Electricity network regulation

• Average electricity prices have risen by 70 per cent in real terms from June 2007 to December 2012. Spiralling network costs in most states are the main contributor to these increases, partly driven by inefficiencies in the industry and flaws in the regulatory environment.
• These flaws require a fundamental nationally and consumer-focused package of reforms that removes the interlinked regulatory barriers to the efficiency of electricity networks. Reforms made in late 2012, including improvements to the regulatory rules, better resourcing of the regulator and greater representation of consumers, have only partly addressed these flaws.
• Resolving benchmarking and interconnector problems will be a worthwhile addition to these recent reforms. But there remains a need for further significant policy changes to make a substantive difference to future electricity network prices, and to produce better outcomes for consumers - the latter being the primary objective of the regulatory arrangements. The changes needed include:
  • modified reliability requirements to promote efficiency
  • improved demand management
  • more efficient planning of large transmission investments
  • changes to state regulatory arrangements and network business ownership
  • adding some urgency to the existing tardy reform process. The Standing Council on Energy and Resources needs to accelerate reforms - particularly for reliability and planning - which have been bogged down by successive reviews. Delays to reform cost consumers across the National Electricity Market (NEM) hundreds of millions of dollars.
• The gains from a package of reforms are significant. Indicative estimates suggest:
  • in New South Wales alone, $1.1 billion in distribution network capital expenditure could be deferred until the next five year regulatory period by adopting a reliability framework that takes into account consumers' preferences for reliability. The actual savings are likely to be larger
  • adopting a different reliability framework for the transmission network could generate large efficiency gains in the order of $2.2 billion to $3.8 billion over 30 years
  • if carefully implemented, critical peak pricing and the rollout of smart meters could produce average savings of around $100-$200 per household each year in regions with impending capacity constraints (after accounting for the costs of smart meters).
• Reliability is critical to electricity networks, but some consumers are forced to pay for higher reliability than they value.
  • Reliability decisions should be based on trading off the costs of achieving them against what customers are willing to pay, rather than by prescriptive (sometimes politically influenced) standards.
• A large share (in New South Wales, some 25 per cent) of retail electricity bills is required to meet a few (around 40) hours of very high ('critical peak') demand each year. Avoiding this requires a phased and coordinated suite of reforms, including consumer consultation, the removal of retail price regulation, and the staged introduction of smart meters, accompanied by time based pricing for critical peak periods.
  • This would defer costly investment, ease price pressures on customers, and reduce the large hidden cross subsidies effectively paid by (often lower income) people who do not heavily use power in peak times, to those who do.
• Rolling out smart meters would also produce major savings in network operating costs - such as through remote meter reading and fault detection.
  • The Commission is proposing a process that learns from the experience of the Victorian smart meter rollout, and that will genuinely benefit consumers.
• State-owned network businesses have conflicting objectives, which reduce their efficiency and undermine the effectiveness of incentive regulation. Their privately-owned counterparts are better at efficiently meeting the long term interests of their customers.
  • State-owned network businesses should be privatised.
• The efficiency and effectiveness of recently announced reforms could be enhanced.
  • Given their overlapping roles, the three fully-funded consumer advocacy bodies in the NEM should be ultimately amalgamated into a single statutory body that would act on behalf of all consumers. It should be fully funded through an industry levy, and have the required expertise to play a leading, but not exclusive, role in representing customers in all regulatory processes. Partial funding - on a contestable basis - should continue for individual advocacy groups.
  • A review of the Australian Energy Regulator is proposed for 2014. The Australian Energy Market Commission, the Australian Energy Market Operator and the new consumer representative body should also be reviewed by 2018 so that the scope for improvement in all of the main NEM institutions will have been assessed.
  • At this stage, benchmarking - which compares the relative performance of businesses - is too unreliable to set regulated revenue allowances. Nevertheless, greater and more effective use of benchmarking could better inform the regulator's decisions.
  • There is no evidence of insufficient capacity in the interconnectors carrying power between jurisdictions, as is sometimes alleged. In fact, they are sometimes underutilised because of perverse incentives and design flaws created by the regulatory regime. Changes to the National Electricity Rules should address these problems.
  • In considering the benefits for consumers, it is important not to blame network businesses for the current inefficiencies. Mostly, they are responding to regulatory incentives and structures that impede their efficiency.

• Preliminaries
  • Cover, Copyright, Letter, Terms of reference, Disclosure of interests, Contents, Acknowledgments and Abbreviations and explanations
• Overview - including key points (The main messages)
• Recommendations and findings
• Chapter 1 About the inquiry
  • 1.1 What are the perceived problems?
  • 1.2 Overview of the regulatory framework and its institutions
  • 1.3 The Commission's approach to its terms of reference
  • 1.4 A guide to the report
• Chapter 2 The structure and performance of the National Electricity Market
  • 2.1 The structure of the National Electricity Market
  • 2.2 The scale of the network and its costs
  • 2.3 The nature of demand
  • 2.4 Prices have been rising
  • 2.5 The proximate reasons for higher network charges
  • 2.6 Reliability
  • 2.7 What is at stake?
• Chapter 3 The rationale for regulation of electricity networks
  • 3.1 The characteristics of electricity networks
  • 3.2 Evidence about the costs of market power
  • 3.3 The case for regulating monopolies
  • 3.4 Are deadweight losses passé? New theories of why monopolies should be regulated
  • 3.5 The alternative policy implications of different theories of monopoly regulation
  • 3.6 In summary
• Chapter 4 A framework for benchmarking
  • 4.1 Benchmarking managerial efficiency and performance
  • 4.2 Benchmarking techniques
  • 4.3 What should be benchmarked?
  • 4.4 The use of benchmarking for Australian electricity networks
  • 4.5 Criteria for judging benchmarking
  • 4.6 Validity - does the measure test what it claims to?
  • 4.7 Other scientific criteria for judging benchmarking
  • 4.8 Testing the credibility of results
  • 4.9 No perfect measure is possible
• Chapter 5 Incentive regulation and benchmarking
  • 5.1 Incentive regulation
  • 5.2 Incentive regulation and the electricity sector
  • 5.3 Ensuring effective incentives
  • 5.4 The AER's ability to determine expenditure forecasts
• Chapter 6 Empirical evidence of network efficiency
  • 6.1 Existing evidence and arguments
  • 6.2 The relative impacts of the WACC, capex and opex
  • 6.3 Demand driven augmentation
  • 6.4 What does the RAB tell us?
  • 6.5 Expenditure, allowances and timing
  • 6.6 Public and private ownership
  • 6.7 Conclusions
• Chapter 7 Ownership
  • 7.1 A framework for considering ownership
  • 7.2 Incentive regulation and state-owned corporations
  • 7.3 Non-commercial imperatives and interference
  • 7.4 The productivity and performance of state-owned network businesses
  • 7.5 The perceived risks of privatisation
  • 7.6 The bottom line on private ownership
  • 7.7 The transition to privatisation
• Chapter 8 How should the Australian Energy Regulator use benchmarking?
  • 8.1 Should benchmarking be used in a mechanistic role to set revenue allowances?
  • 8.2 Benchmarking the effectiveness of the regulatory regime
  • 8.3 Could more targeted analysis act as a filter?
  • 8.4 Benchmarking could be a trigger for negotiated settlements
  • 8.5 Information and 'moral suasion'
  • 8.6 The long-run application of benchmarking
  • 8.7 The regulator's benchmarking practices
  • 8.8 Conclusion
• Chapter 9 Peak demand and demand management
  • 9.1 What is peak demand and why is it a problem?
  • 9.2 A roadmap for how this report addresses peak demand management
  • 9.3 Facets of the peak demand problem
  • 9.4 What is demand management and how can it provide a solution?
  • 9.5 Demand management is not widely implemented
  • 9.6 Why is the uptake of demand management so low?
  • 9.7 Gauging the prospective benefits and costs of demand management
• Chapter 10 Technologies to achieve demand management
  • 10.1 Understanding smart meters
  • 10.2 Rolling out smart meters involves major challenges
  • 10.3 Creating the optimal incentives for deploying demand management technologies
  • 10.4 A hybrid approach that blends a market-based and regulated approach
  • 10.5 There must be a role for other parties
  • 10.6 Control of the information hub
  • 10.7 Direct load as an alternative or complementary option
• Chapter 11 Moving to time-based pricing for the distribution network
  • 11.1 Introduction
  • 11.2 How do distribution businesses currently price?
  • 11.3 Do the National Electricity Rules facilitate time-based and other efficient pricing approaches?
  • 11.4 Designing time-based prices for distribution networks
  • 11.5 A supervising role for SCER is a first step in implementing time-based pricing
  • 11.6 A NEM-wide licensing regime for network providers
  • 11.7 Tightening and augmenting aspects of the Rules
  • 11.8 Guidelines to support methodological development and data collection
  • 11.9 Addressing affordability and equity issues
  • 11.10 The nature of the transition to time-based pricing
  • 11.11 The importance of effective engagement and customer education
• Chapter 12 Complementary reforms to support demand management
  • 12.1 Choice of revenue control mechanism - revenue caps versus weighted average price caps
  • 12.2 The incentives of network businesses to undertake demand management
  • 12.3 Retailers' incentives and price regulation
  • 12.4 The AEMC's proposed 'demand response mechanism' in the Power of Choice review
• Chapter 13 Distributed generation
  • 13.1 What is distributed generation?
  • 13.2 Scale of distributed generation in Australia
  • 13.3 Potential benefits of distributed generation
  • 13.4 Effects of distributed generation on network costs
  • 13.5 Obstacles to efficient network investment
  • 13.6 Benchmarking to achieve efficient levels of network use of distributed generation
• Chapter 14 Building a reliability framework in order to benchmark
  • 14.1 What issues does reliability raise?
  • 14.2 Reliability under incentive regulation
  • 14.3 The costs of reliability for network businesses
  • 14.4 What level of reliability is efficient?
  • 14.5 Measuring the value of reliability
  • 14.6 Concluding comments
• Chapter 15 Distribution reliability
  • 15.1 Introduction
  • 15.2 Reliability performance of distribution businesses in the National Electricity Market
  • 15.3 Reliability settings for distribution networks in the National Electricity Market
  • 15.4 An efficient and effective distribution reliability framework - a bolstered STPIS
• Chapter 16 Transmission reliability and planning
  • 16.1 Introduction
  • 16.2 The special characteristics of transmission networks
  • 16.3 The broader planning context and economic regulation
  • 16.4 An efficient transmission framework?
  • 16.5 The way forward
  • 16.6 Delivering reliability in the shorter term
  • 16.7 Changes to transmission reliability
  • 16.8 Contestability in new connections and other separable transmission investments
• Chapter 17 The Regulatory Investment Test for Transmission
  • 17.1 The current framework
  • 17.2 Issues with the current RIT-T
  • 17.3 The future role of the RIT-T
  • 17.4 Other potential improvements
• Chapter 18 The role of interconnectors
  • 18.1 Background and perceived problems
  • 18.2 Some conceptual considerations
  • 18.3 Evidence of the efficiency of interconnection
• Chapter 19 Efficient use of interconnectors
  • 19.1 The spot market
  • 19.2 Disorderly bidding
  • 19.3 Potential solutions
  • 19.4 More fundamental reforms
  • 19.5 The hedging market
• Chapter 20 Merchant interconnectors
  • 20.1 The role of merchant interconnectors in the National Electricity Market
  • 20.2 Regulatory biases
  • 20.3 Beneficiary pays
• Chapter 21 Governance
  • 21.1 Governance and performance of the Australian Energy Regulator
  • 21.2 Reform of Australian Energy Regulator governance
  • 21.3 What about AEMO, the AEMC and other NEM bodies?
  • 21.4 Consumer engagement and representation
  • 21.5 Processes for amending electricity network regulation
  • 21.6 Merits review processes
• Appendix A Conduct of the inquiry
• References

Please note: Appendices B to F are only available online and are not in the printed copy.

• Appendix B The hold-up problem (PDF - 202 Kb)
• Appendix C Hedging in the electricity market (PDF - 331 Kb)
• Appendix D Modelling indirect effects in the RIT-T (PDF - 229 Kb)
• Appendix E International regulators' approach to merchant transmission investment (PDF - 108 Kb)
• Appendix F Current transmission reliability and planning frameworks (PDF - 418 Kb)