework on how these costs should be allocated and shared.
A lack of clarity also means DNSPs are less likely to plan distribution networks to accommodate distributed generation. The sharing of costs could be improved by developing guidance on the conditions and circumstances for allocating the network reinforcement costs across new distributed generation projects and across customers when they result in system wide benefits. These guidelines could inform future price determinations and connection charges. Addressing these barriers through improved guidance and cost recovery mechanisms is a longer term issue and could potentially benefit network efficiency more broadly, not just for distributed generation.
Options to address sharing network reinforcement costs include guidance, a distributed generation cost recovery scheme for DNSPs or more efficient incentives for DNSPs to invest overall. There is currently a proposal to amend the National Electricity Rules for connecting embedded generators before the AEMC. The proposed rule change could set broad principles for sharing reinforcement costs and the AER could then develop the necessary guidance material. While this is a national issue the Victorian
82 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Government could engage with the AER, AEMC, DNSPs and distributed generator proponents to develop a solution for incorporation into Victoria’s next round of DNSP pricing determinations. The pricing determinations are expected in October 2015 providing sufficient time to work on a possible solution or solutions. The AEMC’s consideration of the Proposal to amend the NERs for connecting embedded generators provides an avenue for the Victorian Government to engage the relevant stakeholders.
Recommendation 5.1 That to clarify the circumstances and conditions in which network reinforcement costs can be spread across new distributed generators and other users, the Victorian Government: • make a submission seeking the development of principles for cost sharing to the Australian Energy Market Commission’s consideration of the Proposal to amend the National Electricity Rules for connecting embedded generators. This submission be prepared by the Department of Primary Industries in consultation with the Australian Energy Regulator (AER), distribution network service providers and distributed generator proponents • advocate to the AER for appropriate guidance on cost sharing arrangements for the connection of distributed generators before the next round of network distribution pricing determinations expected in 2015.
5.5 Regulatory incentives
Addressing market power concerns and improving information is a necessary but not sufficient step to removing barriers to connection of distributed generation. Distributed generators need to negotiate connection with a monopolist whose incentives for efficient augmentation through distributed generation are further dampened by the regulatory environment.
In particular, it is argued that the current regulatory structure favours investment in traditional ‘poles and wires’ delivery systems. Participants raised concerns about the extent to which there are sufficient incentives for distribution businesses to reveal network value and encourage investment in distributed generation even where there are network benefits. For example, the Grattan Institute suggested that:
… the current regulatory environment does not always recognise the economic value of such distributed generation… Many of the current regulations do not create the incentives for network operators to recognise the value of distributed generation. Indeed, because many of them earn a guaranteed rate of return on “necessary” augmentation, they have an incentive to discourage distributed generation that would reduce peak demand. (sub. 86, p. 2)
ACIL Tasman suggested distribution businesses have limited incentive to innovate except when the payback is short because there is no incentive across revenue periods.
… where capital expenditure deferral benefits accrue across regulatory periods … the building blocks approach reduces the benefits to the distributors as the benefits may be returned to customers at the subsequent price review. This could reduce the viability of demand management initiatives to the distributors. (ACIL Tasman 2011b, p.6)
NETWORK VALUE 83 ACIL Tasman also noted that ‘a DNSP’s revenue is based on a return on its regulatory asset base so there is an incentive for the DNSPs to invest in network solutions to increase the regulatory asset base’ (ACIL Tasman 2012c, p.48)
These views are shared by participants in this inquiry who, based on their experiences, argued that regulatory incentives are making it harder for the proponents of distributed generation. Mike Reeves argued that:
The business model for the monopoly distributers is that they are paid for investing in their network rather than ‘deferring network augmentation by encouraging distributed generation’. They also have no incentive to pass on any network value to the DG. (sub. DR130, p. 3)
Similarly, Anne-Marie Gibson stated that:
… power distributors receive significant incentives to upgrade network infrastructure. The introduction of distributed energy generation, particularly in regional and remote areas of substantial size, will in fact delay or significantly decrease the requirement for some of the infrastructure projects being undertaken. (sub. DR155, p. 1)
Currently there is an incentive scheme, the Demand Management Embedded Generation Connection Incentive Scheme (DMEGCIS) (previously DMIS), designed to encourage DNSPs to investigate demand management options, including distributed generation. The scheme, as it applies to distributed generation, has a number of shortcomings:
• the amount provided to distribution businesses is too small to be effective • uncertainty associated with the ex-post assessment of the DMIS payment because DNSPs have no certainty of recouping their costs • narrow focus of expenditure (ACIL Tasman 2011b, pp.17, 39).
The AER identified that the ‘DMIS is not intended to be the sole or even primary source of cost recovery’ and included $221 million for Demand Side Participation (DSP) in the Queensland DNSPs’ price determinations (AER 2010c). While DSP includes distributed generation, most of the $221m in Queensland was allocated to funding DSP technologies such as air-conditioning and pool filtration direct load control and some pilots of pricing options. This suggests that exploring options for distributed generation is not the primary focus of DNSPs even when financial incentives are offered.
The AEMC’s Power of Choice Review’s directions paper noted that current regulatory arrangements could create:
… a bias towards capital expenditure in favour of operating expenditure, both in terms of the potential to make profit and certainty about cost recovery. Therefore, other factors being equal, operating expenditure on DSP [demand side participation] may be at a disadvantage compared to capital expenditure. (AEMC 2012f, p.138)
The Power of Choice Review is considering a number of these issues in a broader context. Two specific issues highlighted in this review were:
• How to recover the costs of the existing network — there are different views on how these costs interact with distributed generation. Some proponents of distributed generation argue that they do not use the network and therefore should not pay. Distribution businesses argue that costs are not avoided by distributed generators
84 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION as the network is still required as a form of insurance. Distributed generators can access electricity if their systems are unavailable and the system still has sufficient capacity if distributed generation is not available at a time of peak demand. In addition, the way network charges are currently levied means that as the amount of distributed generation increases, the network costs are shared across a deceasing volume of electricity sales. • Finding mechanisms that will allow distributed generators to be paid for network savings.
In relation to the first point, the increasing burden of network costs being shared across less electricity will need to be addressed in the longer run but the problem is not unique to distributed generation as it can also result from falling demand for other reasons such as energy saving (chapter 4). These issues should be considered in more general regulatory and price reforms.
The Commission’s views on recovering network value is discussed in the following section.
5.6 Recovering network value
The Commission considers that recovering the network value and paying it to the proponents of distributed generation is important to ensure there are incentives for the efficient incorporation of distributed generation into Victoria’s electricity system. However, recovering this value is not easy. Ceramic Fuel Cells noted that they accept that it is hard to produce a single specific figure for the network value’ (sub. DR135, p. 5).
Advice provided to the Commission by ACIL Tasman suggested that the network value of distributed generation is in the nature of a local specific capital value that is unrelated to the quantity of energy generated, and is not easily incorporated into the FiT payment (ACIL Tasman 2012). The Commission’s view is that the network value is appropriately dealt with outside of the FiT payment.
Possible options for addressing this network value, include:
• Recognising that there is a value but do nothing because of the difficulty and possible transactions costs involved in trying to calculate it. These costs arise because the network value will vary by location, time of day, type of generator and the extent to which the DNSP can rely on the generator producing electricity when it is needed. • Improving regulatory structures to provide incentives to reveal the network value — proposed changes to the regulations governing incentive structures for distribution businesses, simpler (and less costly) connection processes, and better information about local bottlenecks may make the value more accessible to distributed generators. • The value could be estimated and spread across all distributed generators and reflected in FiT payments, but as noted earlier this is not the Commission’s preferred approach because the network value is not based on output.
However, none of these options is particularly effective in identifying the network value and ensuring it is paid to the distributed generation proponent.
The Commission considers that another option is to use the AER’s price reset process to consider the value of any network benefits from distributed generation and to then require distribution companies to make payments based on this value.
NETWORK VALUE 85 The payments could be made available to large distributed generators, retailers (to pass on to relevant distributed generators), or aggregators who may be responsible for aggregating a number of distributed generators to have an appreciable effect on the network.
Distribution businesses are already required to provide the AER with estimates of the need for and cost of network investment as part of the price reset process. Those requirements could be modified to include providing estimates of the network costs and benefits of distributed generation (or demand side responses more broadly). This information would be the basis for identifying the areas of the network where the network benefits of distributed generation would be positive and setting up how payments would be made to proponents bringing forward proposals that would realise those benefits.
Recommendation 5.2 That the Victorian Government, through the Department of Primary Industries investigate whether, and how, the Australian Energy Regulator’s price reset process can be used to: • Identify the network value of distributed generation • Require distribution businesses to make available payments based on that value. Subject to the investigation producing a practical solution, and in the absence of any other relevant developments, the Victorian Government prepare and submit a rule change proposal so it could be considered by the AEMC prior to the next price reset process in 2015.
86 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 6 Connecting generators to the distribution network
Although distributed generation can have many advantages, it does not always easily fit into today’s centralised power systems. Even if overall benefits are positive, additional network costs can discourage distribution network service providers (DNSPs) from connecting a distributed generator. It is therefore not surprising that the most commonly raised immediate barrier to greater adoption of medium-scale distributed generation is the process for connecting these systems to the electricity network.
Distributed generators require access to distribution networks for a range of reasons including selling electricity and balancing system loads (ClimateWorks et al. 2011, p.9). Connecting distributed generation is of particular interest to this inquiry because the connection processes and costs can have significant impacts on the efficiency and viability of medium-scale distributed generation projects.
Connection barriers relate to connection costs (chapter 5) and the connection process (this chapter and chapter 7). Efficient connection would mean DNSPs have incentives to remove artificial barriers to entry, with efficient costs, timing and risk allocation. Material barriers to connection can be addressed at two levels:
(1) The connection process: the Commission considers there are clear barriers in the connection process that could be ameliorated now. These changes are necessary, would improve competition between distributed generation and other options for achieving the National Electricity Objective (NEO), and increase the efficient use of distributed generation. These important barriers are the primary focus for this chapter and chapter 7. (2) DNSPs’ incentives to plan and manage the system to make efficient use of distributed generation: many participants argued that addressing the connection process alone will not be sufficient to guarantee efficient use of distributed generation. The Commission considers that some of these DNSP incentive issues are longer term in nature, but that they have a strong impact on the barriers to distributed generation. The Commission examines these barriers, recommends some more immediate actions and identifies areas where longer term action may be needed in chapter 5.
Such connection barriers indicate a probable underinvestment in distributed generation in Victoria, primarily at the medium-scale where the connection barriers are more significant.
The terms of reference of the inquiry ask the Commission to identify barriers to distributed renewable and low emissions generation in Victoria, including co-generation and tri-generation. This chapter and chapter 7 examine barriers in the connection process for medium-scale and ‘household-scale’1 distributed generation respectively. Each has different connection processes, the proponents have differing capacity to deal with DNSPs, and scale creates different kinds of network impacts.
This chapter first sets out, in section 6.1, the regulatory context along with work currently underway to address connection barriers. Section 6.2 describes the benefits of medium-scale generation and section 6.3 summarises participants’ views on barriers to
1 ‘Household-scale’ includes small-scale distributed generators owned by small business and community groups.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 87 connecting. The right to connect and export (section 6.4) and the connection process (section 6.5) are analysed in more detail, followed by section 6.6 which discusses the impact of implementing the Commission’s recommendations.
6.1 Context
Connection of distributed generation is regulated by national and state arrangements. The national connection arrangements outlined in section 2.2.3 and appendix B include the connection elements of the COAG principles for feed-in-tariffs, chapter 5 and 5A of the National Electricity Rules (NER) and the National Customer Energy Framework (NECF). Chapter 5A of the NER provides basic, standard and negotiated connection services. The NECF and chapter 5A are not implemented in Victoria and the implementation date has not yet been announced.
In 2009, the Australian Energy Market Commission (AEMC) conducted a Review of Energy Market Frameworks in Light of Climate Change Policies. The AEMC concluded that regulatory barriers prevent the efficient connection of distributed generators and that addressing these barriers is likely to further the National Electricity Objective (NEO) (AEMC 2009c, p.76). Many actions have been implemented or initiated to address these barriers (table 6.1).
After the introduction of the NECF in Victoria, those seeking medium-scale connection will follow the process illustrated in figure 6.1. Prior to implementing the NECF in Victoria, connection is governed by chapter 5 of the NER, and supplemented by Victorian regulations including Electricity Industry Guideline No. 15: Connection of Embedded Generation (ESC 2004a), the Electricity Distribution Code (ESC 2012a) and distribution licences). Chapter 2 and section 6.4 describe the regulatory context in more detail.
88 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Table 6.1 Actions to address barriers to distributed generator connection
Date Action Details July 2010 AEMO Small Generator Sets out principles to minimise Framework Design barriers to cost-effective participation by small generators in the NEM July 2011 AEMC responded to proposal Aimed to improve incentives for by Minister for Energy and DNSPs to invest more efficiently. Resources (Victoria) on Total AEMC concluded the TFP approach Factor Productivity (TFP) in has merit but practical network pricing regulation implementation issues exist December Distributed generators The AEMC completed a rule change 2011 included in the Demand process to include distributed Management Incentive generation in the DMIS Scheme (DMIS) June 2012 Proposal to the AEMC to ClimateWorks, Seed and the PCA amend the NER for connecting proposal to streamline connection embedded generators processes and improve DNSP incentives for engagement April 2012 AEMC published draft Main components are an annual determination on rule change planning and reporting process, a proposed by MCE on Demand Side Engagement Strategy, Distribution Network Planning and a Regulatory Investment Test for and Expansion Framework Distribution (RIT-D) June 2012 AER published guidelines on Provides guidance on connection connection charges charges under the new chapter 5A September Final AEMC Demand Side Aims to improve opportunities for 2012 Participation (DSP) Report: The DSP Power of Choice September Outcome of AEMO Small Aims to simplify registration of 2012 Generator Aggregator distributed generators Framework rule change request to AEMC April 2013 Final report of Productivity Seeks, among other things, to Commission inquiry into address barriers to distributed electricity network regulation generation To be Commencement of Chapter Expands the NER for connection of determined 5A of the NER in Victoria household and medium-scale distributed generation
Notes: Australian Energy Market Operator (AEMO), Australian Energy Market Commission (AEMC), Clean Energy Council (CEC), Ministerial Council on Energy (MCE), National Electricity Market (NEM), Property Council of Australia (PCA). Source: Commission analysis.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 89 Figure 6.1 Connection approval process for medium-scale distributed generator retail customers (with NECF)
Preliminary inquiry from potential applicant wishing to connect DNSP has 5 days to provide information
Applicant lodges application on form determined by DNSP
Additional information required Application incomplete
DNSP informs applicant DNSP informs applicant of additional of deficiency information needed
Application complete DNSP has 10 days to advise whether the service is Completed covered by an approved application submitted connection process and, if so, make a connection offer • offer open for 45 days • expedited connection may be available Site visit, if needed
Not approved service. Basic connection DNSP notifies applicant service or standard of the negotiation connection service process & possible changes & expenses DNSP uses best endeavours to make offer within 65 days Use agreement of receiving completed pre-approved by AER application* Negotiated Offer open for 20 days connection offer
Agree Not agreed Legend AER – Australian Energy Offer terms form Option of dispute Regulator connection contract resolution through AER DNSP – Distributed Network Service * This applies to negotiation, Provider not dispute resolution Source: Commission analysis.
90 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 6.2 Benefits of medium-scale distributed generation
Depending on location and operation, medium-scale generators offer several advantages in network support and electricity supply to the owner and other parties in the electricity system:
• Greater potential for network savings at lower cost than small-scale renewables because of economies of scale. CSIRO estimates co- and tri-generation could provide nearly five times more peak generation capacity than local renewables at one sixth of the cost (Dunstan et al. 2011, pp.12, 68). • With strong demand for green building office space, co-generation can contribute to national emissions reduction targets and improved green building ratings which improve rental returns for building owners (ClimateWorks et al. 2011, p.15). • Low transaction costs with less than 100 medium- to large-scale plants making up 295 MW of installed capacity compared with around 50 000 small-scale PV installations making up around 75 MW of installed capacity in Victoria in 2010.2 • Co- and tri-generation plants can switch on at full capacity or switch off unlike solar PV which cannot guarantee maximum production when the network is constrained and the electricity spot prices peak (Dunstan et al. 2011, p.74).
The net benefits of medium-scale generation vary by location and operation, and achieving many of these benefits requires connection to the network. Many participants were concerned about significant barriers to connecting medium-scale generators.
6.3 Barriers to medium-scale distributed generation
The Commission consulted with different stakeholder groups during the inquiry.
Medium- scale connection barriers: proponent view
A survey conducted by Senergy of connected distributed generators found a range of connection issues although the survey did not include the DNSPs (box 6.1).
A separate survey conducted by Entura for Sustainability Victoria (SV) in 2010 found that:
• The majority of survey respondents and interviewees found their working relationship with the DNSP to be average or below normal expectations and believed that this resulted in longer project implementation times and increased costs. • There is a clear relationship between the quality of the perceived working relationship with the DNSPs, and the number of grid connection problems faced, the technical requirements needed and the cost of grid connection (SV 2010, p.i). • Despite the challenges, ‘there is generally a good success rate in connection to the grid’ (SV 2010, p.i).
2 Natural gas 133 MW, waste gas 45 MW, black liquor 55 MW, landfill gas 40 MW, sewage gas 22 MW (ESAA 2011, pp.20–21; CEC 2011a).
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 91 Box 6.1 Senergy report on distributed generation connection experiences Senergy surveyed distributed generator proponents after the connection process was completed. Distribution network service providers (DNSP) were not involved in the survey. The main concerns highlighted by respondents in the interface between the DNSP and the customer included: • access to the appropriate DNSP representatives for connection related issues (e.g. legal and technical staff) • excessive response times from DNSPs for apparently straight forward queries • lack of transparency in, and understanding of, connection processes • fear that accessing dispute resolution services would have a negative impact on a distributed generation project or even the proponent’s distributed generation project portfolio. In addition, even though the regulatory instruments define some aspects of the connection process, respondents said that DNSPs often fail to meet their obligations, including: • inadequate and/or delayed connection enquiry responses • insufficient detail provided on the DNSP’s management of the process or scheduling of connection related activities • lack of commitment to firm delivery dates for connection offers, or to meet such milestones if they are committed to, and a lack of understanding of the importance of such milestones • inadequate data provision (both in detail and timing) required to fully assess the commercial significance of a connection offer, despite the National Electricity Rules requiring this data to be provided • not paying avoided use of system charges as required by the current legislation • issues respondents raised about the negotiation process included: – DNSPs using their information to advantage during the connection process – unwillingness to negotiate terms in the offer and significant delays in responding to requests to reconsider terms, often leading to non-preferred agreement terms being signed due to external commercial pressures. These terms included open ended liability on the distributed generator – not providing access to DNSP legal representatives – insufficient information on cost estimates and work scopes for applicants to assess their fairness or reasonableness. Source: Senergy 2011, pp.3–4.
Medium-scale connection barriers: DNSP view
Connecting medium-scale distributed generation can also involve significant cost for DNSPs in understanding network capacity, reinforcing the network and responding to inquiries. As mentioned in Unlocking the Barriers to Cogeneration, currently the impact of a proposed distributed generation project on the network is unknown until both the DNSP and project proponent commit significant time and resources (ClimateWorks et al. 2011, p.24). Overcoming the technical barriers to connection can involve many millions of dollars of investment in the network (Senergy 2011, p.12) but DNSPs suggested there are no simple solutions to some of these problems (UE, sub. 77, p. 5).
92 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION DNSP participants recognised the potential benefits of distributed generation but raised concerns about the impact on their networks. CitiPower/Powercor ‘support the connection of distributed generation to their distribution systems, including wind farms, provided that these connections promote the National Electricity Objective and the Businesses’ safety obligations’ (sub. 80, attachment 1, p. 5).
While knowledge varies considerably, the distributed generator proponents do not always have a good understanding of the connection process and requirements (Senergy 2011, p.19). In the Commission’s roundtables, the DNSPs indicated that they have a large number of distributed generation inquiries, not all of which have the resources and knowledge to follow through with a connection. Proponents may also be operating under some uncertainty:
It is therefore likely that while negotiating with the DNSP, the project owner is also in negotiations with tenants or other stakeholders on the design of the building itself. They may not, therefore, be in a position to provide the DNSP with the required information for the connection application to proceed as the NER and the DNSPs currently require. (ClimateWorks et al. 2011, p.23)
DNSPs acknowledge better communication with distributed generation proponents may help to improve proponents’ appreciation of connection challenges:
UE understand that customers perceive these legitimate technical issues as a barrier to connection and we will be seeking to improve in this area. (sub. 77, p.5)
There is also a barrier in the economic regulation in that DNSPs face uncertainty about whether they can receive a return on the cost of studies and time spent responding to distributed generator inquiries (AEMC 2012f, p.169).
The Commission’s view
Table 6.1 detailed several processes that are in progress or will be implemented to reduce the barriers to distributed generation connection. The proposed AEMC rule change by ClimateWorks, Seed and PCA could make significant progress in clarifying connection processes and rights (box 6.2). The Commission considers that all of the actions in table 6.1 will reduce connection barriers but some barriers will remain. The key issues and material barriers to medium-scale distributed generation identified by the Commission’s analysis and through submissions (chapter 3) are:
• information and planning on network capacity (chapter 5) • sharing network costs, benefits and risks (chapter 5) • regulatory incentives for efficient connection (chapter 5) • right to connect and export (this chapter) • process, timelines and uncertainty (this chapter).
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 93 Box 6.2 Proposal to amend the National Electricity Rules for connecting embedded generators On 18 April 2012, the AEMC received a rule change request from ClimateWorks Australia, Seed Advisory and the Property Council of Australia. The applicants argued that the National Electricity Rules (NER) deter distributed generators from connecting to the electricity grid, as the connection process is uncertain, complex, burdensome, time consuming, inefficient and costly. The application proposed that the NER be amended to: (1) Provide an automatic right of connection to the grid and standard access terms. This would apply to generators that meet ‘Automatic Access Standards’. (2) Enable embedded generators a right to export electricity to the grid. (3) Provide an improved connection process for embedded generators that are ineligible for automatic access and a right to export electricity to the grid. (4) Allow DNSPs to charge an optional fee-for-service. This is to promote collaboration with proponents during the connection process. (5) Oblige DNSPs to publish annual network reports identifying where capacity is limited. Source: ClimateWorks et al. 2012.
6.4 Right to connect and export
Some proponents of distributed generation argued that there are network access barriers for medium-scale distributed generators caused by ambiguity around standards and no obligation on DNSPs to provide an automatic right to connect and export electricity.
This contrasts with household-scale distributed generation, where systems that meet AS4777 can automatically connect through Guideline 15 and the Electricity Distribution Code (ESC 2012a) and there is an automatic right to export through the FiT regulations (provided FiT eligibility criteria are satisfied). Similarly, for large generators 30 MW or greater, network connection cannot be refused when they meet the automatic standards in Schedule 5.2 of the NER. An automatic connection and a right to negotiate export, subject to transmission network constraints, are granted under chapter 5 of the NER.
The arrangements for medium-scale generators are not as clear. There is no automatic right to connect and in the draft report the Commission concluded DNSPs have discretion to set minimum technical standards. DNSPs have strong incentives to manage impacts on their network and weak incentives to reduce the cost of connection to distributed generators who must pay for costly network studies and network reinforcement. The AEMC concluded this arrangement is a key barrier to connecting distributed generation (AEMC 2009b, p.28). Many inquiry participants supported this view:
As a priority, enabling automatic access for cogeneration systems up to 5MW should be immediately implemented because, relative to the size of their installation, the costs of connection and the current connection process are very high. (ClimateWorks et al. 2011, p. 36)
94 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Once connected to the network, medium-scale generators can face conditions on their connection agreement that prevent the export of electricity. A right to export would allow generators to separately negotiate a price with a retailer or other party, potentially subject to network constraints, as is the case on the transmission network. While improving these connection arrangements for medium-scale generators could present some challenges for DNSPs, the Commission considers that opportunities to improve the connection process while maintaining appropriate safeguards on the network should be explored.
Opportunities for improvement
An automatic right of connection and export based on a specific process and technical standards, as advocated by some participants, is one way to establish an equivalent connection process across all sizes of generation. In response to the draft report, however, the CEC stated that the technical standards have been defined in Electricity Distribution Code (EDC) and that this is not the source of barriers that other participants have claimed (CEC, sub. DR197, p. 18). The Commission assessed the clarity of technical standards for medium-scale distributed generators by looking at relevant State and national regulations.
National minimum technical standards
At the national level, there are no minimum technical standards for non-registered generators3 in the NERs. In theory the standard connection service that will be available to distributed generators when chapter 5A is introduced in Victoria would allow DNSPs to offer a standardised process and automatic connection with specific terms and conditions that could include minimum technical standards. United Energy (UE), however, stated it will not establish standard connection offers given the vast differences between connections:
… there may be a perception that automatic access may be provided via the NECF standard connection offer contracts. UE has considered this approach and has not progressed contracts in this area due to the need to standardise the technical and cost arrangements in these contracts, nor do we believe that there is a high volume requirement in the UE distribution area. (sub. 77, p. 5)
If standard connection services are not established through chapter 5A, at the national level, medium-scale distributed generators would be left to negotiate technical standards with the DNSPs through chapter 5 or chapter 5A of negotiated connection service. The general standards in chapter 5 does not apply to these smaller generators:
Chapter 5 of the NER sets out the technical conditions for the connection of generators. However, these provisions do not apply to generating systems that are subject to, or eligible for, an exemption from registration. In the case where the Chapter 5 technical conditions do not apply, the technical requirements for a connection to the distribution network would be determined by the relevant distributor in accordance with jurisdictional and local network requirements. (AEMC 2012a, p.18)
3 There is a standing exemption from registration for generators under 5 MW, which covers the majority of medium-scale distributed generators.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 95 Victorian minimum technical standards
At the State level, clause 7 of the Electricity Distribution Code (EDC) details the technical standards for medium-scale embedded generators. These include obligations, mainly on the embedded generator, in relation to:
• supply frequency • co-ordination and compliance of embedded generating units • minimum requirements for embedded generating units • negative sequence voltage • harmonics • inductive interference • fault levels (ESC 2012a clauses 7.2 to 7.8).
The Victorian Government intends to retain some Victorian-specific regulation relating to embedded generator connections after the NECF is applied in Victoria (DPI 2011n).
While the CEC considered that the technical standards in the EDC are sufficient, other participants raised concerns. The EDC standards depend on information the DNSPs hold on network condition, DNSPs can set more stringent requirements, the EDC is not the only set of requirements, and there is minimal guidance on how the State requirements should apply.
Limited information can make it difficult to determine whether a project meets the clause 7 requirements of the EDC. The Commission understands that fault levels are a key issue, given they are a strong driver of network reinforcement costs, medium-scale generators can contribute significantly to fault levels, and fault level ‘headroom’ is constrained in the Melbourne CBD where many developers wish to install medium-scale generators. The EDC states that fault levels should not exceed set standards. Some distributed generator proponents claimed that, with limited information available by location on network condition and planning for other customers, it is difficult to determine whether a distributed generator would exceed the fault levels in the EDC. In 2009, the fault levels at some locations were reportedly slightly higher than those expressed in clause 7.8 and action was being taken to address the issue (SKM 2009, p.4). Where fault levels are exceeded distributed generators will cause a breach of clause 7.8. Participants also mentioned the minimum technical requirements of the EDC have not been changed since 2006 and are out of date.
Clause 7 of the EDC is not the only set of requirements which apply to medium-scale distributed generators. Entura, in its survey of distributed generators for SV, concluded it was the complexity and lack of clarity around which standards apply which confuses proponents:
The problem is not that there aren’t specific requirements existing, it stems that there are many documents from different sources and the proponents struggle to identify if a requirement has precedence or which requirement is for their installation. (SV 2010, p.14)
The AEMC noted that jurisdictional arrangements contain minimal guidance for DNSPs and embedded generators, giving DNSPs considerable discretion to set the minimum technical standards (AEMC 2009b, p.45). Distributed generator participants claimed DNSPs ‘gold plate’ network protection by mandating high levels of protection equipment for unlikely safety and reliability events. These participants also claimed the DNSPs show little flexibility to negotiate lower cost solutions to network protection.
96 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION These ambiguities present barriers to medium-scale distributed generators:
[Proponents face] a need to renegotiate all technical requirements for an identical embedded generator by the same proponent, but in a different location. While some technical requirements will likely be location specific, there may be scope for some requirements to be standardised. (NERA 2008, p.37)4
Developing technical standards
In the Demand Side Participation Stage 2 Review, the AEMC recommended reducing the barriers to connecting distributed generators. NERA Economic Consulting’s advice to the AEMC in that review was that ‘the barriers reflected mainly inexperience and a lack of operating procedures and standards to facilitate the connection of distributed generators’ and that there was potential to rebalance the discretion DNSPs have in setting minimum technical standards (NERA 2008, p.37). Accordingly the Demand Management Incentive Scheme was expanded to include embedded generators. The AEMC also recommended the reliability panel examine minimum technical standards for embedded generators.
ClimateWorks, Seed and the PCA recently submitted a rule change request to the AEMC that proposed developing minimum technical standards for medium-scale distributed generation (ClimateWorks et al. 2012). The Commission understands they are also developing a technical brief which outlines the issues that should be examined in developing a technical standard. The rule change request could be the mechanism the AEMC uses to address minimum technical standards but the process for development is not clear:
To provide for greater certainty and timeliness in processing connection applications for embedded generators, the proponents suggest that automatic access standards for embedded generators be developed. The rule change request does not include an actual proposed standard or suggestions of how it may be developed or by whom. (AEMC 2012b, p.18)
The Commission understands a scoping study on developing a technical standards is also underway under the auspices of the COAG Select Committee on Climate Change (SCCC). All jurisdictions (including Victoria) support this work, which will examine international examples of technical standards to identify options to develop standards for connecting distributed generation in Australia.
ClimateWorks, Seed and PCA acknowledge that medium-scale systems have more significant impacts on networks than household-scale inverter connected systems and that developing standards will be challenging (ClimateWorks et al. 2011, p.41). During consultation the PCA suggested that not all applications would proceed through an automatic right of connection with an Australian Standard but that such a standard would assist some applicants.
The CEC does not consider ambiguity around technical standards is a barrier to connection, but even if it is, they are sceptical about whether technical standards would be effective:
4 The CEC (sub. DR197, p. 18) suggested the NERA report is referring to other states but there is evidence of similar problems in Victoria (NECA, sub. DR174, p. 4) (ClimateWorks et al. 2011, p.11).
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 97 … while the CEC agrees that there may be merit in exploring the avenue of developing automatic access standards for distributed generation, the magnitude of the barriers present to the development [of] such an approach creates extreme uncertainty and complexity. In conjunction, the CEC is not certain that such an approach will efficiently remove the barriers to distributed generation which the Commission has identified. (sub. DR197, p. 5)
The CEC instead emphasises the importance of an improved connection process, with upfront recognition of the core issues and a program to resolve them, as discussed in section 6.5.
The SCCC’s scoping study should help to resolve the question of whether it is practical to develop standards, as should the AEMC’s consideration of the rule change request by ClimateWorks, Seed and the PCA.
ClimateWorks suggested the Victorian Government could support development of an Australian Standard for connecting medium-scale distributed generators. In particular the Victorian Government could assist the SCCC’s scoping study by:
• Reviewing the extent to which current Victorian technical requirements differ from those of other (NEM) states and the magnitude of the task of harmonising standards. This could include the requirements of the relevant Act(s) and the Distribution Code, any requirements that Energy Safe Victoria (ESV) imposes on connections and any requirements imposed by the DNSPs, for example, the Service Installation Rules (SIRs), which are DNSP defined but have the effect of a regulatory instrument. • Reviewing the obligations, enforcement and penalties on all parties for safely connecting distributed generators to the network. DNSPs have taken the stance that the obligation for ensuring safety rests predominantly with them, but this is inconsistent with ClimateWorks’ understanding of the regulatory framework more generally. (ClimateWorks 2012)
If minimum technical standards are established a right to connect would require legislative obligations on DNSPs to make a connection offer when the standards and reinforcement costs are met.
Right to export
There is some ambiguity about whether distributed generators have a right to export electricity to the network through an established connection. The EDC places obligations on the DNSPs and distributed generators in relation to connection agreements and export of electricity. Clause 7.1.1 of the EDC appears to provide a right to export for distributed generators: ‘a distributor must ensure that its distribution system is able to receive a supply of electricity from an embedded generating unit... in accordance with an agreement… on the terms and conditions of dispatch, connection and disconnection’. However:
DG [distributed generator] proponents argued that DNSPs are placing onerous restrictions on DG proponents in their connection agreements which can limit their export capability. For example DNSPs may restrict the operation of DG installations by requiring it to run in 'island mode' (that is, not synchronised with the network) and this consequently prevents any energy from being exported. However, DNSPs consider that placing these terms in the connection agreement is their only opportunity to collectively
98 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION identify and mitigate any technical and performance issues associated with DG that could arise in the network. (AEMC 2012f, p.176)
Clause 7.8 of the EDC requires embedded generators to design or operate so as not to cause fault levels in the distribution system to exceed specified levels, which may negate the apparent right to export in clause 7.1.1. The AER states ‘embedded generators have no firm right of access to the shared network and are subject to network constraints for exporting electricity’ (AER 2012d, p.65). Seed submitted to the AER that ‘to argue that clause 7.8 trumps clause 7.1 in governing the connection of embedded generators is based on a construction of the intent of the Distribution Code for which we believe there is no evidence’ (Seed 2012, p.2).
It is unclear whether the barrier to export is in the EDC or the way AER interprets the EDC. The rule change request by ClimateWorks, Seed and the PCA provides an avenue to resolve this uncertainty.
The Commission’s view
The Commission considers that ideally medium-scale distributed generators and DNSPs would have clarity about:
• minimum technical standards • network condition • cost sharing arrangements for network reinforcement (chapter 5) • the process that gives a right to connect and export electricity if minimum standards are met and network reinforcement costs are paid.
In progressing to this ideal, key questions for the Victorian Government include the role of government in supporting development of a standard, the efficiency of establishing such an arrangement, and the maintenance of appropriate safeguards for the network. As highlighted by CitiPower, the impact on all network customers and the cost sharing arrangements for automatic connection require careful and explicit consideration (sub. DR184, p. 6). The Commission considered these issues in chapter 5.
Role of Government
The Commission considers that there is only a role for government if there are broad net benefits to the community or market failures. The beneficiaries of the development of automatic access standards for medium-scale generators are national energy consumers, through increased competition, and mainly the distributed generators. Medium-scale distributed generators should therefore provide the majority of the funding for the development of the standard. One arguable source of market failure is a lack of coordination in competing medium-scale generators working together to develop a standard. If there is a coordination problem any intervention should target coordination rather than funding. Where there are benefits to national electricity users, the Victorian Government could support development of the standards along with other jurisdictions (including the Commonwealth) and the distributed generators.
Efficiency of developing a standard
The Commission considers that if automatic connection based on minimum technical standards is possible for large- and small-scale generators, then such a process could be possible for medium-scale. The question is whether the benefits of developing standards exceed the costs.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 99 If practical, consistent minimum standards would eliminate the confusion and delay caused by the DNSPs having discretion to negotiate standards on a case-by-case basis. Minimum technical standards also provide the developers of distributed generation unites with the information on DNSP requirements they need to improve system integration (Bauknecht & Brunekreeft 2008, p.485). Distributed generator proponents may then make commercial decisions to connect or not connect based on predetermined standards and the cost of meeting those standards. Those who do not meet the standards could choose not to connect or negotiate a tailored connection service.
The SCCC scoping study and the PCA’s technical brief should identify the costs and benefits and timeframes for developing such a technical standard. The AEMC’s consideration of the rule change request by ClimateWorks, Seed and the PCA will also provide useful information. The Commission considers there is merit in exploring the development of technical standards that apply to Victorian DNSPs for standard types of distributed generation projects below 5 MW, and using such standards as the basis of an automatic right to connect.
Safeguards
The highest net benefits would result from an appropriate balance between the discretion afforded to DNSPs in setting minimum technical standards and maintaining their flexibility to address technical issues on constrained local networks. To ensure the safety and reliability of the network, large-scale power stations must do significant preparatory work to meet the minimum standards that guarantee a right to connect. It is appropriate that similar but proportional safeguards are established for connecting medium-scale generators. Net benefits can be maximised by recognising that prudent risk management does not always require ‘gold plated’ network protection, and would rather give flexibility to adopt alternative lower cost network protection solutions. Distributed generators should have a right to export electricity to the network once they have met the standards for network connection and resolved any reasonable fault level issues. This would give the distributed generator the opportunity to negotiate with an aggregator or retailer, or to register and sell through the NEM. Consultation with participants suggested there was some scope to define minimum technical standards for distributed generators that would improve information to proponents on network requirements and network condition, and reduce duplication in considering equivalent plant in different locations.
Conclusion
If the ClimateWorks, Seed and PCA rule change request to the AEMC is successful it could result in common standards and an automatic right to connect. In recommendation 6.1 the Commission proposes that the Victorian Government support this proposed rule change. Victoria could support this work by making a submission on the AEMC rule change and compiling and making available information on its own standards. If the ClimateWorks, Seed and PCA rule change request is unsuccessful, the Victorian Government could support private sector initiatives to develop agreed standards, being mindful of the role of state government and the likely beneficiaries of this work.
100 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 6.5 Process: cost, timelines and uncertainty
The connection process was raised by many participants as a source of uncertainty and delay and therefore a barrier to distributed generation (details of the medium-scale connection process are set out in chapter 2 and figure 6.1).
Participants identified key causes of delay and uncertainty at several stages in the connection process:
• Information on the connection process: distributed generator proponents claim there is a lack of accessible consolidated information on the connection process including information requirements, national and state regulatory instruments and the rights and responsibilities of the various parties: Some jurisdictions have developed guidelines on cogeneration connection, but there is still no NEM-wide regulated process for cogeneration connection. A number of processes are underway that could partially address these issues, like the AEMC’s ‘Comprehensive Technical Standards Review’, but even if these deliver on their potential there will still be major gaps. (EEC, sub. DR200, p. 11) When the NECF is in place in Victoria, some generators would be eligible for connection through either a standard (if offered by the DNSP) or negotiated connection service through chapter 5A, or connection through chapter 5. • No standard process: each DNSP has its own process and medium-scale projects are assessed on a case-by-case basis: NERA commented that distributors appear to take an ad hoc approach to each embedded generator connection. (AEMC 2009b, p.45) This exacerbates the problems caused by uncertainty about minimum technical standards and a lack of information on network condition. • Engagement between proponent and DNSP: in the Commission’s distributed generators roundtable, participants identified poor information exchange as a driver of uncertainty. DNSPs can ask for more information partway through the process, so distributed generator proponents do not know where they stand. In one extreme case ‘the owner received approval of its connection application, only to have it subsequently withdrawn, without explanation for the change of approach’ (ClimateWorks et al. 2011, p.24). DNSPs also have limited capacity to recover the costs of responding to inquiries and the regulatory incentives to engage with distributed generator proponents are not strong (ACIL Tasman 2011b, p.6). Distributed generator participants claimed that these arrangements have discouraged DNSPs from building or retaining skills in this area: Furthermore, the historical focus of [DNSPs] on network augmentation has left them critically under-skilled in understanding both the potential for DSP to reliably reduce peak demand, and the options for using DSP effectively. (EEC, sub. DR200, p. 9) • Connection times: distributed generator participants noted that long delays can reduce the viability of proposals and increase investment costs with: Uncertain and often completely unjustifiable timeframes for negotiating an agreement. In Victoria, the connection approval process is typically more than 6 months with many taking 12 months or longer. (EEC, sub. DR200, p. 11)
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 101 But a 65 working day timeframe, as proposed by ClimateWorks, Seed and PCA may not be realistic. DNSPs claim it can take up to 12 months for a simple connection and up to two years for a more complex one (ClimateWorks et al. 2011, p.23). While legislation requires DNSPs to make a connection offer within 65 working days, 40 per cent of distributed generation systems have had a connection period greater than 12 months (SV 2010, p.i). It is therefore difficult to determine what timeframe would be realistic. Distributed generator roundtable participants mentioned that while it can take longer than four years to get a connection, there are examples of DNSPs providing an answer within two weeks. The ability to assess appropriate timeframes and DNSPs’ performance against those timeframes is exacerbated by a lack of reporting. There is no consolidated public reporting by DNSPs of their performance on timeframes for medium-scale connection offers. Some participants claimed, however, that connection is more difficult in Victoria than in other states: The Council has received informal comments from some members that connecting cogeneration and trigeneration units in Victoria is more challenging than in other states. There could be a number of factors that have driven these Council members’ experiences, including the available capacity to accommodate cogeneration in central Melbourne. (EEC, sub. DR200, p. 2) A key source of delay in the initial inquiry stage is the ability to restart the clock on decision-making timeframes. If the DNSP requests more information on the 19th day of a 20 day decision making period this can restart the timeframes. • Negotiation/arbitration costs and processes: any costs and delays through dispute resolution add to a process in which cost and delay is already posing barriers to connection (Senergy 2011, p. 33). Many participants identified that distributed generator proponents are concerned about the potential adverse ramifications of using dispute resolution systems through the AER (MEFL, sub. 75, pp. 9–10). The DNSP may not like the outcome which could in turn have a negative impact on the project due to adverse ‘retaliation’ from the DNSP. This could impact the project or even the developer’s project portfolio. While difficult to prove there is suspicion amongst the industry that this is a real threat. (CEC, sub. 76, attachment 3, p. 9)
However, one respondent to Entura’s survey for SV escalated issues to the AER and was satisfied with the outcome: … we ended up taking them to the regulator [the AER] and although we never had a hearing, once we got it to that level we had a letter in the post saying we would be connected for free. (SV 2010, p.13)
Opportunities for improvement
The adverse impact of the inefficient connection process on distributed generation is generally acknowledged among participants. Some stakeholders responded to the Commission’s conclusion in the draft report that many of the actions outlined in table 6.1 would help improve connection barriers:
United Energy concurs with the Commission’s conclusion that recently implemented and proposed changes to the national electricity regulatory framework will address the perceived barriers to connection of distributed generation. (UE, sub. DR199, p. 2)
ClimateWorks, the CEC and some other participants, however, claim that even after the introduction of chapter 5A in Victoria and other changes, barriers to connecting
102 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION medium-scale distributed energy will persist (ClimateWorks et al. 2011, p. 11). The CEC stated:
… the CEC is of the firm position that this [5A] amendment to the Rules will not simplify the process at all. Rather, it is expected to only gazette the barriers which the Commission has identified and introduce further complexity. (sub. DR197, p. 9)
The ClimateWorks, Seed Advisory and the PCA submitted a rule change request to the AEMC which aims to streamline the process for distributed generators connecting through chapter 5 (box 6.3).
Box 6.3 Streamlining connection of embedded generators The chart below summarises the proposed new two track connection process incorporating ClimateWorks, Seed and the Property Council of Australia proposed rule changes.
Connection Connection Connection Agreement Enquiry Application Offer
Received within 20 day Submit Connection Enquiry maximum time, as entitled Automatic May invite DNSP to advise Site satisfies automatic to automatic connection on connection issues in access standards in for standard fee, amended Access design phase on a fee-for- amended Ch 5 in Ch 5 service basis Standard connection agreement
Offer required to be made Submit Connection Enquiry no more than 65 days after May invite DNSP to advise Connection Application Negotiated full application on connection issues in proceeds under specified Opt-in boilerplate contract design phase on a fee-for- timeframe in amended Ch 5 Access terms common across service basis DNSPs
The proposed changes aim to replace case-by-case negotiations with a standardised process that is clearer, more certain and efficient. The declared intention of the proposal is to encourage distributed generation without compromising the integrity of the national electricity grid. Source: ClimateWorks et al. 2012.
The CEC argued that many distributed generators will still need to connect through the chapter 5A negotiated connection service even if the changes to chapter 5 proposed by ClimateWorks, Seed and the PCA succeed (CEC, sub. DR197, p. 4). The CEC therefore, is considering submitting a rule change proposal to the AEMC to reduce information asymmetry problem. The proposal would:
… tie all negotiable connection costs to the information provided by the DNSP at the start of the connection negotiation process. This approach limits the cost which the DNSP can charge to that which can be revealed through the information provided. The DNSP then carries the responsibility of ensuring that the information is complete and accurate and that applicants are well informed. (CEC, sub. 197, p. 20)
The two requests for rule changes reflect the views of the proponents of rule changes and other participants that there are opportunities to improve the connection process, even after the introduction of chapter 5A in Victoria. These opportunities would:
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 103 • improve information on connection processes • standardise connection processes • improve engagement and information exchange • reduce connection times • improve dispute resolution.
Improve information on connection processes
The report, Unlocking the Barriers to Cogeneration (UBC) stated that in states other than Victoria ‘it is almost standard for DNSPs to provide online information, an information line and a form outlining the connection process’ (ClimateWorks et al. 2011, p.22). Several bodies have developed connection guidelines to support distributed generator proponents and DNSPs to navigate the complex connection process, including:
• CitiPower/Powercor: Customer Guidelines for Sub-transmission Connected Embedded Generation (CitiPower & Powercor Australia 2010) • Electricity Networks Association: ENA Guideline for the Preparation of Documentation for Connection of Embedded Generation within Distribution Networks (Energy Networks Australia 2011).
The CEC submission said ‘Sustainability Victoria has developed a Victoria specific connection guideline intended to assist connection applicants in understanding the process and the obligations of all relevant parties and to identify risks associated with the process’ (sub. DR197, p. 5). The CEC believed that this guideline is awaiting ministerial approval before its release and suggested expediting the release process.
Standardise connection processes
In some other countries there are standardised connection processes and participants suggested this approach could work in Victoria:
International jurisdictions, such as New Zealand and the United Kingdom, have implemented and benefited from a requirement by networks to publish standard connection contracts, standard connection processes and published connection charges and tariffs. (Exigency, sub. 4, p. 3)
As mentioned, the CEC argued that the majority of distributed generators will connect through the negotiated connection process which limits the potential for standardising processes (sub. DR197, p.4). A survey by Entura for SV, however, found that while some requirements of the application process vary some could be consistent across different sites:
… the costs for filling out the documentation for the DNSP and conducting the load flow studies could be standard, however equipment costs and augmentation required is site specific and as such the costs associated with these will remain variable. (SV 2010, p.9)
The rule change request by ClimateWorks, Seed and the PCA and many submissions to this inquiry proposed a national, standardised connection process and practical district level licensing frameworks. In addition to the calls in this inquiry, the AEMC in its Power of Choice review received a number of submissions calling for a standardised connection process (AEMC 2012f, p.166).
104 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Improve engagement and information exchange
ClimateWorks, Seed and the PCA suggested ‘DNSPs do not have a strong incentive to collaborate in the development and improvement of a connection enquiry or application’ (ClimateWorks et al. 2012, p.17). Entura, in its survey for SV, highlighted the importance of early engagement:
… early engagement/communication with the DNSP at the detailed design stage, rather than later in the design process, may better facilitate a successful connection of the DG system to the grid. (SV 2010, p.16)
A lack of resources for DNSPs to engage with distributed generators during the preliminary inquiry stage ‘could be easily resolved, as UBC project owners have indicated they would be prepared to pay on a fee for service basis to ensure this engagement process occurred’ (ClimateWorks et al. 2011, p.23). The rule change request by ClimateWorks, Seed and PCA includes such a proposal (ClimateWorks et al. 2012).
In addition, the interplay between minimum technical standards (section 6.4), information on network condition and early communication between DNSPs and distributed generators can have important impacts on project outcomes:
By having set standards for those wishing to install DG projects, project managers will be able to factor in all possible barriers at the pre-feasibility stage. This can assist in ensuring they do not reach a point in the project where they are unable to change things or in a position where they suddenly find themselves being informed of a new set of standards from the DNSP that weren’t originally accounted for, thus putting the project on hold. (SV 2010, p.14)
The CEC similarly argued that earlier and more complete communication about technical standards, information requirements and network condition would allow distributed generators to assess the viability of their proposal earlier, reducing costs of redesign, additional network studies and progressing unviable projects (CEC, sub. DR197, p. 14). The CEC argued, however, that it would be difficult to achieve these savings by setting predetermined standards. Instead the CEC suggested DNSPs should be obliged to provide the necessary technical information requirements to applicants in the early stages of a connection application.
Reduce connection times
Distributed generator proponents participating in the inquiry suggested the connection timeframes should be substantially shortened.
The case study proponents consider that a timeframe of between one and three months for completing the connection application process would be consistent with the wider commercial building development process, with an outer limit of six months in extreme cases. (ClimateWorks et al. 2011, p.23)
The CEC also claims that earlier provision of technical and information requirements and network condition would save time as well as cost (sub. DR197, p. 14).
The PCA rule change request outlines a 20 day connection decision for standard connections and a 65 day connection decisions for non-standard connection (ClimateWorks et al. 2012, p.11).
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 105 Improve dispute resolution
Several participants argued for improved dispute resolution processes. During consultation the AER indicated its processes encourage alternative dispute resolution prior to arbitration which offers an avenue to minimise the costs of disputes. The AER’s processes allow for preliminary consideration prior to formal consideration of disputes, although legislation allows for formal considerations to take six months or more (AER 2011b, p.6). The Moreland Energy Foundation Ltd (MEFL) recommended that the government should ‘establish a connection ombudsman or other dispute resolution process to resolve disputes arising out of connection processes’ (MEFL, sub. 75 attachment 1, p. 2). The Energy Efficiency Council recommended establishing a distributed generation ombudsman in the AER (EEC, sub. DR200).
The ClimateWorks, Seed and PCA rule change request submitted to the AEMC aims to address many of the connection process barriers raised in this inquiry. The rule change request does not, however, address dispute resolution processes (box 6.2).
The Commission’s view
Efficient and clear processes can reduce time and uncertainty and thereby support the efficient entry of distributed generation, resulting in effective competition in related markets. The outcomes of efficient connection processes include early withdrawal of unsound proposals and improvements to sound proposals (such as redesign to reduce, mitigate or avoid costly network reinforcement). An efficient process would also enable a progressively sharper focus on the key issues and data collection.
As illustrated in figure 6.2, an efficient process would identify critical issues at the start of the process and progressively reduce their uncertainty. Distributed generator proponents normally prefer to delay outlays on the project until such uncertainty is reduced, to avoid the risk of wasting money if, for example, the assessment indicates the project needs redesigning or cannot proceed. DNSPs would also benefit as relevant information would be provided more quickly on higher quality more viable proposals. Accurate, timely information on network condition, as outlined in chapter 5, is critical to support investment decisions by distributed generator proponents, and the connection process.
106 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Figure 6.2 Framing the connection process from a business perspective Current process under Chapter 5A
Unlimited Unlimited Clock stop/reset with information x 5 days x 10 days request/network study
DNSP advises Agree Information Preliminary standard or Application request/site Negotiation Offer inquiry negotd process, visit expected costs Dispute resolution
Possible improvement to the process
One timeframe with no resets, clock stop permitted
DNSP advises Agree Preliminary Information standard or inquiry w/better Application request/ Negotiation Offer negotd process, engagement site visit expected costs Dispute resolution
Notes: Negotiated (negotd); preliminary inquiry (Prelim. Inq); expected cost (exp. Cost). Source: Commission analysis.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 107 The Commission considers the following actions would improve the connection process for medium-scale distributed generators and reduce uncertainty, timeframes and costs to business: • Improve information on the connection process: information on minimum technical standards (section 6.4), network condition, cost sharing (chapter 5) and the process and information required from distributed generator proponents would help to streamline connection and reduce uncertainty. In addition to supporting improved information made available through the ClimateWorks, Seed and PCA rule change request to the AEMC, the Victorian Government should release Sustainability Victoria’s connection guidelines for distributed generators. • Standardise connection processes: as medium-scale distributed generators are treated on a case-by-case basis, the costs of connection could be reduced significantly by standardising connection processes. • Improve engagement with customers: DNSPs have limited incentive to engage with distributed generator proponents to help improve their applications and identify information needs during the preliminary inquiry stage and negotiation. Earlier and more thorough communication about technical standards, information requirements and network condition would allow proponents to make earlier decisions about their projects. This could reduce connection costs by hundreds of thousands of dollars through reduced network studies, project redesign and progress of unviable projects. There is a case for examining the incentives and accountability for DNSPs to provide this information in a timely manner. As noted in the draft report, 100 per cent pass through of costs creates disincentives for DNSPs and there are alternative incentive options (DR pp. 74-75). • Clarify timeframes: establishing negotiated, project-specific time limits for each stage of the connection process, and reporting performance against these time limits. There is already a requirement for DNSPs to make a connection offer within 65 working days but with 40 per cent of projects taking greater than 12 months (SV 2010, p.i) this suggests the current arrangements could be significantly improved. The Commission considers there is a role for increased monitoring and reporting of DNSPs performance on connecting medium-scale embedded generators. Also establishing processes that allow the ‘clock to stop’ while the distributed generator proponent responds to information requests, but not to be reset, would encourage DNSPs to identify and communicate information requirements early so DNSPs retain sufficient time to subsequently reach a decision. Shortening the timeframes would improve integration at an operational level, by allowing the distributed generator connection to progress at the same rate as a broader commercial building approval process. Timeframes, however, need to allow DNSPs to perform the tasks required of them and if longer than 65 working days is required, this should be recognised in the process so developers have clarity for their decision making.
The Commission considers that the evidence of a problem in conflict resolution arrangements is not convincing. Responsibility for these arrangements is moving from the ESC to the AER whose arbitration processes for distributed generation are largely untested. Resorting to regulated arbitration should be a last resort as using commercial mediation in advance of arbitration would reduce the costs of dispute resolution and would help remove barriers to distributed generation. The CEC supported this position (sub. DR197, p. 24). With the movement to national regulation of the energy market, national mechanisms are the preferred avenue for addressing medium-scale connection barriers. The Commission considers that the Proposal to amend the NERs for connecting embedded generators by ClimateWorks, Seed and the PCA has the potential to address many of the opportunities for improvement, including information on processes, standardised
108 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION processes and specific timeframes (ClimateWorks et al. 2012, pp.7, 15 & 26). As noted this proposed amendment also has the potential to establish an automatic right to connect and export for distributed generation projects that conform to specified standards (section 6.4). The Commission considers the best course is that the Victorian Government supports those aspects of the rule change request that address the problems identified in this report. If the rule change is not implemented by June 2013, the Commission suggests the Victorian Government expedites options to reduce barriers to distributed generation using Victorian regulatory instruments that sunset once equivalent national regulatory instruments are introduced. Options that align with chapter 5A would be consistent with Victoria’s commitment to work with other jurisdiction to harmonise arrangements prior to the introduction of chapter 5A and should relieve participant concerns about national consistency (UE, sub. DR199, p.4). The Victorian Government might consider: • If the NECF has been introduced, using Victorian regulatory instruments (for example, distribution licences) to require DNSPs in Victoria to establish efficient connection arrangements by incorporating them into standard connection offers that are submitted to and approved by the AER. • If the NECF has not been introduced, adding the wording from the relevant clauses of chapter 5A to the EDC, to establish standard and negotiated connection services. The Victorian Government could pass legislative amendments to the Electricity Industry Act 2000 (Vic) to require these to be assessed and approved by the AER. The rule change proposal by ClimateWorks, Seed and the PCA came forward during the course of this inquiry. The CEC’s submission signalled it intends to submit a rule change and others may come forward in the future. The Victorian Government should support these initiatives on their merits where they provide net benefits to the Victorian community.
Recommendation 6.1 That, to facilitate efficient connection of medium-scale distributed generators up to 5 MW, the Victorian Government support initiatives that: • clarify minimum technical standards and cost sharing arrangements that would support a right to connect and export • improve information on the connection process, including publishing Sustainability Victoria’s guide to distributed generation connection in Victoria • improve exchange of information and engagement between the distribution network service provider and distributed generator early in the connection process • standardise and simplify connection processes and incorporate more reliable timeframes. In the first instance, the Victorian Government, through the Department of Primary Industries (DPI), indicate to the AEMC its support for those aspects of the ClimateWorks, Seed and PCA Proposal to amend the National Electricity Rules for connecting embedded generators that progress the above objectives. DPI should make the AEMC aware of this view during the AEMC’s consultation process on the rule change proposal. Should these issues not be resolved through the national rule change process by June 2013, the Government, subject to a positive cost benefit assessment, use Victorian regulatory instruments such as adding a licence condition requiring distribution network service providers in Victoria to establish such standards and rights.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 109 6.6 Cost savings from improved medium-scale connection process
The connection process for medium-scale generators is lengthy, complex and uncertain and can have a major (but unverified) impact on the financial viability of projects.
A Property Council of Australia survey of its Victorian members in 2010 indicated that there were 23 co/trigeneration proposals being considered for implementation in the CBD, Docklands and city fringe areas. Nineteen of the projects identified were expected to proceed in the relatively short term. A saving of one week for each of these projects is a reduction of over $1 million in holding costs alone5. (ClimateWorks et al. 2012, p.19)
There would also be savings in rework and design:
One of the UBC Project members quoted a cost of $200,000 in engineering design work to rework the design package in response to changes required by the DNSP. (ClimateWorks et al. 2012, p.19)
There is significant potential for cost-effective distributed energy in Victoria. The Institute for Sustainable Futures (ISF) claimed that strategically planned and implemented decentralised energy projects could reduce electricity sector emissions by 6.2 per cent and save consumers around $437 million per annum by 2020 (ISF 2012). The current share between household-scale and medium-scale distributed generation suggests much of this growth would be in medium-scale plant.
In the Commission’s view, while it is difficult to be precise the adverse impact of connection barriers to medium-scale distributed generation are likely to be material. While improvement to the connection process would be helpful, it is the efficiency of incentives for DNSPs to invest in their networks and the cost sharing arrangements (chapter 5) that are likely to make the most significant difference to removing barriers to distributed generation.
5 The PCA assumes holding costs of $50,000 to $70,000 per week for commercial property projects. Nineteen projects x $50,000 = $1,140,000.
110 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 7 Facilitating connection of household-scale distributed generation
Connecting household-scale distributed generation to the distribution network can benefit electricity consumers by allowing customers to generate their own energy, reducing the amount of energy they buy and their retail electricity bills, and allowing them to export electricity to the network. Unlike medium-scale distributed generation, household-scale distributed generation units usually have minimal impact on the distribution network, unless many household-scale generators are concentrated in a region.
From JEN’s perspective, there are no barriers to connecting micro DG [distributed generation] units to the grid. (JEN, sub. 79, p. 7) Small systems are also not likely to require any upgrade or changes to the distribution network, meaning the requirements for the network company to dedicate resources should be minimal. (CFCL, sub. 41, p. 9)
The inquiry terms of reference ask the Commission to identify State and/or local regulatory and other barriers to the development of distributed renewable and low-emissions generation in Victoria. Through research and consultation, the Commission has concluded that the barriers to connecting distributed generation to the distribution network in Victoria vary according to generator size. This chapter concentrates on the barriers to efficient connection of household-scale distributed generation which, due to Victoria’s current feed-in tariff (FiT) arrangements, are predominantly solar PV systems of 5 kW or less capacity. Medium-scale connection is addressed in chapter 6.
The Commission considers that the FiT application and connection process for household-scale solar PV is best conceptualised as three separate, but interrelated, processes that occur side by side. These processes are described in more detail in appendix B.
(1) Physical installation, connection and metering — installing and connecting a household-scale distributed generator into the distribution network is currently governed by a small embedded generator connection process under State-based regulation.1 Installation of household-scale distributed generation is also governed by safety regulation administered by Energy Safe Victoria (ESV) and national metering requirements under chapter 7 of the National Electricity Rules (NER). When the National Energy Customer Framework (NECF) is applied in Victoria, household-scale distributed generators will be able to connect under a basic connection service for micro-embedded generators in a new chapter 5A of the NER. (2) Contracting with the retailer — while arguably an aspect of selling electricity (chapter 8), the connection process is interconnected with the FiT application process. The FiT contract will not come into effect until the customer has appropriate bi-directional metering installed and is connected to the electricity distribution grid. (3) Applying for small-scale technology certificates (STCs) — to be eligible for STCs, the installer must be a licensed electrician with Clean Energy Council (CEC)
1 This includes: distribution licence conditions, the Electricity Distribution Code (ESC 2012a); Electricity Industry Guideline No. 14: Provision of Services by Electricity Distributors (ESC 2004b); and Electricity Industry Guideline No. 15: Connection of Embedded Generation (ESC 2004a).
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 111 accreditation and the homeowner must sign the Commonwealth Solar PV STC Assignment and Written Compliance Statement (Clean Energy Regulator 2012b; ESV 2010, pp.7–8).
This chapter outlines the regulatory and other barriers to the connection of household-scale distributed generation, drawing on submissions received and stakeholder consultations (including several post-draft report roundtables attended by industry). This chapter then discusses opportunities to streamline the household-scale connection process, and the Commission’s view and recommendation for improved household-scale connection. The chapter concludes with an estimate of the administrative cost savings resulting from the improved household-scale connection process.
7.1 Barriers to household-scale connection raised by stakeholders
The Commission received many submissions from household-scale distributed generation customers who have experienced difficulties and delays as a result of ‘red tape’ and other barriers to connection (Elizabeth Walsh, sub. DR96, p.1; Robin Friday, sub. DR103, p.1; Pam and Peter Hannan, sub. DR132, p.1; and others). Submissions from local government and industry also supported simplifying connection (AGL, sub. DR193, p. 2) and ‘the seemingly excessive hurdles to grid connection’ (Whitehorse City Council, sub. DR169, p. 3).
The number of submissions from solar PV customers detailing the difficulties they had connecting and accessing a FiT is also reflected in solar complaints received by the Energy and Water Ombudsman Victoria (EWOV). Solar case data provided to the Commission from EWOV for January 2011 to May 2012 indicated that there was a spike in the number of solar referrals and investigations in the lead up to the closure of the premium feed-in tariff (PFiT) scheme2 — in September, October and November 2011 — but that the number of solar complaints significantly reduced in 2012. Despite this fall there continues to be a significant number of complaints. From January to May 2012, EWOV received 3642 solar complaints, an average of 728 complaints per month (figure 7.1).
2 The PFiT scheme closed to new applicants on 29 December 2011. On 1 September 2011, the Victorian Government announced that the PFiT scheme would soon reach its capacity cap, expected to occur in late November 2011. PFiT applicants were advised to submit their paperwork (the Solar Connection Form, Electrical Work Request and Certificate of Electrical Safety) by 30 September 2011 to meet the PFiT closure deadline (DPI 2011f; DPI 2011e).
112 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Figure 7.1 Solar PV complaints EWOV received: January 2011 to May 2012
Notes: EWOV changed its case handling procedures in November 2011. As such, the majority of solar cases were lodged as referrals unless they were complex or the provider requested an investigation. Source: EWOV 2012.
EWOV also provided data on the top 30 solar issues by month it registered from January 2011 to May 2012. The top 10 solar issues are summarised in table 7.1. In 2012, the most common solar issues registered by EWOV were:
• PFiT not being credited to customers’ retail bills (1395 issues received) • poor customer service (612 issues received) • billing delays (539 issues received) • existing supply connection upgrade delays (358 issues received) • failing to respond to customer enquiries (354 issues received) • other billing errors (331 issues received).
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 113 Table 7.1 Top 10 solar issues by month registered by EWOV: January 2011 to May 2012
January 2011 to January 2012 to Solar issues Total December 2011 May 2012 Billing- tariff- PFiT- not applied 2 597 1 395 3 992 Customer service- poor 1 685 612 2 297 service Customer service- failure to 1 627 354 1 981 respond Billing- delay 1 140 539 1 679 Provision- existing connection- 967 358 1 325 supply upgrade- delay Provision- existing connection- 1 037 150 1 187 meter exchange Customer service- failure to 969 131 1 100 consult/inform Billing- error- other 709 331 1 040 Customer service- incorrect 595 248 843 advice/information Billing- high- general 544 190 734 Total 11 870 4 308 16 178
Notes: Solar issues registered in 2011 would be in relation to the PFiT and SFiT. The PFiT closed to new applicants on 29 December 2011. Solar cases registered in 2012 would be in relation to existing PFiT customers, and the TFiT and SFiT schemes. The TFiT scheme commenced on 1 January 2012. Source: EWOV 2012.
7.1.1 Specific connection barriers
Stakeholders also identified specific barriers to connection:
• Incorrect or confusing information: about the solar process, or about the billing of FiTs, had been provided to customers by their electricity retailer, distribution network service provider (DNSP) or solar installer (EWOV, sub. 48, p. 2; NECA, sub. 37, p.5; Whitehorse City Council, sub. DR169, p. 3). EWOV noted that in 2011-12, 24 per cent of solar cases involved complaints about quality of service and information provided by retailers (sub. DR163, p. 3). Household-scale roundtable participants also noted issues with misleading information about solar PV being marketed to customers. Installers raised concerns that solar retailers may recommend particular systems to PV customers without a site inspection and/or technical assessment. This may mean a customer purchases a system and only finds out it is unsuitable when it is installed, causing unnecessary cost and, in some instances, delay. Stakeholders at the Commission’s household-scale connection roundtable also raised concerns that, in practice, a number of steps in the connection process may be skipped or occur out of order. This, perhaps, reflects customer confusion about what the connection process involves. For example, there were concerns that distributed generation customers only enquire into the available retail tariffs after purchasing and installing their PV system. Similarly, a number of DNSPs stated that
114 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION the ‘approval to connect’ step is often skipped and that the first time they are informed that a PV system has been installed is on receiving the Electrical Work Request (EWR) and Certificate of Electrical Safety (CES). • Complicated processes: there is a relatively high administrative burden, many parties are involved and roles and responsibilities are not clear (box 7.1). Various submissions from solar PV customers related the difficulties they personally experienced in connecting and accessing a FiT. For example, Kathryn Miller and Matthew Thomas related: … connection process for distributed generators is more complex than necessary… involves too many players and too much paperwork. Our connection process was stressful, time consuming and inefficient. It involved five entities: the installer of our PV cells; an inspector to certify the installation; Jemena; the installer of a new meter; and our retailer, Origin. It took about two months from entering the contract with the provider of the PV system to finalising the agreement with Origin. We expect that it would have taken a lot longer, had we not gone to the effort of chasing up each and every entity involved. (sub. DR190, p. 9) Roundtable participants noted it is the distributed generation customer or installer representing them that bears the cost of unclear accountabilities. The customer is reliant on each step in the connection process being complete but has no means of ensuring that each party performs its role competently and efficiently. One solar PV customer said that the current process: … [left] consumers at the whim of electrical suppliers, retailers, and the government in regard to a feed-in tariff, and at a total loss as to how to overcome this impasse… [left] consumers in the position of spending significant funds, without being able to calculate the financial or other benefit to them, until after the fact. (Lois Knight, sub. DR119, p. 1) • Lack of visibility in the connection process: various stakeholders at the household-scale connection roundtable argued that lack of visibility compounds process problems. Multiple parties, lack of follow-up and confirmation that each stage in the connection process has been completed, mean customers are unaware of — and are unable to find out — whether their application is progressing or has stalled, contributing to significant delays (EWOV, sub. DR163, pp. 3-4). This can also result in loss of customer confidence in the connection process, and more frequent customer complaints to retailers and/or EWOV. • Planning barriers: those who live in heritage areas are required to seek local government approval to install solar PV. ‘It is absurd that for such a small investment that all three level of government should be involved’ (NECA, sub. 37, p. 5). It is not clear, however, whether such problems are isolated or widespread. • CEC accreditation: some participants consider CEC accreditation a costly and unnecessary step in the solar PV connection process. Similar concerns were raised by Renewable Energy Solutions Australia in the context of silent wind turbines (RESA, sub. 78, p.2). The National Electrical and Communications Association (NECA) argued: Licensed electricians in Victoria are already qualified to install solar PV but the federal government has created another level of bureaucracy by insisting electricians obtain CEC accreditation to be able to install solar PV systems and claim solar credits for their customers. The CEC are a barrier because the accreditation fees far outstrip those that licensed electricians pay Energy Safe Victoria (ESV). Not only are the fees a barrier but the process of obtaining accreditation is complicated and protracted. (NECA, sub. 37, p. 5)
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 115 The Commission noted participants’ views that CEC accreditation may be a barrier to household-scale connection in its draft report. In response to the draft report, the CEC noted that CEC accreditation ‘is not as onerous as many other accreditation systems’ and provides ‘a wide range of other benefits to the solar industry including maintaining and improving standards, coordinating industry and protecting consumer safety’ (sub. DR197, p. 29). • DNSP monopoly on metering installation: Ceramic Fuel Cells Limited (CFCL) identified the Victorian requirement that only DNSPs can install or re-program meters, as a specific barrier to the connection of distributed generators to the distribution grid (sub. 41, p. 17). Metering installation is a contestable service in other Australian jurisdictions under the national framework (NER, chapter 7). It allows a registered market generator or the retailer to be responsible for types 1 to 4 metering installations (AEMO 2009, pp.1–2). However, the AMI (advanced metering infrastructure) jurisdictional derogation mandates that Victorian DNSPs are the ‘responsible person’ for metering installations, eliminating contestability (NER, cl 9.9B.3).3 The Mildura Development Corporation commented that: Smart meter installation contestability should also be encouraged as long as the NEM [National Electricity Marker] has an appropriate standard or a list of approved products (such as CEC has for solar PV) and the customer installs the smart meter in the approved manner. (sub. DR177, p.3) NECA was ‘fully supportive of a process that will enable contestability of meter installation’ and suggested adopting a system similar to that in New South Wales and Western Australia may be appropriate (sub. DR174, p.5). • Broader problems with the electrical connection process: NECA argued that problems with household-scale connection raised in the Commission’s draft report reflect broader systemic problems with the electrical connection process (sub. DR174, p. 4). NECA’s submission referenced two surveys of Victorian registered electrical contractors conducted in 2007 and 2010 on the performance of Victorian DNSPs and electricity retailers. NECA noted that the survey results ‘reveal a complex, confusing and inefficient system’ and recommended: – limiting the role of the retailer to ‘ensuring the necessary energy contract between the retailer and customer is in place’ – establishing a system in which electrical contractors can organise new connections (on behalf of the customer) by dealing directly with the DNSP – expanding the role of electrical contractors to include responsibility for distributed generator installation, connection to the distribution system, and metering upgrade (sub. DR 174, pp. 4-5).
3 See National Electricity Amendment (Victorian Jurisdictional Derogation, Advanced Metering Infrastructure Roll Out) Rule 2009 No. 2 (AEMC 2009a).
116 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Box 7.1 Complicated connection process There is consensus across stakeholder groups that the connection process is complex: Retailers Customers are required to sign a feed-in tariff contract with their retailer before the metering can be configured for solar and again each time the customer changes retailers or moves into a property with solar. This process often delays the process for a customer to have the feed-in tariff applied. In other states the feed-in tariff payments are regulated through legislation and the electricity retail contract, with scheme payments applied as a pass through of distribution tariffs, plus any retailer premium payments. (AGL, sub. 72, p. 4) Installers The installation of small-scale PV is an involved process which can include a solar company, electrical retailer, electrical distribution company, solar design and installer and solar inspector. This does not take into account government departments and agencies, the Clean Energy Council (CEC) and green certificate traders. With so many participants a customer can be forgiven for being confused about who is responsible for what in the whole installation process. (NECA, sub. 37, p. 5) Customer representatives: Delays in the application of FiTs sometimes occurred because customers did not know that several forms needed to be completed. Delays and errors were frequent, with some customers missing out on PFiT because the electricity retailer or DNSP: • lost paperwork – which caused delays in the completion of the solar process • delayed raising service orders or raised incorrect service orders • delayed completing service orders to upgrade or re-configure the meter • provided incorrect or untimely advice about eligibility, timeframes and requirements. (EWOV, sub. 48, p. 2) Source: Various submissions.
7.2 Timeliness of household-scale connection
The current connection process for household-scale distributed generation is shaped by a combination of national and State regulation, industry interpretation of regulatory requirements, and business practice. Through desktop research and post-draft report consultation, the Commission has identified the various regulations — if any — that govern each stage of household-scale connection and whether there are timeframes prescribed for various steps and sub-steps.
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 117 7.2.1 Connection process timeframes mandated by regulation
Installation, connection and metering
There are regulatory timeframes built into the connection process for the DNSP and installer up to the EWR and CES being submitted to the retailer, and after the DNSP receives the Service Paperwork and Service Order Request from the retailer. It is a licence condition that installers comply with CES requirements. Penalty units apply4 and non-compliance can result in licence suspension or cancellation, or criminal prosecution (DPI 2011c). Similarly, DNSPs are obliged to comply with connection timeframes specified in their distribution licence, and Essential Services Commission (ESC) Codes and Guidelines.5 The ESC can suspend or revoke a distribution licence for non-compliance with licence conditions.
• It is a distribution licence requirement that DNSPs offer connection services within 65 business days of customer request or when the DNSP receives all the information ‘reasonably require[d] to make the offer, whichever is the later’ (cl 7.1 and 11.1). • Although DNSPs and household-scale distributed generators may enter into a standard connection agreement in accordance with Electricity Industry Guideline No. 15 — Connection of Embedded Generation (ESC 2004a), the ESC has determined that a specific connection agreement is not required for small embedded generator6 connections. The ESC considers that there are adequate protections in the Electricity Distribution Code (ESC 2012a) which ‘the parties may rely on… provided the small embedded generators are informed of their rights and obligations’ (ESC 2007, p.12). • Clause 3.2 of the Electricity Industry Guideline 15: Connection of Embedded Generation requires DNSPS to have a ‘fair and reasonable’ standard connection agreement for ‘small embedded generators’ that the AER has approved. If requested by a customer or retailer, DNSPS must make a small embedded generator standard connection offer within 65 business days ‘adapted only to reflect the particular circumstances of the small embedded generator’ (cl 3.2.5). The Commission understands that ‘the AER does not intend to seek DNSPs to submit their terms and conditions for small embedded generators under Guideline 15 for approval unless there is evidence that the current arrangement is not working’ (AER 2010b).7
The Commission notes that it is standard industry practice for household-scale distributed generation applications to be automatically approved on request. For household-scale, the approval to connect step is generally a formality and the lengthy information and technical assessment requirements that apply to larger distributed
4 See Electrical Safety Act 1998 (Vic) ss 44, 45 and 45A; Electrical Safety (Installations) Regulations 2009 (Vic) regs 238, 239, 243 and 253. 5 The Electricity Customer Metering Code (ESC 2011a) supplements metering regulation under the NER and national Metrology Procedure. Under cl 6.1(d), on written customer request the DNSP must use its ‘reasonable endeavours’ to install metering within 20 business days. Similarly, the national B2B Procedure: Service Order Process (AEMO 2011a) states that once the DNSP has received the Service Order Request and Service Paperwork, it must use ‘reasonable endeavours’ to complete meter reconfiguration within 20 business days (AEMO 2011a, pp.55–56).
6 ‘Small embedded generators’ are defined as embedded generators of 2 kW or less and/or embedded generators that meet Australian Standard AS4777. 7 See box B.2 for a detailed explanation of the AER’s approach to approving small embedded generator standard connection agreements under the Electricity Industry Guideline 15: Connection of Embedded Generation (ESC 2004a).
118 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION generators do not occur in practice. Based on the information available on Victorian DNSP websites, the approval process for household-scale distributed generation varies between Victorian DNSPs (see table B.2 in appendix B).
Contracting with a retailer
The FiT provisions of the Electricity Industry Act 2000 (Vic) (EI Act) require that distributed generation customers selling exported electricity through a FiT retail contract, must contract with their retailer. Retail industry practice requires FiT customers to have two separate contracts with their electricity retailer: a supply contract and a FiT contract. The Energy Retailers Association of Australia (ERAA) argued that requiring customers to sign a separate FiT contact ‘adds complexity and cost to the process for both retailers and customers’ (sub. DR180, p. 1). Similarly, AGL submitted that requiring customer to sign a separate FiT contract ‘often delay[s] the process for a customer to have the feed-in tariff applied’ and that, going forward, customers should not be required to sign a separate contract (sub. DR193, p. 3). The FiT contract only comes into effect, and the customer starts receiving FiT credits, when:
• the retailer has received the signed FiT contract • the technical/physical preconditions for participation in the FiT scheme have been met — that is the solar PV system is installed and connected to the distribution grid and, the meter is upgraded and/or reconfigured for solar.
A high-level summary of the connection process — including the identification of key process blockages — for household-scale solar PV is set out in figure 7.2. Any applicable timeframes prescribed by regulation are also included in figure 7.2.
The detail of the connection process varies slightly across individual retailers and DNSPs, and depends on the type of distributed generation involved. There are many detailed sub-steps that occur during the connection process, which are not reflected in figure 7.2. These relate to Victorian electrical safety regulation, AMI installation requirements, and the Use of System Agreements and Business-to-Business (B2B) Procedures that govern the relationship and communications between the retailer and DNSP.8 Use of System Agreements between individual DNSPs and retailers include agreed procedures and process timeframes relating to the connection of household-scale distributed generators.
8 B2B Communications between Victorian retailers and DNSPs are governed by State-based Use of System Agreements and national B2B Procedures (AEMO 2011b) developed by the Information Exchange Committee established by AEMO (NER cl 7.2A).
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 119 Figure 7.2 Connection process for household-scale solar PV (5 kw or less) in Victoria
Source: Commission analysis drawing on CEC 2012c and stakeholder feedback.
120 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 7.2.2 Stakeholder feedback on the timeliness of connection
The Commission notes there is little or no performance data published on the length of time taken for household-scale connection. This is an important gap that obliges the Commission to rely on more partial and anecdotal information than is desirable. The Commission has been advised by the Department of Primary Industries (DPI) that in practice its takes on average three months for household-scale solar PV connections to be processed but where there are high volumes of connection applications, the processing time is likely to stretch to four months on average (DPI 2012e).
However, the Commission has received feedback from industry and solar PV customers that the processing timeframes can be significantly longer than three to four months, and that there can be significant variation in timeframes, with some solar PV customers experiencing significant delays. Installers at the Commission’s roundtable consultations noted that there are many instances where solar PV customers experience connection processing timeframes of up to six to 12 months and that a three month average may be a conservative estimate.
The pilot connection process for another form of distributed generation technology, fuel cells, appears to have been significantly more efficient. CFCL reported an average processing time of 40 days, based on their experience installing BlueGen units across approximately 20 sites in Victoria (sub. DR135, p. 3).9 The Commission notes that there are differences between the connection process for BlueGen units and solar PV, with the key differences being that there is no regulated FiT nor small-scale technology certificates (STCs) available for fuel cells, and the priority apparently given to the BlueGen unit pilot by the parties involved. However, the connection process for BlueGen units is broadly similar — involving the same four parties, submission of paperwork (including a CES) and a retailer/network service provider interface. 10
While there are regulatory timeframes mandated for provision of electrical safety paperwork at the installation stage, and obligations on the DNSP at the approval to connect and metering installation stages, there are no timeframes prescribed for the majority of steps. Discussions with installers, retailers and DNSPs indicated that the key process bottleneck is in the Business-to-Business (B2B) communication, where the Service Paperwork (EWR and CES) and Service Order Request for appropriate metering are forwarded from the retailer to the DNSP. This is reflected in a number of submissions from solar PV customers who have complained about the processing delays and service provided by their retailers (for example: Ann Scally, sub. DR131, p.1).
Stakeholder feedback has been that, in the majority of cases, the connection process operates fairly smoothly up the B2B interface. Similarly, the majority of stakeholders indicated that once the Service Order Request has been received and accepted by the DNSP, the metering upgrade usually progresses without any significant problems. Although, some stakeholders had a different view. For example, during the Commission’s consultation in Castlemaine the Mount Alexander Sustainability Group raised concerns about delays at the DNSP end of the B2B interface.
Data provided by EWOV on the number of solar meter exchange issues registered each month demonstrates that metering complaints were most acute during the lead up to the PFiT closure on 29 December 2011. The number of meter exchange issues registered peaked at 221 in September 2011, then tapered off from January to May
9 Caution should be taken in extrapolating the BlueGen unit connection processing data, given the very small sample size. 10 The connection process for BlueGen units in Victoria is outlined in CFCL, sub. 41, p. 17.
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 121 2012 (table 7.2). In addition, EWOV only registered 150 issues of metering exchange for solar from January to May 2012 — an average of 30 a month. This is compared with 1037 meter exchange issues registered in 2011, an average of 86 a month (table 7.1).
Table 7.2 Number of solar meter exchange issues by month registered by EWOV: May 2011 to May 2012
May June July Aug Sept Oct Nov Dec Jan Feb Mar Apr May 11 11 11 11 11 11 11 11 12 12 12 12 12 71 79 99 158 221 83 87 53 47 27 28 15 33
Notes: PFiT closed to new applicants on 29 December 2011. On 1 September 2011, the Victorian Government announced that the PFiT scheme would soon reach its scheme capacity cap, expected to occur in late November 2011. PFiT applicants were advised that they needed to submit their paperwork (the Solar Connection Form, EWR and CES) by 30 September 2011 to meet the PFiT closure deadline. Source: EWOV 2012.
7.3 Why does the Victorian connection process work the way it does?
The two key pieces of Victorian regulation that shape the household-scale connection process are the Electrical Safety Act 1998 (Vic) (Electrical Safety Act) and FiT provisions of the EI Act.
7.3.1 The Victorian electrical safety system
The Electricity Safety Act and the various associated regulations — including the Electricity Safety (Installations) Regulations 2009 (Vic) — govern the design construction and maintenance of electricity networks in Victoria. CitiPower/Powercor noted that safety legislation was one of the ‘drivers’ of the household-scale connection process (sub. DR184, p. 4).
Compliance with the Victorian electricity safety framework requires that after a solar PV system is installed a CES is prepared, which includes a Certificate of Compliance and a Certificate of Inspection (ESV 2012b). The CES warrants that the PV system:
• complies with the Electrical Safety Act and regulations • was tested by the installer in accordance with the regulations before it was connected to the electricity supply • was inspected by a licensed electrical inspector in accordance with the regulations before it was connected to the electricity supply (Electrical Safety Act ss 44, 45 and 45A).
The ESV recently introduced an online system which allows the submission of electronic certificates and reduces some of the reporting requirements in paper certificates. However, paper certificates can still be used by parties that do not wish to use the online system (ESV nd, p.2).
122 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 7.3.2 Rationale for a retail feed-in tariff contract
Concerns about consumer protection are another reason why the current connection process for household-scale distributed generation works the way it does in Victoria. DPI argued that a separate retail FiT contract is an important consumer protection safeguard for three main reasons.
(1) A separate FiT contract facilitates ministerial referrals to the Essential Services Commission (ESC) to assess the terms and conditions of a retail FiT offer, in circumstances where the Minister for Energy and Resources has concerns that terms and conditions of the offer are not ‘fair and reasonable’. (2) Separate contracts are appropriate because specific clauses applicable to the supply and export of electricity may differ. FiT contracts provide customers with specific information on the export of electricity, for example any administration fees, how any Green certificates (such as RECs) are handled or the treatment of excess credits (whether they can be applied as credits or as direct cash payments and whether excess credits are paid out or extinguished when a contract is terminated). In addition, the retail supply and FiT contracts will frequently have different start dates because many customers enter into a FiT contract with their retailer when they already have an existing supply contract. (3) The FiT contract ensures that customer protections (as outlined in the Energy Retail Code (ESC 2012b) for supply contracts) are also applied where customers are exporting to the grid (DPI 2012e).
The Commission notes that while it is standard industry practice for Victorian electricity retailers to have separate supply and FiT contracts with their customers, there is no legal requirement for separate contracts. The EI Act requires that a contract for the export of PFiT and TFiT generation be in place between the retailer and FiT customer.11 These specific references to a contract relate to the provision of a customer's principal place of residence and customer eligibility criteria at the point of PFiT/TFiT scheme closure. There is no mention of a contract for SFiT generation. Division 5A of the EI Act makes various references to an ‘offer’ and the ‘terms and conditions’ for the purchase of exported generation by licenced retailers. It has been industry practice to implement these terms and conditions through a separate FiT retail contract.
7.4 Opportunities for improvement raised by stakeholders
In the draft report, the Commission sought feedback on how the Victorian process for connection of household-scale distributed generation could be improved. Many submissions from stakeholders were supportive of simplifying the household-scale connection (for example: NAGA, sub. DR140, p. 2). In addition, the Commission held a roundtable to discuss barriers to household-scale connection. Opportunities to improve the household connection process were also discussed at the retail business roundtable and during other post-draft report stakeholder meetings, including with solar PV installers. The Commission notes that Victoria is obliged to address barriers to the streamlining and simplification of connection process in accordance with the COAG FiT principles, which state:
11 See EI Act ss 40FA, 40FAB, 40FC and 40FCA.
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 123 … connection arrangements for small renewables customers should be standardised and simplified to recognise the market power imbalance between small renewable customers and networks. (COAG 2008, p.2)
Addressing the connection barriers faced by household-scale distributed generation proponents is also consistent with the Victorian Government’s commitment to reduce red tape. In the Victorian Budget, 2011-12 Strategy and Outlook, Budget Paper No.2, the Victorian Government committed to a 25 per cent reduction in existing regulatory costs to be achieved by July 2014 (DTF 2011, p.17).
Specific suggestions to improve the Victorian household-scale connection model are described below.
7.4.1 One connection process for all Victorian DNSPs
At present, the connection process varies across all five DNSPs in Victoria. But a uniform connection process would be difficult to achieve because of the number of Victorian DNSPs. CitiPower/Powercor argued:
In terms of a single connection process for all Victorian DNSPs, the Businesses understand the connection application form is already common across Victorian DNSPs. Further the processes undertaken by each DNSP are similar. Where there are differences, these have evolved over time based on the systems implemented across each DNSP. To impose a single system across the Victorian DNSPs would be extremely expensive potentially requiring replacement of multiple systems across multiple DNSPs. It would not appear cost effective to require replacement of systems where the processes are already similar and the connection application process is identical. (sub. DR184, p. 4) However, roundtable discussions and individual meetings with installers, retailers and DNSPs recognised that there may be value in some standardisation. The EWR and CES forms are already standard across all Victorian DNSPs, although there is some variation in the Solar Connection Form across DNSPs. The content of the Solar Connection Form is managed by Victorian DNSPs (CitiPower/Powercor 2012a).
7.4.2 No requirement for connection approval by the DNSP
Household-scale and retail business roundtable participants noted that, in practice, Victorian DNSPs automatically approve household-scale connection applications without conducting a technical assessment to determine the impact the connection will have on the distribution network (as required by NER chapter 5). DNSPs therefore accept the risk of any detrimental network impacts of the additional generation exported by house-hold scale PV. The connection processes in Queensland was cited as an example where automatic approval for household-scale distributed generation (below a set threshold) is formalised. However, Victorian DNSPs maintained approval to connect should be retained to ensure that safety and security of the network. AGL argued that ‘in general, small generation should have an automatic right to connect’ but ‘issues will arise where there is a significant penetration of like technologies, which may in aggregate create technical issues’ (sub. DR193, p. 2).
CFCL supported the Commission’s draft recommendation to facilitate household-scale connection and argued that an ‘install and notify’ process would be the most efficient solution (sub. DR135, p. 2). CFCL recommended that Victoria adopt the process in the United Kingdom (UK), where ‘a distributed generator of less than 3.6 kW can be installed and connected to the distribution grid by an accredited installer, who then must notify
124 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION the relevant network operator within 28 days’ (sub. DR135, p. 2). In the UK, prior approval from the network operator is not required (Energy Networks Association 2011).
7.4.3 Removing the obligation that distributed generation customers enter into a separate FiT contract
Retailers at roundtable consultations noted that the FiT contracting process can be difficult and a key reason for delays in FiT credits being applied to customer retail bills. Retailers noted that they must post a physical copy of the FiT contract to the customer for the customer to sign and post back to the retailer. Some FiT customers fail to sign and return the FiT contract because they do not understand that it is industry practice to require a separate contract to participate in a FiT scheme. Retailers noted that many FiT customers assume that once the PV system is installed and the metering complete, they will start receiving FiT credits for exported electricity.
Many retailers transfer a FiT customer’s supply retail tariff to time-of-use (TOU) pricing once the relevant DNSP has reassigned the customer to a TOU network tariff. Network tariff reassignment generally occurs after the PV system is installed and connected to the distribution grid. In certain circumstances, Victorian DNSPs can reassign solar PV customers to a TOU network tariff if the retailer requests the reassignment on behalf of the PV customer and the customer consents. Supply tariff reassignment is discussed in more detail in section B.4.2. Network and retail tariff reassignment without consent has been a problem in the past for a number of solar PV customers (ESC 2010). Customers lose their current rates for dedicated off-peak loads (off-peak electricity rates for hot water, heating or air-conditioning) when they enter into a solar FiT arrangement with their supply retailer (DPI 2012f). Network and retail supply tariff reassignment, and other changes to supply tariff structure increases the complexity of the retail contracting and billing process, and are often an additional source of confusion for solar customers. The Commission received submissions from FiT customers detailing their difficulties with the retail FiT contracting process and the associated confusion and uncertainty. For example, Lois Knight (sub. DR119) described the retail FiT contracting process as ‘a gamble’ because electricity retailers are not under any obligation to purchase exported generation until after the installation, connection and metering process is complete. Lois Knight recommended:
The RETAILER SHOULD HAVE AN OBLIGATION, UNDER THE ACT, to provide a signed, written commitment to buy-back at a SPECIFIC RATE, such commitment to expire in no less than 20 weeks. This obligation should be AT THE TIME THE CONSUMER IS ABOUT TO BUY A SOLAR SYSTEM, PRIOR TO COMMITTING TO BUY – NOT 8-16 weeks’ later... after funds spent and all works done. (sub. DR119, p. 2)
In the draft report, the Commission noted that other Australian jurisdictions, such as New South Wales, combine the terms and conditions for supply of electricity and FiTs into a single retail contract. Participants at the retail business roundtable argued that removing the separate FiT contract in Victoria could reduce administrative costs for retailers and processing time for customers. The Commission notes that there is no legal requirement that Victorian customers have separate supply and FiT (export) contracts with their retailer.
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 125 7.4.4 Introducing meter contestability
In New South Wales, Accredited Service Providers (ASPs) are able to complete some of the functions undertaken by DNSPs in Victoria (NSW Government 2010; NSW Trade & Investment 2012; Department of Water & Energy 2007). ASPs can act on behalf of the DNSP to obtain and install a meter as well as installing the PV system. CFCL supported allowing third party service providers to install meters in Victoria (sub. 41, p. 17; sub. DR135, p. 2).
NER chapter 7 governs metering provision, installation and maintenance. Metering installation is a contestable service under the national framework for types 1 to 4 metering installations (cl 7.2.2 and 7.2.3; AEMO 2009, pp.1–2). However, the AMI rollout jurisdictional derogation mandates that Victorian DNSPs must be the ‘responsible person’ for meters installed as part of Victoria’s AMI rollout, eliminating contestability ((AEMC 2009a); NER cl 9.9B.3). As such, introducing metering contestability is not practicable in Victoria at present. Under cl 9.9B.2, the jurisdictional rollout derogation will expire on the earlier of:
• 31 December 2013 (the scheduled completion date of the AMI rollout) • amendment(s) to the NER that facilitate the rollout of smart meters and provide for transfer of regulation of ‘relevant metering installations’ under cl9.9B (the derogation) to the standard metering requirements under chapter 7 of the NER.
Once the jurisdictional derogation expires, metering will revert to a contestable service in Victoria (cl 9.9B.2). The AER’s Wholesale Markets Quarterly Compliance Report October – December 2011, published in February 2012, clarifies that the jurisdictional derogation is current and expected to remain in place until the AMI rollout is completed (AER 2012j, pp.23–24).
In the draft report, the Commission’s draft recommendation 4.3 to streamline household-scale connection included requiring the Victorian Government to establish meter installation contestability. The Commission has since been advised that metering contestability will resume once the AMI rollout is complete on 31 December 2013. The Victorian Government’s rule change proposal for a jurisdictional derogation from the NER chapter 7 was accepted by the AEMC because it was required to ensure ‘smart meters [are] rolled out to all small electricity customers in Victoria within an accelerated timeframe’ consistent with the National Electricity Objective (AEMC 2009e, p.vii). The Commission therefore considers that meter contestability is not appropriate until the AMI rollout is complete, and is therefore not pursuing this aspect of its draft recommendation in its final report.
7.4.5 Remove the retailer from the installation, connection and metering process
Double handling of paperwork and unnecessary duplication could also be substantially reduced by removing the need to go through the retailer in the connection process. In other Australian jurisdictions — including New South Wales, South Australia and Queensland — the installer submits the necessary paperwork directly to the DNSP (CEC 2012b; ETSA Utilities 2012, p.4; Energex 2011, p.3). Some household-scale roundtable participants argued that the retailer only needs to be involved in advising the customer of the applicable retail and network tariffs (including any potential changes to their supply tariff), entering into the FiT contract and billing the customer (including crediting the FiT to the customer’s supply bill). The retailer does not need to be involved in other aspects of connection, and installers and customers should deal directly with the DNSP. AGL recommended that DNSPs should ‘play a more proactive
126 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION role in liaising with customers during the initial [installation] stage… rather than requiring retailers to be unnecessarily involved in this process’ (sub. DR193, p. 3). However, some roundtable participants argued that because of the Victorian electricity industry structure, Victorian DNSPs have less customer contact than other Australian jurisdictions and therefore:
• have limited call centre capacity and processes in place to respond to customer enquiries • do not handle customer billing, and lack billing systems and procedures to manage credit risk.
For example, CitiPower/Powercor stated that:
In terms of double handling of paperwork and other duplicative steps, a number of these have come about as a consequence of retailers being the principal interface with the customer. (sub. DR184, p. 5)
At the retail business roundtable, retailers agreed that removing the need for the EWR and CES to pass through the retailer would be a more efficient but that retailers would need some involvement in the connection process to bill the FiT customer. The PFiT and TFiT schemes are funded through a DNSP ‘pass through model’. This involves the DNSP crediting the relevant electricity retailer for PFiT and TFiT generation conveyed along the distribution network within the DNSP’s distribution area. DNSPs apply the PFiT or TFiT credit against the distribution network charges payable by the retailer. Retailers may choose to offer a PFiT and TFiT above the statutory minimum tariff credit. Retailers therefore need to know the DNSP’s supply network tariff (including whether the network tariff has been reassigned to TOU pricing) to advise the customer of the FiT and any changes to the retail tariff structure. Roundtable participants argued that network tariff issues are a greater issue in Victoria than in other Australian jurisdictions.
Reducing the role of the retailer in the connection process could minimise process cost and delay, resulting from poor B2B communication and/or incomplete or misdirected paperwork. A number of household-scale roundtable participants suggested that most problems with missing paperwork occur at the retailer to DNSP interface. The ERAA stated:
… the current Victorian feed-in tariff schemes place unnecessary administrative burden on retailers and customers, with retailers being required to act as middle men between distributors, solar PV installers, and customers. Retailers have to process, validate and relay to distributors a range of forms when much of this work would be more efficiently managed by distributors. (sub. DR180, p. 1)
7.4.6 Online connection process
Retailers at the retail business roundtable suggested providing the opportunity for the EWR to be completed electronically would be an improvement. Retailers noted that the EWR is a standard form, used by all DNSPs in Victoria. They suggested that it would be feasible for all Victorian DNSPs to make available a pdf version of the form on their websites for installers to access, complete and submit online, with functionality to ensure it is completed correctly and received by the DNSP. This would also improve visibility of the connection process.
For example, Energex (a Queensland DNSP) has a pdf Application to Network Connect an Inverter Energy System (including Solar PV) form on its website which is electronically completed and submitted directly to the DNSP (Energex 2010). Energex also has an
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 127 online facility for distributed generation customers to track the progress of their connection application. When the EWR is submitted electronically the installer is provided with a reference number. Customers can quote the reference number when contacting their electricity retailer and use that number to track the progress through the Energex website (Energex 2011, p.6).
AGL supported an online automated connection process, noting that this would ‘substantially minimise’ processing timeframes and that ‘such as system operates successfully in South Australia… with lower error rates and significantly lower customer complaints than exist in Victoria’ (sub. DR193, p. 3). South Australian small embedded generator (SEG) applicants can apply to ETSA Utilities (the sole DNSP for South Australia) for connection through an online application form. The connection process is fully automated through the online system (ETSA Utilities 2012).
Participants at the household-scale connection and retail business roundtables noted that a single online portal for connection applications would be more difficult to achieve in Victoria because it would require the processes of the five Victorian DNSPs to be standardised. DNSP roundtable participants argued that whether Victorian DNSPs invest in developing an online portal will be dictated by business needs. The Commission understands that CitiPower/Powercor is developing an online portal but that it does not extend to distributed generation connections. CitiPower/Powercor supported the development of such a system if the Commission believes the benefits would exceed the costs (sub. DR184, p. 5).
CFCL maintained that introducing an online process to allow all parties to access information and paperwork simultaneously could significantly simplify and shorten the connection process:
At the very least, providing an on-line system to automate and streamline the process, allowing the customer, retailer and distributor to share information and provide sign-offs etc much more efficiently than via hard copy forms. The current system requires all information to be channelled through the retailer to the distributor – creating an inefficient bottleneck. (sub. 41, p. 17)
7.4.7 Improving information
EWOV identified that the DPI website currently provides good information, including information on the connection process:
The DPI website remains the hub of solar information. It is a centralised and trusted source of information for EWOV, customers, electricity retailers and distributors. (EWOV, sub. 48, p. 3)
However, roundtable participants agreed that customer information on the connection processes could be significantly improved. They suggested providing customers with accurate upfront information on applicable retail tariffs, installation costs and the connection process is essential because of the flow on effect this can have on the rest of the connection process. Installers raised concerns that there is minimal independent advice available to assist customers to make informed decisions, given that some electricity retailers have a business interest in marketing particular PV systems. Retailers also raised concerns that some customers only enquire about the retail tariffs after purchasing and installing a PV system. The Commission notes that the DPI website is an important information source for solar PV customers (see for example: Misleading Claims About Solar (DPI 2011g)) but providing more information upfront would assist the connection process to run more smoothly.
128 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 7.5 The Commission’s view
In section 7.4 the Commission noted that improving the connection process for household-scale distributed generation would be consistent with the COAG FiT principles and the Victorian Government’s commitment to reduce red tape. The Commission concurs with submissions that the household-scale connection process is unnecessarily complicated and contains unnecessary steps. This imposes considerable cost on the consumers and businesses involved, particularly installers who often mediate the process on behalf of the owners of PV systems.
Although the household-scale connection process is governed by regulation it is also shaped by business practice and industry regulation. The Commission considers that there are two key opportunities to improve the household-scale distributed generation connection process:
(1) remove the retailer from the physical installation, connection and metering arm of the connection process (figure 7.3) (2) clarify that there is no legal requirement for a separate Fit (export) contract with the retailer and require retailers to have a combined supply and FiT (export) contract.
Implementing these process improvements requires changes to Victorian regulation, as well as changes to the current practices by private agents in the Victorian electricity industry. The Commission is limited to recommending changes that the Victorian Government has the power to implement.
7.5.1 Process improvement 1: remove retailer from the physical installation, connection and metering arm of the connection process
Based on stakeholder roundtables and meetings, it is clear that the retailer only needs to be involved in the contractual and billing aspects of the FiT arrangement. The retailer’s only roles in the connection process are:
• receiving the Service Paperwork (EWR and CES) from the installer and forwarding it — along with the Service Order Request for metering installation and reconfiguration — to the DNSP • advising the household-scale distributed generation customer of applicable tariffs (including any changes to the supply tariff), restructuring the customer’s retail tariff after network tariff reassignment, billing the customer for electricity consumed and applying the FiT credit against the customer’s supply bill.
If the retailer were removed from the physical installation, connection and metering arm of the connection process, then the installer would be able to submit the EWR and CES directly to the DNSP. This would: • remove the double handling of paperwork and reduce the duplication (CFCL, sub. 41, p. 17) and unnecessary steps (Origin, sub. 81) identified by stakeholders • reduce the complexity of the installation, connection and metering process because only three parties are involved instead of four • decrease the likelihood that paperwork would be misplaced or misdirected • eliminate the key process bottleneck reducing cost and delay.
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 129 There are no legal or regulatory barriers to removing the retailer from the connection process and having Service Paperwork submitted directly to the DNSP. The current arrangement — in which the EWR and CES pass from the installer to the retailer and the retailer to the DNSP — appears to be based on industry practice, reflected in Use of System Agreements between retailers and DNSPs, and B2B Procedures.
7.5.2 Process improvement 2: require retailers to combine their supply and FiT (export) contracts
The intention in requiring a FiT contract was to provide household-scale distributed generation customers with consumer protections. However, the Commission considers these protections can be achieved and the connection process made more efficient by incorporating FiT (export) provisions into the supply contract for households and small business. This would allow distributed generation customers to have a single combined retail contract that clearly sets out the customer’s, and retailer’s, rights and obligations in supply and export. Combining the contracts would reduce administration costs for retailers and processing time for customers. It would also minimise the delays many customers experience before they start receiving credits from their retailer for exported electricity.
The Victorian Government should clarify that there is no requirement in the EI Act for retailers with more than 5000 customers to have separate supply and FiT (export) contracts. Separate contracts have arisen through industry practice. In addition, the Victorian Government should consider amending the EI Act to specifically require that the terms and conditions for purchasing electricity from a household-scale generator be incorporated in the retailer’s supply contract. Requiring a single combined retail contract would ensure that, at a high-level, all Victorian retailers have a consistent contracting process, in line with other Australian jurisdictions. This would also make it easier for households to understand and navigate the connection process.
The Commission therefore recommends that the EI Act be amended to require retailers with more than 5000 customers to include a default FiT clause (reflecting the new FiT scheme specified in recommendation 9.1) in their retail supply contracts unless the customer has instructed otherwise. Retailers would automatically put household-scale distributed generation customers on a default FiT offer (once they are notified by the DNSP that their supply customer has solar PV installed and connected, and appropriate bi-directional metering in place). This caters for customers who have not contacted their retailer to enquire about available tariffs and entered a FiT contract before they have purchased and installed their solar PV system — which is a common source of delay. Customers put on the default FiT have the option of changing FiT offers or switching retailers to participate in another retailer’s FiT scheme. Customers that have made prior tariff enquiries and nominated the retail FiT offer they wish to accept would be unaffected by this change.
The EI Act does not require small retailers (with 5000 or less customers) to offer a FiT, unless they choose to do so. The Commission’s recommendation would not increase the obligations imposed on small retailers who would inform their supply customers that they do not offer a FiT at the tariff enquiry stage of the connection process. As is currently the case, these customers would need to switch electricity retailers if they wish to participate in a Victorian FiT scheme.
The Commission considers that a mechanism to notify the retailer that their supply customer is installing a solar PV system, and when the system is connected and appropriate metering complete would need to be built into the streamlined connection process. The Commission therefore recommends that:
130 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • the Solar Connection Form that customers complete and submit to the DNSP be amended to include a new box for the customer to fill in the name of their retailer. The Solar Connection Form is developed by Victorian DNSPs by agreement and is largely standard.12 Victorian DNSPs would need to agree to amend the form. Industry could also agree that the DNSP would notify the customer’s retailer on receipt of the application to connect. This would provide retailers with advanced notice of a distributed generation connection. • the DNSP notify the customer’s supply retailer — that the customer has a PV system installed and connected, and appropriate metering — once the metering installation and/or reconfiguration is complete. This is a new, but not onerous, step in the installation, connection and metering process. Under the B2B Procedure: Service Order Process (AEMO 2011a) and Use of System Agreements between Victorian retailers and DNSPs, DNSPs already provide the retailer with a Business Receipt and Business Acceptance in response to the Service Order Request for appropriate metering. DNSPs also already send retailers a Service Order Response and Service Order Status when the meter is successfully installed and/or reconfigured (CitiPower/Powercor 2012a; SP Ausnet 2012).
While ‘household-scale’ currently refers to solar PV customers of 5 kW or less — because of the eligibility criteria for the PFiT and TFiT schemes — going forward the Commission is recommending that a new FiT be created that covers all renewable and low-emissions distributed generation technologies (100 kW or less) (recommendation 9.1). The Commission’s recommended process improvements would apply to all household-scale distributed generation connections under the new FiT scheme contemplated by recommendation 9.1, and may be adapted to cater for different technologies. The recommended process improvements are not retrospective and would not apply to TFiT or SFiT connection applicants. Figure 7.3 illustrates how the Commission’s two recommended process improvements would streamline the household-scale connection process.
12 The main difference is that the Solar Connection Form applies to PV systems up to 4.5 kW in the SP AusNet distribution area but to PV systems up to 10 kW for all other Victorian distribution areas.
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 131 Figure 7.3 Improved connection process for household-scale solar PV (5 kw or less) in Victoria
Source: Commission analysis.
132 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 7.5.3 Supporting recommendations
In addition, the Commission considers there are opportunities to improve information provision and visibility of the connection process for household-scale distributed generation, and to ensure that a strategic approach is taken to address systemic process problems. The Commission has therefore considered what is needed to support the two key process improvements discussed above:
• process visibility: improve visibility of the connection process, so that customers are informed about the progress of their application and can determine if, and where, their application has stalled at any stage in the connection process. This may be achieved through an online portal to fully automate the installation, connection and metering process, or more limited use of electronic technology. For example: a pdf EWR form that can be submitted online to DNSPs, or an online facility for customers and installers to track the connection application. DNSPs may find that there is a stronger business case for electronic submission or an online portal, once the retailer is removed from the connection process and they receive paperwork and enquiries directly from installers • better upfront information: ensure that customers are well-informed about the key process improvements — including their role and accountabilities, the role of other parties in the connection process, and the likely retail and installation costs • strategic approach: require DPI to work with Consumer Affairs Victoria and EWOV to identify and respond to ongoing systemic process problems.
7.5.4 Implementation of process improvements and supporting recommendations
Implementation of the Commission’s two key process improvements and supporting recommendations would require the agreement of Victorian retailers and DNSPs, because it is predominately business practice — not regulatory requirements — that dictates the flow of paperwork in the household-scale connection process. The Commission recommends that DPI initiate discussions between Victorian retailers and DNSPS to reach an industry agreement on changes necessary to implement the two key process improvements and supporting recommendations discussed above. These changes would need to be reflected in the Use of System Agreements between Victorian DNSPs and retailers. Victorian electricity retailers and DNSPs are required — in distribution and retail licence conditions — to enter into Use of System Agreements. Licensed retailers must have a Use of System Agreement with each DNSP in whose distribution area the supply point of any customer of the retailer is located. The ESC has oversight of Use of System Agreements under Victorian distribution licences cl 4. DNSPs must submit default Use of System Agreements to the ESC for approval. The terms and conditions of Use of System Agreements must be ‘fair and reasonable’.
If the Victorian Government accepts the Commission’s recommendation for process improvement, in the event that industry is unable to reach agreement by 31 December 2013 on implementing them, then the Commission recommends that the Victorian Government amend the EI Act:
• to create a deemed electricity distribution licence condition that DNSPs vary their Use of System Agreements with applicable retailers to implement these process reforms • to impose a distribution licence condition that Victorian DNSPs amend the Solar Connection Form to add in a new box for customers to fill in the name of their supply retailer.
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 133 The Commission notes that there are also some practical challenges to implementation that would need to be addressed. For example, DNSPs would need to develop their customer interface capacity to deal directly with installers and respond to customer enquiries. Installers would also need to be consulted and educated about process changes.
Recommendation 7.1 That to facilitate the connection of all renewable and low-emissions distributed generation (100 kW or less) under the new feed-in tariff (FiT) scheme contemplated by recommendation 9.1, the Victorian Government: • amend the Electricity Industry Act 2000 (Vic) (EI Act) to require that Victorian retailers with more than 5000 customers include a default FiT clause in all their retail supply contracts, which is activated — unless the customer has instructed otherwise — when the retailer is notified by the distribution network service provider (DNSP) that the supply customer has met all the physical and technical preconditions for connecting distributed generation. Retailers and customers would be free to agree on a FiT outside this default offer. The default FiT offer would give effect to the new FiT specified in recommendation 9.1. That the Victorian Government require the Department of Primary Industries (DPI) to: • increase the information available to household-scale distributed generation customers — about the customer’s role and the role of other parties in the new FiT connection process, and the likely retail and installation costs — by being proactive in the provision of upfront independent information that: – outlines the impact of recommended process improvements – identifies which party is accountable for each step in the connection process and who bears the risk for any resulting cost and delay – clearly indicates to the customer the risk of not being informed • in conjunction with Consumer Affairs Victoria and the Energy and Water Ombudsman Victoria identify, and respond to, ongoing systemic process problems • initiate a process with Victorian retailers and DNSPs to establish an industry agreement on processes that: – improves visibility of the connection process, so that customers are informed about the progress of their application and can determine if, and where, their application has stalled at any stage in the connection process – allows for the installer to submit the Electrical Work Request and Certificate of Electrical Safety directly to the DNSP, and amend the Solar Connection Form to require customers to fill in the name of their supply retailer. In the event that industry is unable to agree by 31 December 2013 on improving process visibility and removing the retailer from physical installation, connection and metering process, the Victorian Government, subject to a positive cost benefit assessment, amend the EI Act to: • create a deemed electricity distribution licence condition that DNSPs vary their Use of System Agreements with applicable retailers to implement these process reforms • impose a distribution licence condition that Victorian DNSPs amend the Solar Connection Form to add in a new box for customers to fill in the name of their supply retailer.
134 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 7.6 Cost savings from improved household-scale connection process
While there are potentially fewer connection barriers for household-scale generators than for medium-scale generators their removal could play an important role in assisting the solar PV industry as other Victorian policy settings are changing. If fully implemented, the Commission’s recommendations to improve the small-scale connection process would reduce administrative burden and connection times. The Commission estimated the potential magnitude of these benefits and technical assumptions (box 7.2) were tested with electricity retailers, PV installers, EWOV and DNSPs.
Box 7.2 Assumptions supporting estimated benefits The final assumptions include: • Contract processing: it currently takes retailers one hour to process a contract when there are no errors. When there is an error the retailer spends two hours and customers 0.5 hours. Because of delays through mail and processing this step adds two or four days to the total connection time without or with errors respectively. • Retailer processing the Certificate of Electrical Safety (CES) and Electrical Work Request (EWR): the retailer spends one or two hours processing the CES and EWR without or with errors respectively. Time spent by the customer, installer and distribution network service provider (DNSP) would not change when no error occurs but with an error the customer, installer and DNSP spend an additional one hour each. • Total connection time: connection currently takes around three months and the Commission assumed that when the EWR does not get processed correctly the customer or installer finds out after the three months. The Commission assumed it takes another three months to get connected. By removing the retailer from this process the Commission assumed that any error would be identified 1.5 months earlier. That is, the total connection time would take 4.5 months with a streamlined process instead of six months currently. • Labour costs: labour is valued at $69 per hour with on-costs and customers’ time is valued at $33 per hour13. • Administrative costs: postage, storage, telephone calls and other costs total $15 per application to process the contract and to $15 to process the CES and EWR combined. • Error rate: detailed data from Energy and Water Ombudsman Victoria and a retailer suggested an error rate of around 20 per cent but the Commission assumed a conservative error rate of 15 per cent. • Number of PV installations: there is a significant reduction in the rate of take up from 20 000 in 2012 to 15 000 in 2013, based on ACIL Tasman’s assumptions in their report on the Small-scale Renewable Energy Scheme to the Australian Energy Market Commission (ACIL Tasman 2011a, p.42). Source: Commission analysis.
13 Based on ABS average weekly earnings, average hours worked (ABS Feb 2012, cat. 6302, 6105) and a multiplier for on-costs of 1.75 from the Victorian Guide to Regulation (Victorian Government 2011).
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 135 7.6.1 Savings arising from the Commission’s recommendations
There are two main types of savings: the reduction in administrative burden and the ‘bring forward’ benefit of producing electricity sooner.
The Commission assumed the administrative burden and delay involved in processing contracts and double handling by the retailer of the CES and EWR paperwork would reduce to zero. The error rate is also assumed to approximately halve from 15 per cent to 8 per cent. The administrative burden saving is estimated at $185 or $490 per connection without or with errors respectively (table 7.3). Assuming 15 000 connections per year (based on ACIL Tasman 2011a, p.42) then across Victoria the administrative burden reduction alone would be in the order of $3 million per year. This point estimate depends in particular on the number of connections and is best considered as a range of about $3 to $5 million per year.
Time savings, or the ‘bring forward’, were based on the number of days of additional FiT revenue and avoided retail cost resulting from earlier connection of solar PV systems. Unsubsidised FiT revenue ($62) and avoided retail cost ($431) for solar PV systems totals $493 per year or $1.35 per day. The ‘bring forward’ of revenue is minimal for those that do not experience errors now ($5). Those who would be expected to experience errors with current processes and would in the future will have additional revenue of $50 and the reduced error rate means those that would be expected to experience an error in the current system and do not in the future will have additional revenue of $95 (table 7.4). These ‘bring forward’ savings are important at the individual level but are not significant in aggregate. The Commission considers its estimates are conservative.
Table 7.3 Reduced administrative burden w/o errors with errors business hours 1 2 customer hours 0 0.5 Contract processing: delay (days) 2 4 admin costs $15 $15 total $85 $170 business hours 1 4 customer hours 0.5 1 Reduced retailer involvement in delay (days) 2 34.50 connection: admin costs $15 $15 total $100 $325 Total savings per application $185 $490 Applications expected (2013) 15,000 Current error rate 85% 15% Error rate with recommendations 92% 8% Total savings in Victoria $3 m approx.
Note: Savings rounded due to indicative nature of the calculations. Source: Commission analysis.
136 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Table 7.4 Savings for different types of connections Additional FiT Proportion of Reduced admin revenue and Days saved connections burden avoided retail cost 85%: no errors currently, 4 $185 $5 no errors in future
7%: errors currently, no 69 $490 $95 errors in future 8%: errors currently, 39 $140 $50 errors in the future
Notes: Savings rounded to nearest five dollars. Source: Commission analysis.
FACILITATING CONNECTION OF HOUSEHOLD-SCALE DISTRIBUTED GENERATION 137
8 Selling electricity
Many distributed generators seek to not only produce electricity for their own use but also to export surplus electricity into the grid. The options for how electricity is sold vary depending on the size of the generator and the generation technology used.
Small-scale renewable generators (less than 100 kW) are eligible to receive regulated feed-in tariffs (FiTs). In the case of larger distributed generators and those using non- renewable energy sources there is no regulated payment (FiT) for the electricity exported to the grid. As highlighted in chapter 2, the options for these generators include:
• registered generators can sell through the NEM at spot prices • non-market and exempt generators can sell through a private agreement outside the NEM to a local retailer or customer located at the same connection point.
An additional option, selling to a small generator aggregator, may also be available if a rule change currently being considered by the AEMC is approved. There are practical differences in the issues facing small- and medium-scale generators seeking to sell electricity. The options available to medium-scale distributed generation are broader but the regulatory constraints more complex. This chapter, therefore, first discusses the role and scope of FiTs for small-scale distributed generation relevant to terms of reference 1, and this discussion is further continued in chapter 9 which also addresses terms of reference 2. Second, the chapter considers some of the broader regulatory issues facing medium-scale distributed generation seeking to on-sell electricity in a range of circumstances.
8.1 Overview of Victorian feed-in tariff schemes
There are three Victorian FiT schemes that are relevant to small distributed generators (up to 100 kW), including, and in particular, solar photovoltaic (PV) — the standard feed-in tariff (SFiT), the premium feed-in tariff (PFiT) and the transitional feed-in tariff (TFiT). All electricity retailers with 5 000 customers or more are required to make offers to eligible customers under the TFiT and SFiT. PFiT is now closed to new entrants, but continues until 2024.
An explicit minimum net feed-in tariff is established within the PFiT and TFiT which only applies to solar PV technology. There is no minimum FiT for other technologies except to the extent that the prices and terms and conditions must be fair and reasonable. However, a guidance paper, released by the Essential Services Commission (ESC) outlines the methodology for assessing ‘fair and reasonable’ FiTs and includes that an offer (by a retailer) must:
Specify that the retailer will pay or credit the customer, for electricity supplied by the customer under a feed-in contract, at a rate not less than the rate the customer pays to buy electricity from the retailer. (DPI 2011j)
In effect this sets a minimum FiT for renewable technologies.
The Victorian FiT schemes were established with a range of objectives summarised in table 8.1
SELLING ELECTRICITY 139 Table 8.1 Objectives of Victorian feed-in tariffs
Type of FiT Established Original Objectives Develop Victoria’s substantial wind energy resource Ensure timely and efficient connection of wind energy generators Address problems where the benefits and costs of SFiT 2004 connecting wind farms are not shared equally amongst market participants Remove market barriers that constrain the development of a small wind turbine industry in Victoria Reduce cost barriers to installing small-scale solar PV systems Encourage the continued uptake of solar PVs as part of a greenhouse gas abatement strategy for Victoria Modernise the regulatory approach to crediting and qualifying customers PFiT 2009 Assist households to make a personal contribution to tackling climate change Ensure certainty for owners of solar PV systems Ensure certainty for retailers and distribution network service providers Support the solar industry Ensure that the level of subsidy is equitable, given the cost to electricity users, including those on concessions Support renewable energy in the transition to a lower emissions future Provide a fair and reasonable price to households TFiT 2011 feeding solar into the grid Manage changing prices as PV costs have dropped by around 50 per cent Reduce the boom and bust cycle for the solar panel industry Provide an average payback period of less than 10 years.
Sources: Brumby 2004; Batchelor 2009; O’Brien 2011.
Overall the objectives in table 8.1 fall into three broad categories:
• reduce greenhouse gas emissions, including assisting households to make a personal contribution to environmental outcomes • support innovation and the development of a new industry by stimulating the demand for investing in distributed generation • ensure fair payments for electricity from small-scale PV investments.
140 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The ongoing relevance of these objectives needs review in light of the introduction of a price on carbon and the maturing of distribution generation technologies.
8.2 Reconsideration of Victorian FiT objectives
The importance of clear public policy objectives for FiT schemes was emphasised by AGL who suggested that the ‘lack of underlying public policy objectives’ is the ‘main driver of the poor outcomes experienced by most jurisdictions’ in relation to FiT schemes (sub. 72, p. 1). Ceramic Fuel Cells Limited (CFCL) also commented that ‘FiTs have become clouded’ by the ‘design and rate of tariffs’ that have been set to achieve other policy objectives, ‘notably to support the solar PV industry as a form of industry development (and as a subsidiary goal, to reduce greenhouse gas emissions)’ (sub. 41, p. 10).
8.2.1 Objective of reducing greenhouse gas emissions
The introduction of a national approach to pricing carbon on 1 July 2012 has significantly changed the context for the FiT objective of reducing greenhouse gas emissions. Under this pricing mechanism, around 300 of Australia’s largest carbon emitters, including gas retailers, are required to pay for each tonne of carbon pollution they release into the atmosphere.
Recent data (table 8.2) reported by corporations under the requirements of the National Greenhouse and Energy Reporting Act 2007 (Cth) indicate a number of large-scale generators are subject to the carbon pricing mechanism.
Table 8.2 Top ten greenhouse gas emitters (by registered corporation) – by total scope 1 gas emissions Example of generators owned Greenhouse gas Registered corporation by the corporation emissions (t CO2-e) • Lidell power station Macquarie Generation 20 330 773 • Bayswater power station • Mount Piper Power Station • Munmorah Power Station Delta Electricity 19 792 536 • Vales Point Power Station • Wallerawang Power Station Great Energy Alliance • Loy Yang A Power Station 19 378 906 Corporation Pty Ltd International Power (Australia) • Loy Yang B Power Station 16 764 353 Holdings TRUenergy Holdings Pty Ltd • Yallourn Power Station 16 143 406 • Callide Power Station CS Energy Limited • Kogan Creek Power Station 14 880 516 • Wivanhoe Power Station Eraring Energy • Eraring Power Station 11 725 490 BlueScope Steel Limited 11 371 293 Loy Yang Holdings Pty Ltd 10 165 819 Oz Gen Holdings Australia Pty Ltd 9 717 866
Source: Clean Energy Regulator 2012c.
SELLING ELECTRICITY 141 A price of $23 per tonne of carbon pollution now applies, moving to a market determined price from 2015. The price on carbon is a mechanism that provides a market-based incentive to reduce carbon pollution.
Explicitly pricing carbon ensures all companies and individuals either explicitly or implicitly factor into decisions the costs of greenhouse gas emissions. Companies and individuals do not need to make complex calculations about the emission intensity of particular goods, as the price of the goods will reflect that key information. Over time, as prices reflect the emission content of goods, producers and consumers will have an incentive to find ways to reduce emissions. For instance, electricity producers will look to reduce the use of emission-intensive fossil fuels to generate electricity and consumers will be encouraged to use less electricity. (Commonwealth Treasury 2011, p. 19)
The Productivity Commission (PC) found that the costs of reducing emissions are lower when consumers and producers make decisions, rather than government (PC 2011). Looking at over 1000 carbon policy measures across nine countries the PC also found that:
Emission trading schemes were found to be relatively cost effective, while policies encouraging small-scale renewable generation and biofuels have generated little abatement for substantially higher cost. (PC 2011, p. xiv)
More importantly, stylised modelling by the PC for Australia suggested that relative to a price-based approach ‘the abatement from existing policies for electricity could have been achieved at a fraction of the cost’ (PC 2011, p. xiv).
Implications for Victorian feed-in tariffs
One of the objectives of establishing the premium and transitional FiTs was to reduce greenhouse gas emissions prior to the introduction of a national approach. From a regulatory design perspective it is important to ensure that the most appropriate regulatory instrument is assigned to a given problem — provided that the case for government intervention is established. It is also important to ensure consistency with the National Electricity Objectives (NEO) as previously stated.
The Commission notes that work by the Commonwealth Government and the PC indicates that the objective of reducing greenhouse gas emissions is most appropriately addressed through a price on carbon.
In the draft report the Commission stated that if the objective of the FiT was to reduce greenhouse gas emissions then it would appear that this objective is no longer valid, on the grounds that a more appropriate regulatory (market-based) instrument has been adopted. It is also the case that FiTs will not be necessary as a complementary policy.
As noted by ACIL Tasman ‘if distributed generation is not the lowest cost of abating greenhouse gas emissions, a FiT that is set at a price above the value of the output of the distributed generation will “force” distributed generation in situations where abatement could be achieved more efficiently another way.’ More importantly, ‘it would add costs and cause electricity prices to be higher than necessary…therefore a FiT that is set at a price above the value of the distributed generation would be contrary to the NEO and the long term interests of consumers unless it is delivering benefits unrelated to climate change and greenhouse gas abatement’ (ACIL Tasman 2012, p. 39).
With specific reference to solar PV the AEMC reported that ‘solar PV provides a relatively expensive means of achieving abatement.’ (AEMC 2011b, p.58)
142 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Other Commonwealth initiatives
There are also other Commonwealth initiatives that seek to achieve environmental objectives similar to those of the Victorian FiTs. This includes the Renewable Energy Target which is designed to deliver the Commonwealth Government's commitment to ensure that 20 per cent of Australia's electricity supply will come from renewable sources by 2020 and consists of the Large-scale Renewable Energy Target (LRET) and the Small-scale Renewable Energy Scheme (SRES). These schemes create a financial incentive to invest in renewable energy sources through the creation and sale of renewable energy certificates. The purposes of the schemes are to:
• encourage additional generation of electricity from renewable sources • reduce emissions of greenhouse gases in the electricity sector • ensure that renewable energy sources are ecologically sustainable.
The draft report noted that while there are mixed views from participants on whether Commonwealth policies adequately deal with greenhouse gas emission issues (for example see: Warburton Community Hydro Project, sub. 69, p. 3, Simply Energy sub. 58, p. 1-2), the Commission considers that the combined effect of these policies is likely to be substantial and provide additional assistance for households to make a personal contribution to reducing greenhouse gas emissions (an objective of the PFiT). In response to the draft report several participants disagreed with the Commission’s view that Commonwealth policies (including the price on carbon) would adequately deal with greenhouse gas emission issues. For instance, Eleonora Symmonds (sub. DR106, p. 1) suggested that VCEC was ‘wrong to say that [solar panels] are an inefficient and expensive way to cut greenhouse emissions. Other forms of questionable green energy schemes are far worse.’
Kathryn Miller and Matthew Thomas (sub. DR190, p. 6) disagreed ‘that the introduction of a carbon price renders as irrelevant the impact of a FiT on greenhouse gas emissions’. From a consumer perspective they argued that:
For consumers, the carbon price will be effective only if they can choose to purchase low carbon electricity. This requires sufficient low-carbon electricity to be available in the system. If consumers are still forced to purchase high– carbon electricity, then the carbon price will just increase electricity prices without reducing greenhouse gas emissions. (sub DR190, p. 6-7)
They also suggested that ‘the carbon price does not take into account the air pollution caused by different forms of energy generation [and that] …It is appropriate that a FiT encourage ‘cleaner’ energy generation, in the sense of fewer air-borne pollutants’ (sub. DR190, p. 6).
The Energy Innovation Co-operative argued that ‘the Commonwealth’s current measures are in no way complete policy coverage of the issue [and that] whilst the current Federal Opposition maintains its trenchant opposition to the actions taken by the Federal Government, these reforms such as they are remain at risk of reversal’ (sub. DR160, p. 2).
The City of Port Phillip argued that the Victorian Government should remain a key driver of the take-up of energy efficiency and renewable energy:
[we do not accept the] VCEC position that greenhouse gas abatement is solely an Australian Government issue and that the carbon price (and a future emissions trading scheme) is an adequate mechanism in of its self to drive greenhouse gas abatement. We consider that the Victorian Government
SELLING ELECTRICITY 143 should be driving a greater up-take of energy efficiency, and renewable energy (combined policies to prevent vulnerable households going into fuel poverty) to ensure that we can all transition to a low carbon economy. A gross feed-in tariff should be part of these measures. (sub. DR111, p. 1)
While the Commission acknowledges that installation of small-scale distributed generation can reduce greenhouse gas emissions it is important to understand the relative costs of pursuing such an objective, particularly if it is not a least cost approach. Work undertaken by the AEMC highlighted the relative costs of greenhouse gas emission abatement through small-scale distributed generation:
There is a substantial difference between the abatement costs for the LRET and SRES, with the LRET ranging from around $55 to $80 per t/CO2-e compared to about $300 to $500 per t/CO2-e for the SRES in 2010/11 dollars. The differences in abatement costs between the LRET and SRES highlights the significant difference in value for money which can be achieved from large scale renewable investments compared to small scale renewable investments. (AEMC 2011b, p.58)
Given Commonwealth policies in this area, and the strong likelihood that small-scale distributed generation (particularly PV) is a relatively expensive option for the abatement of greenhouse gas emissions, the Commission considers that Victorian FiTs are no longer an appropriate regulatory instrument to assign to reducing greenhouse gas emissions, particularly given the cross-subsidies and potential inequities inherent in current FiTs (chapter 3). This does not preclude distributed generation from helping in the adjustment to a low-carbon economy. The Commission envisages that current Commonwealth programs, combined with improvements to connection processes proposed in this report will result in incentives to invest in distributed generation and as a result reduce greenhouse gas emissions.
8.2.2 Industry support
A further objective often cited in support of regulated FiTs is the development of, or support for, a particular industry. Current Victorian FiT eligibility criteria are skewed towards very small solar PV technology, and to other forms of distributed renewable generation technology.
The Grattan Institute pointed to the fact that early movers (or first movers) face costs that are not easily recovered within an electricity market context.
That is because early investors face high costs, low returns and the risk of competitors free-riding on their initiative. They require a reliable, long-term carbon price to underpin their investments. Yet the carbon price is inherently uncertain because it depends on the decisions of governments. For both these reasons, investment in low-emission technologies is and will remain critically inadequate. (Wood 2012, p.1)
It also suggested that the some form of government support for industry may be justified because of the barriers early movers face:
Government support for renewable energy, via feed-in-tariffs or otherwise, is economically justifiable only in so far as it is needed to overcome these obstacles, and aims at driving down the cost of renewable energy generation technologies. (sub. 86, p. 1)
144 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION A range of other participants argued in response to the draft report that the objectives of FiTs should be to support growth and investment in distributed generation. The Property Council of Australia (sub. DR191, p. 8) for example commented that ‘FiTs leverage private investment that can accelerate the uptake of distributed and renewable energy generation’. Peter Richardson also argued that ‘there is a great need for innovation in the building industry, to encourage solar, and even wind energy systems …’(sub. DR186, p. 1)
The Commission notes that there is a range of electricity saving and management options to assist customers to minimise their expenditure on electricity, including:
• energy efficient appliances (lighting, heating, cooling) or production processes • equipment that helps to shift the use of electricity to times when electricity from the grid is less costly • technologies that generate electricity, which may also include on-site storage and/or export to the grid • different fuel sources.
Analysis for the Commission and other jurisdictions indicates that the PFiT and TFiT are higher than a market-determined price, and therefore assist the solar PV industry. This assistance can change the way customers decide between the electricity saving options. In a competitive market, customers would optimise between the various options available to minimise their spend on electricity. But a higher FiT for solar PV makes this option more attractive than would otherwise be the case, and potentially crowds out alternatives. This reduces the demand for other industries such as those supplying electricity saving technologies and those building and operating large-scale renewable generators.
More generally the current SFiT arrangements target ‘renewable’ generation technologies. This disadvantages other technologies that have ‘low-emission’ characteristics and distorts consumer consumption decisions. Electricity generated from fuel cells, for instance, is not considered a ‘renewable’ form of distributed generation as it relies on gas (a non-renewable energy source) to produce electricity and heat. However, it is considered to be both low-emission and efficient (sub. 41, p. 4).
While additional assistance to solar PV (through the PFiT and TFit) may benefit the solar PV industry, it is likely to be at the expense of other distributed generation technologies (or more generally other industries supplying innovative energy efficiency related products or services). As outlined in the Commission’s inquiry into the Victorian manufacturing industry, ‘selective assistance that lowers the costs of a particular firm or manufacturing industry may improve its competitiveness, but at the expense of the competitiveness of other sectors’ (VCEC 2011, p. 90). While there may be specific cases where assistance is justifiable, as suggested by the Grattan Institute, there are other programs within Government (at a Commonwealth and State level) which are better suited to addressing issues confronted by ‘early or ‘first movers’.
Industry assistance, through regulated FiTs and discriminatory eligibility criteria, is not the most appropriate way to support the establishment of a sustainable industry, particularly when (in the case of the solar PV industry) the industry is already reasonably well established. The industry support argument is also undermined by policy uncertainty created by previous FiTs, which have been subject to significant change at short notice.
SELLING ELECTRICITY 145 8.2.3 Providing a ‘fair and reasonable’ price
One of the objectives cited in support of FiT schemes is to ensure that households and small businesses have access to a fair and reasonable price for the electricity that they export into the grid.
The Commission proposed in the draft report that providing a fair and reasonable price for exported electricity (based on the market value of energy) is the most relevant objective for Victorian FiTs and is consistent with COAG national FiT principles. However, the mechanism for achieving this objective may not require a FiT to be specified and regulated.
The following discussion relates to current Victorian FiT arrangements which cover generation capacity of up to 100 kW. Under these arrangements the owner of a distributed generator has a relationship with (and is a customer of) an electricity retail business. The Commission understands that the policy intent of Victorian FiTs (particularly the SFiT) was to encourage system installations where generating capacity is proportionate to the electricity consumption at the site — for instance it was not intended to capture installations that are primarily electricity generators.
Consistent with COAG national principles for FiT schemes, the Commission considers that small-scale generators of electricity exported to the grid (or distribution system) should receive a fair and reasonable price. The key question is how ‘fair and reasonable’ is defined, especially in view of the proposed appropriate objective for a FiT.
In response to the draft report there were many participants who reiterated views that a ‘fair and reasonable price’ should:
(1) relate to a payback period on their investment in solar PV and therefore provide an incentive to invest. For example, Alan Griffin commented: In respect of both the TFIT and SFIT schemes, and particularly the SFIT scheme, I believe that it is paramount to continue to offer a reasonable and fair value rate which will ensure that the return on investment is in the current timeframe of 6-7 years. Any cut to the SFIT regime before that 6-7 year pay back will have a materially detrimental impact on the industry who needs to have ROI certainty in order to invest in solar (and other renewable generation). This impact cannot be underestimated and must not be ignored. (sub. DR149, p.1) (2) be based on a one-for-one tariff arrangement. For example, Gerard Noonan (sub. 115) noted: If, post FiT, households receive only wholesale price for electricity generated they are not able to get any meaningful advantage from installing a solar system. At current rates they will earn only 5 to 7 cents per kWh sent to the grid, but have to pay 20 to 25 cents per kWh taken from the grid. They also pay a connection fee for access to the grid. This is not a Fair and Reasonable System. It is exploitation. It is no incentive for Victorians to install a power generation system. To be a Fair and Reasonable system, the value of power exported to the grid for small systems should be 1:1 on the purchase price of electricity. (sub. DR115, p. 1) (3) also include an allowance for the merit order effect. The Alternative Technology Association shared its view that: … it is in the long term interest of all consumers, and hence in keeping with the National Electricity Objective and the National Electricity Law, to recognise the merit order effect (MoE) in any feed-in tariff, and for a FiT to
146 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION be valued at a level that shares this benefit between all consumers while providing an incentive for the uptake of more distributed generation. (sub. DR189, p. 11)
These issues, which are relevant to which methodology should be adopted to promote the establishment of a ‘fair and reasonable’ price for electricity exported to the grid by distributed generators, are considered in greater detail in chapter 9.1
The Commission’s view, as noted in chapter 4, is that the strongest justification for a FiT is to provide an efficient price signal to investors in small-scale distributed generators that will help achieve efficient use of distributed generation in a competitive electricity market. Accordingly, the Commission considers that distributed generators should receive a price that reflects the value of the electricity exported to the grid that would encourage the efficient use of distributed generation, and minimises cross subsidies among users.
8.3 Barriers to establishing fair and reasonable FiTs
The draft report noted that there may be barriers that impact on the ability of the market to establish ‘fair and reasonable’ feed-in tariffs. These are discussed below.
8.3.1 Is there competition within the Victorian electricity retail market?
In a competitive and well informed electricity market it is reasonable to assume that competition among retailers would lead to efficient prices and services. In an ideal scenario prices would reflect the true value of the electricity supplied taking into account the time and location the electricity is produced, and the demand at that time and location. If the price is determined in a competitive retail market, it is reasonable to assume that this would be consistent with a ‘fair and reasonable’ price. It is relevant therefore to consider whether there is effective competition in the Victorian electricity retail market.
Since 2002, when full retail competition commenced, Victorian electricity customers can choose their electricity retailer from an increasing pool of retail businesses. The extent to which consumers are exercising choice is partly reflected in the number of customers transferring between retail businesses. Recent data on customer transfers each month is shown in figure 8.1. VaasaETT (2012, p.17) reported that the Victorian electricity market has the highest levels of customer switching across 32 different electricity markets worldwide.
1 The concept of fair and reasonable has been interpreted by many participants as meaning one-for-one, consistent with the Essential Services Commission guideline (ESC 2008). To avoid confusion chapter 9 uses the term ‘efficient and fair’ when referring to a FiT based on the wholesale price of electricity.
SELLING ELECTRICITY 147 Figure 8.1 Monthly small customer transfers between retailers: February 2010 to February 2012
75000 70000 65000 60000 55000 50000 45000 40000 35000 30000 25000 20000 15000 10000 5000 Jul-10 Jul-11 Jun-10 Jun-11 Apr-10 Apr-11 Jan-11 Jan-12 Feb-11 Feb-12 Sep-10 Sep-11 Oct-10 Oct-11 Mar-10 Mar-11 Mar-12 Nov-10 Nov-11 Aug-10 Aug-11 Dec-10 Dec-11 May-10 May-11
VIC NSW QLD SA
Source: AEMO 2012b, p.1.
Recent reviews of the effectiveness of retail electricity market competition in Victoria
The draft report noted recent reviews of electricity retail competition in Victoria, in particular by the Australian Energy Market Commission (AEMC) which released its final report of a Review of the Effectiveness of Competition in Electricity and Gas Retail Markets in Victoria in 2007 – in which competition in the Victorian electricity retail sector was found to be effective (AEMC 2007, p.viii). The findings of the AEMC review formed the basis for removing electricity (and gas) retail price regulation in Victoria in January 2009.2
In the draft report the Commission observed that (while the review undertaken by the AEMC was in the context of the market for the retail supply of electricity) the AEMC finding is a useful indicator of the effectiveness of competition in Victorian FiT market. However, in practice, retailer processes and responsiveness to attracting new customers appear to be more active in the retail electricity supply market than for distributed generation. Reasons for this may include:
• The complexity of the decisions involved in assessing the case for installing distributed generation and selling the excess electricity is greater than for purchasing electricity alone.
2 Section 13 of the Electricity Industry Act 2000 (Vic) allows for the reintroduction of price regulation in the event that the AEMC concludes that competition in the retail market for electricity is not effective and recommends price controls be reintroduced. (This would be based on the findings of a Ministerial Council on Energy (now SCER) directed, review by the AEMC).
148 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • There is currently a lot of change in the broader regulatory environment for retail customers, including distributed generators. This is likely to add to the uncertainty and confusion in the market in the near term. • Many retailers and most, if not all, major retailers own centralised generation assets which may affect their incentives to offer competitive tariffs to distributed generation that potentially competes with their own generation businesses. • Some sectors of the market have emerged only recently. Consumers and retailers have not had the opportunity to develop systems and expertise and gain the experience needed to compete in the electricity market.
Current feed-in tariff offers
Current FiT legislation requires electricity retailers to publish their FiT offer terms and conditions relating to each of the FiT schemes in the Government Gazette and on their website. AGL made the point that most electricity retailers voluntarily offer FiTs higher than the regulated rate for renewable embedded generation. AGL stated that it ‘believes that no market failure has been identified which justifies additional mandated feed-in tariff policies being introduced or maintained’ (sub. 72, p. 2). Responding to the draft report, Origin Energy commented:
It is important to emphasise that from the perspective of a retailer, most customers with embedded generation will remain fundamentally purchasers of energy from the grid. Retailers have an incentive to retain these customers as they will provide a return in a competitive market place. (sub. DR196, p. 10)
The information provided on Victorian electricity retailer websites and in the Government Gazette is summarised below (table 8.3). While this may not fully reflect the complete range of offers in the FiT market (TRUEnergy, sub. DR198, p.2) it does highlight that some retailers offer FiTs in excess of the TFit and PFiT statutory minimum tariff price. The additional or ‘top up’ amount is between 4 and 8 cents per kWh — this may reflect the additional value to the retailer of the solar PV generated electricity.
SELLING ELECTRICITY 149 Table 8.3 Example of retailer feed-in tariffs Transition Standard FiT Premium Retailer Distribution zone al FiT c/kWh FiT c/kWh c/kWh Jemena – Domestic General 25.1 Jemena – Small Business 26.3 United Energy – Domestic General 24.2 United Energy – Small Business 28.3 AGL CitiPower – Domestic General 22.7 33 68 CitiPower – Small Business 25.1 Powercor – Domestic General 26.0 Powercor – Small Business 28.9 SP Ausnet – Domestic General 26.3 SP Ausnet – Small Business 30.3 Australian Power All 1-for-1 25 60 and Gas Click Energy All 1-for-1 29 64 Country Energy All 1-for-1 31 60 Diamond Energy All 1-for-1 33 68 peak Dodo All electricity 25 60 rate Energy Australia All 1-for-1 25 60 Lumo All 1-for-1 31 66 Momentum All 1-for-1 25 60 Neighbourhood All 1-for-1 25 66 Energy not less than Origin All 31 66 1-for-1 Jemena – Domestic General 25.1 Jemena – Small Business 26.3 United Energy – Domestic General 24.2 United Energy – Small Business 28.3 Powerdirect CitiPower – Domestic General 22.7 31 68 CitiPower – Small Business 25.1 Powercor – Domestic General 26.0 Powercor – Small Business 28.8 SP Ausnet – Domestic General 26.3 SP Ausnet – Small Business 30.3 Red Energy All 1-for-1 33 68.2 Simply Energy All 1-for-1 25 60 TRUenergy All 1-for-1 31 60
Note: As at 19 June 2012 Sources: DPI 2012i and Commission analysis.
150 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION In contrast to the point made by AGL, some participants such as Ceramic Fuel Cells Limited (CFCL) argued that, from their experience, retailers are reluctant to offer, what they considered to be a ‘fair and reasonable’ FiT, if there is no requirement to do so (sub. 41, p. 16). Warburton Community Hydro Project also referred to difficulties in reaching agreement with retailers:
… our project has had some difficulty in identifying retailers willing to enter into an agreement with us under the SFiT. This is in large part due to the lack of similar projects as ourselves, and the overwhelming number of households seeking connection under the PFiT. In large retailing organisations it has been difficult to find the person or team responsible for SFiT’s, even when they publicly publish documents or websites stating they do offer such arrangements in line with the legislation. Those that do offer them often limit them in terms of MWHrs annually, which seems to us not to be in the intent or legislation of the SFiT. (sub. DR69, p. 3)
Commenting on the draft report Dandenong Ranges Renewable Energy Association argued that:
The biggest flaw in the draft report we think, is the assumption that the market will deliver a “fair and reasonable price” for exported electricity. We believe that a minimum price must be mandated (as the Clean Energy Council has recommended). After the NSW government closed their mandatory feed in tariff, customers were receiving nil payments from their electricity retailers for green power fed into the grid. (sub. DR114, p. 1)
The Mildura Development Cooperation also remarked that
It is apparent that there is ineffective competition in the electricity retail market from the customer’s point of view…We suggest that the obligation to offer a feed in tariff be maintained until a public audit of the retail market confirms there is sufficient competition and demand in the feed in tariff market. (sub. DR177, p. 3)
In the presence of a competitive market for electricity from distributed generation, there is no rationale for government intervention, unless it can be demonstrated that there are significant impediments (market failures) that would lead to inefficient outcomes. While there is sufficient evidence to suggest that the retail electricity market is competitive, participants were concerned that retailers are not as responsive to distributed generation. For example, unlike the process for changing retailers to supply electricity, signing up to a FiT is complex and lengthy.
These experiences raise questions about whether the market behaviour of those purchasing electricity from distributed generation reflects that which would be expected in a competitive market that would set ‘fair and reasonable’ FiTs.
Market power issues: vertical integration of retail energy businesses
Some participants claimed vertical integration of electricity retailers with upstream generation facilities affects the incentives retailers face when engaging with, and offering a FiT, to small and medium-scale (or aggregated groups of) generators. The Australian Solar Round Table considered that:
The market for power from distributed and embedded generation is distorted by an imbalance of market power. A small number of players dominate the market. (sub. 56, p. 9)
SELLING ELECTRICITY 151 Responding to the draft report the Alternative Technology Association stated that:
… vertical integration of retail and centralised generation businesses is a significant barrier to the proliferation of DG. ATA however disagrees that new retailers entering the market, or the AEMO generator aggregator Rule Change, will address this barrier. Importantly, ATA contends, new entrants in the Victorian retail market are unlikely to improve the level of competition in the market for the purchase of electricity from DG … three retailers control approximately 70% of the retail market for electricity. Each of these ‘big three’ also has substantial generation assets in the energy market. What is perhaps less well known is that the majority of the remaining second and third tier retailers also own substantial generation assets (for example, Red Energy owns Snowy Hydro; Momentum is Hydro Tasmania’s retail arm). To the best of ATA’s knowledge • only three of the second/third tier retailers (Australian Power and Gas, Click Energy and Dodo) do not own generation assets • only one of these ‘independent’ retailers (AP&G) has more than 5,000 customers (the current legislative trigger that requires retailers to offer a feed-in tariff in Victoria). (sub. DR189, pp. 3,5)
While there are significant ownership links between the electricity retail market and upstream electricity generation production (including in renewable energy) (box 8.1) the Commission considers that, notwithstanding comments made by the ATA, following a transition period, the capacity of new retailers to enter the market will help offset the incentives that result from vertical integration.
The Commission is proposing a transition period (chapter 10), within which the Victorian Government can assess progress in Victoria and other jurisdictions (including NSW which has deregulated FiTs) to determine whether vertical integration and ownership structures are impeding the development of competitive FiTs in practice.
152 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Box 8.1 Examples of ownership links between electricity retailers and upstream energy production AGL Energy • owns wind farms • owns 10 hydro-electric generating schemes (16 power stations in Victoria and New South Wales) • owns and operates two gas fired electricity generation plants in South Australia and Victoria • has a 32.5 per cent equity investment in Loy Yang Power (one of Australia’s largest coal-fired power stations) • owns and operates several renewable landfill gas and biogas (sewage) generation facilities • owns and operates a 4.4 MW gas fired co-generation plant at Symex Holdings in Port Melbourne • AGL, with First Solar (Australia) Pty Ltd, delivers large-scale solar PV power projects totalling 159 MW at Nyngan (106 MW) and Broken Hill (53 MW) in New South Wales. Origin Energy • has a generation portfolio of 5310 MW • operates eight power stations (mainly gas fired) • has a 50 per cent interest in three co-generation plants • owns a wind farm facility. TRUenergy • owns and operates a portfolio of electricity generation facilities, including coal (Yallourn in Victoria), gas and wind assets. Snowy Hydro • owns Red Energy. Hydro Tasmania • owns Momentum Energy. Sources: Commission analysis of retailer websites.
8.3.2 Structural issues
The current regulated structure of the electricity industry impedes the establishment of fair and reasonable FiTs. It separates retail, distribution and generation businesses and, while distribution network service providers (DNSPs) and transmission businesses operate under a price or revenue cap, the retail sector operates in a competitive market. These structures can impact the incentives faced by retailers, particularly when they may not be able to access the full benefits of electricity exported by distributed generators.
It is important to note that due to the disaggregated centralised energy supply chain in Australia, no one business in this supply chain can capture the full value of the distributed energy. This acts to dilute the incentive to invest, and has the potential to result in significant investments that do not achieve socially efficient energy supply. (CSIRO 2009, p. 40)
SELLING ELECTRICITY 153 However, this issue is most likely to be resolved by amending the broader network regulatory arrangements to reinforce the incentives to accommodate distributed generation efficiently. As noted by ACIL Tasman:
Our view is that it would be more appropriate to address any shortcomings in the economic regulatory regime by changing those arrangements than by adding to the complexity of regulated FiTs. (ACIL Tasman 2012c, p. 44)
For the reasons outlined in chapter 4 the Commission’s view is that a FiT is not the appropriate regulatory instrument to address deficiencies in the structure of the electricity market. Chapter 4 discusses how broader network costs and benefits that accrue to distribution businesses could be recognised. The discussion notes that without alternative means of recognising these values, a FiT will be less than the full value of the electricity generated in locations where distributed generation has network benefits.
8.3.3 Information and transaction costs
In a well-functioning market, both the seller of electricity (the owner of the distributed generator) and the purchaser (the retailer) would have access to sufficient information to make informed decisions and complete transactions. While having access to information is critical, it is also important that the information is in a form that is clear and accessible to the customer.
As noted by the AEMC:
When consumers are unable to access necessary information, or the information which is available is perceived to be complex and costly to decipher, there is a risk that consumers (or specific groups of consumers) are not sufficiently well-informed. Consequently, consumers may make inefficient decisions. (AEMC 2011e, p. 29)
Two potential problems may arise. First, information may be costly to obtain, particularly for individuals participating in the small-scale distributed generator market. Without adequate information, individuals may decide to not participate in the market, leading to less distributed generation than is optimal. Alternatively, they may make poor decisions where the products they purchase do not deliver the outcomes they expect. Second, there may be information asymmetries, where one side of the market (for example, the retailer) is more informed about the benefits and costs of the electricity being fed into the distribution system. ACIL Tasman noted that:
Distributed generators, particularly residential and small business customers, generally do not have perfect information as to the true value of the electricity they would export to the grid… (ACIL Tasman 2012c, p. 41)
This additional information could be used by the retailer to negotiate a price that is lower than what would have been achieved if all parties had access to the same information.
The Energy and Water Ombudsman Victoria (EWOV) noted that:
Between 1 January 2011 and 31 December 2011, EWOV received 8,524 solar cases and registered 17,993 solar case issues. During this period, 21% of these cases - 1,805 cases and 3,229 issues - were about issues with the application of the Premium Feed-in Tariff (PFiT) and Standard Feed-in Tariffs (SFiT). (sub. 48, p. 1)
154 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION A case study provided by EWOV highlights some of the difficulties faced by consumers, particularly when incorrect information is provided.
The customer owns two properties and decided to place solar panels on his holiday home after his electricity retailer confirmed in writing that he will be able to receive PFiT credits for this property. However, after the panels were installed he received a PFiT form that stated eligibility required the residence to be the primary residence of the customer. The electricity retailer subsequently confirmed that he will not be able to receive PFiT credits for this property. As a result of EWOV's investigation, the electricity retailer paid the customer $2,800 in recognition of providing incorrect information. (sub. 48, p. 3)
The Commission notes cases come to EWOV only after customers have been unable to resolve their complaint directly with their electricity retailer or DNSP and have subsequently chosen to take the complaint further. Further information from EWOV on household issues is shown in chapter 7.
Ideally data would be publicly available to allow FiTs to be compared. In this regard, the Commission notes that the Electricity Industry Act 2000 (Vic) requires Victorian retailers to publish FiT information (including tariffs and terms and conditions) as part of their retail licence conditions.
To assess the availability of this information in practice, the Commission reviewed the extent of information on FiT offer terms and conditions available online. A number of non-governmental organisations and businesses publish price comparator information, including the Moreland Energy Foundation Limited (MEFL 2009) and Energy Matters (Energy Matters 2009). However, much of this information is out of date. The ESC’s ‘YourChoice’ website, allows comparison of retail electricity supply offers, but does not allow direct comparison of FiTs.
The Commission also visited electricity retailer websites to compare the information available on FiT offers. The Commission considers that retailers present the terms and conditions of their FiT offers in different formats and it is often hard to find information on specific terms and conditions, making it difficult to compare offers across retailers. In some cases electricity retailers have combined all offers into one set of terms and conditions; in others they have separated the offers into discrete terms and conditions. This situation makes it difficult for consumers to make informed choices.
This is consistent with IPART’s observations on information disclosure by retailers operating in New South Wales:
We are concerned that the current practices of retailers in disclosing the key features of their [FiT] offers are not assisting customers to assess these offers and make well informed decisions. (IPART 2012, p. 99)
IPART, in recommending a benchmark range for a ‘fair and reasonable’ FiT, argued that:
… our recommended form of regulation needs to be supported by actions to improve the quality and accessibility of information available to customers about the financial consequences of installing PV generation and retailers’ voluntary feed-in tariff offers. (IPART 2012, p. 98)
SELLING ELECTRICITY 155 These supporting actions included:
• Ensuring that retailers provide information to customers that is accurate, clear and concise – including information provided via call centres and door to door marketers. • That the NSW Government and the solar industry provide clear information to customers about small-scale solar PV, including the potential financial consequences to households and small business customers who choose to install solar PV units. (IPART 2012, p. 98)
Information and transaction cost issues — including those resulting from the complexity of the market, and a changing regulatory environment — were discussed in chapter 4. In addition, consumer regulation in the retail electricity market is in a state of flux as responsibility is expected to shift to the AER and new connection processes and charging regimes introduced. But the timing of these changes has not been agreed, adding further to uncertainty in the market.
8.3.4 Limitations on time-of-use and locational pricing
Electricity use varies widely depending on the time of day and season. At times there are large peaks in demand which drive much of the cost of generating and supplying electricity. Large peaks in demand may cause network congestion in particular locations, and lead to increases in the wholesale price of electricity when this is supplied from more expensive peak supply sources (for example, gas-fired generators).
Time of use and location have two elements that impact on the value of distributed generation:
• Output value — output from distributed generation will have more value in locations where the system losses from transporting electricity from centralised generators are high and at times when demand is at its peak so the costs of purchasing electricity on the wholesale market are high. These values should be reflected in an efficient FiT and provide incentives for people to invest in distributed generation. • Network value — at locations where the network is congested there is additional value to distributed generation that produces at times when the extra local supply delays network investment. The Commission has concluded that FiTs are not a good way to approximate or reward distributed generation for this capital value (chapter 4).
Smart meters can allow consumers to monitor their electricity use more closely and make more informed decisions about when and how they use electricity. Having access to time-of-use and locational pricing information would also allow customers considering installing distributed generation technology to access better information to guide their decisions.
As noted by ACIL Tasman:
Peak demand, or a closer proxy such as the maximum electricity consumed in any half hour interval, will be able to be measured with the smart meters that are currently being installed in Victoria. However, there is currently a moratorium preventing the additional information collected by these meters being used in retail electricity pricing, although it has recently begun to be used in settling the wholesale market. Customers with smart meters are being billed as if they had the historic type of
156 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION meters. This will continue for as long as the moratorium is in effect, until 2013. (ACIL Tasman 2012c, pp.27–28)
A submission by Alan Pears noted that time-of-use pricing provides an incentive to shift electricity consumption to times when lower marginal cost generators (eg coal power stations) are available and the network is under-utilised [and that] given that higher TOU [time-of-use] prices tend to apply in afternoons and early evenings, a substantial proportion of the output of PV systems may avoid high priced electricity. [However] present TOU pricing in Victoria is crude [and] high prices from 7am to 11pm weekdays make it very difficult to change behaviour to capture lower prices’ (sub. DR192, p. 8).
… carefully designed TOU pricing structures, along with energy storage and smart load management systems, could avoid or reduce regressive impacts and empower energy users to change behaviour. (sub. DR192, p. 8)
Access to better information (price signals), within a competitive electricity market is likely to lead to FiTs that better reflect the value of distributed generation. The Commission notes that there is currently a ban on the rollout of time-of-use retail prices before 2013. Modelling undertaken by Deloitte Access Economics indicated that banning time-of-use tariffs until at least 2013 delays about 24 per cent ($490 million) of the estimated benefits of smart meters, the proportion of the benefits attributable to time-of-use tariffs and demand management (DAE 2011, p. 13).
8.3.5 Conclusion
The predominant view expressed by proponents was that retailers are far less responsive to customers supplying electricity from distributed generation than in competing for customers without distributed generation.3 For example, unlike the process for changing retailers to supply electricity, the processes for signing up to a FiT is complex and lengthy. Distributed generation proponents, particularly in areas not subject to regulated FiTs, have found it difficult to negotiate a FiT for electricity fed into the network. The Commission formed the view that the incentives for retailers to compete for customers with distributed generation were, on the whole, weaker than incentives to compete for non-distributed generation customers. These experiences raise questions about whether the market behaviour of those purchasing electricity from distributed generation reflects that which would be expected in a competitive market that would set ‘fair and reasonable’ FiTs.
The Commission considers the underlying causes of these difficult, complex and lengthy processes include:
• information and transactions costs • market power issues • limitations on time of use and locational pricing • uncertainty of the regulatory environment, coupled with the transition to a national regime.
On its own none of the above factors constitutes a market barrier sufficient to prevent competitive outcomes from emerging (as long as adequate consumer protection,
3 This may simply reflect the relative profitability of customers with distributed generators to retail businesses when compared to other non-distributed generation customers — which is likely to vary between retailer business models.
SELLING ELECTRICITY 157 transparency and information is provided) combined they are likely to present significant short term barriers.
Several of the changes in the NEM that are underway or have been foreshadowed are likely to reduce these barriers, as will the Commission’s recommendations in chapters 5 and 6, if accepted. Other aspects can be addressed through consumer protection, reasonable access to information and maturing of the market. Accordingly, the Commission considers a market-based FiT is likely to provide the most efficient outcome in the long term. However, there are important transition issues and in the short term moving too rapidly to market determined FiTs may cause unnecessary disruption and hinder the transition to a fully competitive market. Observation of the electricity market in Victoria and NSW over the transition period would provide further evidence on how FiTs are performing and whether further measures to improve market outcomes are justified. These issues are discussed further in chapter 9 and 10.
8.4 Impacts of other policy settings on medium- scale distributed generation
Beyond the barriers to connection of distributed generation (chapter 6), several participants pointed to difficulties caused by the impact of current policy and regulatory settings on the ability of medium-scale distributed generators to sell the electricity produced. These concerns related to:
• the ability of medium-scale generators to attract a fair and reasonable FiT • constraints on medium-scale generators selling electricity through the grid (including through private networks).
Medium-scale generators have a range of options on how they can or would like to sell electricity. Some of these, such as becoming a market generator or selling to a retailer, involve selling electricity at a wholesale price. Other suggested approaches would involve selling to retail customers. While this may be attractive to some distributed generators it currently has practical and regulatory challenges.
Alan Pears noted that distributed generation competes with the existing electricity industry to deliver electricity services:
… but it is not allowed to compete on equal terms, because a distributed generator is not allowed to sell its electricity across property boundaries. This is an artefact of the way the present electricity market has been designed … (Pears 2012)
The Energy Efficiency Council (EEC) also noted that:
Where distributed generators sell all these services to a small numbers of clients directly they can capture [much of the benefits of DG]. However, there are a number of regulations that impede these transactions, such as requirements for competition in electricity supply. (sub. DR200, p. 10)
For example, participants (roundtable meetings) noted that the consequences of current regulatory requirements (for selling electricity) become more acute when a distributed generator proponent wishes to sell electricity to one or more adjacent buildings — where the installation of a shared co-generation facility would provide a more efficient solution.
158 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION An option is for the developer to invest in infrastructure to share the electricity between the various buildings. However, ClimateWorks claimed that the proponent would face commercial barriers to selling the electricity as:
• businesses expect that negotiating with a retailer to sell electricity onto the grid from the cogeneration plant and purchase it from the grid for the other buildings will result in unfavourable terms • becoming a retailer, even if exempt from the requirements of the retail licence (or future authorisation under the NECF), involves significant administrative and working capital costs. (ClimateWorks et al. 2011, p.30)
Under the proposed National Energy Customer Framework (NECF), electricity retailers will be regulated by a retailer authorisation and exemption regime, administered by the Australian Energy Regulator. Under this framework, sellers of electricity will be required to have a retailer authorisation or be exempt from the requirement to have an authorisation. The AER has published an Exempt Selling Guideline (2011f), which sets out its approach to retail exemptions and the types of available exemptions: deemed, registrable and individual exemptions. The AER may grant a retail exemption subject to specific conditions.
The Exempt Selling Guideline advises that decentralised energy (including on-site co- generation and tri-generation) will be treated as an ‘exempt seller characteristic’ and on-site distributed generators will need to apply for an individual retail exemption on a case-by-case basis. The Guideline states that the AER: ‘will grant exemptions in these situations where the initiative is in the long term interests of energy consumers having regard to all of the criteria and factors we are required to assess’ (AER 2011f, p.17).
Even for those seeking to sell at the wholesale price it is argued that the processes are costly and difficult. Costs of becoming a market generator are discussed in chapter 2.
For distributed generators negotiating a price with retailers for electricity exported to the grid, the Commission considers that competition in the retail market (as it further develops), and recent ‘aggregation’ and ‘right to export’ rule changes being considered by the AEMC reduce the risk of negotiations resulting in unfavourable terms for the distributed generation proponent. The Commission’s view on the recovery of network benefits (due to deferred augmentation) is discussed in chapter 5.
A number of these issues are also being considered by the AEMC in its review of demand side participation in the NEM. In particular it is considering:
Efficient options which enhance the ability of a DG installation … to sell their demand response services to parties other than their existing retailer (AEMC 2012f, p.161)
The AEMC review will consider portability and licence exemptions for retail and network activities. These issues have been raised by participants in this inquiry.
As noted by the AEMC (2012) there is a number of options to facilitate the portability of energy produced by a distributed generator – including the use of ‘subtractive metering’. Subtractive metering involves using a ‘parent’ meter to monitor total use at a site and a ‘child’ meter to measure the load or generation at a subsidiary connection point behind the parent meter. However:
While subtractive metering (in the context of an embedded network) is currently allowed in the NEM, it is not universally endorsed by retailers and distributors due to the perceived complexities associated with defining the
SELLING ELECTRICITY 159 party responsible for metering at the ‘child’ connection points. (AEMC 2012f, p.175)
According to AEMO (2012a, p.3)this situation is ‘due to regulatory uncertainty introduced by a lack of relevant regulation in the Rules’. AEMO has called for ‘the regulatory framework for subtractive metering [to] be clarified and formalised.’
The Commission considers that the AEMC review of demand side participation is the appropriate review mechanism to evaluate perceived constraints on distributed generators selling electricity and engaging in value creating activities in the electricity market. The evaluation should recognise that distributed generation is part of a suite of activities that can contribute to effective and efficient demand side participation.
Precinct scale
The parties interested in large-scale precinct projects were concerned about many of the problems raised above but also face some specific issues relating to:
• planning • ability to enter longer term contracts with customers • lack of regulation covering the provision of district heating and cooling networks, including access rights for infrastructure on public and private land, and tariffs for the sale of heating and cooling to customers.
According to Prendergast Projects, developers are now ‘investigating methods of energy efficiency and maximisation GHG [greenhouse gas] emission reduction at a precinct scale’(sub. DR185, p. 1). Importantly they also state that:
The development of low emission centralised heating, cooling and/or trigeneration systems is often more efficient at a precinct level due to economies of scale and non-simultaneous demands of a variety of different building types…In all precinct scale projects they would not occur without a central coordinating organisation, and the willing participation of local developers, building owners and tenants. (sub. DR185, p. 3)
Precinct-scale projects involve a number of parties, including but not limited to: facilitators of large-scale urban renewal (for example, Places Victoria), land developers, local government, regulators (for example, energy and environmental), businesses, community groups, utilities (electricity, gas and water), building designers, architects and alternative technology proponents. Interest in distributed generation has extended to interest in precinct-scale opportunities in a number of Australian and overseas jurisdictions (box 8.2).
The City of Melbourne noted that:
There exists … several precincts where urban renewal and redevelopment of previously industrial sites will require the provision of new energy infrastructure. Specifically, these sites include Fisherman’s Bend, E-Gate, and the underdeveloped remainder of Docklands. Infill development will occur in the City North, Southbank and Arden-Macaulay … When developing infrastructure in these precincts, there exists opportunities to future proof infrastructure to enable distributed generation connections … Establishment of distributed generation in these areas would ease pressure on networks upstream and assist in meeting the City’s objectives of decarbonising the electricity supply…The City would support initiatives that
160 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION address the delivery of future infrastructure and would welcome the involvement of the DPI and the State Government in addressing these issues. (sub. DR185, pp. 1-2)
Precinct-scale projects are prone to complex and uncertain regulatory rules. Uncertainty includes difficulty identifying the likely problems, lack of clarity about how and whether the existing regulatory structures can resolve those problems and, if not, what other solutions need to be developed.
Box 8.2 On-selling of distributed generation in the United Kingdom and Sydney As part of the consultation process to develop the Exempt Selling Guideline, the Australian Energy Regulator published an issues paper on retail exemptions in June 2010 and invited submissions from interested parties. A submission from the City of Sydney discussed the Woking and London models in the United Kingdom (UK) and the proposed Sydney model, part of the municipality’s Decentralised Energy Master Plan 2010-2030. In the UK, decentralised energy was stimulated by the Electricity (Exemption from the Requirements for a Licence) Order 2001 which led to the Woking private wire and other decentralised energy systems. These were class exemptions, so permission was not required from any of the vested interest energy players, including the distribution network operator, or the regulator – the Office of Gas and Electricity Markets (Ofgem). Compliance with the order was sufficient to implement decentralised energy projects. The exemption supply limits were 50 megawatts (without Secretary of State approval) or 100 megawatts (with Secretary of State approval) for each generation site over private wires. This enabled significant growth in non-residential supply. However, the exempt limit for home use was only one megawatt (about 1,000 homes) for each generation site with limited exempt aggregated supply over public wires. This enabled the growth of decentralised energy in towns and cities such as Woking and London and led to the enactment of the Electricity Supply Licence Modification 2009 or local electricity supplier licenses to retail electricity over the local public wires distribution network based on the ‘virtual private wire’ over public wires principle… The City of Sydney model will utilise and take advantage of the knowledge and features of both the Woking and London models but adapted for the City of Sydney environment. The barriers to decentralised energy and the solutions to those barriers are very similar to those encountered in the Woking and London models. Therefore, the strategic direction for the City’s own trigeneration and renewable energy projects for its own property portfolio will need to follow the foregoing principles by establishing decentralised energy projects specifically designed to trade electricity with each other across the local distribution networks using the ‘virtual private wire’ concept and to utilise and incorporate other related monitoring and control systems, such as Building Energy Management Systems, monitoring and targeting software and metering, to provide a ‘smart grid’ approach to delivering the Sustainable Sydney 2030 targets. Sources: City of Sydney 2010, pp.3–4, appendix 1: 10–11; AER 2010a.
SELLING ELECTRICITY 161 Given the complexities associated with precinct-scale developments the Commission is not in a position to recommend specific solutions. The Commission however, does see merit in the Victorian Government sponsoring a combined approach to identifying, evaluating and addressing some of these issues, as broadly proposed by ClimateWorks (2011).
The Commission considers that the most effective way to identify practical solutions to the barriers to precinct scale projects is to focus on one or more projects to identify the problems and develop solutions. This information would inform future projects and the removal of unnecessary regulatory and administrative barriers. Such a process would involve:
• Selecting one or more precincts where there is a strong preliminary business case for distributed generation and using these projects to identify likely problems and solutions. • Establishing a project facilitation group, consisting of relevant stakeholders (developers, regulators, utilities, community representatives etc.) to examine barriers to distributed generation, identifying practical solutions and undertake an assessment of the costs and benefits (including any competition and longer term cost impacts on Victorian electricity consumers) of removing these impediments. Action to remove these impediments should be undertaken where a clear net benefit is identified. • Documenting the results of the project facilitation groups’ efforts so they can inform government, industry and community organisations, and inform future precinct-scale distributed generation projects and government policy directions.
As precinct-scale processes involve an array of government approval and regulatory processes there is a case for the State to take a role in supporting and facilitating early projects. Given that Government is likely to have greater expertise and authority about their own processes, facilitation by Government is likely to be less costly than private sector facilitation.
Recommendation 8.1 That, to inform future policy development, and assist in the efficient consideration of distributed generation options, the Victorian Government facilitate precinct scale development by: • Selecting an appropriate precinct scale project, or projects, and bringing relevant interested parties together in a project facilitation group. • Taking the new precinct development and thoroughly examining the regulatory and other barriers to distributed generation including the net benefit of reducing or removing those barriers. • Subject to the outcome of this assessment, taking action to remove the barriers. • Documenting the results and disseminating the information to government, industry and community organisations to inform future precinct scale distributed generation projects and policy directions (electricity, planning etc.).
162 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 9 Future Victorian feed-in tariff arrangements
The terms of reference require the Commission to:
(1) assess the design, efficiency and effectiveness of feed-in tariff (FiT) schemes, including market-based gross FiT schemes, in the context of a national carbon price (2) provide a recommendation as to whether existing FiT arrangements should be continued, phased out or amended. Where phase-out of existing arrangements is proposed, the appraisal should give consideration to whether any transitional arrangements may be necessary. Any changes to existing arrangements would not be applied retrospectively.
This chapter addresses these two issues, with the exception of transitional arrangements which are discussed in chapter 10.
In approaching these issues the Commission considers that distributed generation (including renewable and low-emission technologies) should contribute to achieving the National Electricity Objective (NEO), in a way that improves efficiency and effectiveness without cross subsidies. The key to achieving these outcomes is to identify the sources of economic value from distributed generation and strengthen the competitive frameworks and market-based incentives for achieving that value, having regard to the carbon tax introduced on 1 July 2012.
The two key components of value from distributed generation are the output value (which includes system losses and now incorporates the carbon tax) and the network value (discussed in chapter 4). The output value refers to the value of the electricity actually generated, for which price (or FiT in the case of ‘household-scale’ generators) is the right charging mechanism. The Commission has assessed the design, efficiency and effectiveness of current and potential FiT schemes against the principles outlined in chapter 4 to ensure:
• incentives reflect economic value • no cross subsidies • efficient assignment of policy instruments • technology neutrality • efficient and predictable processes.
Turning to the second term of reference, the Commission recommends that any changes to the existing FiT arrangements should ensure that customers already on these schemes continue to receive existing FiTs according to their existing contracts and previously announced Government commitments on completion dates.
In the draft report the Commission concluded that future FiTs — which more accurately reflect the output value of electricity for household-scale distributed generation — should be determined in a competitive retail market. Market determined FiTs would not discriminate against particular technologies or customers, rather they would be based on the value of the electricity supplied by distributed generators (which would include the impact of the carbon tax and reduced network losses). This deregulation would be supported by consumer protection and information measures, and be phased in to maintain certainty that the market will continue to offer a competitive FiT. Existing contractual arrangements would be maintained.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 163 While some inquiry participants supported the Commission’s draft recommendation to move to a market-based FiT, many were critical of the approach. Many participants argued that the proposed market FiT was too low, or that market-based FiTs would not be offered without government regulation. The participants who were sceptical that the market would deliver fair and reasonable FiTs pointed to a lack of competition among retailers, or retailers being conflicted because they own upstream generation or have business models that do not value buying power from distributed generators (chapter 8).
Several methodologies were proposed for calculating ‘fair and reasonable’ FiTs, with numerous justifications or reasons as to why those methodologies would be appropriate. A sample of views is presented in table 9.1.
Table 9.1 Methodologies proposed by participants
Methodology Rationale/justification proposed by inquiry participants
One-for-one The FIT offered to householders needs to be, as a minimum, equal to (a FiT equal the retail electricity price. The provision of such an incentive is largely to the retail offset in cost by the reduction needed in expensive peaking power price of generation and by reduced demand on the distribution system which electricity) can fail at times of peak demand. (David and Pamela Rothfield, sub. 66, p. 1) The proposal to end the current 1:1 standard feed-in tariff … will significantl[y] damage investment in solar energy… electricity retailers will be able to buy power from a solar producer at a lower cost than what they sell power for – effectively giving money to the retailers instead. (Anthony Jones, sub. DR123, p.1) … a fair ongoing incentive would be that the price paid to the consumer/generator … should be at least equal to the price at which he purchases power from the grid to make him ‘neutral’ as between his own power and grid derived power. (John Sime, sub. DR153, p. 1) … a 1:1 FiT combined with time of use pricing (ie payment for exports would be equal to the retail price of zero (or low) emission electricity at the time of export) … it would be economically efficient. It would also recognise lower emission options both through the carbon price included in the benchmark retail price and through further adjustments in the up-front incentive based on spill over abatement benefits and correction of distortions in carbon pricing. (Alan Pears, sub. DR192, p.10)
164 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Table 9.1 Methodologies proposed by participants (cont)
Methodology Rationale/Justification proposed by inquiry participants
Payback Any cut to the SFIT regime before [a] 6-7 year pay back will have a period materially detrimental impact on the industry who needs to have ROI [return on investment] certainty in order to invest in solar (and other renewable generation). (Enviromate, sub. DR133, p. 1) … for our project [a ‘75-90kW run-of the river Hydro Scheme’], feasibility is comfortably achieved at FiT equal to retail prices (the current arrangement, and our expectations when the Project planning work commenced)… Feasibility fails at under 15 cents per kwH. If the new FiT Policy leaves us completely at the mercy of market forces, and wholesale market rates as low as 10 cents or less per kwH, we will have no choice but to cancel the Project immediately. (Warbuton Hydro Group, sub. DR167, p. 2) As prices are still too high for systems to pay back in a reasonable period, and because rebates have been wound back, feed-in tariffs are the main way of providing incentives for the uptake of solar systems and are therefore essential. (Jenny Francis, sub. 39, p.1) A sensible FiT will drive additional investment in distributed energy if a financial business case is clear and acceptable to investors… FiT rates that would drive an acceptable return (i.e. 5 to 7 yrs) for the case studies considered are comparable to recent premium FiTs in Australian states. (PCA, sub. DR191, pp. 22, 24)
Market We agree that the true value of distributed generation to energy determined retailers represents the avoided wholesale energy cost … network value should not be captured in a widely-available FiT offer, given the location and time-dependent factors governing the true value of distributed generation to the network. (Simply Energy, sub. DR172, p. 3) … establishing a fair and reasonable value for solar PV should be left to the market. Competition will help drive an efficient outcome. (ESSA, sub. DR194, p. 1) … a “one for one” FIT paid only by one participant in the supply chain for energy (the retailer) is inequitable and has proven costly to electricity retailers and their stakeholders. [We] strongly support a transition to a market based tariff to apply to the standard FIT as soon as possible. (Origin Energy, sub. DR196, p. 1)
Allowance DG [distributed generation] that generates electricity during the for merit daytime, such as solar PV, materially reduces the wholesale energy order effect cost paid by all consumers. In a competitive market for the sale of energy, this benefit, known as Merit Order Effect (MoE), would flow through to all electricity consumers in the form of lower electricity prices … Given the level of vertical integration present in the Victorian market … ATA do not understand how the market, and more specifically the majority of electricity retailers, acting under their own commercial imperatives, could possibly ensure that over the longer term, fair and reasonable value for electricity from DG will be paid to DG proponents. (ATA, sub. DR189, pp. 8-9)
Source: Commission analysis of submissions.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 165 Further discussion of the impact of lower FiTs on the attractiveness of installing solar panels and the viability of the solar industry is provided in chapter 10.
9.1 Design, efficiency and effectiveness of feed-in tariff schemes
Consistent with terms of reference 1, this section addresses a range of design, efficiency and effectiveness issues including:
• the value of distributed generation • market-based FiTs • eligibility • net or gross metering • information provision • billing arrangements.
9.1.1 The value of distributed generation
In chapter 8 the Commission concluded that the most appropriate objective of small-scale FiT schemes is to ensure that households and small business have access to fair and reasonable prices for electricity produced by distributed generators. As noted in chapter 8, the concept of ‘fair and reasonable’ is often interpreted by many participants as meaning one-for-one.1 To avoid confusion this chapter uses the term ‘efficient and fair’ when referring to a FiT based on the wholesale price of electricity.
ACIL Tasman noted that the FiT payment is better able to reflect the energy (output) value of electricity exported to the grid by a distributed generator, while a separate payment that is not based on output (discussed in chapter 4) may be needed to reflect the network value of distributed generation.
Several FiT methodologies that have been used in Australia were evaluated by ACIL Tasman on behalf of the Commission (table 9.2). These include:
(1) an X for one FiT — where the FiT payment is a multiple of the retail price of electricity (2) a payback FiT — where the FiT payment is calculated to ensure that a distributed generator, ‘pays for itself’ within a targeted period (3) a wholesale market based FiT – where the FiT payment is based on the components of the wholesale price of electricity that are avoided by the distributed generation.
Based on an assessment of these methodologies against efficiency, effectiveness, equity and administrative simplicity criteria, ACIL Tasman concluded that:
None of the methodologies for calculating FiTs satisfy the efficiency or effectiveness criteria and all have adverse equity implications.
1 Consistent with Methodology for Assessment of Fair and Reasonable Feed-in Tariffs and Terms and Conditions (ESC 2008).
166 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The main issue is the inability of any of these FiTs to send appropriate signals regarding the network value of distributed generation. Depending on consumption and generation profiles, they exacerbate the inefficiency arising from network pricing and create cross subsidies. That said, the wholesale market based FiT is an efficient representation of the energy value (only) of distributed generation. (ACIL Tasman 2012c, p.viii)
A summary of the assessment is shown in table 9.3.
Table 9.2 ACIL Tasman assessment of FiT designs
Methodology Strengths Weaknesses X for one Administratively • overstates the energy value of simple distributed generation, particularly if X is set at 1 (or higher) • inequitable if payment exceeds sum of energy value and network value of distributed generation Payback period Degree of • determined without regard to the certainty for impact the distributed generator has on distributed the electricity supply system generator • inefficient — they pay more for investors generators with higher costs and less for generators with lower costs • inequitable — if the payments are more than the value of the distributed generation and are funded by electricity customers, this amounts to a burden on electricity customers that do not have distributed generation Wholesale price Provides a more • efficiency and effectiveness of the FiT is efficient payment limited by the assumptions used in for the energy forecasting the value of the electricity exported to the generated — the forecast may or may grid not accurately reflect the costs avoided • customers with distributed generation that are paid a wholesale market-based FiT avoid paying for electricity they generate and use on-site. In doing this, they avoid the network component of the retail price of electricity as well as the energy component • more difficult to administer — need to account for characteristics of different generation technologies
Source: ACIL Tasman 2012c, pp.60–66.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 167 Table 9.3 Assessment of feed-in tariff methodologies
Efficiency and Administrative Methodology Equity effectiveness simplicity X for one 1 1 4 Payback period 2 1 2 Wholesale price 3 3 3
Note: Score out of five, where a higher number implies a higher ranking. Source: ACIL Tasman 2012c, p.71.
The Commission asked ACIL Tasman (2012c) to provide indicative estimates of the potential size of FiTs based on a wholesale price methodology. It is important to note that the wholesale price varies substantially across different times of the day and year. The generation profile of different technologies also varies with some producing more electricity when demand, and hence the wholesale price, is highest. Therefore, if a FiT is set at a single average rate, regardless of the time of day or the level of the wholesale price, it would need to be different for different technologies. To illustrate this point, ACIL Tasman estimated FiTs for various generation technologies (which have different generation profiles)2:
• Flat generation profile: represents a generator that generates constantly throughout the year. This profile is presented mainly to illustrate the difference in value between this generation profile and others, which target higher price periods. Therefore, it was not adjusted for on-site consumption. This profile could be used to represent a gas-fired (or similar) generator in ‘always on’ mode or a fuel cell. • Solar generation profile: reflects a representative solar photovoltaic (PV) system installed by a representative residential customer. It is assumed that the PV system is 2.5 kW in capacity and, therefore generates 2.95 MWh each year, based on the number of small-scale technology certificates a system of that size is deemed to produce. • Storage device: which imports electricity from the grid at one time of day (when the electricity price is low) and exports it at another time (when the electricity price is high). This profile is based loosely on the possible capabilities of an electric car. • Peak generator profile: represents a distributed generator that targets high price periods. This profile could represent a stand-alone gas-fired co-generation unit (or similar) or a co-generation unit whose operator reduces demand during high price periods to maximise electricity exports when prices are high. Three thresholds were calculated so that the generator generated whenever the wholesale price exceeded, $50 per MWh, $100 per MWh and $150 per MWh. The results for a generator generating when the wholesale price is $100 per MWh are presented in table 9.4.
Table 9.4 shows that the estimated average energy value of distributed generation in 2013 (for flat rate and solar PV generators most commonly used by households) is the range of approximately 6 – 8 cents per kWh depending on the distributed generation technology. This range also incorporates differentials for the location of the distributed generator. For example, Yallourn represents a distributed generator (and relevant transmission and distribution loss factors) nearest to existing centralised brown coal
2 See ACIL Tasman (2012c) for a more detailed discussion on methodology and underlying assumptions.
168 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION generators. For Yallourn the transmission and distribution loss factors are minimal compared with Red Cliffs which is furthest from the Latrobe Valley. The values in table 9.4 include the impact of the price on carbon.
Table 9.4 Estimated average energy value of distributed generation for various generation profiles (nominal)
2013 2014 2015 Generation Location cents per kWh cents per kWh cents per kWh Yallourn 5.7 6.5 6.9 Flat Keilor 6.1 6.9 7.3 Red Cliffs 6.8 7.7 8.2 Yallourn 6.6 9.7 11.7 Solar PV Keilor 7.0 10.2 12.4 Red Cliffs 7.8 11.4 13.8 Yallourn 11.4 14.2 16.0 Storage device Keilor 12.0 15.0 16.9 (battery) Red Cliffs 13.4 16.8 18.9 Yallourn 58.8 75.8 49.9 Peak $100 Keilor 62.1 80.1 63.3 Red Cliffs 69.4 89.5 70.8
Notes: The above estimates include the impact of the price on carbon and reduced network losses. Source: ACIL Tasman 2012c, p.81.
High FiTs do not necessarily mean large incomes because the amount of electricity sold by a distributed generator may be small. For example, based on the 2013 estimates for a 1 kW generator, ACIL Tasman estimated the average annual revenue for solar PV selling at a FiT of 7 cents per kWh, would be $73. This compares with $46 for a peaking plant that sells electricity at 62 cents per kWh when the wholesale price rises above $100 per MW –– see table ES 1 (ACIL Tasman 2012c, p.x). An important point for solar PV customers is that a large source of financial benefit is avoiding the purchase of electricity from their retailer (and therefore the retail price of electricity). An illustration of this is provided in box 9.1.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 169 Box 9.1 Sources of financial benefit for solar PV customers In Victoria, householders who have operating solar PV systems benefit financially from: 1. Replacing imports of electricity from the grid with their own electricity, for which they avoid paying the retail price 2. Exporting electricity to the grid, for which they receive a payment or credit These benefits are principally influenced by: • the proportion of the household PV output that the householder uses ‘in house’ and the proportion that is exported. This depends on the householder’s usage profile, the size of the system and how much electricity it generates • the size of the FiT payment • the retail price the householder pays for electricity imports. The largest financial benefit to the householder is the avoided cost of the electricity they use ‘in house’. This is larger than the benefit from selling exported electricity at a FiT rate based on the wholesale price because the customer not only avoids paying for the energy but also avoids the other components of the retail price. To indicate the size of each benefit, consider a typical householder at Keilor who uses 5,500 kWh of electricity each year, which is approximately the amount used by the average Victorian 2 to 3 person household. Without a solar PV system, the householder’s annual electricity bill in 2013 would be $1,375. This includes approximately $419 for energy, $488 for network and metering costs, $50 for green scheme costs and $418 for retailer costs. The following table shows estimates of the impact of different sized PV systems on their electricity bill. The table shows that this householder would save between $383 and $615 in 2013 depending on the size of their PV system. Between 97 and 83 per cent of this saving is the value of electricity displaced from the grid by the householder’s own generation (as the system size increases, a greater proportion of the electricity is exported). By 2015, these proportions are estimated to be 95 and 76 per cent respectively.
2013 2014 2015 Electricity bill (no $1,375 $1,553 $1,634 PV system) Retail price 25.0 28.2 29.7 (c/kWh) System size (kW) 1.4 2.5 3 1.4 2.5 3 1.4 2.5 3 FiT rate 7.0 10.2 12.4 FiT payment $12 $73 $107 $18 $107 $156 $22 $129 $189 benefit Avoided retail $370 $481 $508 $418 $543 $574 $440 $571 $603 price benefit Net electricity bill $992 $821 $760 $1,117 $904 $824 $1,172 $934 $842 Annual saving due to solar PV $383 $554 $615 $437 $650 $730 $462 $700 $792 system
Notes: Some columns do not add due to rounding; All dollar values are nominal; Retail prices include energy costs, network charges and retailer costs and are assumed to have no fixed component. The retail prices incorporate ACIL Tasman’s projections of wholesale price and costs associated with large and small scale renewable energy certificates, changes in network charges in line with the most recent revenue determination and a carbon price beginning on 1 July 2012 at $23 per tonne CO2e increasing at four per cent real per annum Source: ACIL Tasman 2012a.
170 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The solar PV estimates provided by ACIL Tasman are within in a similar range to recent estimates for solar PV FiTs by the Independent Pricing and Regulatory Tribunal (IPART) in New South Wales, Essential Services Commission of South Australia (ESCOSA) in South Australia, and in Queensland (IPART 2012; ACIL Tasman 2011c)).3
The Commission observes that while the point estimates of the value of energy differ slightly (and may represent variations in methodology, and assumed solar profiles) among the three jurisdictions, they are broadly of a similar magnitude. Moreover, it is clear that these estimates for 2012 are well below all three Victorian FiTs (60 cents per kWh, 25 cents per kWh and the current range of standard FiT (SFiT) offers, see chapter 8).
Table 9.5 IPART final estimates of the value of PV exports to retailers (cents per kWh, $2011/12)
Method used 2011/12 2012/13 Wholesale market value 5.2 – 7.0 7.5 – 9.8 Direct financial gain to 8.3 – 10.3 TBC retailers
Source: IPART 2012, p.44.
Table 9.6 ESCOSA value of exported PV output (nominal cents per kWh)
2011 2012-13 2013-14 Both Carbon No carbon Carbon No carbon
scenarios scenario scenario scenario scenario Reduced wholesale 6.4 8.9 8.1 10.2 9.0 electricity cost Avoided losses 0.6 0.8 0.7 0.9 0.8 Market and ancillary service 0.1 0.1 0.1 0.1 0.1 fees Total 7.1 9.8 9.0 11.2 9.9
Source: ACIL Tasman 2011c, p. iv.
In South Australia, all electricity retailers are required to provide the ESCOSA determined FiT premium to solar customers. In addition to the FiT premium, the distribution network service provider (DNSP), ETSA Utilities, is required to provide a FiT to solar customers for electricity fed into its network. The actual FiT provided by ETSA Utilities varies depending on the date at which a solar customer is connected to its network. The requirement for the DNSP to provide a FiT will cease for solar installations after 30 September 2013 — with a retailer FiT payment (based on output value) remaining.
3 The ACIL Tasman estimate is at the bottom end of the IPART estimate and below that of ESCOSA.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 171 Table 9.7 Summary of South Australia FiT scheme — including electricity distribution FiT (nominal cents per kWh, GST exclusive
Solar PV cell installation/approval date 2011-12 2012-13 2013-14 Class 1 7.1 + 44 = 9.8 + 44 = 11.2 + 44 = Before 1 October 2011 51.1 53.8 55.2 Class 2 7.1 + 16 = 9.8 + 16 = 11.2 + 16 = 1 October 2011 – 30 September 2013 23.1 25.8 27.2 Class 3 N/A N/A 11.2 From 1 October 2013
Source: ESCOSA 2012, p.47.
Table 9.8 Summary of Queensland solar bonus scheme (cents per kWh, GST exclusive)
Network connection 2012-13 2013-14 2014-15 application lodgement date Before 10 July 2012 44.0 44.0 44.0 10 July 2012 onward 8.0 8.0 n/a
Source: Queensland Department of Employment, Economic Development & Innovation 2012.
In Queensland, customers who lodged a network connection application before 10 July 2012 and install an inverter energy system by 30 June 2013 are eligible for the 44 cents per kWh FiT until 1 July 2028. Customers who lodge a network connection application after 10 July 2012 are eligible for the 8 cents per kWh FiT. The tariff is scheduled to end on the 1 July 2014, but will be reviewed before 1 July 2013 in light of a separate Queensland Competition Authority review of solar PV feed-in tariffs for Queensland (Queensland Department of Employment, Economic Development & Innovation 2012).
Taking into account the relative imprecision in the various point estimates (including the sensitivity of estimates to various parameter assumptions) the Commission characterises these state results as suggesting that a Victorian FiT for 2013 in the range of 6 – 8 cents per kWh is likely to be ‘efficient and fair’ for small-scale generated electricity: although retailers might choose to offer higher rates. This 2013 estimate was current as at May 2012. On the introduction of the recommended approach, the estimate needs to be updated periodically by the Essential Services Commission (ESC) using the wholesale price methodology adopted by ACIL Tasman.
9.1.2 Participants’ views
Responding to the draft report a number of participants expressed concerns about the energy value of distributed generation estimated by ACIL Tasman — particularly the value of electricity generated by solar PV. While some participants believed the FiT estimated by ACIL Tasman was too low (for example, sub. DR90, sub. DR91, sub. DR97 and sub. DR98), there appeared to be some misunderstanding of the Commission’s draft recommendation 6.1, particularly in relation to ‘non-retrospectivity’. For example, one submission argued that:
172 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Many domestic installations were initiated on the basis of a known installation cost and known FiT; depending on the customers idea of a fair & reasonable payback period. To now alter the FiT to a ‘significantly lower’ rate is MOVING THE GOAL POSTS (sub. DR95, p. 1)
A further submission stated:
[we] invested in our solar system SOLEY based on the promises of the then Victorian government that the minimum premium feed-in-tariff would be 60c/KWh through until, I believe, 2025. Given that this was legislated, and our decision was based on the government keeping its promise, I expect that we will enjoy receiving this premium feed-in-tariff until at least that date. (sub. DFT87, p. 1)
The terms of reference requires that ‘any changes to existing arrangements would not be applied retrospectively’. As the Commission stated in the draft report, its view is that ‘non retrospectivity’ means that customers who are currently on a premium FiT (PFiT) would remain on this tariff until its contracted expiry date on 31 October 2024. Similarly, those customers on a transitional FiT (TFiT) would remain on that tariff until its contracted expiry date on 31 December 2016. The Commission recognises that the transition to new FiT arrangements, and associated communication to existing solar PV customers is extremely important and is considered in detail in chapter 10.
Other responses As illustrated in table 9.1, submissions have proposed many different methodologies for calculating FiTs, with differing reasons for supporting those methodologies. This section presents several of those views in more detail.
Alternative Technology Association
The Alternative Technology Association (ATA) (sub. 73) contended that any FiT arrangement should comprise the following components (summarised in figure 9.1), which put together represent a value stack that can be used to determine the FiT.
Figure 9.1 ATA — value stack
Wholesale Energy Value
Avoided Distribution and Transmission Losses
C/kWh Avoided Market Fees
Environmental Benefits
Reduction in wholesale prices – Merit Order Effect
Source: ATA, sub. 73, p. 5.
ATA also suggested that ‘households will not entertain investment in distributed generation unless the financial payback to them is within a decade’ and reported that ‘a FiT in the order of 24c – 25c/kWh, guaranteed for at least 10 years, and on a net… basis, would be required’ (sub. 73, p. 10). This FiT rate, according to ATA is broadly in keeping with the value-based approach summarised above. It was also suggested that the funding of the FiT be levied through distribution network service providers, as is the case for the Victorian PFiT and TFiT schemes (sub. DR189, p. 9).
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 173 In addition, ATA stated that ‘given that typically, solar PV generation and residential load curves do not meet, ATA do not believe there to be sufficient value in deferred distribution network asset for it to warrant recognition through a FiT’. However, ATA also noted that for a demand side generator with a different generation profile, ‘this value may be material and should be remunerated through a FiT on a generator by generator basis’ (sub. 73, p. 5).
Clean Energy Council
The Clean Energy Council (CEC) commented that ‘as the cost of solar power continues to drop we should move beyond incentive based feed-in tariffs to a system where consumers are simply paid the fair value for their solar power’. CEC suggested that its ‘analysis show[s] that the fair and reasonable value of solar is between 12 - 16 cents per kilowatt hour’ — which includes an amount (not specifically quantified) to reflect the network value of solar PV (CEC 2012d). The basis of this calculation was understood to be based on a roundtable discussion at the CEC.
… the recommendation that a mandatory minimum value should be paid to consumers for their solar power was important, but to be fair the required payment must include the network benefits too. (CEC 2012d)
Environment Victoria
Environment Victoria supported a gross FiT that provides for a 10 year return on investment (ROI).
We recommend a rate that provides a 10 year ROI, noting that this will be lower than the previous 60c given the falling cost of solar panels. We recommend that falling costs of panels be factored into the structure of the FiT. This could be reflected through a declining ‘first year’ rate for new applicants for the FiT. The FiT should still be guaranteed for a particular period (10 or 15 years) in order to provide the investment certainty required. (sub. 51, p. 6)
Environment Victoria provided little guidance or evidence on the level of its proposed FiT, but argued that it needed to be much higher than that suggested by the Commission in the draft report.
The Commission also received a number of submissions from individuals (submitted as an Environment Victoria pro forma submission) which called for a FiT of 35 cents per kWh based on recent research by the Melbourne Energy Institute. The pro forma submissions argued that the FiT should include the ‘financial benefits provided to all consumers from the deferral of infrastructure upgrade, reduction in grid losses, and the merit order effect.’
Property Council of Australia
Focusing on medium-scale distributed generation the Property Council of Australia (PCA) state that a ‘sensible FiT’ would be capable of driving ‘additional’ investment in distributed energy generation that would lead to a more effective decentralised electricity system that avoided or reduced the need for network upgrades that are funded by all electricity users. Based on several case studies of medium-scale co-generation and tri-generation, the PCA reported:
For solar PV – the sweet spot for investment for commercially acceptable paybacks of 6 years converged at 40 c/kWh …
174 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION For co/trigeneration – the sweet spot for investment was… around 15 c/kWh (for a 6 year payback period). (sub. DR191, p. 25)4
PCA recognised that while ‘FiTs avoid direct Government funding [they] are likely to introduce a degree of cross-subsidisation.’ They argued, however, that ‘this perceived inefficiency can translate into long term benefits for all customers’ (sub. DR191, p. 31).
Solar Energy Industries Association (SEIA)
The SEIA proposed calculating the amount payable to a distributed generator which involved deducting the amount of electricity exported to the grid from the amount of electricity imported from the grid to arrive at a ‘net amount’.5 In effect the customer is receiving the retail rate for electricity exported to the grid up to the point where their electricity consumption equals their generation. If the customer is a net exporter, producing in total more electricity than they use, they would receive a wholesale based FiT for additional exported electricity. If the customer is a net importer, producing in total less energy than they use they would pay the retail price for the additional imported electricity. A similar approach was canvassed by Kathryn Miller and Matthew Thomas:
We recommend that a FiT be paid on a one-to-one basis up until the point when the distributed generator contributes an excess of energy to the market … After that, generators should be paid a FiT based on the wholesale price of the energy. (sub. DR190, p. 5) Commission’s view The methodologies proposed fall broadly into three categories:
• payback period — a return to investors in distributed generation within a specified timeframe • payment reflecting the value of distributed generation — retail price based • payment reflecting the value of distributed generation — wholesale price plus (with proposed additions to reflect network losses, network benefits and merit order effects).
Before turning to these methodologies, the Commission notes that ATA suggested that a regulated FiT should be ‘levied through distribution network service providers’. As discussed in appendix B such an approach is used for the PFiT and TFiT programs. That is, the DNSP funds the payment of the FiT, and (in broad terms) recovers these funds from all of the users of its electricity network (through its network use charges). A question therefore arises as to whether this is an appropriate model for new FiT arrangements.
DNSPs are monopolies operating under price regulation administered by the Australian Energy Regulator (AER). It is difficult to see how a market-based FiT could be negotiated with consumers. The only option would be for the Government to specify the FiT, which runs the risk of the price being set too high or low, as discussed in chapter 8. The price would then be recovered from all users of the network, including users that do not have distributed generation, exacerbating cross subsidies across users of the network.
4 The Commission notes that the FiT amounts are based on a commercial rate of return applied in development projects. The amounts shown are gross FiTs and are the highest suggested by inquiry participants. 5 During discussions at the Commission’s transitional arrangements roundtable.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 175 A further consideration is that DNSPs do not realise the output value of electricity exported into the network (only the network benefits) — this output value is only realised by retailers who buy and sell electricity.
Payback period
As outlined in chapter 8, the Commission understands that both the PFiT and TFiT were based on a payback period methodology, at the then prevailing cost of solar PV systems, which resulted in FiTs of 60 cents and 25 cents per kWh. A FiT based on a specific payback period is determined without regard to the impact the distributed generator has on the electricity supply system. This approach is also inefficient as it rewards generation systems with higher capital costs more than it rewards systems with lower costs. This can lead to distortions as older or more costly technologies remain attractive to investors, which may slow the development and adoption of more efficient technologies. A payback period approach is also likely to lead to FiTs that are higher than the output value of electricity exported to the network which exacerbates cross subsidies between those customers with, and those without, distributed generation. In South Australia, ESCOSA noted that ‘the generous subsidies to existing customers with solar PV…adds around $65 to the average annual household energy bill’ (ESCOSA 2012, p.vi).
A payback period approach is not consistent with the Commission’s view that the price for exported electricity should be based on the value of the electricity.
Retail price
A number of inquiry participants were concerned that the draft report recommended a market-based FiT that was likely to be significantly less than the price they pay for electricity from their retailer — and would lead to distributed generators subsidising electricity retailers. In other words, some participants argued that the FiT should be equal to the retail price they are charged for electricity supplied.
It is important to understand that the price paid by a retail customer for electricity from a retailer contains several components (table 9.9).
Table 9.9 Victorian residential electricity price 2012-13
Component Percentage contribution
Wholesale price of electricity 33.9
Retail (operating costs and margin) 27.2
Distribution network costs 22.8
Metering 8.6
Transmission network costs 4.3
Carbon reduction policies 3.2
Total 100
Source: AEMC 2011d.
Retailers who buy electricity from distributed generators can avoid such costs as:
• electricity purchase costs • National Electricity Market fees
176 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • electricity losses (transmission and distribution) (IPART 2012, p.49).
These avoidable costs are the benefits that a retailer receives when a customer with a distributed generator exports electricity to the grid. These avoidable cost components are relevant to the price that a retailer should pay for the electricity exported from a distributed generator. Other costs that a retailer cannot avoid (such as, retail costs, network charges and costs associated with various green schemes) should not be included in such a price. Including such costs would significantly overstate the value of the exported electricity. The Commission’s view is that retailers should not be obliged to pay an amount for electricity exported by distributed generators that includes costs that they cannot avoid.
Setting the FiT equal to the retail price significantly exceeds the value of the electricity exported to the network. According to ACIL Tasman, if the full retail price of electricity is paid for the output from a distributed generator, this can be more than three times its true energy value (ACIL Tasman 2012c, p. 60).
Alan Pears (sub. DR192) suggested, however, that if the electricity market were truly competitive then the price that a distributed generator could sell their electricity to a neighbour would be the retail price, not the wholesale price. More specifically the submission proposed;
… a combination of an up-front incentive (which can adjust for carbon price distortions and other societal benefits) and a 1:1 FiT combined with time of use pricing (i.e. payment for exports would be equal to the retail price of zero (or low) emission electricity at the time of export)… For larger scale projects, an independently verified shadow cost of running an alternative supply to neighbours or the marginal cost of using the local network could be used to adjust the retail price for use in setting export prices. (sub. DR192, p. 10)
This raises an interesting point relating to ‘alternative selling arrangements’. It has been suggested to the Commission that there may be other models for investing in distributed generation that would allow more consumers to benefit from avoiding the retail price of electricity. For example, Simon Holmes a Court (2012) pointed to shared ownership models which would enable larger-scale distributed generation to be delivered and provide more individuals with the opportunity to participate in renewable energy activities. Two case studies, including ‘regional solar parks’ and ‘urban rooftops’ were cited as specific examples of projects involving shared ownership. Under these schemes individuals form energy co-operatives which sell shares to fund the installation of distributed generation (such as solar panels). In the future it may be possible to adapt such schemes to provide individuals with the prospect of participating in the distributed generation market and avoiding or offsetting their import of electricity from retail businesses (at the retail price).
The Commission’s view is that while shared ownership schemes do not justify ‘obligating’ a retailer to purchase electricity from a distributed generator at a price that is greater than the value of that electricity to the retailer, there may be value in considering whether there are more innovative ways of returning the value of distributed generation to those investing in its installation and operation.
Wholesale price plus
A number of participants have suggested that the FiT should be based on the wholesale price of electricity but with various other components added to reflect a number of perceived benefits. These components include:
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 177 • merit order effect (MOE) • benefits associated with the potential deferral of network augmentation.
Merit order effect
A number of submissions argued that the MOE can be used to justify higher FiTs for distributed generation. For example, ATA argued that:
… some of the value of the downward pressure on wholesale electricity prices should be returned to system owners when assessing a fair and reasonable FiT value…Ignoring this benefit, on any basis, would be short- changing PV or other DG customers, and therefore cannot be considered to be fair and reasonable. (sub. 73, p. 9) ATA estimated the value of the MOE at around $40 million during the first year of 200 MW of new solar PV installed in the Victorian market and valued the exported electricity from solar (to capture the MOE) in the range of 30.2 to 31.9 cents per kWh (assuming net arrangements) (sub. DR189, p. 6).
However, it is not clear why distributed generation is singled out for special attention in relation to the merit order effect. ACIL note that the introduction of new generation, regardless of type, can affect the wholesale electricity prices in two ways:
The first effect is driven by a reduction in ‘market’ demand. The effect will be the same whether demand is reduced by distributed generation, regardless of its fuel source, by energy efficiency or by other means. The second effect relies on the new generator entering the market at a lower bid than existing generators. This is the objective of all new generators regardless of their fuel source. If they do not enter the market at a lower price than existing generators, they will not be dispatched and will not earn revenue. (ACIL Tasman 2012c, p.22)
Both effects have the potential to reduce wholesale electricity prices.
The Commission accepts that the MOE exists — to the extent that introducing a lower cost supply of electricity will lower the average market price. However, it does not follow that distributed generators should appropriate any of the benefits of the reduction in wholesale prices in the form of higher FiTs. In other competitive markets the benefits of cost reductions are passed onto consumers and the party responsible for the cost reduction benefits to the extent that they are able to undercut other suppliers.
Technologies with low marginal costs (such as solar PV) benefit from being able to sell their output at prices above the cost required to generate that output, it is not clear whether there is a further need to transfer benefits (of the MOE) that would normally accrue to the wider energy customer base. A further concern is that artificially encouraging small-scale distributed generation to reduce the wholesale price of electricity will make other larger-scale renewable and low-emission technologies less attractive and make it more difficult to earn sufficient revenue to recover the large capital costs associated with such systems. By providing additional rewards for small distributed generation, this may displace more efficient larger-scale (lower cost sources) of renewable energy, and lead to over investment in technology that may not be optimal long term.
No participants have made the case that the electricity market is sufficiently different from all other markets to require that the benefits of lowering average market prices
178 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION should flow to one type of producer. The Commission therefore does not accept the MOE justifies higher FiTs for renewable distributed generation.
Deferral of network augmentation
As outlined in chapter 5, identifying, measuring and recovering the network value and paying it to the proponents of distributed generation is important to ensure there are incentives to invest in distributed generation in areas where it has most value for Victoria’s electricity system. However, recovering this value is not easy and is appropriately dealt with outside of the FiT payment. Whilst there may be several options for capturing the network value, the Commission has recommended that the Victorian Government, through the Department of Primary Industries, consider using the AER’s price reset process to identify the value of any network benefits from distributed generation and require DNSPs to make payments based on this value (recommendation 4.2).
The Commission’s view
Having regard to all of the evidence and analysis following the draft report, the Commission considers a wholesale price plus option (which includes the effect of the price on carbon and reduced network losses) is the most appropriate methodology to value the electricity exported into the network by distributed generators. This approach captures the output value of the exported electricity and distribution and transmission losses that are avoided. In theory this is the price that a competitive retailer would offer as it reflects the value of the electricity that they can on-sell. An important question is whether there is a need for regulation to set this price.
9.1.3 Market-based feed-in tariffs
In the draft report the Commission suggested that the competitive market should determine the FiT payment, provided that competition in the retail electricity market is effective. If competition is effective, it is reasonable to assume the market determined FiTs would be consistent with the output value of the electricity supplied by the distributed generator.
Allowing the market to determine the FiT is a natural progression of the Victorian electricity market. As highlighted in chapter 8, Victoria removed retail price regulation of electricity in 2009 — leaving the market to set retail prices (within a customer protection framework). This is consistent with IPART which recently recommended that the FiTs be market determined.
While some participants supported the Commission’s direction, others questioned whether the electricity market would deliver fair and reasonable FiTs.
Participant views Some participants were concerned that an unregulated FiT would lead to retailers choosing not to offer fair and reasonable rates (Environment Victoria, sub. 51, p. 6). Others (including the Australian Photovoltaic Association, sub. 67, p. 4 and ATA, sub. 73, p. 2) argued that a regulated FiT created investment certainty for consumers and industry players:
… feed-in tariffs (FiTs) offer the best opportunity to capture the market failures that exist in the national electricity market (NEM) … As a policy mechanism, FiTs … offer the greatest potential for investment certainty for consumers and industry players in the relevant technology space. (ATA, sub. 73, p. 2)
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 179 The ATA was concerned that since the ‘disaggregation and privatisation of the Victorian energy market’ retailers and distribution businesses were not incentivised to offer a fair and a reasonable price for electricity exported by distributed generators (sub. DR189, p. 3). Similarly Kathryn Miller and Matthew Thomas questioned whether there was effective competition in the FiT market:
Although there is generally competition in the electricity market, this competition is substantially reduced for distributed generators…The market power of retailers means that the price signal given by the headline price for the FiT is undermined by having to pay higher retail prices. (sub. DR190, p.2)
From a retail perspective AGL argued that market determined FiTs were more appropriate in the current environment where jurisdictions were removing price controls where competition is effective. It was suggested by AGL that regulating FiTs would be a significant retrograde step in relation to microeconomic reform of Australia’s energy market (sub. 72, p. 1). On a similar note the Energy Supply Association of Australia believed that regulating a FiT could undermine competition in the electricity market, particularly if it was set too high and retailers avoided certain customers with solar PV — thus discouraging vigorous competition among retailers (sub. 74, p. 2).
As outlined in chapter 8, a number of factors suggest there is some degree of competition in the Victorian FiT market, including that competition in the Victorian electricity retail market has been judged to be effective. However, given the concerns raised by participants in this inquiry, the Commission sees value in monitoring the short-term development of market-based FiTs in Victoria and continuing an obligation for retailers with more than 5000 customers to offer FiTs to small-scale distributed generator proponents until 31 December 2016. During this transition period, practical evidence on how FiTs are evolving in Victoria (and other jurisdictions including New South Wales) could be gathered and used to assess whether further refinements are necessary. As discussed in chapter 10, this transitional period assists in meeting the terms of reference requirement that recommended changes are not applied retrospectively, particularly in the case of current SFiT customers.6
9.1.4 Eligibility
The main FiT eligibility criteria relate to the capacity or size of the distributed generation system and the technology (table 9.10).
6 SFiT contracts differ between retailers with some allowing for changes in FiTs while others lock in a rate for a particular period (see table 10. 1).
180 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Table 9.10 Feed-in tariff eligibility – technology and capacity Type of FiT Eligible technology System capacity PFiT Solar PV 5kW or less TFiT Solar PV 5 kW or less SFiT Small renewable energy generation Less than 100 kW (excludes facilities (solar, wind, hydro and biomass) solar PV with a capacity of connected to the distribution network 5kW or less)
Notes: See Appendix B for greater detail on the various FiT schemes Source: Commission analysis.
Distributed generator technology • In chapter 4 the Commission considered that FiTs should not unnecessarily favour one technology over another. They should be technology neutral, with differences in policy or approach only justified on technical grounds. This ensures that the relative merits of all technologies are considered and no single approach is advantaged over another. The terms of reference for this inquiry refer to renewable and low-emission technologies, and it is these that the Commission has focused on — that is that eligible technology includes at least renewable and low-emission distributed generators.
The current Victorian SFiT specifically applies to renewable technologies generating less than 100 kW, such as solar PV (between 5 kW and 100 kW), hydro, biomass and wind. The current arrangements, however, do not refer to generation technologies that may be considered ‘low-emission’. This point was raised by Ceramic Fuel Cells Limited (CFCL): Extending the feed in tariff to a broader range of low emissions technologies gives homes and businesses a wider choice of on-site energy generation products. (sub. 41, p. 1) Similarly Jemena (JEN) believed that technology neutrality should be a key feature of future FiT arrangements (sub. 79, p. 3).
In its review of environmental regulation in Victoria the Commission noted that low- emission technologies (renewable or not), which demonstrate a capacity to significantly reduce greenhouse gas emissions, should not be disadvantaged when seeking to enter the electricity market (VCEC 2009, p.381). This raises a question regarding what constitutes a low-emission distributed generation technology. Table 9.11 shows average emission intensities for a number of generator fuels. The data, however, do not include all fuels and exclude fuels (such as biomass) which are important for distributed generation.
Table 9.11 Emission intensity of selected generators by fuel type Fuel Type Average kg CO2-e/GJ of fuel over all power stations Black coal 91.1 Brown coal 92.6 Hydro 0 Liquid fuel 68.8 Natural gas 51.3 Wind 0 Solar PV 0 Source: ACIL Tasman 2012b.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 181 Defining low-emission distributed generation technology
Moreland Energy Foundation suggested that the definition of low-emission should ‘exclude systems with higher greenhouse gas emissions per kWh produced than a high efficiency combined heat and power or co-generation system’ (sub. 75, p. 3). In the draft report the Commission adopted the definition recommended by the Clean Energy Finance Corporation (CEFC) Expert Review that the eligibility for low-emissions technology be defined as technologies that produce 50 per cent, or less, of the emissions intensity of electricity generation in Australia (Commonwealth Government 2012c, p.15).
While there were further comments made by some participants, (including by the Energy Innovation Co-operative (sub. DR160, p. 4)) who disagreed with this definition of ‘low-emission’ and more broadly to the widening of the SFiT criteria to allow for non-renewable technologies, there was no new evidence to support an alternative to the definition recommended by the CEFC. Consistent with the draft report the Commission recommends adopting this definition of ‘low-emission’ — for the purpose of FiT eligibility.
The Commission notes that the definition of ‘low-emission’ is relevant only for the purpose of future SFiT arrangements that apply to a broader range of possible distributed generator technologies with a capacity of 100kW or less. The Commission considers the definition should not artificially restrict the specific types of technologies (and associated fuels) that are able to access the FiT — indeed following the introduction of a market-based FiT post December 2016 this definition would no longer be required.
Distributed generator size The current FiT arrangements (combined) apply to distributed generators less than 100 kW. According to CitiPower/Powercor:
The Businesses consider that the scale of generation activity under a FiT scheme should be 100kW. This is consistent with the current scale criterion for Standard FiTs. A proponent generating above 100kW would be operating at capacity beyond that of a household or small business and would be in a position to negotiate their own contract for the exported energy, as opposed to relying on a FiT scheme. (sub. 80, p. 4)
An alternative view was expressed by other participants. For instance it was suggested that all small-scale renewable generators should be included up to 30 MW (Reeves, sub. 27, p. 1). Similarly Christine Easdown suggested:
While it is important that feed-in tariffs be regulated to ensure that the community receive a fair and reasonable price for green electricity fed back into the grid, it is important to maintain a feed in tariff that will encourage both domestic and community based renewable energy projects of all sizes. (sub. 32, p. 1)
PCA advocated for a FiT that applies more broadly, accommodating medium-scale generation from businesses. It stated that a ‘sensibly’ designed FiT would:
Leverage private sector investment by offering incentives that are open to mid-scale distributed generation from businesses. (sub. DR191, p. 1) and that
182 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The commercial property sector in particular offers scale and scope to make a meaningful contribution to the desired increase in distributed renewable and low carbon energy. (sub. DR191 p. 31)
The Commission’s view is that owners of generators greater than 100 kW are likely to be larger businesses, or commercial entities that have access to sufficient resources to negotiate a FiT payment with a relevant retailer or establish alternative arrangements for selling surplus electricity. Further options may also be available to medium-scale distributed generators through a proposed rule change currently being considered by the Australian Energy Market Commission (AEMC). The rule change proposed by the Australian Energy Market Operator (AEMO) seeks to introduce a new category of market participant into the National Electricity Rules called a 'small generation aggregator'. Under the proposed rule change, small generation aggregators would only have to register once with AEMO and would have market responsibility for multiple generating units participating in the National Electricity Market (NEM). According to the proposal, registering each generating unit separately would not be required, significantly reducing costs and improving access to the market. This would allow distributed generators to use an aggregator to more easily enter and sell in the NEM (AEMC 2012c, pp.1–5). On 5 July 2012, the AEMC published a draft rule determination on the Small Generation Aggregator Framework. The AEMC’s draft rule broadly reflects that rule change requested by AEMO (AEMC 2012g, p.2).
A more specific suggestion by several proponents was that the threshold should be 100 kW or less (rather than the current less than 100 kW). David Sparks noted that:
If a potential owner of an embedded generator sets out to purchase a generator it will be quickly realized that such machines in the range of 100 kW would be typically 75, 80, 100, 120, 150 kW etc. Therefore to utilize the full potential of the DPI criteria it would be necessary be a little deceptive and purchase a 100 kW generator and declare that it is 99 kW. This is a genuine problem which I have encountered with retailers. (sub. 43, p. 2)
From a practical perspective, the Commission recommends a size eligibility criterion for the new FiT of 100 kW or less, which is a marginal adjustment to the current SFiT criterion.
9.1.5 Gross or net metering
Several submissions queried whether the FiT should be based on net or gross metering. Under gross metering all of the electricity generated by a customer (through a solar PV system for example) is measured, together with the electricity consumed by that customer. A gross FiT is applied to all of the electricity that is generated (including electricity consumed on-site) while the relevant retail price is applied to all the electricity consumed, regardless of where it is generated. Therefore the gross meter measures the entire output of the distributed generator separately to electricity consumption.
Under net metering the electricity generated by a customer and that customer’s consumption of electricity are netted out within a specified time period. Electricity generated and consumed at the time of generation is not metered — the customer does not pay for this electricity, and is also not paid for the amount generated at this time. The internally generated electricity consumed by the customer is therefore valued at the retail price of electricity, as this is the amount that the customer saves.
If the amount generated exceeds the amount consumed at a particular point in time, this amount is exported and measured — for which the customer receives the applicable feed-in tariff. If the amount generated is less than the amount consumed at
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 183 a particular point in time, the required amount of electricity is imported and measured — with the customer paying the applicable retail tariff.
Metering arrangements in other jurisdictions Many FiTs worldwide are based on gross metering (and gross FiTs). In some cases renewable electricity generators are paid a base rate for all the electricity they generate, and a premium for any electricity exported into the grid. Germany’s FiT scheme, considered to be the world’s most developed, operates under a gross tariff. Under this scheme, solar PV generators are paid for electricity generated and used on-site (approximately 9 euro cents per kWh for the first 30 per cent of their annual electricity generation, and approximately 13 euro cents per kWh thereafter). Any electricity exported into the grid attracts a tariff of approximately 25 euro cents per kWh. Similarly, in the United Kingdom, solar PV generators receive a gross tariff of 8.9 to 21.0 pence per kWh for all electricity produced. On top of this, any electricity exported into the grid receives an additional tariff of 3 pence per kWh. While its large-scale renewable energy generators receive gross FiTs, Japan’s residential solar PV generators are subject to a net FiT. Under this scheme, generators are paid a tariff of 42 yen per kWh for electricity exported into the grid.
Table 9.12 Feed-in tariff schemes
Tariff rate per Gross/ Systems Jurisdiction Implementation Duration kWh net included Solar Victoria January 2012 25 cents Net 5 years <5kW Northern Residential July 2011 19.77 Net Territory solar Scheduled Solar Queenslandc July 2012 8 cents Net to end 1 <5kW July 2014 8.05 euro centsa, 12.43 Gross Roof-top Germany January 2012 euro centsb 20 years solar <30kW 24.42 euro cents Net 21 pence Gross Solar UK April 2010 25 years 24 pence Net <4kW Suspended: Residential Spain 28.88 euro cents Gross 25 years January 2012 solar Residential Japan July 2012 42 yen Net 10 years solar
Notes: a for first 30 per cent of total annual electricity generation; b for the remainder of electricity generated; c From 10 July 2012 the Queensland Solar Bonus Scheme feed-in tariff changed from 44 cents per kilowatt hour to 8 cents per kilowatt hour. Source: Commission analysis.
184 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Participants’ views While ACIL Tasman’s preferred gross metered FiT may be more effective in reflecting the output value, Victoria’s current FiTs are paid on a net basis. This implies significant sunk costs in smart meters, billing systems and other administrative aspects. The potential benefits of a gross tariff need to be weighed against the additional costs of change.
Jemena (JEN) highlights that it has installed (single element) smart meters under the Advanced Metering Infrastructure (AMI) program which can only support net metering. Furthermore JEN asserted:
To support gross metering, a dual element meter is required. While the cost difference of a single-element and dual-element meter may be small relative to the cost of a small-scaled DG [distributed generator], the modifications to JEN’s AMI IT systems to support gross metering would be prohibitive. (sub. 79, p. 6)
Similarly United Energy (UE) believed that, while gross metering may offer improved load forecasting at times of high demand, there may be additional costs:
The minimum standard of metering under the AMI program is single element metering which enables a net feed in tariff as opposed to measuring the full energy generated from the distributed generation which may occur with a two element interval meter. Two element interval meters have only been funded for UE in order to continue the metering configuration for dedicated off peak circuits – hot water and slab heating customers. (sub. 77, p. 4)
Continuing the theme of minimising costs to relevant parties, Origin Energy also supported net metering arrangements for small distributed generation systems (sub 81, p. 1). Citipower/Powercor, however, suggested that gross metering may not be as costly as highlighted in the draft report and a full consideration of the costs and benefits may make a compelling case for gross metering (sub. DR184, p. 3).
Several other submissions focused on the ‘broader societal’ benefits of gross metering, including Moreland Energy Foundation and Environment Victoria (sub. 75, p. 6; sub. 51, p. 5).
The Commission sees value in supporting a nationally consistent approach to metering arrangements, provided that it is not detrimental to the welfare of Victorian electricity customers. In this context the Commission notes that recent regulatory changes in South Australia and New South Wales have implemented net FiTs. As the role of distributed generation in the electricity market develops, however, there may be broader benefits to the industry from adapting their systems to allow for gross metering. Under the Commission’s proposed market-based regulatory framework, this would remain an option.
9.1.6 Information provision
As noted in chapter 8, it is important that electricity customers considering distributed generation options have access to relevant information to be able to evaluate FiT offers in a timely and cost-effective manner. Accessibility of information could be improved by standardising FiT offers to allow customers to compare retailer offerings — ultimately choosing the best offer that meets their needs, taking into account personal preferences.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 185 The Commission found in its desk-top reviews of retailer and other comparison sites that it is often difficult to understand how FiT offers interact with other retail market offers, terms and conditions. To improve customers’ capacity to make well-informed decisions (from their perspective) it is important that they understand the financial implications of the service packages they are being offered by retailers. This is particularly important as more innovative (and potentially more complex) FiT products are offered by retail businesses.
In due course the National Electricity Customer Framework (NECF) will transfer regulation of Victorian electricity retailers to a national regime, requiring retailers to comply with AER Retail Pricing Information Guideline (2012a). The guideline requires electricity retailers to provide pricing information to the AER, which will be put into a price comparator website (maintained by the AER). Under the AER’s Guideline, retailers must include some FiT offer information. The Commission’s view is that FiTs should form part of the pricing information provided under the price disclosure guidelines, and be included on the AER’s price comparison site ‘Energy Made Easy’. Furthermore, the Commission understands that the requirement to publish FiT terms and conditions on Victorian retailer websites will remain under the NECF, as a direct statutory obligation under the Electricity Industry Act 2000 (Vic) (EI Act).
The implementation of the NECF in Victoria has been deferred (O’Brien 2012b). In the interim, Victorian electricity retailers will be subject to:
• information provisions of the Energy Retail Code (ESC 2012b, pp.34–35) • Code of Conduct for Marketing Retail Energy in Victoria (ESC 2009a, pp.6–8) • internet publication requirements under Guideline 19: Energy Price and Product Disclosure (ESC 2009b) and the EI Act ss 35B, 35C and 36A.
In addition, the ESC maintains a price comparator website ‘YourChoice’ that allows customers to compare standing and market offers of Victorian electricity retailers.7 At this stage, YourChoice is limited to comparing retail contract offers for supply. It does not have the functionality to compare FiT offers. The Commission considers that an independent comparator website should be developed and made available to consumers. To support competition among retailers offering FiTs the website should be available by the end of the transition period recommended by the Commission, and provided by the Victorian Government if it is not available from the private sector or the Commonwealth.
To assist the market to transition to the new arrangement the Commission sees merit in also establishing an indicative benchmark range for FiTs that provides customers a starting point when seeking alternative offers from retailers. As shown earlier (table 9.4), ACIL Tasman has, as a starting point, estimated the value of distributed generation for various generation profiles and technologies. Such a benchmark range would provide customers with some basic cost information that they would have difficulty acquiring on their own. This benchmark rate would need to be updated as appropriate until market FiTs are reasonably established.
7 See: http://www.yourchoice.vic.gov.au.
186 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 9.1.7 Billing arrangements
In looking at future Victorian FiT arrangements it was suggested that the Commission consider billing and payment arrangements. The Minister for Energy and Resources wrote to the Commission8 listing several issues including:
• the retailer be required to pay the customer at the end of each normal billing period any amount earned by the customer from the feed-in • that customers be paid in cash, not just credits that are wiped out if not used.
The EI Act provides that, as a statutory minimum, the PFiT and TFiT for the electricity which customers export to the grid must be credited to their accounts (ss 40 FA(2)(a) and 40 FAB(2)(a)) rather than paid to them. This provision is drafted to take account of a risk that if the EI Act required the FiT to be paid rather than credited, then a court may characterise the FiT as an excise duty. Under the Australian Constitution, only the Commonwealth may impose excise duties; any charges imposed by a State which are held to be excise duties are invalid and unenforceable (DPI 2009, p.2). In this respect, Victoria is no different to other states. The Commission notes retailers may choose to pay customers in cash and several retailers already offer cash payments to customers.
The Commission notes that the fair and reasonable criteria the ESC applies when considering current FiT offers states that:
An offer must state that the retailer will pay or credit the customer for electricity supplied under the feed-in contract with the same frequency as the customer is billed for electricity supplied to the customer. (DPI 2011j)
Under the Commission’s recommended approach, a FiT would be available to all distributed generators, including at locations other than the principal place of residence. For some customers it is conceivable that the value of the energy exported by distributed generators will be consistently greater than the value of the energy consumed (for example, holiday homes). It will be important that retailers disclose what payment arrangements will be applied in the information that they provide to customers.
9.1.8 The Commission’s view
An approach that specifies a specific FiT risks setting a price that is either too low or too high (regulatory error), leading to inefficient investment in distributed generation. It may also impose costs on other electricity consumers or impact on the competitiveness of the retail electricity market if retailers are obliged to offer FiTs that are higher than market determined FiTs (or above the value of the distributed generation). This could result if retailers attempt to avoid certain customers or classes of customers. This was noted by the Australian Solar Round Table:
… retailers may either try to avoid entering into market contracts with these customers, or offer them higher retail electricity rates than other customers (Australian Solar Energy Round Table 2011, p.7)
The market determined FiT, in an effectively competitive environment, would reflect the value of the generated electricity to the retailers, and would therefore avoid any
8 The letter from the Minister for Energy and Resources is available on the Commission’s website, www.vcec.vic.gov.au.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 187 unintended cross subsidisation. How best to move Victoria to a more efficient market-based FiT is discussed in the rest of this chapter.
As previously noted there are some impediments to an efficient market determined FiT which appropriately rewards small distributed generators for the output value of the electricity that they produce, including:
• Information and transaction costs: there are concerns that, especially for smaller distributed generation proponents, information is difficult and costly to obtain and is not always in a form which is clear and accessible to the customer. These costs are compounded by the newness of some technologies and uncertainty caused by changing national regulation. • Market power issues: vertical integration of retail electricity businesses. There are significant ownership links between the electricity retail market and centralised electricity generation which may impact on the incentives retailers face when engaging with and offering a FiT with small-scale (or aggregated groups of) generators. • Limitations on time-of-use and locational pricing: not all Victorians have access to meters that collect time-of-use and location aspects of their power use and production. This limits the ability to develop FiTs that better reflect the value of distributed generation at different times and locations.
On their own none of the above factors constitutes a market barrier sufficient to prevent competitive outcomes from emerging (provided adequate consumer protection, transparency and information is available). However, taken as a whole, they are likely to present significant short-term barriers until key reforms are in place (including through the Commission’s recommendations and the ongoing changes to the NEM and its regulation).
In moving to a market-based FiT it is important that customers (owners of small-scale distributed generators) are well informed about electricity retailers’ service offerings. As noted in chapter 8, it is likely that current FiT information provided by retailers is inadequate, and confusing in its presentation. These information shortcomings may reduce the likelihood of efficient participation in the FiT market. Given the interrelationship between FiT offerings and retail market contracts for the supply of electricity, more targeted and comparable information on FiT offerings can support, rather than hinder, the further development of retail competition.
The Commission considers that future Victorian FiT arrangements should be administratively simple, capable of being implemented at low cost and consistent with achieving national consistency. Having regard to this and noting the significant past investment in equipment and systems that support net metering of small-scale distributed generation, the Commission considers it likely that mandating gross metering, to support gross FiTs, would increase costs. Notwithstanding this view, the Commission’s recommendations are not a barrier to gross metering, the introduction of gross FiTs or businesses adapting their systems to accommodate both.
9.1.9 Terms of reference 1: The Commission’s summary view
Drawing all these elements together, the Commission’s view on the design, efficiency and effectiveness of FiT schemes (including gross feed-in schemes) may be summarised as follows:
• With the advent of the carbon tax, the energy value for distributed generation output is best captured through a wholesale-based price (which includes the
188 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION carbon tax and reduced network losses) set by the competitive market. The role of a FiT scheme is to recover this value. • FiT schemes should: − be based on such market prices, and be part of a transition to a fully market-based approach for pricing electricity from distributed generation − include the ability to compare market-based offers (for example, through a FiT comparator website) − provide an indicative benchmark range (consistent with the approach outlined by ACIL Tasman 2012) with periodic updates until market FiTs are reasonably established − not be mandated to exceed such a market-based price, because this would mean cross subsidies from customers without distributed generators to customers with distributed generators − be technology neutral so that the most efficient choices among generation technologies can be made − be confined to ‘household-scale’ distributed generation of 100 kW or less, as larger scale producers are better placed to compete in the market and are more likely to have access to alternative mechanisms for selling/exporting electricity to the grid. • Adopting time-of-use pricing is desirable where feasible, because it provides a stronger economic signal to distributed generators of the value of production when overall electricity demand is high. • While there are arguments in favour of gross FiT schemes, there would be significant costs in replacing recently installed smart meters and changing retailers’ supporting infrastructure and computer systems to be able to adopt such schemes. Therefore, while not ruling out such schemes if they were to arise in the marketplace as a result of competition, the Commission sees no clear value in mandating them.
9.2 Terms of reference 2: Implications for existing Victorian feed-in tariff schemes
The terms of reference require the Commission to recommend whether existing FiT arrangements should be continued, phased-out or amended. Transitional arrangements are discussed in chapter 10.
The Commission’s approach to future Victorian FiT arrangements reflects its view that the retail market is expected to be sufficiently competitive that, with a transition to allow for changes in consumer regulation and growth in market experience, this market is likely to be capable of setting prices for the output value of distributed generation that are in the long-term interests of consumers and producers.
The Commission’s approach is consistent with the COAG National Principles for Feed-in Tariff Schemes, in particular:
That Governments agree that residential and small business consumers with small renewables (small renewable consumers) should have the right to export energy to the electricity grid and require market participants to provide payment for that export which is at least equal to the value of that energy in the relevant electricity market and the relevant electricity network it feeds in to, taking into account the time of day during which energy is exported. (Commonwealth Government 2012c, p.1)
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 189 Chapter 8 stated that the objectives of FiT policy should focus on ensuring that low-emission and renewable small-scale generators receive efficient and fair value for the electricity exported to the grid. In designing efficient and fair future Victorian FiT arrangements the Commission has been guided by the principles outlined in chapter 4. That is, in summary, future arrangements should:
• embody incentives that reflect economic value • contain no cross subsidies • have regard to the efficient assignment of policy instruments • be technology neutral • consist of efficient and predictable processes.
A key part of future FiT arrangements is the determination of the payment for electricity generated by distributed generators. As previously noted, the Commission considers that the output value of distributed generation is best determined with reference to the wholesale market-based approach, where the payment is based on the components of the retail price of electricity that are avoided by the retailer buying electricity from the distributed generator. This is best determined within a well-informed, competitive retail electricity market. In practice, moving to such a scheme would require the following changes in Victoria’s FiT arrangements.
Premium feed-in tariff (PFiT) The PFiT is already closed to new customers. Customers who are receiving a PFiT should continue to do so (under their contracts) until the legislated expiry of the scheme on 31 October 2024.
Transitional feed-in tariff (TFiT) The Commission recommends that the existing Victorian TFiT should be closed (to new customers) by 30 September 2013 or once the 75 MW capacity is reached (as currently provided in legislation), whichever occurs first. The earlier closure date of 30 September (compared to 31 December 2013 in the draft report) reflects views expressed by industry participants (for example sub. DR172) that resourcing (electrical contractors) constraints from November to January would make the transition and closure of the scheme more difficult over that period. Consistent with current legislation the TFiT will close to all existing customers on 31 December 2016.
The approach to phasing out of the TFiT also reduces the costs of future cross subsidisation borne by those not participating in the FiT market. Further transitional measures are discussed in chapter 10.
Standard feed-in tariff (SFiT) The Commission recommends simultaneously closing SFiT to new customers and establishing a new market-based FiT for renewable and low-emission distributed generation. It is also highly desirable, although not necessary, that the timing of these changes coincide with the recommended closure of TFiT to new entrants on 30 September 2013.
Customers who signed up to an SFiT contract prior to its closure should continue to receive their agreed SFiT (consistent with current Fair and Reasonable criteria outlined in the ESC guideline) until 31 December 2016. Options for the Victorian Government to consider in relation to a fair and equitable adjustment for customers who are currently on an SFiT contract are discussed in chapter 10.
190 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The different legislative underpinning for TFiT and SFiT makes transitioning these schemes challenging. A key constraint is that changes to the EI Act are required to change or abolish the SFiT scheme, and this process takes time. In contrast, the TFiT scheme can be closed by notice published in the Government Gazette. There is further complexity in that SFiT contracts vary among retailers, with some contracts specifying a 1 for 1 payment and others allowing the payment to change in response to government policy changes. In addition, changes to the EI Act would be required to extend coverage of the proposed new FiT to renewable and low-emission technologies.
The Commission is not in a position to estimate how soon to the EI Act could be changed. It has assumed that 30 September 2013 may be reasonable, or sooner to coincide with an earlier closure of TFiT. In the following discussion references to 30 September 2013 (and 1 October 2013) should also be taken as referring to an earlier date if this is practical.
The Commission has considered two options to implement its recommended future FiT arrangements that would also meet the terms of reference requirement that the Commission’s recommendations do not apply retrospectively. There may be other implementation options that it did not consider that also give effect to the recommendation.
Option 1: close the SFiT and open a new FiT Under option 1, the SFiT would close to new customers from 30 September 2013 and a new market-based FiT scheme for all small low-emissions or renewable distributed generators (100 kW or less) would open on 1 October 2013. Existing SFiT customers would be unaffected by the scheme closure and continue to receive a fair and reasonable price in accordance with their existing SFiT contract until 31 December 2016. The SFiT scheme would close for existing SFiT customers on 31 December 2016 when the ESC (2008) guideline would be rescinded.
Option 2: have two classes of SFiT customers Under option 2, the SFiT would remain open but there would be two classes of SFiT customers from 30 September 2013: • Class A would be existing SFiT customers — these customers would continue to receive a fair and reasonable price in accordance with their existing SFiT contract until 31 December 2016. • Class B would be new SFiT customers, who enter into the SFiT scheme from 1 October 2013. The Class B SFiT would apply to all small low-emissions or renewable distributed generators (100 kW or less).
This would require the ESC to amend its Methodology for Assessment of Fair and Reasonable Feed-in Tariffs and Terms and Conditions (ESC 2008), so that: • Class A SFiT customers would continue to receive a ‘one-for-one’ price • Class B SFiT customers would receive an ‘efficient and fair’ price.
Both options 1 and 2 would require amendments to the EI Act and associated regulation. Advice to the Commission is that its recommended future FiT arrangements could not be implemented more quickly because of the need to change the legislation. Given this, the Commission considers that option 1 is preferable, being clearer and more certain for customers and industry.
As noted above, to avoid confusion about the criteria used by the ESC, the Commission has adopted ‘efficient and fair’ to characterise FiTs that are based on the wholesale price of electricity.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 191 New Feed-in tariff From 1 October 2013 a new FiT would be determined by the market and expanded to cover renewable and low-emission technology. Under the new FiT, retailers with more than 5000 customers would be required to offer to purchase electricity supplied by low- emission and renewable distributed generators of 100 kW or less. This price would be determined in the retail market and would need to be efficient and fair based on the output value of the distributed electricity supplied to the grid. This last point would require guidance from the ESC.
The Commission considers this is the appropriate next step towards phasing out regulated FiTs, which the Commission suggests be done in three years, subject to the satisfactory completion of the reforms to the NEM that are currently on foot, and consideration of how competition is working in Victoria and in other jurisdictions. Consumer protection, information provision and better connection processes are part of the arrangements going forward. Throughout this transition period the Victorian Government (Department of Primary Industries) would monitor the range of market offers that are made by retailers. It should also draw on the operation of the New South Wales FiT market (in particular) for evidence that may highlight any significant issues that might lead Victoria to make further reforms to improve market outcomes.
The Commission sees merit in the Victorian Government, through the ESC, periodically publishing information on the likely range of prices that would be consistent with the efficient and fair value of electricity supplied by distributed generators based on wholesale prices. Retailers would continue to be required9 to publish up to date information on their websites on prices and terms and conditions for the purchase of electricity from distributed generators, and would provide relevant pricing information to the AER consistent with price disclosure guidelines. This information could then be used as an input into the AER’s price comparison website (which would also enable comparison of FiTs). If this information is not available through either the AER or by private providers, it should be provided by the Victorian Government.
During the transition the ESC would continue to consider the extent to which FiT market offers are consistent with new efficient and fair criterion based on the wholesale price of electricity. Provided they are efficient and fair, retailers would be free to offer a range of tariffs that could vary according to location and time of day.
As mentioned earlier, the Commission considers the new FiT should not be constrained to the principal place of residence, as this would simply lead to greater administrative complexity. Moreover, it would limit opportunities for distributed generation to contribute to improving the performance of the electricity system.
The approach outlined above is consistent with the Commission’s view that over time the retail market is sufficiently competitive to support market determined FiTs, if supported by consumer protection and access to relevant information. It recognises that immediate deregulation could create significant disruption and, given the current state of the market and participants’ concerns about the strength of retailer FiT competition, a more managed transition to a competitive market would provide greater net benefit as:
• Changes to the national retail regulatory framework would have had time to bed down, reducing uncertainty in the market.
9 Under the Electricity Industry Act 2000 (Vic).
192 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • Victoria would have had the opportunity to reduce the significant regulatory burdens that arise from the current cumbersome processes for connecting distributed generation and signing up for FiTs. These changes would make it easier for consumers to choose, and reduce a major business cost on small installers whose businesses would also be disadvantaged by any uncertainty in the transition to deregulated FiTs. • Any consumer protection or information provision regulation could be bedded down, including the proposed move to national information provision, to ensure that these protections are sufficient to support effective competition. • Victoria could monitor deregulation in New South Wales and use the experience there to inform and improve its FiT policy going forward.
For these reasons the Commission is proposing a transition process where the distortions in prices are removed in the first instance but certainty that the market will continue to offer competitive FiTs is maintained. It is proposed that this guarantee be removed after three years once it has been demonstrated that the new market is mature enough to support competitive outcomes. More specific transitionary measures are discussed in chapter 10. A summary of key dates and events is provided in table 9.13.
Table 9.13 Key dates
Event Dates Notes Close TFiT to new 30 September 2013 or when customers 75 MW capacity is reached Close current SFiT 30 September 2013 Legislation required to new customers Establish new FiT 1 October 2013 or Legislation required. ESC to (market-based) immediately after SFiT closure consider whether new FiTs are consistent with efficient and fair criteria — redefined to reflect a wholesale plus value of electricity Publish From 1 October 2013 until 31 information on December 2016 minimum FiTs considered to be efficient and fair Market-based FiTs 1 January 2017 to apply Current SFiT To receive a FiT as per All SFiT customers continue to customers contract made prior to 30 receive 1for1 until 31 December September 2013 (or date of 2016. Afterwards payment SFiT closure) until 31 depends on type of contract. December 2016 Current TFiT Continue on current TFiT As specified in current legislation customers contract until 31 December 2016 Current PFiT Continue on current PFiT As specified in current legislation customers contract until 31 October 2024
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 193 Recommendation 9.1 That, to improve the efficiency and effectiveness of the operation of feed-in tariffs (FiTs) in Victoria, the Victorian Government: • close the Transitional FiT to new entrants, either by 30 September 2013 or once the 75 MW capacity is reached (as currently provided in legislation), whichever occurs first – those customers currently eligible to receive a Premium FiT (which is now closed) or TFiT to continue to receive this tariff until the end of the contracted period • close the Standard FiT to new entrants at the same time as closing TFiT, or as soon as practical thereafter. Ensure that current SFiT customers continue to receive a feed-in tariff not less than the tariff agreed to prior to the date of closure to new entrants, until 31 December 2016 by continuing the ESC ‘Fair and Reasonable’ guideline until 31 December 2016. The ESC guideline to be rescinded with effect from 1 January 2017 • establish a new net FiT scheme simultaneously with the closure of SFiT to new customers, to require that Victorian electricity retailers with more than 5000 customers offer ‘efficient and fair’ prices for electricity exported to the grid by all small low-emissions or renewable distributed generators (100 kW or less) until 31 December 2016. Define low-emissions technology as generators that produce 50 per cent or less of the emissions intensity of electricity generation in Australia • establish market-based FiTs from 1 January 2017 to apply to all new participants for electricity supplied by distributed generators through the retail electricity market • allow market-determined arrangements based on gross payments by mutual agreement • ensure a FiT comparison website is operational by 31 December 2016 (the end of the transition period), provided by the Victorian Government if a Commonwealth or private site is not available. That the Essential Services Commission: • publish information on the likely range of minimum wholesale market-based net feed-in tariffs which would be consistent with an efficient and fair offer — updated at regular intervals and published until 31 December 2016. The methodology adopted by ACIL Tasman suggests (at May 2012) a range of between 6 and 8 cents per kWh for 2013. • From 1 October 2013 to 31 December 2016, assess, on referral from the Minister for Energy whether new FiT offers are consistent with the ‘efficient and fair’ criterion, defined to reflect a wholesale-based value of electricity (including network system losses).
194 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION 10 Transitional arrangements 10.1 Introduction
This chapter addresses transitional issues in implementing recommendation 9.1. Experience from the process and attention to detail of the closure of the premium feed-in tariff (PFiT) has shown the importance of minimising adverse impacts on:
• installers and electricity businesses — especially minimising the creation of boom and bust cycles on distributed generation installation • customers — especially minimising uncertainty and ensuring maximum provision of information.
10.2 What actions has the Commission recommended?
10.2.1 Future feed-in tariff arrangements
The Commission’s terms of reference make it clear that the Commission’s recommendations are not to be retrospective. Contracts will be honoured until the date they are specified to expire. In considering changes to FiTs and transition arrangements, the Commission’s guiding principle has been that ‘a contract is a contract’. Hence those currently on PFiT will continue to receive this tariff until 2024 and those on transitional FiT (TFiT) and standard FiT (SFiT) until 2016.
The Commission has recommended that the Victorian Government:
• close the transitional FiT to new entrants, either by 30 September 2013 or once the 75 MW capacity is reached (as currently provided in legislation), whichever occurs first — those customers that are currently eligible to receive a PFiT (which is now closed) or TFiT to continue to receive this tariff until the end of the contracted period • close the standard FiT to new entrants at the same time as closing TFiT, or as soon as practical thereafter. Ensure that current SFiT customers continue to receive a feed-in tariff not less than the tariff agreed to prior to the date of closure to new entrants, until 31 December 2016 by continuing the Essential Services Commission (ESC) ‘Fair and Reasonable’ guideline until 31 December 2016. The ESC guideline to be rescinded with effect from 1 January 2017 • establish a new FiT scheme simultaneously with the closure of SFiT to new customers, to require that Victorian electricity retailers with more than 5 000 customers offer ‘efficient and fair’ prices for electricity exported to the grid by all small low-emissions or renewable distributed generators (100 kW or less) until 31 December 2016. Define low-emissions technology as generators that produce 50 per cent or less of the emissions intensity of electricity generation in Australia • establish market-based FiTs from 1 January 2017 to apply to all new participants for electricity supplied by distributed generators through the retail electricity market • allow market-determined arrangements based on gross payments by mutual agreement • ensure a FiT comparison website is operational by 31 December 2016 (the end of the transition period), provided by the Victorian Government if a Commonwealth or private site is not available.
TRANSITIONAL ARRANGEMENTS 195 In addition, the Commission has recommended that the ESC:
• publish information on the likely range of minimum wholesale market-based net FiTs which would be consistent with an efficient and fair offer —updated at regular intervals and published until 31 December 2016. The methodology adopted by ACIL Tasman suggests a range of between 6 and 8 cents per kWh for 2013 • from 1 October 2013 to 31 December 2016 consider the extent to which new FiT offers are consistent with efficient and fair criteria, defined to reflect a wholesale-base value of electricity (the output value, including system losses).
This chapter considers the process for transitioning to these new arrangements and the implications for those currently receiving FiTs.
10.3 Implications for current PFiT and TFiT customers
The terms of reference specifically state that ‘any changes to existing arrangements would not be applied retrospectively’ and the Commission has applied this principle to current PFiT, TFiT and SFiT customers. The application of this principle to SFiT customers is discussed in chapter 9.
10.3.1 PFiT customers
If the Commission’s recommendation 9.1 is accepted by the State Government, customers currently receiving the PFiT (which is closed to new customers) will continue to receive this FiT until it is contracted to end in 31 October 2024. The key transition issue is to ensure this information is communicated to existing PFiT customers. (The Commission notes several participants had misunderstood its recommendation and thought their contracted PFiT rate would be terminated early).
At the expiry of their contract these customers would be free to shop around for a new FiT with retailers based on retailer’s ‘efficient and fair’ offers at the time.
10.3.2 TFiT customers
Recommendation 9.1 means customers currently receiving the TFiT could continue to receive that tariff for their contract period (31 December 2016). At the expiry of their contracts the customers could select a new FiT with retailers based on retailers’ ‘efficient and fair’ offers at the time. The Department of Primary Industries (DPI) should ensure that this information is disseminated to existing TFiT customers to minimise uncertainty and unnecessary anxiety.
The TFiT closure in 2016 was foreshadowed at the time TFiT was established and the termination date has been specified in each customer’s TFiT contract.
The Commission suggests that the process for closing TFiT to new customers be modelled on that for the PFiT scheme, with any lessons from that closure to be incorporated in the TFiT closure process. In particular, as part of the closure process, there should be:
• information provided to customers so that they understand the process and timelines • monitoring of the process to identify any problems in enough time that remedial action can be taken
196 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • an effective role for the Energy and Water Ombudsman Victoria (EWOV) and Consumer Affairs Victoria (CAV) so that where problems arise for customers they have a right of redress.
10.4 Implications for current SFiT customers
The implications of the Commission’s recommendations for current SFiT customers are more complex than for TFiT and PFiT customers.
Interpreting non-retrospectivity is not straight forward as the provisions of SFiT contracts vary among retailers (Table 10.1). Some allow for rate changes while others lock in a rate for a particular period.
Table 10.1 Examples of published SFiT contracts Retailers Click • ‘You give your explicit informed consent that the your Standard Solar Energy Feed-in Tariff can change from time to time, in-Iine with the relevant Codes and Guidelines… • The Feed-in Contract may be subject to change as a result of future legislative amendments to the Electricity Industry Amendment (Solar Feed-in Tariff) Act 2009 (Victoria) or a change in any other Codes and Guideline.’ Source: http://www.clickenergy.com.au/downloads/customer/Standard-Feed-In- Contract.pdf (accessed 23/7/2012) Dodo • ‘You agree to sell to US, and We agree to purchase, each kilowatt Power and hour of Feed-in Electricity at Our Standard Feed-In Tariff, being the Gas peak electricity rate (in dollars per kilowatt hour) applying under Your Electricity Sales Contract. We will give You advance written notice of any change to Your Standard Feed-in Tariff. • … this Feed-In Contract will terminate… if Your Facility is a SREGF [Small Renewable Energy Generation Facility], on the date the Standard Feed-In Tariff Scheme (as it applies to Your Facility or this contract) ends or is repealed.’ Source: Victorian Government Gazette, No. S 5 Friday 6 January 2012, pp. 1-14
Origin • ‘Origin may terminate this Agreement… on 30 days written notice for convenience… • … the Parties may vary this Agreement by agreement in writing between the Customer and Origin. The Export Energy Charge is varied each time Origin publishes a new price under section 40G of the Act [Electricity Industry Act 2000 (Vic)]. Origin will notify the Customer as soon as practicable of any variation to the Export Energy Charge.’ Source: http://www.originenergy.com.au/files/FeedinAgreement2122008.pdf (accessed 23/7/2012) TRUenergy • ‘The TRUenergy Feed-In Agreement may be subject to change as a result of future legislative amendments to the Electricity Industry Act 2000. Otherwise, this agreement may only be varied with your explicit informed consent.’ Source: http://www.truenergy.com.au/downloads/TC_SFT_1203_VI_WEB.pdf (accessed 23/7/2012)
TRANSITIONAL ARRANGEMENTS 197 10.4.1 Non-retrospectivity
This issue of how to interpret non-retrospectivity as required by the Commission’s terms of reference was raised by a number of participants to the inquiry. Uncertainty was a particular issue for those with, or contemplating installing, larger distributed generation units. For example Mike Reeves noted that non-retrospectivity of policy may have:
The implication that customers would remain on SFiT ‘until’ the expiry of their contract (page XXIX) is inconsistent with the ‘no end date’ on SFiT on the DPI website and the Commission should clarify this as soon as possible for new customers contemplating their options at the 5 kW cross-over point. (sub. DR130, p. 4)
The critical issue for retailers is that differences in contractual arrangements mean that some retailers are able to change the SFiT rate while other retailers may be obliged to offer the existing one-for-one rate. Some retailers and some consumers may therefore be disadvantaged relative to others.
Submissions from retailers reflected these concerns. For example, AGL noted that:
AGL’s Electricity Generation Feed-in Plan contains clauses the permit changes to the amount of the Feed-in Tariff in line with Regulatory Requirements. Accordingly, AGL does not foresee any contractual difficulties associated with the Commission’s proposed recommendations. (sub. DR193, p. 5)
In contrast, Simply Energy stated:
Simply Energy has contracts in place with existing customers that do not allow the FiT rate to differ from the rate paid for electricity consumption. This means Simply Energy would have two options. Firstly, we could recontract our entire existing SFiT customer base to apply the change. This would be resource-intensive, and would risk losing customers who do not accept the new terms. This option would not be in line with our understanding of the Government’s terms of reference regarding non-retrospectivity. The second option is to retain our current terms for existing customers. Under this scenario we would be significantly disadvantaged compared to other retailers who were able to accommodate a rate change, because SFiT credits are not Government subsidised. We therefore consider that the most equitable solution is to retain the current fair and reasonable interpretation for all existing SFiT customers. (sub. DR172, p. 2)
The Commission considers that there are two options for dealing with existing SFiT customers.
(1) For those customers on ‘floating rate’ contracts the possibility of rate changes are allowed in contracts. In such circumstances changing the meaning of ‘fair and reasonable’ to be market-based would flow through to SFiT customers. (2) Close the current SFiT (and preserve for a period the existing entitlements of those with contracts) and commence a new market-based FiT for all new customers (reflecting the Commission’s recommendations on providing a technologically neutral market-based FiT). Existing SFiT customers could be transitioned onto the new arrangements over time. Participants indicated that there are advantages and disadvantages of both options.
198 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The first option would result in current SFiT customers being treated differently depending upon their retailer and contractual arrangements. And, as noted by Simply Energy, different retailers may be affected differently and some disadvantaged relative to others.
The option to close the current SFiT and quarantine existing customers while creating a new scheme for new entrants was supported by a number of participants, particularly among electricity retailers, including the Energy Retailers Association of Australia (ERAA) (sub. DR180, p. 1)and Origin Energy (sub. DR196, p. 1). Simply Energy’s comments typified the views of these participants:
Simply Energy’s preference is that SFiT also be closed to new applicants rather than amending key features of SFiT for new applicants. This is a simpler approach and will provide a smoother transition from a scheme- specific FiT regime to market-based pricing. (sub. DR 172, p. 2)
AGL also noted there are administrative difficulties in having two mandated tariffs under one scheme. They argued that:
… AGL does not support transitional arrangements that allow for existing Standard FiT customers to receive feed-in tariffs calculated under current arrangements, while new customers to the scheme receive a tariff calculated on the basis of market forces. From a practical perspective, the only way in which AGL could pay different feed-in tariffs to different customers (eg. existing versus new customers to the Standard FiT scheme) would be if distributors develop a separate network code. (sub. DR 193, pp. 3-4)
The Commission agrees there are advantages and disadvantages of each option. A comparison of the two options is provided in table 10.2.
Table 10.2 SFiT options
Option Advantages Disadvantages Option A: SFiT rate to • Consistent with current • Different SFiT customers change if allowed by contractual receiving different rates existing contract arrangements • Some retailers • Minimises cross subsides financially disadvantaged relative to others Option B: Close the current • Provides a clear break • Longer period of SFiT (and preserve for a between old and new current cross subsidy period the existing market-based from customers without entitlements of those with arrangements small-scale distributed contracts) and • Existing SFiT customers generation to SFiT commence a new treated equally customers market-based SFiT • Retailers not disadvantaged because of contractual differences • Administratively simpler for some retailers
Source: Brumby 2004; Batchelor 2009; O’Brien 2011.
TRANSITIONAL ARRANGEMENTS 199 Ultimately, the decision of how to transition existing SFiT customers is a matter for the Government. A strict interpretation of non-retrospectivity would leave contracts unchanged but, for those on contracts that allow for variation in price, the price would fall. This may be perceived as unfair by customers affected. The Government could choose to provide a grace period for these customers, for example, by adopting the same timeline as for TFiT customers.
The Commission considers that option B in table 10.2 would be considered fairer by consumers. It has the added advantage of a clear distinction between the schemes, avoiding confusion about the level of payment and simplifying administration.
If option B were selected, the Commission considers the current SFiT should continue no longer than 31 December 2016 (the same as TFiT).
10.5 Implications for future customers
In the case of future FiT customers (that is those not currently receiving a FiT) the Commission’s recommendation 9.1 raises a number of issues, including:
• closure of the TFiT scheme • the new ‘efficient and fair’ FiT • impact on the take up of PV and impact on the solar industry.
10.5.1 Closure of the TFiT scheme
The Commission has recommended that the TFiT scheme be closed to new customers, either by 30 September 2013 or once the 75 MW capacity is reached (as currently provided in legislation), whichever occurs first. A number of potential transitional issues need to be considered:
• How should the cut off for eligibility be determined? • How should the closure be managed to limit and manage any last minute rush?
In considering these issues, the Commission and inquiry participants have had the benefit of drawing on the experience of closing the PFiT to inform their views.
There is a transitional issue of how to handle customers who apply for entry prior to the TFiT scheme’s closure, but for whom the application process may not be completed before the closure date. This was a particular problem in the case of PFiT and led to many complaints to EWOV (box 10.1).
200 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Box 10.1 Energy and Water Ombudsman Victoria (EWOV) case study The customer submitted all the required solar paperwork prior to the cut-off date of 30 September 2011. Soon after she received a bill without a solar rebate and immediately contacted her electricity retailer. Her electricity retailer initially advised that it had not received the required paperwork. Dissatisfied with the response, the customer made a complaint with EWOV. However, after the complaint was lodged, it was confirmed by the electricity retailer that all paperwork was sent. It was revealed that her electricity retailer had raised a service order to install a bi- directional meter, which occurred on 20 July 2011, but had raised an incorrect service order requesting SFiT instead of PFiT as the solar tariff. EWOV is continuing to investigate this issue with the electricity retailer. It is unlikely that this customer will receive PFiT, even though this was a retailer error, as the scheme is now closed to new customers. Source: EWOV, sub. 48, p. 3.
Legal advice to the Commission indicated that legislation requires that to be eligible for the TFiT scheme the application process must be complete. This has implications for how the transition process for the closure of the TFiT is managed.
In the draft report, the Commission suggested that one option is to base the cut-off on the lodgement of relevant paperwork with the retailer by a specific date. This design would minimise the number of eligibility issues that are caused by factors outside of the control of the consumer. While this approach was supported by a number of participants, for example Mike Reeves (sub. DR130), subsequent advice to the Commission was that this approach is not legally possible.
The alternative is to provide a sufficient period for those who submit paperwork to be eligible for the scheme, which, broadly speaking, was followed in closing PFiT. Along these lines, the Mildura Development Corporation suggested that
… DPI should publish the closing date of the FiT; this should be no less than 35 days prior to the scheduled close. (sub. DR177, p. 4)
In this circumstance, the Commission suggests that there be a specified date at which, if paperwork has been submitted, there is a very high probability that it will be processed prior to the closure of the TFiT. However, it does not seem practical to ensure all those who apply will be eligible because there is nothing to prevent applications right up until the formal closure date.
The other transitional issue relates to the criteria to close the scheme and managing any last minute rush to secure eligibility for the TFiT. The Commission considers that the provision of timely information on when the capacity cap is being approached is critical. Participants expressed a similar view, for example, AGL (sub. DR193) and Mike Reeves who argued that:
The publishing of updates (on the DPI website, outlined previously) of installed MW of solar PV on TFiT would avoid the ‘last-minute’ hard sell advertising that characterized the closing of the PFiT, and inform consumers. (sub. DR130, p. 3)
The Commission agrees with this view. In order to reduce uncertainty and facilitate customers making informed decisions about whether and when to apply for TFiT, it is important that customers are informed on progress towards the capacity cap in case it
TRANSITIONAL ARRANGEMENTS 201 is reached before the legislated closure date for the scheme. This information needs to be published as soon as possible and updated regularly so that potential customers can make informed decisions and can adjust their plans if the cap is reached sooner than expected.
The Commission understands that some data on progress towards the cap is available, but this should be updated monthly.
Information provision during the transition to the Commission’s recommended regime is discussed further in the following section.
10.5.2 New customers on the proposed new FiT
If recommendation 9.1 is accepted, customers eligible for the new FiT and entering an agreement for a FiT for exported electricity would be eligible to receive the ‘efficient and fair’ market rate offered by retailers. The Commission considers it likely that different retailers will offer different rates and conditions and it will be up to each customer to explore the offer that best suits their needs. Under the Commission’s recommendation the offers made by retailers would be available to all distributed generation technologies and not favour a particular technology.
The Commission has suggested that a price comparator website be established to make the process of comparing retailer offers easier. The website should be available by the end of the transition period recommended by the Commission and provided by the Victorian Government if it is not available from the private sector or the Commonwealth.
In addition, once the new ’efficient and fair’ FiT is established, the Commission expects there would be more certainty for distributed generators as there would be no need to make substantive changes in scheme design once implemented. The FiT rate would vary depending on market rates, the same as other contractual arrangements (such a mortgages) that allow for floating rates. Consumers would be aware of this possibility and would need to take into account possible future changes in FiT rates when making the decision to invest in distributed generation.
10.6 Impact on distributed generation customers and industry
A number of submissions raised concerns that the FiT proposed by the Commission would make PV unattractive and damage the solar industry. For example, Robert Mossop argued that:
The success or failure of the solar industry and the development particularly of small scale commercial opportunities in Victoria will depend on maintaining a reasonable return on investment capacity for the investment in solar energy. If no feed-in benefit is able to be reasonably maintained then there will be a significant drop in demand for solar which will cause job losses and likely significantly affect the capacity of the State to meet it’s 20% target for renewable energy by 2020. (sub. DR159, p.1)
Similarly, Enviromate argued that:
Any cut to the SFIT regime before that 6-7 year pay back will have a materially detrimental impact on the industry who needs to have ROI [return on investment] certainty in order to invest in solar (and other renewable
202 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION generation). This impact cannot be underestimated and must not be ignored. (sub. DR133, p. 1)
The Commission notes these views, and considers reduction in the rate of installation is highly likely from the explosive growth between 2009 and 2012. Figure 10.1 shows the capacity of solar PV installed annually, and highlights the impact of the PFiT (introduced in late 2009).
Figure 10.1 Annual installed and cumulative capacity of PV in Victoria (MW)
150
100
50
0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Cumulative installed capacity Annual capacity installed
Note: 2011 data based on first eight months of the year only. Source: CEC 2011a, pp.32, 34.
The AEMC has found, however, that even with lower FiT rates there will still be growth in the installation of small scale renewable electricity generation because:
… forecasts of higher retail electricity prices and reductions in the technology costs for solar PV will still provide incentives for some consumers to take-up the SRES [Small Scale Renewable Energy Scheme]. (AEMC 2011b, p.iii–iv)
The Commission notes that unsustainable policies have contributed to volatility, low long-term certainty and frequent large changes in policies. This will always be a risk until a market-based FiT is established. Moreover, the recent FiTs offered have led to significantly larger take up of solar electricity than contemplated. For example, after the PFiT was introduced on 1 November 2009, the Victorian Climate Change White Paper forecast in July 2010 that Victorian households would install 40 MW of solar by 2014 (DPC 2010, p.15). By the end of 2011 Victorian households had installed an
TRANSITIONAL ARRANGEMENTS 203 estimated 150 MW (CEC 2011a, p.32) and are expected to install approximately 250 MW by 2013-14 (ACIL Tasman 2011a, p.42). The Commission’s recommendations reflect a desire to be very clear about the long-term target and manage the transition process.
Second, there are many indications that FiTs, while a focus in the past, will not necessarily drive future investment in small-scale distributed generation. Other factors that drive the attractiveness of these investments are strengthening, such as the impact of the carbon tax and lower technology costs.
The main benefit to solar customers will continue to be the avoided cost of the electricity produced and used by the customer. For example, in 2013 a household with a 2.5 kW system would save $481 on avoided electricity purchase and receive a benefit of $73 from electricity exported back into the grid (chapter 9).
Third, expanding the FiT will create greater certainty for other technologies or other types of installations that did not receive a FiT in the past.
10.7 Managing the transition
The Commission considers that providing timely, relevant information to market participants is essential to a smooth transition, together with effective, clear roles for the ESC, CAV and EWOV.
10.7.1 Information provision
Effective communication with customers and those likely to be affected by changes to FiTs is essential to ensure a smooth transition to new arrangements.
Reflecting on the experience with closing the PFiT, the Solar Energy Industries Association suggested during consultation that greater clarity with respect to information and time paths was needed, and that a dedicated website be available for clients to understand the changes (what is required, and who is responsible for various installation and contract activity).
The need for information was supported by a wide range of participants (for example, Simply Energy, sub. DR172, p.2, and the Mildura Development Corporation, sub. DR177, p. 4). ERAA expressed a typical view that:
… it is essential that any transitional arrangements are clearly communicated to all parties well in advance. This includes clear communication of eligibility criteria, staged deadlines, visibility of progress towards a scheme cap and consideration of the availability of electrical contractors due to seasonal demands. (sub. DR180, p. 2)
The Commission suggests that during the transition to the proposed FiT arrangements, DPI should also engage in an information campaign and outline the changes and transitional arrangements including:
• relevant dates and cut off criteria • contact information (for example, retailers and EWOV) • who is responsible for various activities • fact sheets and useful tips
204 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • outline of the new arrangements — what is different and the implications for customers.
10.7.2 Role of the ESC
As part of the transition to a market-based FiT, the Commission has recommended that the ESC:
• publish information on the likely range of wholesale market-based net FiT payments which would be consistent with an efficient and fair offer — updated at regular intervals • assess, as required, the extent to which FiT market offers are consistent with efficient and fair criteria, defined to reflect the wholesale value of electricity (the energy value).
10.7.3 Role of CAV and EWOV
Experiences with the closure of PFiT suggest that there may be some companies that take advantage of the closure of the scheme to pressure households to install distributed generation (especially rooftop solar PV) and engage in pressure selling tactics.
The Commission considers that CAV will need to play an active role during the transition period to ensure that all parties act within the law and do not engage in misleading conduct. EWOV will also need to be ready to assist with complaints and queries from the public during the transition period to ensure that consumer complaints and concerns are addressed. As with industry, it is important that CAV and EWOV are notified early of when the FiT schemes will change and the planned changes. With early notice, consumer organisations can adopt proactive strategies that increase consumer protection and respond to consumer questions and complaints.
TRANSITIONAL ARRANGEMENTS 205
Appendix A: Consultation
A.1 Introduction
The Victorian Competition and Efficiency Commission (the Commission) received the terms of reference to undertake an inquiry into feed-in tariff (FiT) arrangements and barriers to distributed energy on 13 January 2012. In keeping with its usual process to consult extensively during public inquiries, the Commission advertised the inquiry in The Age, Herald Sun and the Weekly Times in January and February 2012. The Commission also published an issues paper in February 2012, which outlined:
• the scope of the inquiry • how to make a submission • the Commission’s consultation process • the inquiry timetable.
The issues paper invited participants to register an interest in the inquiry and to make submissions. In total, the Commission received 1256 registrations of interest. Eighty-six individual and 844 proforma submissions via Environment Victoria, were received before the release of the draft report. A further 114 submissions and 100 short submissions were received following the release of the draft report (section A.2).
The Commission held six roundtables. The first roundtable was held on 8 March 2012, with participants from the Energy Efficiency Council. Participants discussed issues relating to connecting distributed generators to the distribution network and FiT pricing. The second roundtable, held on 15 March 2012, focused on connecting distributed generation and FiT prices from the perspective of electricity retailers and distributors. The third roundtable, held on 10 April 2012, discussed similar issues but from a consumer perspective. Roundtable participants included government and non-governmental organisations that deal with, or advocate for, consumer rights (section A.3).
A further three roundtables were held following the release of the draft report. A roundtable to discuss transitional arrangements was held on 30 May 2012 and included representatives from Consumer Affairs Victoria (CAV), Consumer Utilities Advocacy Centre (CUAC), Department of Primary Industries (DPI), electricity retailers, the Energy and Water Ombudsman Victoria (EWOV) and the Solar Energy Industry Association (SEIA). A second roundtable was held on 31 May 2012 which focused on distributed generation connection issues. Attendees at this roundtable included representatives from the electricity retailers and distribution businesses, SEIA and government agencies (DPI and EWOV). A third roundtable was held on 7 June 2012 to discuss both transitional arrangements and connections issues in greater detail with electricity retail businesses and a similar meeting was held with solar installers.
The Commission consulted extensively (including meetings, visits and telephone discussions) with Commonwealth, State and local government departments and agencies, businesses, academics, associations and individuals (section A.4).
A.2 Submissions
The Commission received 200 submissions (table A.1). All submissions are public documents that can be viewed on the Commission’s website.
APPENDIX A: CONSULTATION 207 Table A.1 Submissions received No. Participant No. Participant 1 Comfortid.com Pty Ltd (1) 2 WattSource 3 Jill Dumsday 4 Exigency 5 Gerard Noonan (1) 6 Gerard Noonan (2) 7 H Malcolm Walter 8 BRT Consulting Pty Ltd Dandenong Ranges Renewable 9 Alistair Smith 10 Energy Association (1) 11 Bill Grant 12 Jeremy Ashton 13 Janet M Fitzwater 14 Lucinda Young 15 Solway Nutting 16 Jay Smith 17 Maria & Paul Hayes 18 Trish Sharkey 19 Nicole & Jason Drage 20 Johanna Winchcomb Duncan Brown & Jeanette 21 22 Lucy Armstrong Gillespie 23 Gordon Donaldson 24 Patricia Rivett 25 Emerald for Sustainability 26 Roger Willsher 27 Mike Reeves (1) 28 Louise Flaherty 29 Maria A Bell 30 Sandra Coventry 31 Dean Bridgfoot 32 Christine Easdown 33 Sally Kaptein & Jack Carolan 34 Robin Jensen 35 Fiona M Chant 36 Rebecca Edwards National Electrical & 37 38 Dawn Gilson Communications Association (1) 39 Jenny Francis 40 Alan Jones 41 Ceramic Fuel Cells Limited (1) 42 Neil Rankine 43 David Sparks (1) 44 Prof Alan Pears (1) 45 Climarte 46 Judy McShane Energy & Water Ombudsman 47 Frank Barbara 48 Victoria (1) Mildura Development Corporation 49 50 Ironbark Sustainability (1) Saturn Corporate Resources Pty 51 Environment Victoria 52 Ltd 53 Regional Cleantech Solutions 54 Susie Burke 55 LIVE 56 Australian Solar Round Table (1) 57 Advance Solar Electrical 58 Simply Energy (1) South East Councils Climate 59 60 Enviromate Change Alliance (1) 61 Darebin City Council 62 Rachel Cook 63 Australian PV Association 64 Beyond Zero Emissions 65 F Lisner 66 David & Pamela Rothfield
208 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION Table A.1 Submissions received (cont) No. Participant No. Participant 67 APA Group (1) 68 Alex Macleod Warburton Community Hydro 69 70 Liz Burton Project (1) 71 Union Fenosa Wind Australia 72 AGL (1) Alternative Technology Energy Supply Association of 73 74 Association Australia (1) 75 Moreland Energy Foundation 76 Clean Energy Council Renewable Energy Solutions 77 United Energy (1) 78 Australia Holdings Ltd 79 Jemena 80 CitiPower & Powercor (1) 81 Origin Energy 82 Graham Scarlett (1) Loy Yang Marketing 83 84 Neilson Electronic Systems Pty Ltd Management Company 85 Lumo Energy 86 Grattan Institute D87 Mark Collard D88 Fernando Longo D89 Glenn Michael D90 Lee B Sundin D91 Peter Anzo D92 Regional Cleantech Solutions (2) D93 Withdrawn D94 Stewart Kerr D95 Roger Lambert (1) D96 Elizabeth Walsh D97 Graham Scarlett (2) D98 John A Southern D99 David Barnett D100 Withdrawn D101 Rupert Steiner D102 Recurrent Technologies Pty Ltd D103 Robin Friday D104 David Stratton D105 Roger Lambert (2) D106 Eleonora Symmonds D107 Michael Wakefield D108 Antoni Pisa D109 Peter Strickland D110 Peter Dewez D111 City of Port Phillip D112 Comfortid.com (2) Dandenong Ranges Renewable D113 Seng Tan D114 Energy Association (2) D115 Gerard Noonan (3) D116 Andrew Slodkiewicz D117 Janette Coleman D118 Jane Hildebrant D119 Lois Knight D120 Darren Davis D121 Satish Verma D122 Bernard Dunlop D123 Anthony Jones D124 Roy & Joy Verran D125 Ray Cowling D126 Jan Strawhorn D127 Huw Jones D128 Mike J Dunn D129 David Sparks (2) D130 Mike Reeves (2) D131 Ann Scally D132 Pam & Peter Hannan D133 Enviromate (2) D134 Richard West
APPENDIX A: CONSULTATION 209 Table A.1 Submissions received (cont) No. Participant No. Participant D135 Ceramic Fuel Cells Limited (2) D136 Gerard Verhoef D137 Geoffrey Dillon D138 Patricia Christian Northern Alliance for Greenhouse D139 Bruce Person D140 Action D141 Moira Walsh D142 John Solley D143 John Fisiak D144 Mark Oscar D145 Heinz Herrmann D146 Peter & Colleen Raynes D147 Withdrawn D148 Jeffrey Watkins D149 Alan Griffin D150 William Raper D151 Sandra & Ian Dinsdale D152 Alex Dupleix D153 John Sime D154 Mike Erskine D155 Anne-Marie Gibson D156 Roger Ghost D157 Graeme Hanks D158 John Speelmeyer D159 Robert Mossop D160 Energy Innovation Co-operative D161 Housing Industry Association D162 Jailal Lalji Energy & Water Ombudsman D163 D164 P, S & D Marcuccio Victoria (2) D165 Rowan Ewing D166 Jack Melhuish D167 Warburton Hydro Group (2) D168 Solar Business Council (2) D169 City of Whitehorse D170 LMS Energy D171 Sally McIlroy D172 Simply Energy (2) National Electrical & D173 City of Boroondara D174 Communications Association (2) South East Councils Climate D175 D176 Mike Daffey Change Alliance (2) Mildura Development D177 D178 Gary Davison Corporation (2) Energy Retailers of Australia D179 Lorraine & William Anthony D180 Limited D181 APA Group (2) D182 City of Melbourne D183 Ian Julian D184 CitiPower & Powercor (2) D185 Prendergast Projects D186 Peter Richardson D187 Andrew Lang D188 Owen Willoughby Alternative Technology D189 D190 Kathryn Miller & Matthew Thomas Association (ATA) (2) D191 Property Council of Australia D192 Prof Alan Pears Energy Supply Association of D193 AGL (2) D194 Australia (2) D195 Bernie McComb D196 Origin Energy (2) D197 Clean Energy Council D198 TRUenergy D199 United Energy (2) D200 Energy Efficiency Council
210 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION In addition, the Commission received 844 submissions from individuals submitted as an Environment Victoria proforma submission. Of these, 718 submissions consisted of the Environment Victoria proforma without any additional comments and 126 provided additional comments or replaced the proforma. A list of Environment proforma submitters can be found on the Commission’s website at www.vcec.vic.gov.au. A copy of the Environment proforma submission and individual additional comments can also be viewed on the Commission’s website.
Following the release of the draft report 100 short submissions were also received. A list of these submitters and their submissions can be found on the Commission’s website at www.vcec.vic.gvo.au.
A.3 Roundtables
The Commission held six roundtables: three roundtables in March and April 2012, and a further three roundtables in May and June 2012 following the release of the draft report. Roundtable participants are listed below (tables A.2, A.3, A.4, A.5, A.6 and A.7).
Table A.2 Energy efficiency roundtable Participant Organisation Mark Lampard AECOM Kriston Symons AECOM Brad Knowles Alerton Bob Norris Dalkia Ben Samways Honeywell Simon Helps MWM Randy Gadient Siemens Dr Matthew Butlin Victorian Competition & Efficiency Commission Deborah Cope Victorian Competition & Efficiency Commission
Table A.3 Retailers and distributors roundtable Participant Organisation Nicole Wallis AGL Siva Moorthy Jemena Alice Adriannse Lumo Energy Ian Cupidon Lumo Energy Annalisa Cattanach Powercor and CitiPower Matthew Serpell Powercor and CitiPower Julie Buckland SP Ausnet Kate Jdanova SP Ausnet Ross Evans TRUenergy Marcel La Bouchardiere United Energy Verity Watson United Energy Dr Matthew Butlin Victorian Competition & Efficiency Commission Deborah Cope Victorian Competition & Efficiency Commission
APPENDIX A: CONSULTATION 211 Table A.4 Consumer groups roundtable Participant Organisation Gerard Brody Consumer Action Law Centre Gemma Dodson Consumer Affairs Victoria David Stanford Consumer Utilities Advocacy Centre Dean Lombard Victorian Council of Social Service Dr Matthew Butlin Victorian Competition & Efficiency Commission Deborah Cope Victorian Competition & Efficiency Commission
Table A.5 Transitional arrangements roundtable – May 30 2012 Participant Organisation Jane Harris Consumer Affairs Victoria David Stanford Consumer Utilities Advocacy Centre John Krbaleski Department of Primary Industries Kate Sadler Department of Primary Industries Tamara Abraham Energy & Water Ombudsman Victoria Belinda Crivelli Energy & Water Ombudsman Victoria Robert McCauley RJM Sunpower Jenna Polson Simply Energy Robert Murphy Solar Energy Industries Association Ross Evans TRU Energy Dr Matthew Butlin Victorian Competition & Efficiency Commission Deborah Cope Victorian Competition & Efficiency Commission
Table A.6 Household-scale connection roundtable – May 31 2012 Participant Organisation Andrew Neilson Ceramic Fuel Cells Limited Matthew Serpell CitiPower and Powercor Sandy Atkins Clean Energy Council Kate Sadler Department of Primary Industries Tamara Abraham Energy & Water Ombudsman Victoria Belinda Crivelli Energy & Water Ombudsman Victoria Neil Fraser Energy Safe Victoria Greg Johnson Energy Safe Victoria Jenna Polson Simply Energy Robert Murphy Solar Energy Industries Association Max Rankin SP AusNet Ross Evans TRU Energy
212 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION Table A.6 Household-scale connection roundtable – May 31 2012 (cont) Participant Organisation Dr Matthew Butlin Victorian Competition & Efficiency Commission Deborah Cope Victorian Competition & Efficiency Commission
Table A.7 Retail business roundtable – 7 June 2012 Participant Organisation Kate Sadler Department of Primary Industries David Lee Energy Retailers Association Darren Bailey Origin Energy David Calder Origin Energy Jenna Polson Simply Energy Ross Evans TRU Energy Deborah Cope Victorian Competition & Efficiency Commission Glen Hepburn Victorian Competition & Efficiency Commission
A.4 Stakeholder consultations
The Commission consulted with academics, businesses, industry associations and key interest groups, and drew on the knowledge and expertise of Victorian, Commonwealth and local government departments and agencies. In addition, the Commission conducted a short Victorian Energy Retail Business Survey to assist its analysis of current and future Victorian FiT arrangements. The Commission sent a copy of the survey to all electricity retailers in Victoria, seeking their comments and feedback. The survey responses form part of the Commission’s broader stakeholder consultation process.
Table A.8 Consultation participants Organisation or Individual Organisation or Individual AGL Alan Pears Alternative Technology Association Australian Energy Market Commission Australian Energy Market Operator Australian Energy Regulator Australian Petroleum Production & Building Advisory Council Exploration Association Ceramic Fuel Cells Limited City of Melbourne Clean Energy Council Consumer Action Law Centre Consumer Affairs Victoria Consumer Utilities Advocacy Centre Department of Business & Innovation Department of Finance & Deregulation (Cth) Department of Human Services Department of Justice Department of Premier & Cabinet Department of Primary Industries Department of Treasury & Finance Energy & Water Ombudsman Victoria
APPENDIX A: CONSULTATION 213 Table A.8 Consultation participants (cont) Organisation or Individual Organisation or Individual Energy Efficiency Council Essential Services Commission Exigency Hepburn Shire Council Hepburn Wind Independent Pricing & Regulatory Tribunal Institute for Sustainable Futures (University Jemena of Technology Sydney) Lumo Energy Minister for Energy & Resources Moreland Energy Foundation Mount Alexander Sustainability Group Office of the Renewable Energy Regulator Powercor and CitiPower (Cth) Productivity Commission Property Council of Australia (Victorian Division) Solar Energy Industries Association SP Ausnet Sustainability Victoria Sustainable Melbourne Fund TRUenergy Victorian Council of Social Service
214 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION Appendix B: Regulation of the electricity sector
Appendix B provides background information on the regulation of electricity in Victoria, focusing on the connecting and selling processes for distributed generation. At the time this report was finalised, it was uncertain when the National Energy Customer Framework (NECF) would be applied in Victoria. The delay of the NECF meant that there was some uncertainty about the regulatory arrangements at the time this report was finalised. The Commission’s description of the regulatory framework in appendix B was current as of 20 July 2012.
B.1 Victorian regulation
The Electricity Industry Act 2000 (Vic) (EI Act) and predecessor legislation have regulated the Victorian electricity supply industry for almost two decades, following privatisation of the State-owned electricity industry in the 1990s. The EI Act supplements the national framework for economic regulation of transmission and distribution services by regulating various matters including:
• a licensing regime for those who generate electricity for supply or sale, or the transmission, distribution, supply or sale of electricity • Victorian feed-in tariff (FiT) arrangements for the premium, transitional and standard FiT schemes.
The Essential Services Commission (ESC), established by the Essential Services Commission Act 2001 (Vic), administers the licensing and service standard provisions of the EI Act. Box B.1 outlines key elements of the EI Act.
Box B.1 Electricity Industry Act 2000 (Vic) The Electricity Industry Act 2000 (Vic) regulates the Victorian electricity supply industry. • Part 2 Division 1 sets out the objectives of the Essential Services Commission (ESC), which include promoting the development of full retail competition in the electricity industry. • Part 2 Division 2 sets out ‘reserve’ powers of the ESC with respect to charges for connection to, and the use of, the distribution system. It also provides that the ESC has the power to regulate tariffs for the supply of electricity (s 12(1)). The Governor in Council may make an order to regulate tariffs for the sale of electricity if the Australian Energy Market Commission concludes that competition in a market for electricity is not effective (s 13). • Part 2 Division 3 requires the ESC to license people who generate electricity for supply or sale, or the transmission, distribution, supply or sale of electricity unless the person holds a relevant exemption. Division 3 regulates the conduct of licensees. Licences are transferable and the ESC can suspend or revoke licences. • Part 2 Division 5 regulates the terms and conditions of sale and supply of electricity. It deals with matters including the publication of tariff information, and the terms and conditions for sale of electricity to certain customers. • Part 2 Division 5A governs Victorian feed-in tariff (FiT) schemes. It sets terms and conditions for the purchase of small-scale renewable energy exports, distinguishing between premium, transitional and standard FiT schemes. FiT schemes are discussed in detail in section B.4.3. Source: Electricity Industry Act 2000 (Vic).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 215 A discussion of the national regulatory framework governing the national electricity market (NEM) can be found in section 2.2.1 of this report.
B.2 Regulatory framework after commencement of the NECF
When the National Energy Customer Framework (NECF) commences in Victoria there will be significant changes to the regulation of the Victorian electricity sector, with many Victorian responsibilities being transferred to the national framework. The NECF includes the National Energy Retail Law (NERL), National Energy Retail Rules (NERR), and amends existing national regulation, including introducing chapter 5A into the National Electricity Rules (NER). The NECF was intended to commence in Victoria on 1 July 2012. Since the publication of the Commission’s draft report, the implementation of the NECF has been delayed in Victoria, and a number of other participating jurisdictions — New South Wales, Queensland and South Australia (O’Brien 2012b; Hartcher 2012; Energex 2012; JIG 2012b). At the time this report was finalised, no decision has been announced about when the NECF will be implemented in Victoria (section 2.2.2).
The NECF will be applied in Victoria by the proposed National Energy Retail Law (Victoria) Bill 2012, which will repeal a significant amount of Victorian energy regulation that will become redundant after the NECF is applied. However, Victorian-specific energy legislation will still be necessary in a number of areas after the NECF commences. The Department of Primary Industries (DPI) intends, where feasible, to consolidate the remaining Victorian-specific energy regulation (DPI 2011n; DPI 2011l). Importantly, in relation to the electricity sector:
• The ESC will retain responsibility for licensing distribution, transmission and generation activities in Victoria. Electricity retailers will no longer be regulated through a State-based licensing scheme and will instead be governed by a national retailer authorisation and exemption regime administered by the Australian Energy Regulator (AER). • The NECF is silent on the issue of FiTs and the Victorian FiT schemes will continue unaffected by the commencement of the NECF in Victoria — although retail license conditions that were linked to feed-in tariffs will become direct statutory obligations under an amended EI Act (DPI 2011l; DPI 2011n; Explanatory Memorandum 2012, p.18). B.3 Connecting to the distribution network The process for connecting connection applicants (CA) to the distribution network will change with the commencement of the NECF. Currently there is one connection process under chapter 5 of the NER for distributed generators, which is supplemented by Victorian regulation, including: • distribution licence conditions • Electricity Distribution Code (ESC 2012a) • Electricity Industry Guideline No. 14: Provision of Services by Electricity Distributors (ESC 2004b) • Electricity Industry Guideline No. 15: Connection of Embedded Generation (ESC 2004a). With the commencement of the NECF in Victoria, the majority of these State-based obligations imposed on distribution network service providers (DNSPs) will be replaced or replicated under the national framework and these Victorian sources of regulation will largely be repealed. Therefore, the NER chapter 5 connection process will only be
216 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION supplemented by a minimal number of State-based requirements that the Victorian Government has decided to retain.
After the NECF commences in Victoria, there will be two processes under the NER for connecting distributed generation to the distribution network:
• a process for registered generators or generators exempt from registration by the Australian Energy Market Operator (AEMO), under chapter 5 • a simplified process for retail customers (including non-registered embedded generators who do not intend to participate directly in the NEM) under chapter 5A. Household-scale distributed generators are likely to connect through the chapter 5A process.
Each connection process has associated rights and obligations in relation to accessing the distribution network and specific sizes/types of generators may be excluded from, or find it more difficult to access, current connecting processes. B.3.1 Connecting registered generators under chapter 5 Registration as a generator
To be connected under chapter 5, registration as a generator in the NEM is required unless AEMO grants an exemption from registration where an exemption ‘is not inconsistent with the national electricity objective’ (NER, cl 2.2.1(c)). Section 7 of the National Energy Law (NEL) states:
The objective of this Law [the National Electricity Objective] is to promote efficient investment in, and efficient operation and use of, electricity services for the long term interests of consumers of electricity with respect to- (a) price, quality, safety, reliability and security of supply of electricity; and (b) the reliability, safety and security of the national electricity system.
To register as a generator with AEMO, each of the generating units within a generating system that a distributed generator owns, operates or controls must be classified. Clause 2.2.1 of the NER requires that:
• each generating unit within a generating system must be classified as a ‘scheduled’ generating unit, ‘semi-scheduled’ generating unit or ‘non-scheduled’ generating unit • each generating unit must be further classified as a ‘market’ or ‘non-market’ generating unit.
Generating units within a generating system may be registered under different classifications (AEMO 2010b, p.7). Generator registration has significant implications for participation in the NEM. The consequences of generator classification for distributed generators selling excess electricity into the distribution grid are discussed in section B.4.1.
Table B.1 provides typical definitions and examples of the available generator classifications. Note that in certain circumstances, AEMO may approve a generating unit classification, even though it does not meet the typical definition of a ‘scheduled’, ‘semi-scheduled’ or ‘non-scheduled’ generator.1
1 See NER cl 2.2 and the NEM Generator Registration Guide (AEMO 2010b).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 217 Table B.1 Categories of registration as a generator
Market: Non-market: A generating unit from A generating unit from which the sent out which sent out electricity is electricity is not purchased purchased in its entirety by in its entirety by the local the local retailer or by a retailer or by a customer customer located at the located as the same same connection point connection point Scheduled: Scheduled market Scheduled non-market A generating unit with a generator generator nameplate rating of 30 MW or greater or a Example: 2000 MW power Example: 40 MW group of generating units station from which all of generating system under connected to a common the electricity is sold via contract for all output to a connection point with a the market local retailer located at combined nameplate the same connection rating of 30 MW or greater point Semi-scheduled: Semi-scheduled market Semi-scheduled A generating unit with a generator non-market generator nameplate rating of 30 MW or greater or group Example: 160 MW wind Example: 160 MW wind of generating units farm from which all the farm under contract for all connected to a common electricity is sold via the output to a local retailer connection point with a market located at the same combined nameplate connection point rating of 30 MW or greater and the output of the generating unit is intermittent Non-scheduled: Non-scheduled market Non-scheduled A generating unit with a generator non-market generator nameplate rating of less than 30 MW or a group of Example: 10 MW Example: 10 MW generating units generating system from generating system under connected to a common which all of the electricity contract for all of its output connection point with a is sold via the market to the local retailer at the combined nameplate same connection point rating of less than 30 MW
Source: (AEMO 2010b, pp.7–8).
Exemption from registration
Appendix 6: Guideline on Exemption from Registration as a Generator of the NEM Generator Registration Guide (AEMO 2010b) provides guidance on the circumstances in which AEMO may exempt a generator from registration. Where a Standing Exemption applies, the generator is automatically exempt and there is no need to apply to AEMO for an exemption from registration (AEMO 2010b, p.1).
• A Standing Exemption exists for generating systems with a nameplate rating of less than 5 MW, provided any of the following are met:
218 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION – the generating system has a total nameplate rating at a connection point of less than 5 MW – the generating system is not capable of exporting to a transmission system or distribution system in excess of 5 MW – the generating system has no capability to synchronise or to operate electrically connected to a distribution system or transmission system – the sent out generation of the generating unit is purchased in its entirety by the Local Retailer or by a Customer located at the same connection point (AEMO 2010b, p.36).
• In exceptional circumstances, AEMO may also grant an exemption from registration on a case-by-case basis. On application, AEMO may grant an exemption from registration for generating systems of more than 5 MW and less than 30 MW capacity which export (sell) less than 20 GWh in any 12 months (AEMO 2010b, pp.36–37).
Registration process
Chapter 2 of the NER governs the registration of generators. The registration process is lengthy and requires the connection applicant (CA) to provide detailed documentary evidence that their generating equipment will meet or exceed the technical requirements of chapter 5 of the NER. It may take up to three months for a CA to prepare the documentation required for registration as a generator (AEMO 2010b, p.4).
The registration process consists of four key steps:
(1) CA submits an application (using the appropriate form): – for registration as a generator, accompanied by a registration fee (fees range from $5000 to $7100 depending on generator classification) or – for exemption from registration as a generator, accompanied by an exemption from registration fee ($2000 for 2011-12).2
(2) AEMO reviews the application and responds within five business days. (3) AEMO may request additional information or clarification of the information contained in the application. If such a request is made, the CA has 15 business days to supply the additional information or clarification. (4) Within 15 business days of receiving the application or requested additional information or clarification, AEMO will notify the CA of its determination. If accepted, AEMO will notify the CA of the effective date of registration and of any applicable conditions of registration (AEMO 2010b, pp.5–6). Connection process
The connection process under chapter 5 requires the exchange of detailed technical, prudential and commercial information, and extensive consultation between the CA and the distribution network service provider (DNSP). The process can be summarised into five main steps:
(1) Connection studies and enquiry: the CA conducts a network connection feasibility study (which may include a network stability study) and approaches their local
2 See AEMO Schedule of Registration Fees 2011/12 (www.aemo.com.au/registration/0120-0031.pdf).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 219 DNSP detailing the type, magnitude and timing of the proposed connection. The information to be provided with the connection enquiry is set out in cl 5.3.4 and sch 5.4 of the NER. (2) Response to connection enquiry: the DNSP will liaise with other network service providers to determine the impact the proposed connection may have on existing connection agreements. Within 10 business days, the DNSP must provide preliminary information, including a preliminary program of proposed milestones for the connection process. The DNSP has 20 business days to advise the CA of the technical requirements and all further information required to enable an assessment of the application to connect. (3) Application to connect: the CA submits an application to connect accompanied by the application fee. The application must include proposed technical standards. The CA has an automatic right to connect if the relevant automatic access standards are met. If the application to connect deviates from the relevant automatic access standards, then there is no automatic right to connect, and the parties need to negotiate each proposed technical standard in consultation with AEMO. The DNSP ‘must use reasonable endeavours’ to provide the access arrangements sought by the CA, ‘subject to those arrangements being consistent with good electricity industry practice’ (cl 5.5(e)). – Schedule 5.2 sets out the automatic access standards for registered generators. The automatic access standards do not apply to distributed generators exempt from registration or eligible for exemption under Appendix 6: Guideline on Exemption from Registration as a Generator and where connection is ‘unlikely to cause a material degradation in the quality of supply to other network users’ (NER cl S5.2.1(b)). This means that technical standards for distributed generators of less than 5 MW capacity must be negotiated on a case-by-case basis and there is no automatic right of connection for distributed generators of this size. – The negotiated access standards must meet at least the minimum access standards specified in the sch 5.2 of the NER.
(4) Connection agreement and generator installation: once the access standards have been agreed, the DNSP must prepare an offer to connect based on the agreed standards within the timeframe specified in the preliminary program (or as agreed between the parties). The CA and DNSP will execute the connection agreement that describes the connection and outlines the applicable technical and commercial conditions. AEMO is to be notified within 20 business days of the execution of the connection agreement. The CA may then commence construction and installation of the generator. (5) Inspection and commissioning: Energy Safe Victoria will inspect and test the installed generating system and issue a Certificate of Electrical Safety. A range of connection tests will be performed with a DNSP representative present, before live connection to the distribution network. After connection, an installation engineer will test and commission the generator to ensure it is ready for regular service (AEMO 2011c). The Commission notes that on 18 April 2012, a rule change request — designed to facilitate the process for connecting embedded generators to the distribution grid under NER chapter 5 — was jointly submitted to the AEMC by ClimateWorks Australia, Seed Advisory and the Property Council of Australia. On 14 June 2012, the AEMC released a Consultation Paper on the rule change proposal, National Electricity Amendment (Connecting embedded generators) Rule 2012 (AEMC 2012e). The connecting embedded generators rule change is discussed in chapter 6.
220 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION State-based supplementary connection requirements
Victorian regulation contains supplementary protections for distributed generation proponents connecting under chapter 5 of the NER. These requirements place additional obligations on DNSPs and supplement the NER chapter 5 connections framework. These supplementary connection requirements will be largely redundant under the NECF and will be repealed, with some Victorian-specific supplementary regulation being retained and consolidated.
Victorian regulation supplementing chapter 5 connections includes:
• A Victorian distribution licence condition that DNSPs offer connection services to embedded generators within 65 days of request or when the DNSP receives all the information ‘reasonably require[d] to make the offer, whichever is the later’ (cl 7.1 and 11.1) • Clause 7 ‘Embedded Generators’ of the Electricity Distribution Code (ESC 2012a) which: – obliges DNSPS to ensure they are able to receive supply from a connected embedded generator in accordance with a connection agreement (cl 7.1.1) – obliges DNSPs and embedded generators to ‘negotiate in good faith’ to reach a connection agreement (cl 7.1.2) – outlines technical and safety standards that embedded generators connecting to the distribution system in Victoria must satisfy (cl 7.2 to 7.9)
DNSPs must remedy breaches of the Electricity Distribution Code (see cl 11) and comply with the Code under their distribution licence.
• Electricity Industry Guideline No. 15: Connection of Embedded Generation (ESC 2004a) requires DNSPs to provide embedded generator proponents with ‘reasonable information’ (cl 2.2) and negotiate generator access arrangements in ‘good faith’ (cl. 2.1). • Under the National Electricity (Victoria) Act 2005 (Vic), the AER can resolve disputes on whether the terms, conditions or embedded generation charges of Victorian DNSPs’ embedded generation connection offers are ‘fair and reasonable’ under Electricity Industry Guideline No. 15: Connection of Embedded Generation (ESC 2004a), cl 3.4 (AER 2011b, p.7). Small embedded generator connections
• Under cl 3.2 of the Electricity Industry Guideline No. 15: Connection of Embedded Generation (ESC 2004a), DNSPS must have a ‘fair and reasonable’ standard connection agreement for ‘small embedded generators’ that the AER has approved.3 – ‘Small embedded generators’ are defined as embedded generators of 2 kW or less and/or embedded generators that meet Australian Standard AS4777. – The standard connection agreement must include the terms and conditions for ‘embedded generation services’ provided by the DNSP and ‘embedded generation charges’.
3 Responsibility for approving small embedded generator standard connection agreements was transferred from the ESC to the AER on 1 January 2009 (AER 2012i).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 221 – If requested by a customer or retailer, DNSPS must make a small embedded generator standard connection offer within 65 business days ‘adapted only to reflect the particular circumstances of the small embedded generator’ (cl 3.2.5). Amendments to the Electricity Distribution Code
In August 2007, the ESC published a final decision as part of its review of small embedded generator connections, Final Decision: Network Connection Arrangement for Small Embedded Generators (ESC 2007). The review arose out of concerns about the then current connection arrangement between DNSPs and embedded generators in Victoria. The ESC identified the following issues:
• Embedded generators’ liability regarding safety — DNSPs were concerned that the liability of the embedded generator for the DNSPs’ employees and the general public was not adequately covered without a specific agreement between the distributors and the embedded generators. Some photovoltaic installers also suggested to the Commission that there was an additional risk that some customers would not register their generators, as reported in the United States, because these customers perceive the connection process and connection agreements as too complicated. This was a safety risk to the DNSPs and the general public. • DNSPs’ liability for network availability — DNSPs were concerned that they may be liable to claims by the embedded generators for loss of income during network outages because the network was unable to accept the output of the embedded generators. • Effectiveness of the process — the existing connection agreements become ineffective after a transfer of property ownership. DNSPs did not always receive information on changes in ownership of a supply address and therefore the new owners may not have been aware of their obligations to comply with the safety regulations (ESC 2007, p.5).
In the final decision, the ESC determined that from 1 October 2007 a specific connection agreement between small embedded generators and DNSPs (under Guideline No. 15 cl 3.2) was no longer required. The ESC considered that the DNSP and small embedded generators would be adequately protected by revisions to the Electricity Distribution Code outlined in its final decision (ESC 2007, pp.12–13). The key amendments included requiring the DNSPs to:
• keep a register for all embedded generators connected to their distribution network (cl 7.9) • inform all registered small embedded generators of their rights and obligations under the Code and the circumstances in which the DNSP has the right to disconnect unsafe small embedded generators at regular intervals (on initial connection and at least every 3 years thereafter) (cl 9.1.3A).
The ESC clarified that DNSPs and small embedded generators may enter into specific connection agreements in accordance with Electricity Industry Guideline No. 15 — Connection of Embedded Generation. However, the ESC considered that such connection agreements were not necessary and the parties may rely on the Electricity Distribution Code, provided small embedded generators were informed of their rights and obligations (ESC 2007, p.12).
222 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Australian Energy Regulator approach to approving small embedded generator standard connection agreements
The Commission understands that the AER does not intend to require Victorian DNSPs to submit the terms and conditions of their standard connection agreements for approval unless there are concerns that the current arrangements are not working (box B.2).
Box B.2 Australian Energy Regulator approach to approving small embedded generator standard connection agreements The Commission received the following advice from the Australian Energy Regulator (AER) about its approach to approving small embedded generator standard connection agreements under cl 3.2 of the Electricity Industry Guideline No. 15: Connection of Embedded Generation (ESC 2004a). The AER understands that based on the ESCV’s Final Decision – Network Connection Arrangement for Small Embedded Generators, August 2007, the ESCV amended the Electricity Distribution Code (EDC) to reduce the need for specific connection agreements for small PV generators. In this paper the ESCV identified that, under the current Victorian regulation framework: • A connection agreement for an embedded generator is signed between the original owner of the embedded generator and the relevant distributor. Unless the connection agreement is replaced or revised, the relevant parties to the agreement are the original owner and the distributor. • After a change of ownership, the original connection agreements are not applicable to the new owner under contract law because of the absence of an agreement. Moreover a new owner would not necessarily be aware of the need to have a connection agreement, or of their obligations about the operation of their small embedded generators. Further, distributors do not have the power to require the new owners to have a new connection agreement with the distributors under the existing regulatory framework. • Placing all relevant obligations in the Code [EDC] and requiring the distributors to regularly provide information on these obligations to the owners of the small embedded generators were considered to be the best mechanism to improve the connection arrangement for small embedded generators. • This arrangement would reduce the need for a specific connection agreement between the distributors and the small embedded generators. However, distributors and small embedded generators may still wish to enter into a specific connection agreement in accordance with GL15 to suit their specific requirements. Further, a new chapter 5A has been added to the NER under NECF to regulate the connection of retail customers and small embedded generators (EG). In the near future, all Vic DNSPs will be required to submit for AER approval their model connection contracts for new retail customers with EGs under chapter 5A for basic and standard connections (nearly, if not all, PV customers will be under such contracts). As Guideline 15 was published in 2004, and in view of the modifications made to the EDC and the addition of chapter 5A to the NER, the AER does not intend to seek DNSPs to submit their terms and conditions for small embedded generators under Guideline 15 for approval unless there is evidence that the current arrangement is not working. Source: (AER 2010b).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 223 The Commission notes that it is standard industry practice for household-scale distributed generation applications to be automatically approved on request. For household-scale, the approval to connect step is generally a formality and the lengthy information and technical assessment requirements that apply to larger distributed generators do not occur in practice. Based on the information available on Victorian DNSP websites, the approval process for household-scale distributed generation varies between Victorian DNSPs (table B.2).
Table B.2 Victorian DNSPs approval/connection process for household-scale distributed generation
Victorian Household-scale DNSP approval/connection process DNSP distributed generator CitiPower/ Solar PV up to 10 kW • customer completes the Solar Connection Powercor Form • customer contacts retailer and organises for the retailer to forward the Service Paperwork and Service Order Request • CitiPower/Powercor sends Customer Technical Advisor to check compliance of solar PV installation • CitiPower/Powercor arranges for appropriate metering Inverter energy • customer contacts CitiPower or Powercor systems up to 10 kW, and requests copy of Customer Guidelines including: for Grid Connection of Inverter Power • solar PV arrays Sources • small wind • customer completes Application for generators Network Connection of an Inverter Energy System up to 10 kW form • micro hydro generators • CitiPower/Powercor assesses the application and the impact of the proposed inverter • fuel cells energy system • customer contacts retailer and organises for the retailer to forward the Service Paperwork and Service Order Request • once the retailer forwards the Service Paperwork and Service Order, CitiPower/ Powercor arranges for appropriate metering • CitiPower/Powercor inspects and tests the installation before approving the system for service
224 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Table B.2 Victorian DNSPs approval/connection process for household-scale distributed generation (cont)
Victorian Household-scale DNSP approval/connection process DNSP distributed generator Jemena Solar PV up to 10 kW • customers completes the Solar Connection Form • customer contacts retailer and requests installation of an embedded generator meter and, if necessary, network tariff reassignment • retailer forwards Service Paperwork and Service Order Request • Jemena arranges for metering installation Distributed generators • customers must contract Jemena without an inverter or • Jemena assesses the enquiry, provides above 10 kW per generator connection standards and guides phase proponent through the connection application process SP AusNet Solar PV less than 4.5 • customer completes the Solar Connection kW Form • SP AusNet advises customer once the Solar Connection Form has been received and validated • customer contacts retailer and organises for the retailer to forward the Service Paperwork and Service Order Request • once the retailer forwards the Service Paperwork and Service Order Request, SP AusNet arranges for appropriate metering Solar PV that exceeds • technical review to assess impact on SP 4.5 kW AusNet’s network is required (20 business day timeframe indicated): – Customer to complete the Pre Approval Application for Solar PV Systems form to enable technical review to be conducted – SP AusNet advises customer whether authorisation to connect is granted
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 225 Table B.2 Victorian DNSPs approval/connection process for household-scale distributed generation (cont.)
Victorian Household-scale DNSP approval/connection process DNSP distributed generator • customer completes the Solar Connection Form • SP AusNet advises customer once the Solar Connection Form has been received and validated • customer contacts retailer and organises for the retail to forward the Service Paperwork and Service Order Request • once the retailer forwards the Service Paperwork and Service Order Request, SP AusNet arranges appropriate metering United Solar PV up to 10 kW • customers contacts UE and completes the Energy Solar Connection Form (UE) • customer contacts retailer and fills out a request for solar compatible/bi-directional meter and, if necessary, requests network tariff reassignment • retailer forwards Service Paperwork and Service Order Request • following receipt and processing, UE progresses metering installation within 25 business days
Notes: connection approval process information on household-scale solar PV on Victorian DNSPs' websites accessed on 6 July 2012. Source: Victorian DNSPs websites (CitiPower/Powercor 2012b; CitiPower/Powercor 2010; Jemena nd; Jemena 2011; SP AusNet 2012; UE 2012a; UE 2012b).
B.3.2 Connecting retail customers under chapter 5A
With the commencement of the NECF in Victoria, responsibility for the sale and supply of energy to Victorian retail customers — including new connections to distribution networks — will be transferred to a national regulatory regime. This includes a new chapter 5A in the NER that provides for the electricity connection of retail customers, including embedded generators. The connection process under chapter 5A will vary between Victorian DNSPs.
Chapter 5A applies to retail customers, including embedded generators, who are not registered with AEMO (unless the registered participant is acting as the agent of a retail customer). Retail customers connected under chapter 5A of the NER have direct contracts with their DNSP, as well as their designated retailer.
• Small customers have a contract with a designated retailer to provide customer retail services (that is the sale of electricity) under a standard or market retail contract, governed by Part 2 of the NERL. • Distribution services provided by DNSPs are divided into initial ‘connection’ services and ongoing ‘energisation’ services that come into effect after connection. A retail
226 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION customer will have a distribution contract for connection under chapter 5A of the NER and a separate (deemed) distribution contract for ongoing energisation regulated by Part 3 of the NERL. At this stage it is unclear how these two sets of distribution contracts will interact (Newman & McDermott 2010).
Types of connection service
Chapter 5A provides for three types of connection service for retail customers:
(1) A basic connection service, which will cover retail customers including those who are micro-embedded generators. DNSPs must have a model standing offer for basic connection services that has been approved by the AER. Micro-embedded generators (‘micro EG’) are not defined in chapter 5A according to generator size. The NER states that a micro EG connection is ‘of the kind contemplated by Australian Standard AS 47774 (Grid connection of energy systems via inverters)’ (cl 5A.A.1). According to Standards Australia, AS 4777 applies to inverter energy systems with ratings up to 10 kVA for single-phase, and 30 kVA for three-phase, intended for connection to the low voltage electricity distribution network. It is likely that household-scale distributed generators in Victoria will connect through a basic connection service. (2) A standard connection service, which can cover the terms and conditions for different classes of connection services or different classes of retail customers (including non-registered embedded and micro-embedded generators). DNSPs can choose to prepare a model standing offer for such services and have it approved by the AER. (3) A negotiated connection contract, which covers services that are not subject to a basic or standard connection standard offer, or where a basic or standard connection service is sought but the CA elects to negotiate the terms and conditions of the connection agreement. The terms and conditions for such services are negotiated and if agreement cannot be reached the dispute can be arbitrated by the AER. In relation to a negotiated connection contract, a CA is an applicant for a connection service that is:
– a retail customer (including an embedded generator) – a retailer or other person acting on behalf of a retail customer, or – a real estate developer.
The requirement to have model standing offers approved by the AER published on the websites of Victorian DNSPs will commence as soon as the NECF is applied in Victoria.
Connection process
The connection process under chapter 5A is broadly similar to the connection process under chapter 5, and consists of the following key steps:
(1) Preliminary enquiry: the CA makes a preliminary connection enquiry about connection services. The DNSP has five business days (or longer agreed period) to provide the enquirer with information required to make an informed application. (2) Application to connect: once an application is made, the DNSP must advise the CA if the application is incomplete and, if so, request the CA to resubmit it. The DNSP may also request additional information if ‘reasonably required’. The DNSP
4 The Commission understands that AS 4777 is currently under review (Queensland Government 2012).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 227 has 10 business days after receipt of a complete application/requested additional information (or some other agreed period) to advise the CA whether the proposed connection is a basic connection service, standard connection service or neither. A site inspection may be required for the DNSP to determine the nature of the connection service sought by the CA. (3) Connection offer where a basic or standard connection service is sought: within those same 10 business days (from receipt of a complete application/additional information) or other agreed period, the DNSP must make a connection offer based on the relevant model standing offer. The offer remains open for acceptance for 45 business days, unless extended by agreement. (4) Expedited connection where a basic or standard connection service is sought: where the CA requests an expedited connection and indicates that the terms of the model standing offer would be acceptable in the connection application, the DNSP is taken to have made, and the CA accepted, a connection offer according to the terms of the relevant model standing offer on the date the DNSP receives the connection application. (5) Where a negotiated connection contract applies: the DNSP must advise the CA of the negotiation process and related costs. The DNSP must use its 'best endeavours' to make a negotiated connection offer within 65 business days. A negotiated offer must comply with the minimum statutory requirements and remains open for acceptance for 20 days (unless extended by agreement). In the event that the DNSP and CA cannot reach an agreement — on the proposed or actual terms and conditions of a negotiated connection contract, or the terms and conditions on which a basic or standard connection service is to be provided — then the matter can be arbitrated by the AER.
The introduction of chapter 5A into the NER is designed to simplify the connection of small-scale retail customers, including those with distributed generation. However, connection under chapter 5 still remains an option and distributed generators wishing to sell through the NEM are required to register and connect through the chapter 5 connection framework (section B.4.1). The transparency of the process for small distributed generators connecting under chapter 5A will depend in part on whether DNSPs decide to provide model standing offers for standard connection services. The process for seeking connection under chapter 5A is illustrated in figure B.1.
228 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Figure B.1 Connection under the NECF (chapter 5A) for embedded generators who are retail customers
Preliminary inquiry from potential applicant wishing to connect
DNSP has 5 days to provide information
Applicant lodges application on form determined by DNSP
Additional information required Application incomplete
DNSP informs applicant of DNSP informs applicant of additional information deficiency needed
Application complete DNSP has 10 days to advise whether the service is covered Completed application by an approved connection submitted process and, if so, make a connection offer • offer open for 45 days • expedited connection may be available Site visit, if needed
Not approved service. Basic connection service DNSP notifies applicant of or standard connection the negotiation process & service possible changes & expenses DNSP uses best endeavours to make offer within 65 days of receiving completed Use agreement approved application* by AER Negotiated connection Offer open for 20 days offer
Agree Not agreed Legend AER – Australian Energy Offer terms form Option of dispute Regulator connection contract resolution reduction DNSP – Distributed Network through AER Service Provider * This applies to negotiation, not dispute resolution
Source: Commission analysis of chapter 5A NER.
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 229 B.3.3 Cost of connecting distributed generation
There are fees and charges associated with connecting distributed generators to the distribution network. These costs vary depending on the size/type of generator being connected and type of connection. Generally, connection charges apply to the following four components of a typical connection:
(1) Direct connection assets — these are the premises’ connection assets which run from the connection point to the supply point and where applicable also include the consumer mains. (2) Extensions — an augmentation that requires the connection of a power line or facility outside the present boundaries of the transmission or distribution network owned, controlled or operated by a network service provider. (3) Shared network augmentations — an augmentation of a distribution network means work to enlarge the system or to increase its capacity to transmit or distribute electricity, caused by the connection. This is all augmentations other than extensions. (4) Incidental costs — includes administration, design, certification and inspection fees (AEMC 2012f, pp.171–172; AER 2011g, p.14).
Cost of connecting distributed generation under chapter 5
Chapter 5 of the NER provides that CAs are subject to fees and charges to cover direct costs (such as an application fee) and indirect costs (such as a registration fee). The DNSP and CA must ‘negotiate in good faith’ to reach agreement on connection charges (cl 5.5(f)). Some of these connecting costs are regulated by the AER and some are negotiated between the DNSP and CA. The costs of connecting under chapter 5 are summarised in table B.3.
Table B.3 Cost of connecting distributed generation under chapter 5
Fee or charge Description Registration fee Registered generators and exempt generators (not subject to the 5MW Standing Exemption) pay a registration fee to AEMO. The registration fee varies depending on the type of generator (see AEMO Schedule of Registration Fees 2011/12) Participant fee • Registered generators pay participant fees determined by AEMO in accordance with the NERs cl 2.11 • Exempt generators do not pay participant fees Application fee (cl 5.3.4(b)) • Payable on lodgement of application to connect ‘No more than necessary to cover reasonable costs’ to assess application and prepare offer to connect
230 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Table B.3 Cost of connecting distributed generation under chapter 5 (cont)
Fee or charge Description Connection service charge Paid by the connection applicant (CA) for the (cl 5.5(f)(1)) connection assets provided by the distribution network service provider (DNSP) Negotiated use of system Paid by CA for any required augmentations or charges (cl 5.5(f)(3)(i)) extensions to affected transmission and distribution networks. The maximum negotiated use of system charges must be in accordance with NER chapter 6 and applicable ‘negotiated distribution service criteria’ Costs ‘reasonably incurred’ to Paid by the CA to the DNSP provide distribution network user access (cl 5.5(f)(4)(i)) Compensation to DNSPS and • Compensation paid by DNSP to the embedded embedded generators generator when it is constrained off or on during (cl 5.5(f)(4)(ii)) a trading interval • Compensation paid by the embedded generator to the DNSP when dispatch of the embedded generator causes another generator to be constrained off or on during a trading interval Avoided customer transmission The DNSP must pass through to the CA the use of system (TUOS) charges locational component of prescribed TUOS services (cl 5.5(h)) that the DNSP would normally pay to the transmission network service provider (TNSP), had the embedded generator not been connected to the distribution network. This payment reflects the transmission charges that the DNSP has avoided due to the connection of the embedded generator Reasonable costs to address Paid by generating units with a nameplate rating of impacts on the transmission 10 MW or greater that impact on fault levels, line network determined by the reclosure protocols and stability aspects TNSP (cl 5.3.5(e)) Reasonable costs associated Payment of these costs may be a condition of an with remote control equipment offer to connect and remote monitoring equipment (cl 5.3.5(g)) ‘Reasonable fee’ for assistance Where permitted by the relevant participating in obtaining approvals (cl jurisdiction, the DNSP may charge the CA a 5.3.7(e)) reasonable fee to prepare applications for environmental and planning approvals
Source: Commission analysis.
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 231 Essential Service Commission guidance on connection costs
In addition, Victorian DNSPs are currently subject to guidelines issued by the ESC, including Electricity Industry Guideline No. 14: Provision of Services by Electricity Distributors (ESC 2004b) and Electricity Guideline No. 15: Connection of Embedded Generation (ESC 2004a). These Victoria-specific guidelines were developed to clarify the connection process and regulate connection charging for distributed generation. Guidelines No. 14 and 15 regulate pricing aspects of connection agreements between DNSPs and CAs, including:
• the application fee DNSPs can charge embedded generators on lodgement of an application to connect (Guideline No. 15, cl 2.3). The fee ‘may not be more than necessary to cover the reasonable costs’ to investigate and prepare the offer to connect (cl 2.3(b)) • the charges under, and other terms and conditions of, connections agreements, including the principles DNSPs must observe in setting those charges and other terms and conditions (Guideline No. 15, cl 3) • the payment to embedded generators of a share of DNSPs’ avoided distribution system costs (Guideline No. 15, cl 4) • the payment to embedded generators of DNSPs’ avoided customer transmission use of system (TUOS) usage charges (Guideline No. 15, cl 5) • the determination of customer contributions to the capital cost of new works and augmentations to the network (Guideline No. 14, cl 3).
Electricity Guideline No. 15: Connection of Embedded Generation (ESC 2004a) cl 3.3 requires that connection agreements between Victorian DNSPs and embedded generators must provide for:
• matters contemplated by NER cl 5.5(f): – a connection services charge – a use of system services charge – costs incurred by the DNSP in providing generator access – compensation paid by either party where certain network constraints occur • the DNSP to pass through to the embedded generator a share of the DNSP’s avoided distribution system costs and all of the DNSP’s avoided customer TUOS charges • embedded generation charges and terms and conditions for DNSP’s embedded generation services (distribution services and distribution system augmentation) that are ‘fair and reasonable’: – may cover the incremental capital costs for the DNSP to bring forward ‘shallow augmentation’ works — installation of connection assets and any augmentation up to, and including, the first transformation — to the distribution network as a result of the embedded generation connection – excludes any costs for ‘deep augmentation’ (any augmentation other than shallow augmentation in respect of embedded generation services) • any ‘fair and reasonable’ compensation payable by the embedded generator for failing to provide network support services to the DNSP, as and when required.
232 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Electricity Guideline No. 15: Connection of Embedded Generation (ESC 2004a) also requires that standard ‘fair and reasonable’ embedded generation charges5 apply to small embedded generators6 under small embedded generator standard connection agreements (cl 3.2).
Connection charging under chapter 5 after the NECF is applied in Victoria
In the discussion paper Victorian-Specific Regulatory Requirements Under the National Energy Customer Framework (2011n), DPI concluded that:
• with the insertion of chapter 5A into the NER, which provides a detailed negotiation framework for connection contracts with embedded generators and a connection charging regime, ‘Chapter 5A will effectively cover the field of regulation covered by Guideline 15, and the guideline will therefore not be needed under the NECF’ • that guidance on determination of customer contributions to the capital cost of new works and augmentation contained in Guideline No. 14 will be also addressed in the NECF or through AER guidelines and this guidance will therefore also be redundant after commencement of the NECF in Victoria.
Cost of connecting distributed generation under chapter 5A
Embedded generators connecting through the retail connection process under NER chapter 5A are also subject to connection costs. Clause 5A.E.1 contains connection charge principles and under cl 5A.E.3(a) requires the AER to develop and publish connection charge guidelines, to assist DNSPs to develop connection policies. NER chapter 6 Pt DA requires DNSPs to prepare a connection policy that sets out the circumstances in which they will require a retail customer or real estate developer to pay a connection charge for the provision of the chapter 5A connection service. A DNSP’s connection policy must comply with the connection charge principles in cl 5A.E.1 and the AER’s connection charge guidelines. The AER may approve a DNSP’s connection policy if satisfied that it complies with these two requirements.
Clause 5A.E.3(b) states that the purpose of the AER’s connection charge guidelines is to ensure that connection charges:
• are reasonable, taking into account the efficient costs of providing the connection services arising from the new or altered connection and the revenue a prudent operator would require to provide those connection services • provide, without undue administrative cost, a user-pays signal to reflect the efficient cost of providing the connection services • limit cross-subsidisation of connection costs between different classes (or subclasses) of retail customer • are competitively neutral, if the connection services are contestable.
In addition, chapter 5A specifies that a DNSP may charge the following fees:
5 The charge for distribution services and distribution system augmentation required to allow a distribution system to receive energy from an embedded generator. 6 Defined as embedded generators of 2 kW or less and/or embedded generators that meet Australian Standard AS4777.
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 233 • site inspection fee (cl 5A.D.4): DNSPs may charge 'reasonable expenses' if site inspection is required to determine the nature of the connection service sought • negotiation fee for negotiated connection contracts (cl 5A.C.4(a)): DNSPs may charge 'a reasonable fee to cover expenses directly and reasonably incurred' in assessing the connection application and making a connection offer.
Australian Energy Regulator connection charge guidelines
The AER released its final Connection Charge Guidelines for Electricity Retail Customers: Under chapter 5A of the National Electricity Rules (AER 2012c) in June 2012. Key aspects of the connection charging regime established under chapter 5A and the Connection Charge Guidelines are as follows:
• Shared network augmentations: retail consumers (other than non-registered embedded generators or retail developers) who apply for a connection service requiring an augmentation cannot be required to make a capital contribution to the cost of the augmentation (other than an extension) if the connection is a basic connection service or below a threshold set in the DNSP’s connection policy (cl 5A.E.3(c)(4)). It is intended that retail customers should be excluded from deep system augmentation charges.7 Under the AER Connection Charge Guidelines, a DNSP’s connection policy must include a shared network augmentation charge threshold or thresholds below which retail customers will not be required to contribute to the cost of augmentation. The AER intends that the threshold should be set so that at least residential customers in an urban area would not be required to contribute to the cost of an augmentation (AER 2012c, p.8). • Extension assets: retail customers (including non-registered embedded and micro-embedded generators) are entitled to receive a refund when new users start using an extension connection asset — that was originally installed and funded for their exclusive use — within seven years of its installation. DNSPs are entitled to recover the amount of the refund through a connection charge imposed on new users of the extension asset under their pioneer scheme (cl 5A.E.1(d)). The Connection Charge Guidelines require DNSPs to include a pioneer scheme in their connection policy and publish the details of the scheme on their website (AER 2012c, p.22). • Augmentation assets: DNSPs are required to ‘implement an accounting treatment which ensures that they do not earn a regulated rate of return’ on assets gifted or funded by customers (AER 2012c, p.28).
The Connection Charge Guidelines provide that the total connection charge that a CA will pay to a DNSP will be calculated according to a specific formula (box B.3).
7 See ‘Connection Charge Principles’ note under cl 5A.E.1(b).
234 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Box B.3 Total connection charge under chapter 5A The charge that connection applicants (CAs) pay to the distribution network service provider (DNSP) may be made up of multiple connection services and is calculated in accordance with the following formula: Connection Charge = AS + CC + PS Where: • The ‘Connection Charge’ is the charge imposed by a DNSP for a connection service (a service relating to a new connection and/or connection alternation). • AS is the charge payable to the DNSP for all relevant alternative control connection services, which are subject to economic regulation by the AER. The AER classifies a connection as an ‘alternative control service’ where the service is provided to a small number of identifiable customers on a discretionary or infrequent basis, and costs can be directly attributed to those customers. • CC is the capital contribution payable to the DNSP for all relevant standard control connection services. Standard control services are subject to economic regulation by the AER. • PS is the total payable to the DNSP to account for any pioneer scheme applying to the extension assets to which the CA connects. CAs may also be required to pay a security fee to the DNSP. In determining the total connection charge, a DNSP must: (1) Determine the charge for each component in a fair and reasonable manner. (2) Calculate the charge for each component on the least cost technically acceptable standard necessary for the connection service. However, if the CA requests all or part of a connection service be performed to a higher standard, the CA contributes to the additional cost of providing the service to the standard requested. Capital Contribution The amount of any capital contribution is the difference between the incremental revenue and the incremental cost attributable to the standard control services required by the CA. Where the capital contribution is less than zero, no capital contribution is payable by DNSP or CA. The capital contribution (CC) is calculated according to the following formula:
CC = ICCS + ICSN – IR (n=X Where: • CC is the capital contribution for standard control services. • ICCS are the incremental costs incurred by the DNSP for standard control connection services used solely by the CA. This may include extensions and augmentation of premises connection assets at the connection point. • ICSN are the costs incurred by the DNSP for standard control connection services that are not used solely by the CA. This may include any augmentation (other than an extension) attributable to the new connection. • IR (n=X) is the incremental revenue expected to be received from the new connection — the present value of the revenue stream directly attributable to the new connection. Source: (AER 2012c, pp.10–11, 14–15).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 235 Connection charging for embedded generation retail customers
In relation to embedded generation, the Connection Charge Guidelines for Electricity Retail Customers: Under chapter 5A of the National Electricity Rules (AER 2012c) provide:
• Augmentation costs — retail customers who are non-registered embedded generators are not eligible for the exemption from augmentation charges under cl 5A.E.1(b)(2) and 5A.E.3(c)(4) (cl 7.1.1). • Negotiated or unclassified distribution services — the connection charge for components of an embedded generator connection that are classified by the AER as ‘negotiated distribution services’ or which are unclassified8 are negotiated between the DNSP and CA (cl 7.1.2). • Alternative control services — the cost of components of an embedded generator connection service classified by the AER as an ‘alternative control service’ are regulated by the AER (cl 7.1.3). • Standard control services — DNSPs may seek a capital contribution from an embedded generator if the incremental cost of the standard control connection services exceeds the estimated incremental revenue expected to be derived from standard control connection services (cl 7.1.4) (AER 2012c, p.24).
In addition, the Connection Charge Guidelines state:
Non-registered embedded generators which seek to remove a specific network constraint, will generally be required to pay for the cost of removing the constraint. The AER considers services related to removing shared network constraints for specific users, such as embedded generators, would generally be an alternative control service, negotiated service or unclassified service. However, a DNSP’s normal asset management may lead to a DNSP funding such shared network augmentation if there is a demonstrable net benefit to other network users. Non-registered embedded generators will not be charged a unit rate for shared network augmentation (based on the generation output). (AER 2012c, p.24) Connection charging under chapter 5A after the NECF is applied in Victoria
Both ESC Guidelines No. 14 and 15 and the AER’s Connection Charge Guidelines require that embedded generator connection charges are ‘fair and reasonable’, although there are subtle differences. The major difference is that under NER chapter 5A connection charging framework embedded generators will be liable for deep augmentation costs. Currently under ESC Guideline No. 15 cl 3.3.2, embedded generators are only liable for shallow connection costs of network augmentation and cannot be charged for deep augmentation costs.
The Joint Implementation Group responsible for coordinating the implementation of the NECF has advised that each jurisdiction will institute transitional arrangements to ensure smooth implementation of the NECF. This will include transition to the connection charging regime under chapter 5A of the NER (JIG 2012a, p.2). An interim connection charging regime under the NER chapter 11 modifies the operation of chapter 5A, so
8 ‘Unclassified services’ are not subject to economic regulation by the AER.
236 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION that it does not conflict with jurisdictional electricity distribution price determinations. It is anticipated that the AER’s Connection Charge Guidelines will be implemented when DNSPs submit their connection policies as part of each DNSP’s next distribution pricing proposal. Jurisdictional capital contribution rules will remain in place for each jurisdiction’s current regulatory control period, after which the connection charging framework under chapter 5A will apply (AER 2012d, p.13). As such, cl 38 of the National Energy Retail Law (Victoria) Bill 2012 provides that, in the interim connection charging rules period (until 31 December 2015), transitional connection charging rules under chapter 11 of the NER will apply instead of chapter 5A (Explanatory Memorandum 2012, p.12). Chapter 5A and the interim connection charging regime in Chapter 11 of the NER will only commence in Victoria when the NECF is applied in Victoria.
Distribution planning and reporting
DNSPs are required to consider the impacts of connecting distributed generation as part of their distribution network planning. The national network planning and development framework is supplemented by State-based planning and reporting regulatory arrangements, which vary among jurisdictions (AEMC 2009d, pp.107–111; AEMC 2011c, p.5). On 14 June 2012, the AEMC published a draft rule determination and draft rule in response to a rule change request to amend the NER and establish a national annual distribution network planning and reporting framework (AEMC 2012d).9 The draft rule determination is discussed in chapter 5 of this report.
The current distribution planning arrangements are as follows:
• Chapter 5 of the NER requires that each DNSP review annually the expected future operation of its distribution networks over the next five years, taking into account forecast loads, future generation and market network services, and demand side developments (cl 5.6.2(a) and (d)). The NER does not require that DNSPs publish periodic planning reports (AEMC 2011c, p.5). • In Victoria, the Electricity Distribution Code (ESC 2012a) requires that DNSPs publish annual distribution system planning reports (DSPRs) that plan for the next five calendar years (cl 3.5). A DSPR must cover: – historical and forecast demand – feasible options for meeting forecast demand, such as opportunities for embedded generation and demand management – availability of contributions from the DNSP to embedded generators to reduce forecast demand and defer or avoid augmentation of the distribution system.
• The EI Act s 40FJ requires that, as a licence condition, licensed DNSPs must regularly report10 to the Minister for Energy and Resources on: – the number of solar photovoltaic (PV) systems connected to the distribution network operated by the licensee – the aggregate generating capacity of solar PV systems connected to the distribution network operated by the licensee
9 See the AEMC’s Distribution Network Planning and Expansion Framework website: http://www.aemc.gov.au/Electricity/Rule-changes/Open/Distribution-Network-Planning-and-Expansion- Framework.html 10 On a six monthly basis for solar PV systems eligible for the premium feed-in tariff and on a monthly basis for solar PV systems eligible for the transitional feed-in tariff. Feed-in tariffs are discussed is section B.4.2.
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 237 – the total amount of surplus electricity generated by solar PV systems conveyed along the distribution network operated by the licensee.
When the NECF commences in Victoria, the reporting requirement in the Electricity Distribution Code (ESC 2012a) will become a licence condition. This will ensure that DSPRs continue to be completed by DNSPs until the AEMC’s rule change process regarding a national reporting framework has been completed. Should the AEMC’s rule change commence before the NECF is applied in Victoria, the retention of the reporting requirement in the distribution licences may not be required. These distribution planning and reporting obligations mean that DNSPs must consider, plan for, accommodate and monitor the effects of distributed generators connecting to, and sending surplus electricity generated into, the distribution grid.
B.4 Selling electricity generated
B.4.1 National regulation governing selling
Under the NER, there are currently two options for distributed generators wishing to sell electricity exported to the distribution grid:
(1) registered distributed generators can sell through the NEM at spot prices
(2) registered ‘non-market’ generating units and generating systems exempt from registration can sell through a private bilateral agreement outside of the NEM (generally for an agreed fixed price) to a local retailer or customer located at the same connection point.
Market generators and non-market generators
As noted in section B.3.1, distributed generators wishing to connect under chapter 5 of the NER are required to be registered with AEMO, unless an exemption from registration applies (cl 2.2.1 NER). Registration as a ‘market generator’ is required to sell electricity through the NEM.
Registered generating units must be classified as either ‘market’ or ‘non-market’ generating units (cl 2.2.1(f)). These classifications impose important restrictions on selling surplus electricity generated and exported to the grid.
• Market generating unit (cl 2.2.4) — a generating unit whose sent out electricity is not purchased entirely by the local retailer or a customer located at the same connection point. • Non-market generating unit (cl 2.2.5) — a generating unit whose sent out electricity is purchased entirely by the local retailer or a customer located at the same connection point.
A registered generator may have both ‘market’ and ‘non-market’ generating units within the generating system that it owns, operates or controls (AEMO 2010b, p.7). A registered generator is taken to be a ‘market generator’ in relation to its ‘market’ generating units, and a ‘non-market generator’ in relation to its ‘non-market’ generating units.
• Market generator — must sell all sent out electricity through the spot market and accept payments from AEMO at the spot prices applicable to its connection point. A ‘connection point’ is the agreed point of supply established between a DNSP and distributed generator.
238 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • Non-market generator — is not entitled to receive payment from AEMO for sent out electricity, except for any compensation as a directed or affected participant (as a consequence of a direction from AEMO under cl 4.8.9(a1)(1)).11 Non-market generators can sell sent out electricity through a private bilateral agreement outside of the NEM, for a (usually fixed) price agreed between the non-market generator and a local retailer or customer located at the same connection point. All of a non-market generator’s sent out electricity must be purchased in this way.
In Appendix 6: Guideline on Exemption from Registration as a Generator of the NEM Generator Registration Guide (2010b), AEMO advises that:
Clause 2.2.4(a) of the Rules [NER] states that a generating unit whose sent out generation is not purchased in its entirety by the Local Retailer or by a Customer located at the same connection point must be classified as a market generating unit. This requirement applies regardless of the size of a generating unit. One consequence of this requirement is that, where a person, who would otherwise be eligible for exemption from the requirement to register as a Generator, wishes to receive payment for electricity generated by their generating unit through the NEM, they must apply to AEMO for registration as a Market Generator and its generating unit must be classified as a market generating unit. (AEMO 2010b, p.35)
Small generation aggregators
In the future, there may be a third selling option under national regulation for distributed generators wishing to sell surplus electricity generated through the NEM. Currently, the NER provides for the registration of intermediaries where a generating system involves multiple parties in ownership, control and operator roles (cl 2.9.3). Generators ordinarily required to register as a ‘market generator’ can apply to AEMO for an exemption on the basis that they have nominated another party to act as their intermediary. However, the intermediary will need to apply to AEMO for registration as a generator and each generating unit it is acting for will need to apply for an exemption from registration under cl 2.9.3, incurring fees each time. AEMO will only allow an intermediary exemption if the intermediary satisfies that, from a technical perspective, it can be treated as a CA with respect to the generating system (AEMO 2010b, p.2). However, where the ownership of generating units within a generating system is split, each generating unit must be registered separately as a market generating unit to sell through the NEM (AEMO 2010b, p.2; AEMC 2012c, p.2).
On 22 December 2011, AEMO proposed a rule change to the AEMC to introduce a new category of market participant into the NER called a 'small generation aggregator'. AEMC released a draft rule determination on the rule change request on 5 July 2012.12 Under the proposed rule change, small generation aggregators will only have to register once with AEMO. A small generation aggregator will have market responsibility for the participation of multiple generating units in the NEM. Separate
11 See Appendix 4: AEMO’s Policy on Registration as a Non-Market Generator of the NEM Generator Registration Guide for the conditions that apply to registration as a non-market generator (AEMO 2010b, pp.25–26). 12 See the AEMC’s Small Generation Aggregator Framework website: http://www.aemc.gov.au/electricity/rule-changes/open/small-generation-aggregator-framework.html
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 239 registration of each of the generating units will not be required, significantly reducing costs and improving access to the market. This will allow aggregated generators to more easily enter and sell in the NEM (AEMC 2012c, pp.1–5). AEMO’s draft rule determination broadly reflects the rule change requested by AEMO. The key difference between the proposed rule change and the draft rule is the structure of the new entity within the NER. AEMO proposed that the small generation aggregator is both a registered participant and a market participant. AEMC proposes that a distinction between these categories of participant should be maintained and the draft rule creates a new registered participant the small generation aggregator (SGA), and a new market participant (MSGA) (AEMC 2012g). The AEMC notes that ‘this distinction does not change the practical operation of the framework and it is likely that all SGAs will also be an MSGA’ (AEMC 2012g, p.2). As registered participants, SGAs would be ineligible to connect through NER chapter 5A and would be required to connect to the distribution network through the chapter 5 process.
Network exemptions
Under the NER, any party that engages in an electricity transmission or distribution activity must either be registered with AEMO as a network service provider (NSP) or exempted from registration by AER. The AER’s Electricity Network Service Provider Registration Exemption Guide (AER 2011e) governs the process for applicants seeking an exemption to allow them to operate a privately owned embedded or exempt network (a ‘private network’).
The Guideline defines a ‘private network’ as ‘any network for the supply of electrical energy to a third party, but not a transmission or distribution network registered with the Australian Energy Market Operator (AEMO)’ (AER 2011e, p.8). The AER advises that:
The types of networks covered by the network Guideline include situations where electricity supply is incidental to the main purpose of a business, such as networks within caravan parks, apartments, industrial parks and shopping centres. It also deals with a wide range of industrial, commercial and primary production situations. The AER’s network Guideline sets out the AER’s approach to network exemptions, including a full list of the types of activities which are exempt from the requirement to register as a network service provider. A network exemption can relieve you of the requirement to comply with certain technical requirements set out in Chapter 5 of the NER, and the obligation to provide other network users with access on demand to the network. (AER 2012e)
There are three types of network exemptions: deemed, registrable and individual. The AER maintains an online public register of NSP exemption applications approved by the AER (AER 2012g).
Retailer authorisations and exemptions Retailer authorisations
When the NECF is applied in Victoria, Victorian electricity retailers will be regulated by a retailer authorisation and exemption regime, administered by the AER. Under this framework, sellers of electricity are required to have a retailer authorisation or be exempt from the requirement to be authorised (NERL, cl 88). Under cl 119 of the NERL, the AER maintains a public register of authorised retailers and exempt sellers. The public register is available on the AER website.
240 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Clause 90 of the NERL sets out three entry criteria that an applicant must satisfy to obtain a retailer authorisation:
• organisational and technical capacity — the applicant must have the necessary organisational and technical capacity to meet the obligations of a retailer • financial resources — the applicant must have resources or access to resources so that it will have the financial viability and financial capacity to meet the obligations of a retailer • suitability — the applicant must be a suitable person to hold a retailer authorisation (AER 2012b).
The AER has published a Retailer Authorisation Guideline (AER 2011i), which sets out its approach to applying the above retail entry criteria. The Guideline also addresses the transfer, surrender or revocation of a retailer authorisation.
Retail exemptions
The AER has published an Exempt Selling Guideline (2011f), which sets out its approach to retail exemptions and the types of available exemptions: deemed, registrable and individual exemptions. The AER may grant a retail exemption subject to specific conditions.
Retail exemptions commonly apply to situations where electricity is being ‘onsold’:
Electricity onselling, also known as reselling, occurs where a person (the exempt person) makes arrangements to acquire energy from an authorised retailer and then onsells that energy to persons who are within the limits of an embedded distribution network (being a network that is connected to the main distribution network through a single connection point). Examples of embedded networks where onselling occurs are shopping centre complexes, caravan parks and retirement villages. Potential applicants for exemptions are therefore likely to include the owners and operators of these sites. Other likely onsellers include bodies corporate and landlords of rooming houses. (AER 2011f, pp.2–3)
Under the NERL, the AER must consider a number of policy principles (including choice of retailer) and may consider exempt seller characteristics and customer related factors, in determining retail exemptions (cl 114(2)).
The AER considers that exempt selling is often not in the long term interests of customers. We have seen particular growth in onselling within high density residential developments such as apartment buildings. We do not want onselling to be a motivating factor for developers in deciding how these developments are structured… The most effective way of affording customers the right to a choice of retailer is to ensure that network configuration and metering arrangements for new developments and redevelopments facilitate customer choice of retailer going forward. (AER 2011f, pp.3, 8)
The Exempt Selling Guideline (AER 2011f) advises that decentralised energy (including onsite co-generation and tri-generation) will be treated as an ‘exempt seller characteristic’ and on-site distributed generators will need to apply for an individual retail exemption on a case-by-case basis. The Guideline states that the AER ‘will grant exemptions in these situations where the initiative is in the long term interests of energy
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 241 consumers having regard to all of the criteria and factors we are required to assess’ (AER 2011f, p.17).
Private embedded networks
When the NECF is applied in Victoria, distributed generators who wish to onsell their generation in a private embedded network will usually need to obtain both a retail exemption and a network exemption. The AER has a common application process for both types of exemption (AER 2012e).
B.4.2 Victorian regulation governing selling
Licensing
The Victorian electricity industry is regulated through a licensing regime established under Pt 2 of the EI Act and administered by the ESC. DPI noted that:
The licensing regime has also been utilised directly by Government as an instrument to deliver on specific policies, placing statutory obligations on licensed businesses while bringing compliance with those obligations into the purview of the regulator. (DPI 2011m)
The licensing regime has a diverse range of functions, including:
• limiting entry to the energy sector • imposing regulatory obligations on licensed businesses • imposing statutory obligations on licensed businesses • prohibiting cross-ownership between licensed businesses of different types • identifying energy businesses that may exercise special statutory powers • requiring exit from the energy sector (revocation) • funding regulatory activities (DPI 2011m).
Restrictions on selling electricity
The EI Act prohibits a person from generating electricity for supply or sale unless that person has a license or is exempt from the requirement to hold a license (s 16(1)). Under s 17 of the EI Act, the Governor in Council can make an Order in Council exempting a person from the requirement to obtain a licence. An Exemption Order came into effect on 1 May 2002 (ESC nd, p.1). Exemptions available include:
• generators connected to the transmission or distribution network at a common connection point with a capacity of less than 30 MW • the intermediary distribution and supply of electricity to a short term resident, long term resident, small business customer or large business customer within the limits of the premises owned or occupied by the person engaging in that activity • the metered intermediary sale of electricity within the limits of the premises owned or occupied by the person engaging in that activity (Order in Council 2002; ESC nd, p.1).
A licence exemption automatically applies to any person who falls within the classes of exempt activity specified in the Exemption Order, provided they continue to comply with the relevant exemption obligations set out in the Exemption Order (ESC nd, p.1).
242 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The ESC is empowered by cl 5 of the Exemption Order to issue certificates of opinion where it considers that a particular activity does or does not constitute:
• the intermediary distribution or supply of electricity, or • the metered intermediary sale of electricity, and • if it does so, that activity does or does not, as applicable, constitute the intermediary distribution or supply of electricity or the metered intermediary sale of electricity for the purposes of the Exemption Order.
The ESC made a policy decision in 2011 to cease issuing these certificates, due to confusion regarding their regulatory status (ESC 2011c).
Licensing after commencement of the NECF
The commencement of the NECF will introduce a national retailer authorisation scheme, designed to replace the jurisdictional licensing schemes for energy retailing currently in place in states and territories. In an issues paper discussing Victorian licensing arrangements under the NECF, DPI has stated that:
It is assumed in this paper that commencement of the NERL in the retail sector will see the complete removal of any requirement for a retailer to maintain a Victorian retail licence to sell energy in Victoria. On the other hand, there is no proposed replacement scheme for the authorisation of distribution, transmission or generation activities at the national level beyond what is already provided by market registration requirements…. Therefore, from the point of view of applying the NECF alone, no licensing regime is necessary. (DPI 2011m) DPI has concluded that although the NERL includes a retailer authorisation and exempt selling process, ‘small scale’ generators who sell surplus electricity into the distribution grid are not catered for under the national framework. As such, a Victoria specific regime, regulated by the ESC, will continue to govern distribution licensing in Victoria. DPI has noted its ‘concern that there is a high degree of regulatory fragmentation in the area of licensing, authorisation and exemptions’ and that it will ‘investigate appropriate ways for rationalising this structure in the future’ (DPI 2011m; DPI 2011l). The Commission has been advised by DPI that the Exemption Order (in an amended form) will also continue to exempt generators of less than 30 MW capacity from the need to obtain a generation licence.
B.4.3 Victorian feed-in tariff schemes
In Victoria, certain distributed generators connected to the distribution network are able to sell surplus electricity generated into the distribution grid through FiT schemes under Division 5A of the EI Act.
There are currently three FiT schemes operating in Victoria:
(1) Premium feed-in tariff (PFiT): commenced on 1 November 2009 and ended on 29 December 2011 (the declared scheme capacity day). The PFiT scheme is now closed to new applicants. However, generators participating in the PFiT scheme before the declared scheme capacity day can continue to participate for the 15 year duration of the scheme (until 31 October 2024). (2) Transitional feed-in-tariff (TFiT): commenced on 1 January 2012 and is currently open to new applicants. The TFIT scheme will run for 5 years from its commencement date until 31 December 2016. The scheme can, however, be closed to new
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 243 applicants once certain discretionary trigger points are reached. The Minister for Energy and Resources may declare a TFiT scheme end day if any of the following occur: – the aggregate generating capacity cap of 75 MW of installed scheme generating capacity is met – the average cost per customer of electricity per year arising out of the operation of the TFiT scheme is $5 or more – the Minister considers it appropriate to do so (s 40FEA, EI Act).
(3) Standard feed-in-tariff (SFiT): open to new applicants. The SFiT was initially introduced in 2004 for wind energy generators and was extended to other forms of small-scale renewable energy in 2007 (Batchelor 2007). Unlike the PFiT and TFiT schemes, there is no end date.
Funding of feed-in tariff schemes
In Victoria, to ensure that the customer is paid (in the form of a credit as a statutory minimum) for any surplus generation exported to the distribution grid, the PFiT and TFiT schemes are funded by a DNSP ‘pass through’ model. Under this arrangement, Victorian DNSPs apply the appropriate FiT rebates to licensed electricity retailers’ network bills that, in turn, apply the credits to eligible FiT customers’ bills. The AER regulates the distribution charge that licensed retailers pay the DNSP. The AER allows for the costs associated with the PFiT and TFiT schemes when approving the annual distribution network tariffs applied to retail customers’ network bills. The recovery of costs is underpinned by various national and Victorian regulatory instruments, including:
• NEL cl 2D(1)(b)(iv), 7A(2)(b) and 14B • distribution determinations by the AER under NER chapter 6 Part E, in particular cl 6.12.1(14) • distribution pricing rules under NER chapter 6 Part I, in particular cl 6.18.7A • Victorian Electricity Distribution Network Service Providers, Distribution Determination 2011–2015, Final Decision (AER 2010d), chapter 16 — Cost Pass Throughs • National Electricity (Victoria) Act 2005 (Vic) (‘National Electricity (Victoria) Law’) ss 16A and 16AB • EI Act ss 40FI and 40FH.
Distribution licence condition to credit retailers for PFIT and TFiT generation
Victorian electricity retailers and DNSPs are required — in the form of a distribution and retail licence conditions — to enter into ‘Use of System Agreements’. Licensed retailers must have a Use of System Agreement with each DNSP in whose distribution area the supply point of any customer of the retailer is located. The EI Act s 40FH states that it is a deemed Victorian distribution licence condition that Use of System Agreements include a condition that the DNSPs apply PFiT and TFiT credits — 60c and 25c per kWh respectively — to the relevant licensed retailer for PFiT and TFiT scheme generation conveyed along the distribution network in the DNSP’s distribution area.
244 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION DNSP cost recovery for PFIT, TFiT and SFiT schemes
In addition, the Revenue and Pricing Principles contained in the NEL cl 7A(2)(b) state that DNSPS ‘should be provided with a reasonable opportunity to recover at least the efficient costs the operator [DNSP] incurs in… complying with a regulatory obligation’. The National Electricity (Victoria) Law s 16A deems that the PFiT and TFiT credit obligation imposed on Victorian DNSPs under the EI Act s 40FH is a regulatory obligation under the NEL.
Under the NER cl 6.18.2, Victorian DNSPs must submit pricing proposals to the AER for each year of the regulatory control period, and the NER and National Electricity (Victoria) Law require that a DNSP’s pricing proposal must provide for tariffs designed to pass on to customers the DNSP’s costs for participating in the PFiT and TFiT schemes. NER cl 6.18.7A(b) states:
The amount to be passed on to customers for a particular regulatory year must not exceed the estimated amount of jurisdictional scheme amounts for a Distribution Network Service Provider's approved jurisdictional schemes adjusted for over or under recovery …
The PFiT and TFiT schemes under the EI Act are jurisdictional schemes for the purposes of the NER. Victorian DNSPs are therefore able to recover the costs associated with the PFiT and TFiT schemes from all their customers through approved annual network tariffs applied to customers’ network bills. The increased network tariffs are then reflected in an increased retail energy price that Victorian retailers charge all Victorian electricity consumers, resulting in a cross subsidy.
The SFiT scheme is funded differently to the PFiT and TFiT schemes. Under the EI Act, licensed retailers with more than 5000 customers are required to fund the SFiT scheme, by paying or crediting the SFiT customer for generation exported to the distribution grid (DPI nd, p.1). As a consequence, retailers presumably fund SFiT payments by smearing the costs across their retail customer base, again resulting in a cross subsidy. There is no regulated or standard process for how Victorian retailers must fund the SFiT scheme.
Premium feed-in tariff scheme Eligibility
All licensed retailers with more than 5000 customers were required to offer a PFiT to qualifying customers. Licensed retailers with 5000 or less customers could choose to offer a PFiT to qualifying customers. Note that the PFiT scheme closed to new applicants on 29 December 2011. A ‘qualifying customer’:
• purchases electricity from a licensed retailer, and • engages in the generation of electricity using a solar PV system with a capacity of 5kW or less connected to the distribution network, and • for householders: is claiming only one solar PV system on a property that is a principal place of residence, or • for persons that occupy one or more properties (other than as a place of residence): – is claiming only one solar PV system at each of those properties, and – the person's annual consumption rate of electricity is 100 MWh or less, and • has been exempted by Order under s 17 from the requirement to hold a licence in respect of the generation of electricity for supply and sale, and
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 245 • has net metering in place.
Price, terms and conditions
The PFiT is prescribed as not less than 60 cents per kWh credit for surplus electricity fed into the grid (s 40FA(2)(a) of the EI Act). In certain circumstances, retailers can extinguish excess PFiT credits that have accrued and are older than 12 months (DPI 2012c).13 A PFiT offer must comply with statutory minimum terms and conditions. Other terms and conditions of a PFiT offer must be ‘fair and reasonable’. A number of electricity retailers have offered a ‘top-up’ over and above the statutory minimum rate.
Transitional feed-in tariff scheme Eligibility
All licensed retailers with more than 5000 customers must offer a TFiT to eligible customers (‘TFiT scheme customers’). Licensed retailers with 5000 or less customers may choose to offer a TFiT to TFiT scheme customers. A ‘TFiT scheme customer’:
• purchases electricity from a licensed retailer, and • engages in the generation of electricity using a solar PV system with a capacity of 5kW or less connected to the distribution network on or after 1 January 2012, and • for householders: is only claiming one solar PV system on a property that is a principal place of residence, or • for persons that occupy one or more properties (other than as a place of residence): – is only claiming one solar PV system at each of those properties, and – the person's annual consumption rate of electricity is 100 MWh or less, and • has been exempted by Order under s 17 from the requirement to hold a licence in respect of the generation of electricity for supply and sale, and • has net metering in place.
Price, terms and conditions
The TFiT is prescribed as not less than 25 cents per kWh credit for surplus electricity fed into the grid (s 40FAB(2)(a) of the EI Act). In certain circumstances, retailers can extinguish excess TFiT credits that have accrued and are older than 12 months (DPI 2012c).14 A TFiT offer must comply with statutory minimum terms and conditions. Other terms and conditions of a TFiT offer must be ‘fair and reasonable’. A number of electricity retailers have offered a ‘top-up’ over and above the statutory minimum rate.
Standard feed-in tariff scheme Eligibility
All licensed retailers with more than 5000 customers must offer a SFiT to relevant generators. A ‘relevant generator’ is:
13 See EI Act s 40FA(2)(d). 14 See EI Act s 40FAB(2)(d).
246 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION • a generation company, or • a person engaging in the generation of electricity that has been exempted by Order under s 17 from the requirement to hold a licence in respect of the generation of electricity for supply and sale, and • engages in the generation of electricity using a small renewable energy generation facility connected to the distribution network, with a capacity of less than 100 kW, defined as: – solar, wind, hydro and biomass generating facilities – other forms of small renewable energy specified in an Order in Council published in the Government Gazette. The Commission understands that the power to extend the definition of ‘small renewable energy generation facility’ has not yet been used.
The SFiT specifically excludes:
• energy created from the combustion of fossil fuels, or materials or waste products derived from fossil fuels, and • since the commencement of the TFiT scheme, solar PV systems with a capacity of 5 kW or less, connected to the distribution system.
Price, terms and conditions
Unlike the PFiT and TFiT schemes, the SFiT price is not prescribed by the EI Act and each licensed retailer has discretion to set its own tariff price. However, the EI Act requires that the SFiT price and associated terms and conditions must be ‘fair and reasonable’ (s 40FB). The ESC has interpreted a ‘fair and reasonable’ price to mean that the rate offered to the customer must be not less than the rate the customer pays to buy electricity from the retailer (box B.4). Similarly, DPI’s website states that SFiT customers receive a ‘“one-for-one” payment rate for any excess electricity they feed back into the state’s electricity grid’ (DPI 2011d).
Although not mandated by legislation, DPI’s website also advises that:
The Standard Feed-in Tariff’s threshold is not designed for system installations where the generating capacity is significantly disproportionate to the actual energy used. This does not mean that the maximum system capacity must be in use at all times, although the entire capacity should be required for a significant portion of the year to offset your energy consumption. (DPI 2011d)
Obligation on licensed retailers to publish feed-in tariff offers
As discussed above, the EI Act regulates the electricity industry in Victoria through a licensing regime that, amongst other things, imposes statutory obligations on licensed businesses. This includes imposing a licence condition on electricity retailers to publish FiT terms and conditions online. The EI Act requires that FiT offer information on licensed retailers’ websites must be kept up-to-date (ss 40N, 40NA and 40NB) but does not provide any guidance on how this information must be presented.15
15 Note that the obligation on licensed electricity retailers to publish tariffs and terms and conditions of sale under ESC Guideline No. 19: Energy Price and Product Disclosure (2009c) — currently under review — does
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 247 • Licensed retailers that sell electricity to more than 5000 customers (‘relevant licensees’) must publish the terms and conditions of their PFiT, TFiT and SFiT offers (ss 40FF and 40G). • Licensed retailers that sell electricity to 5000 or less customers (‘small retail licensees’) and choose to offer a PFiT and/or TFiT, must publish the terms and conditions of their PTiT and/or TFiT offers. If a small retail licensee decides to no longer purchase electricity through a PFiT and/or TFiT scheme, it may publish a notice in the Government Gazette to that effect. The small retail licensee’s obligations under the PFiT and/or TFiT scheme will cease on the day such a notice is published (s 40FG).
The terms and conditions of FiT offers take effect two months after publication, unless they are referred to the ESC for assessment (s 40H). The criteria considered by the ESC in assessing whether a FiT offer is ‘fair and reasonable’ effectively prescribe the matters that should be included in a fair and reasonable offer published by licensed retailers. The role of the ESC is discussed below. The EI Act also sets minimum terms and conditions for PFiT and TFiT offers (ss 40FA and 40FAB). These statutory conditions form the required minimum content of a published offer.
Electricity pricing information requirements
In addition to the obligation on Victorian electricity retailers to publish FiT offer terms and conditions, retailers are subject to pricing information requirements in ESC Codes and Guidelines. These Codes and Guidelines only apply to retail supply contracts. They include:
• information provisions of the Energy Retail Code (ESC 2012b, pp.34–35) • Code of Conduct for Marketing Retail Energy in Victoria (ESC 2009a, pp.6–8) • internet publication requirements under Guideline 19: Energy Price and Product Disclosure (ESC 2009b) and the EI Act ss 35B, 35C and 36A.
In addition, the ESC maintains a price comparator website ‘YourChoice’ that allows customers to compare standing and market offers of Victorian electricity retailers.16 At this stage, YourChoice is limited to comparing retail contract offers for supply. It does not currently have the functionality to compare FiT offers.
Role of the Essential Services Commission
The EI Act provides that the Minister for Energy and Resources may refer matters to the ESC for assessment if the Minister considers that the terms and conditions of a licensed retailer’s FiT offers may not be ‘fair and reasonable’ (s 40I(1)(a)):
• for licensed retailers that have published their FiT terms and conditions — the referral must be before the PFiT, TFiT and SFiT terms and conditions take effect (published terms and conditions take effect two months after publication) • for licensed retailers that have failed to publish the their FiT terms and conditions as required — the referral may be at any time.
not extend to feed-in tariff offers. See Guideline 19: Energy Price and Product Disclosure – Issues Paper (ESC 2011b). 16 See: http://www.yourchoice.vic.gov.au.
248 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION The ESC must assess the referred terms and conditions as to whether they are fair and reasonable and report to the Minister on its assessment (s 40J(1)). The ESC can recommend (in the case of published retail FiT offers) or determine (in the case of retail FiT offers that have not been published):
• Any terms and conditions of a licensed retailer’s PFiT and TFiT scheme — apart from the statutory minimum conditions which are not reviewable — are not ‘fair and reasonable’, and recommend or determine alternative terms and conditions. The recommended or determined terms and conditions must be consistent with the statutory minimum conditions. • Any prices, terms and conditions of a licensed retailer’s SFiT scheme are not ‘fair and reasonable’, and recommend or determine alternative prices, terms and conditions (ss 40J and 40L).
On receipt of such a report from the ESC, the Minister may declare (by notice published in the Government Gazette) that the ESC recommended or determined PFiT, TFiT or SFiT terms and conditions apply to the licensed retailer named in the declaration (ss40M, 40MA and 40MAB). A small number of referrals have been made under this mechanism.17 The meaning of ‘fair and reasonable’ is discussed in box B.4.
Box B.4 Fair and reasonable feed-in tariff offers The Department of Primary Industries (DPI) has published criteria for assessing whether feed-in tariff (FiT) offers are ‘fair and reasonable’. The DPI criteria outline the rights and obligations of customers and licensed retailers that must be included for a FiT offer to be ‘fair and reasonable’. The DPI criteria require that an offer must, among other things: • require that the retailer will pay or credit the customer, for electricity supplied under a FiT contract, at a rate not less than the rate the customer pays to buy electricity from the retailer • require the FiT will be credited with the same frequency as the customer is billed and address billing arrangements • outline how the FiT credit will be calculated based on a reading of the customer’s meter • state all additional costs related to the FiT contract • provide for each parties’ rights and obligations in relation to under and overpayment of the FiT credit • cover variation and termination of the FiT contract. In a guidance paper Methodology for Assessment of Fair and Reasonable Feed-in Tariffs and Terms and Conditions (2008), the Essential Services Commission (ESC) outlined its approach to evaluating FiT offers referred for assessment under s 40I of the Electricity Industry Act 2000 (Vic). The ESC has clarified that it will apply the DPI criteria, plus the following additional criteria, when assessing the fairness and reasonableness of the terms and conditions of referred retailers’ FiT offers.
17 See the ESC website: esc.vic.gov.au.
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 249 Box B.4 Fair and reasonable feed-in tariff offers (cont) (1) Cost of service provision — any charge and terms and conditions imposed under FiT offers must be based on the reasonable costs that the retailer incurs in providing goods or services to small renewable energy generators in relation to the purchase of energy from such generators. (2) Cost allocation — the costs that a retailer incurs in accepting supply from a small renewable generator must not include costs not associated with accepting that supply and only include an appropriate allocation of any common costs incurred by the retailer in accepting that supply and in providing any other goods or services in relation to that supply. (3) Cost differentials — a retailer’s FiT offer terms and conditions must be the same for all small renewable energy generators unless there is a material difference in the cost of accepting supply from and providing associated goods and/or services to different small renewable energy generators or classes of small renewable energy generators. (4) Simplicity — the charges and terms and conditions for the FiT should be simple and easy to understand. Source: (ESC 2008, pp.8–12).
Regulation of feed-in tariff schemes after commencement of the NECF
Once the NECF commences in Victoria, the regulation of electricity retailers will be governed by a national regime and the Victorian retail licensing regime will be repealed. Current retail licence conditions relating to FiTs will continue to operate unaffected in a practical sense, as they will be enforced as direct statutory requirements under the EI Act instead of licence conditions. The National Energy Retail Law (Victoria) Bill 2012 proposes consequential amendments to the FiT provisions of the EI Act to reflect the repeal of electricity retail licensing. The Explanatory Memorandum states:
Currently, the requirement for retailers to comply with the feed-in tariff schemes is linked to their licences. The effect of the amendments made by this clause [75], and by clauses 76 to 95, is to create a direct statutory obligation for retailers to comply instead of the current deemed licence condition. (Explanatory Memorandum 2012, p.18)
This means that under an amended EI Act:
• the FiT scheme provisions — including the eligibility criteria, price, terms and conditions — will be unchanged • electricity retailers will still be obliged to publish on their websites, and keep up-to-date, their FiT offer terms and conditions • the ESC will continue to assess whether referred FiT offers are ‘fair and reasonable’.
Publication of feed-in tariff information after commencement of the NECF
After the commencement of the NECF in Victoria, there will be extra obligations on Victorian electricity retailers to publish pricing information.
• The AER’s ‘Energy Made Easy’ price comparator website became operational for Tasmanian and ACT energy consumers on 1 July 2012, as part of the retail pricing information requirements under the NERL (AER 2012f, p.5). Division 11 of the NERL also requires the AER to publish retail pricing information guidelines. Version 3.0 of
250 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION the AER Retail Pricing Information Guideline (AER 2012a) was released in June 2012. Victorian electricity retailers will be subject to the AER Retail Pricing Information Guideline once Victoria applies the NECF. The Guideline aims: … to assist small customers in readily comparing standing offer prices and market offer prices offered by retailers, by specifying the manner and form in which details of standing offer prices and market offer prices are to be presented by retailers. (AER 2012a, p.2) The NERL (s 63) and the Guideline require retailers to produce an ‘Energy Price Fact Sheet’ for each standing and market (contract) offer that a retailer offers to new small customers on or from 1 July 2012. These Energy Price Fact Sheets are generated on the AER’s Energy Made Easy price comparator website, allowing small customers to compare retail offers. Victorian retailers’ standing and market offers to new small customers will be available to compare on the Energy Made Easy website once the NECF is applied in Victoria. Retailers are also required to publish Energy Price Fact Sheets on their websites for each of their contract offers that are generally available to small customers on or from 1 July 21012. The Guideline specifies what information must be included on each Energy Price Fact Sheet and how it should be presented (AER 2012a). The AER Retail Pricing Information Guideline (AER 2012a) states that: An Energy Price Fact Sheet must clearly indicate when a contract offer is available to customers with solar photovoltaic systems. It must also indicate the solar feed-in tariff (or solar feed-in tariffs if there are more than one) available to customers entering into the contract offer associated with the Energy Price Fact Sheet. (AER 2012a, p.8) The Commission understands that retailers are only required to provide basic solar FiT offer information on Energy Price Fact Sheets. An example given indicates that solar FiT information should describe the available tariff(s) and state the tariff price(s) in cents per kWh exported (inclusive of GST) (AER 2012a, p.10).
• Amendments to the EI Act (as proposed in the National Energy Retail Law (Victoria) Bill 2012) will institute new price comparator requirements (a substituted Division 6). These provisions will require the ESC to continue to maintain the ‘YourChoice’ website, to assist small customers to compare standing offer and market offer retail prices required to be presented by the NERL and AER Retail Pricing Information Guideline (2012a). It will also require that retailers provide the ESC with information and data about standing and market offer prices (Explanatory Memorandum 2012, p.20). At the time this report was finalised, the ESC was still considering the ongoing role of YourChoice now that the NECF has been delayed in Victoria. Feed-in tariff application process
The process of installing a small renewable energy generation facility or solar PV system and applying for a FiT can be complex, and the terms and conditions in FiT contracts vary between retailers. Unlike the process for connecting distributed generation under the national framework, the process for applying for a Victorian FiT is not provided for by legislation. The Commission considers that the TFiT application and connection process for household-scale solar PV is best conceptualised as three separate, but interrelated, processes that occur side by side.
(1) Physical installation, connection and metering
Installation of solar PV is largely governed by the Electrical Safety Act 1998 (Vic) and Electricity Safety (Installations) Regulations 2009 (Vic), administered by Energy Safe Victoria (ESV). ESV regulates the licensing and registration of electricians, and the issuing and auditing of Certificates of Electrical Safety (CESs), to ensure that electrical
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 251 work is of a satisfactory standard and has been performed by a licensed electrician (ESV 2012a). The Commonwealth Government’s Small-Scale Renewable Energy Scheme requires solar PV to be installed by licensed electricians, who are accredited by the Clean Energy Council (Renewable Energy (Electricity) Regulations (Cth) reg 20AC).
Connection is governed by Victorian regulation covering small embedded generator connections. This will be replaced by a basic connection service under NER chapter 5A, when the NECF commences in Victoria. A solar PV customer also needs to complete the connection and approval processes required by their DNSP (section B.3). The Commission has been advised that, in practice, household-scale solar PV connections are generally approved automatically, without lengthy technical site assessments.
Metering provision, installation and maintenance is governed by NER chapter 7. Metering provision, installation and maintenance for types 1 to 4 metering installations is a contestable service under the national framework and is the responsibility of the ‘responsible person’ (cl 7.2.2 and 7.2.3) (AEMO 2009, pp.1–2). Except where the responsible person is also a registered ‘metering provider’, they must contract a ‘metering provider’ to install and maintain the meter (cl 7.4.1). Under the Victorian advanced metering infrastructure (AMI) jurisdictional derogation, the DNSP is the ‘responsible person’ for relevant metering installations18 in Victoria (cl 9.9B.3) (AEMC 2009e; AEMC 2011f). Once the AMI rollout derogation expires, metering will become contestable under chapter 7 of the NER. The AMI rollout derogation will expire on 31 December 2013 (the scheduled completion date), or earlier if the NER is amended to facilitate the rollout of smart meters and transfer regulation of the AMI rollout to the standard metering requirements under the NER.
(2) Contracting with the retailer
This process is governed by the FiT provisions of the EI Act, Division 5A. Division 5A requires that household-scale solar PV customers who wish to participate in the TFiT scheme enter into a TFit (export) contract with their supply retailer. It also mandates that a TFiT contract will not come into effect — that is, the customer will not receive any FiT credits for exported electricity — until the solar PV system is installed and connected, and appropriate metering is in place. Although there is no legal requirement that Victorian retailers have separate supply and FiT (export) contracts with their customers, it is industry practice that separate contracts are required.
Many FiT customers find that their supply tariff structure changes once they enter into a FiT contract with their electricity retailer. The changes usually reflect network tariff reassignment to time of use (TOU) pricing and loss of current rates for dedicated off- peak loads.19 Although the former Victorian Government announced a moratorium on TOU pricing on 22 March 2010, the Commission understands that TOU pricing will become more widely available to Victorian consumers on a voluntary basis in 2013 (Batchelor 2010; DPI 2012g). Under the agreement reached with the Victorian Government, Victorian DNSPs have discretion to reassign solar PV customers’ network tariff to TOU pricing at the retailer’s request (on behalf of the customer). Network tariff reassignment generally occurs after the PV system is connected and the metering upgrade/reconfiguration is complete. Retailers will generally discuss network tariff
18 A ‘relevant metering installation’ is a metering installation installed as part of the AMI roll out, for a connection point in Victoria for customers that consume less than 160 MhW per annum of energy (that is Victorian residential and most small business customers).
19 Customers lose their current rates for dedicated off-peak loads (off-peak electricity rates for hot water, heating or air-conditioning) when they enter into a solar FiT arrangement with their supply retailer (DPI 2012f).
252 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION reassignment with their customer at the tariff enquiry stage. If the customer consents to a TOU network tariff, many retailers will also restructure the customer’s retail tariff to TOU pricing as well.
(3) Applying for Small-Scale Technology Certificates/Solar Credits
Small-scale solar PV customers are generally eligible to receive Small-Scale Technology Certificates (STCs) under the Commonwealth Renewable Energy Target (RET). The Renewable Energy (Electricity) Act 2000 (Cth) s 23C and Renewable Energy (Electricity) Regulations 2001 (Cth) reg 20A govern the process for applying for Small-Scale Technology Certificates and Solar Credits. Customers can either:
• assign the right to create STCs to their solar retailer or installer, in exchange for a discount on the upfront cost of your system • sell the STCs themselves.
The Commonwealth Government’s Solar Credits scheme also multiplies the number of certificates for the first 1.5 KW of the installed PV system (DPI 2011i). Customers who chose to assign the right to create STCs to their solar retailer or installer must sign a Solar PV STC Assignment Form and a Written Compliance Statement (which verifies that the small-scale solar panel, wind or hydro installation was installed by an accredited installer).
Paperwork for solar PV systems
There are several forms — required for solar PV installation and connection, to apply for any applicable rebates and to participate in a FiT scheme — that must be completed. All necessary paperwork must be complete for a FiT applicant to participate in a FiT scheme. These forms include:
• a Commonwealth Solar PV STC Assignment and Written Compliance Statement to assign the right to create Small-Scale Technology Certificates (STCs) to the retailer or installer, in return for an upfront discount or payment. Note that this is not a requirement for a Victorian FiT, although most customers will wish to complete this paperwork to obtain an upfront discount on their solar PV system • a Solar Connection Form to notify the DNSP that a solar PV system will be installed at the customer's address and to outline customer rights and obligations in relation to this installation • an Electrical Work Request (EWR) form and CES, which are usually completed by the installer and forwarded to the retailer, to notify the retailer that the installed solar PV system has been wired and inspected for safety. The retailer then sends the EWR and CES (the Service Paperwork) to the DNSP, along with a Service Order Request for the bi-directional metering to be installed and/or reconfigured • a Victorian FiT contract with an electricity retailer must be entered into. The customer can sign the FiT contract at the same time as the EWR and CES are lodged but it does not take effect until appropriate metering is in place and the PV system is connected to the grid • any other paperwork specific to the retailer and/or DNSP must be completed (CEC 2011b, p.2; CEC 2012c; DPI 2011h).
See below for a flowchart on the high-level connection process for household-scale solar PV in Victoria, which includes applying for an applicable FiT (figure B.2). The Commission notes that the detail of the connection process will vary slightly across individual retailers and DNSPs, and will depend on the type of technology involved. The
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 253 Commission also notes that there are many detailed sub-steps that occur during the connection process, which are not reflected in figure B.2. These relate to Victorian electrical safety regulation, AMI installation requirements, and the Use of System Agreements and Business-to-Business (B2B) Procedures that govern communications between the retailer and DNSP.20
20 See: Installation Requirements: Installation and Inspection of Grid-connected PV Systems (ESV 2011); Safety of Solar Panel Installations in Victoria (ESV 2010); and Smart Meters – Installation (DPI 2012b). B2B Communications between Victorian retailers and DNSPs are governed by State-based Use of System Agreements and national B2B Procedures developed by the Information Exchange Committee established by AEMO (NER cl 7.2A). See: B2B Procedures (AEMO 2011b).
254 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION Figure B.2 Connection for household-scale solar PV (5 kw or less) in Victoria
Source: Commission analysis, drawing on (CEC 2012c).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 255 Costs associated with participating in a feed-in tariff scheme
The EI Act does not prescribe any fees or charges for applying for and participating in the PFiT, TFiT or SFiT schemes. However, some electricity retailers may charge administration fees as part of their FiT electricity contracts (DPI 2011k). The funding and cost recovery for Victorian FiT schemes was discussed earlier.
Bi-directional metering is required to receive a FiT. Old style accumulation meters are unable to measure electricity generated and sent into the grid from distributed generators. Bi-directional meters allow two-way electricity flows and the ability to record those flows on a half hourly basis (DPI 2011a; DPI 2011b). The Victorian Government is rolling out AMI (‘smart meters’) across Victoria. The rollout is scheduled to be complete by 31 December 2013. Once the AMI rollout is complete, new meters will not need to be installed but installed meters may need to be reconfigured for new solar PV connections. Victorian DNSPs are able to recover expenditure associated with the AMI rollout from consumers through metering service charges incorporated into all Victorian customers’ electricity bills. AER approved meter charges vary across Victorian DNSPs (AER 2011a).
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268 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION