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October 2006 Final Decision Electricity Distribution Price Review 2006-10 October 2005 Price Determination as amended in accordance with a decision of the Appeal Panel dated 17 February 2006 Final Decision Volume 1 Statement of Purpose and Reasons Essential Services Commission Level 2, 35 Spring Street Melbourne VIC 3000, Australia Telephone 61 3 9651 0222 Facsimile 61 3 9651 3688 [email protected] www.esc.vic.gov.au Contents Page PREFACE ................................................................................................................................................................VII PART A: OVERVIEW AND INTRODUCTION ..............................................................................................1 Key outcomes of the review ...................................................................................................................................1 Focus of this review................................................................................................................................................2 Enhanced accountability ..............................................................................................................................3 Establishing forecast revenue requirements.................................................................................................5 Real price reductions ............................................................................................................................................10 Consultation process.............................................................................................................................................11 Issues arising from the review ..............................................................................................................................12 Looking ahead ......................................................................................................................................................13 1 INTRODUCTION ..............................................................................................................................................15 1.1 Legislative framework ...............................................................................................................................15 1.2 The Commission’s consultation process....................................................................................................18 1.3 The Commission’s broad framework and approach ..................................................................................19 1.4 Structure of the Decision ...........................................................................................................................22 PART B1: 2 SERVICES PROVIDED AND ENERGY DELIVERED ...............................................................23 SERVICE STANDARDS ...................................................................................................................................27 2.1 Final Decision............................................................................................................................................28 2.1.1 Reliability measures ....................................................................................................................28 2.1.2 Quality of supply measures .........................................................................................................30 2.1.3 Customer service measures .........................................................................................................31 2.2 Reasons for the Decision ...........................................................................................................................32 2.2.1 Reliability measures ....................................................................................................................32 2.2.2 Quality of supply measures .........................................................................................................45 2.2.3 Customer service measures .........................................................................................................53 ATTACHMENT 1: EXAMPLES OF WORST SERVED FEEDERS ..............................................................61 ATTACHMENT 2: TARGETED LEVELS — RELIABILITY MEASURES ................................................64 3 SERVICE INCENTIVE MECHANISMS ........................................................................................................69 3.1 Final Decision............................................................................................................................................70 3.1.1 S-factor scheme ...........................................................................................................................70 3.1.2 GSL payments scheme ................................................................................................................75 3.1.3 Other service incentive arrangements..........................................................................................76 3.1.4 Operation of the service incentive mechanisms ..........................................................................77 3.2 Reasons for the Decision ...........................................................................................................................78 3.2.1 S-factor scheme ...........................................................................................................................78 3.2.2 GSL payments scheme ..............................................................................................................102 October 06 i Essential Services Commission, Victoria Contents 3.2.3 3.2.4 Other proposed service incentive arrangements ........................................................................115 Exclusion criteria.......................................................................................................................122 ATTACHMENT: ANNUAL HEALTH CARD ....................................................................................................129 4 GROWTH FORECASTS ................................................................................................................................131 4.1 Final Decision..........................................................................................................................................131 4.2 Reasons for the Decision .........................................................................................................................133 4.2.1 Historic growth rates .................................................................................................................136 4.2.2 Assumptions underpinning the different scenarios....................................................................138 4.2.3 Price elasticity of demand .........................................................................................................150 PART B2: REVENUE REQUIREMENT — DUOS .......................................................................................153 5 RELEVANT COSTS........................................................................................................................................159 5.1 Final Decision..........................................................................................................................................160 5.2 Reasons for the Decision .........................................................................................................................163 5.2.1 Allocation between retail and distribution services...................................................................165 5.2.2 Allocation between prescribed and excluded services...............................................................166 5.2.3 Capitalisation of indirect (corporate) overheads........................................................................166 5.2.4 Movements in provisions ..........................................................................................................167 5.2.5 The market price for services ....................................................................................................168 5.2.6 Other adjustments......................................................................................................................185 5.2.7 Further adjustments to CitiPower and Powercor .......................................................................185 5.2.8 Summary ...................................................................................................................................192 6 OPERATING AND MAINTENANCE EXPENDITURE .............................................................................195 6.1 Final Decision..........................................................................................................................................195 6.2 Reasons for the Decision .........................................................................................................................196 6.2.1 Distributors’ proposed operating and maintenance expenditure................................................197 6.2.2 Base operating and maintenance expenditure............................................................................199 6.2.3 Rate of change ...........................................................................................................................205 6.2.4 Impact of growth .......................................................................................................................211 6.2.5 Step changes ..............................................................................................................................212 7 CAPITAL EXPENDITURE ............................................................................................................................251 7.1 Final Decision..........................................................................................................................................252 7.2 Reasons for the Decision .........................................................................................................................254 7.2.1 Commission’s objectives...........................................................................................................255 7.2.2 Framework and approach ..........................................................................................................257 7.2.3 Distributors’ proposed capital expenditure................................................................................258 7.2.4 Review of the distributors’ proposals ........................................................................................261 7.2.5 Aggregate level of capital expenditure ......................................................................................265 7.2.6 Implementation of capital works programs ...............................................................................267 7.2.7 Information asymmetry .............................................................................................................268 7.2.8 Commission’s determination of capital expenditure requirements............................................269 October 06 ii Essential Services Commission, Victoria Contents 7.2.9 Assessment of the distributors’ capital expenditure proposals by asset category......................272 8 REGULATORY ASSET BASE ......................................................................................................................321 8.1 Final Decision..........................................................................................................................................321 8.2 Reasons for the Final Decision ................................................................................................................323 8.2.1 Opening value of the asset base (1 January 2006).....................................................................324 8.2.2 Rolled forward values of the regulatory asset base (2006-10)...................................................327 9 COST OF CAPITAL FINANCING................................................................................................................331 9.1 Final Decision..........................................................................................................................................332 9.2 Reasons for the Decision .........................................................................................................................332 9.2.1 Methodology for estimating the after-tax WACC .....................................................................333 9.2.2 Estimating the after-tax WACC ................................................................................................338 9.2.3 Taxation.....................................................................................................................................398 10 EFFICIENCY CARRYOVER MECHANISM ...................................................................................415 10.1 Final Decision..........................................................................................................................................417 10.2 Reasons for the Decision .........................................................................................................................418 10.2.1 Calculation of the 2001-05 efficiency carryover amounts.........................................................418 10.2.2 Efficiency carryover mechanism in the 2006-10 regulatory period ..........................................430 ATTACHMENT: PART B3: 11 PRICES — DUOS............................................................................................................................439 REVENUE REQUIREMENT ..............................................................................................................443 11.1 Final Decision..........................................................................................................................................443 11.2 Reasons for the Final Decision ................................................................................................................446 11.2.1 Distributors’ proposed revenue requirement .............................................................................449 11.2.2 Translation of revenue requirement into forecast tariff revenue requirement ...........................451 ATTACHMENT: 12 2001-05 BENCHMARK ADJUSTMENT FOR CARRYOVER MECHANISM.........437 CALCULATION OF THE S FACTOR INCLUSIVE P0...............................................459 PRICE CONTROL ARRANGEMENTS.............................................................................................461 12.1 Reporting requirements............................................................................................................................461 12.1.1 Tariff Strategy Report................................................................................................................462 12.1.2 Annual Tariff Report .................................................................................................................464 12.2 Pricing principles .....................................................................................................................................465 12.3 Price control formulas..............................................................................................................................467 12.3.1 Distribution price control formula .............................................................................................467 12.3.2 Transmission price control formula...........................................................................................476 12.4 Rebalancing constraints ...........................................................................................................................478 12.4.1 Distribution tariff rebalancing constraint...................................................................................478 12.4.2 Transmission rebalancing constraint .........................................................................................481 12.5 Tariff re-assignment.................................................................................................................................486 12.6 Pass through provisions ...........................................................................................................................487 12.7 Tariff approval process ............................................................................................................................490 October 06 iii Essential Services Commission, Victoria Contents 12.7.1 Tariffs for the 2006 calendar year .............................................................................................490 12.7.2 Tariffs for the 2007-10 calendar years.......................................................................................492 12.8 Demand management and non-network solutions ...................................................................................492 12.8.1 Benefits associated with the interval meter rollout (IMRO)......................................................494 12.8.2 Weighted average price cap.......................................................................................................494 12.8.3 Building blocks approach ..........................................................................................................495 12.8.4 Service incentive mechanism ....................................................................................................497 12.8.5 Stakeholder responses ...............................................................................................................498 PART B4: 13 PRESCRIBED METERING SERVICES......................................................................................503 REVENUE REQUIREMENT — METERING ..................................................................................505 13.1 Final Decision..........................................................................................................................................505 13.2 Reasons for the Decision .........................................................................................................................507 13.2.1 Responsibility for metering services .........................................................................................507 13.2.2 Regulation of metering services ................................................................................................509 13.2.3 Revenue requirement.................................................................................................................512 13.2.4 Enhanced offerings....................................................................................................................554 ATTACHMENT: FORECAST QUANTITIES AND UNIT COSTS..................................................................557 14 PRICE CONTROLS AND INCENTIVE ARRANGEMENTS — METERING .............................565 14.1 Final Decision..........................................................................................................................................566 14.2 Reasons for the Decision .........................................................................................................................569 14.2.1 Price controls.............................................................................................................................570 14.2.2 Incentive arrangements..............................................................................................................577 14.2.3 Metering service charges...........................................................................................................582 14.2.4 Excluded service charges ..........................................................................................................585 PART C: 15 EXCLUDED SERVICES AND OTHER ACTIVITIES...............................................................591 EXCLUDED SERVICES AND OTHER ACTIVITIES.....................................................................593 15.1 Changes to excluded services during the 2006-2010 regulatory period ..................................................593 15.1.1 Final Decision............................................................................................................................593 15.1.2 Reasons for the Decision ...........................................................................................................595 15.2 Policies and definitions............................................................................................................................600 15.2.1 Final Decision............................................................................................................................600 15.2.2 Reasons for the Decision ...........................................................................................................600 15.3 Revisions to excluded service charges.....................................................................................................602 15.4 Other Activities........................................................................................................................................604 PART D: SUMMARY OF THE FINAL DECISION BY DISTRIBUTOR.................................................607 AGLE .................................................................................................................................................................608 CitiPower............................................................................................................................................................626 Powercor.............................................................................................................................................................645 SP AusNet ..........................................................................................................................................................665 United Energy.....................................................................................................................................................684 October 06 iv Essential Services Commission, Victoria Contents APPENDIX A THE PRICE REVIEW PROCESS .......................................................................................703 The price review process ....................................................................................................................................703 Commission’s publication and submissions received from stakeholders ...........................................................706 Public forums and workshops.............................................................................................................................717 Independent advice and consultancies in relation to the price review ................................................................720 GLOSSARY AND ABBREVIATIONS .................................................................................................................722 REFERENCES ........................................................................................................................................................730 October 06 v Essential Services Commission, Victoria October 06 vi Essential Services Commission, Victoria Final Decision PREFACE The Essential Services Commission (the Commission) is required to review and decide on new price controls for the charges to be levied by the five Victorian electricity distributors from 1 January 2006. The Commission’s decisions are framed by the Essential Services Commission Act 2001, the Electricity Industry Act 2000 and the Victorian Tariff Order. This price review is the second review of the electricity distribution price controls that apply to the five Victorian distributors undertaken by an independent regulator. It has provided an opportunity for Victorian customers to review the services and service levels provided by the distributors and balance their service-related requirements against the prices that they are willing to pay. The Commission has undertaken extensive consultation with stakeholders and information gathering and analysis in reaching this Determination. Consultation began in March 2004 and has taken the form of consultation papers, workshops, public information sessions in Melbourne and regional centres and submissions from the distributors and other stakeholders. A Draft Decision was released in June 2005 that provided stakeholders with the opportunity to comment on the Commission’s views before it made its Final Determination. Advice has also been obtained from technical consultants. The Determination comprises two volumes: • Final Decision Volume 1 — Statement of Purpose and Reasons: the Statement of Purpose and Reasons provides the context for the review and outlines the key issues, the various comments and submissions received and the Commission’s analysis, reasons and conclusions regarding the new price controls. It is structured around the key issues that have been addressed by the Commission throughout this price review. • Final Decision Volume 2 — Price Determination: the Price Determination sets out the detailed price controls and the associated implementation mechanisms which gives effect to those price controls. The price controls represent the translation of the Commission’s conclusions presented in the Final Decision into a legal document that will provide the basis for regulating the charges levied by the distributors. These controls will be implemented on 1 January 2006 and apply for a five year period. In conducting this review and making this Determination, the Commission has been guided by the statutory framework. The Commission considers that this Determination, which has been arrived at following the extensive price review process, provides a firm foundation for electricity distribution services for the next regulatory period and beyond. A.C. Larkin Acting Chairperson October 06 vii Essential Services Commission, Victoria Final Decision October 06 viii Essential Services Commission, Victoria Final Decision PART A: OVERVIEW AND INTRODUCTION The Commission has made a Final Decision on the prices and service levels applying to the five Victorian distribution businesses for the period 2006-2010. This overview summarises the key outcomes, issues and future regulatory policy implications that have emerged from this, the second major independent review of the electricity distribution charges for the five Victorian monopoly distributors, since the electricity industry reforms of the mid 1990s. The key theme and objective of this review has been to substantially increase the accountability of the businesses for maintaining and improving the delivery of reliable electricity distribution services to Victorian customers. Reliability of essential services such as electricity distribution services has a significant impact on economic growth, competitiveness and the welfare of all Victorian citizens. The prices paid for distribution services account for approximately 40 per cent of electricity customers' total bills. Moreover, the sale of such services is expected to generate industry revenues of around $6.3 billion over the next five years. The adequacy of revenue, return and incentive is critical to the necessary investment in, and maintenance of, reliable networks. Key outcomes of the review The price controls established for the five Victorian monopoly distribution businesses provide for the financing of $3.3 billion1 of capital expenditure for the period of 2006-10. This represents an increase of around 43 per cent above the actual capital investment made by the businesses during the period 2001-2005 including metering, or around 30 per cent excluding metering. The Commission considers that this level of capital expenditure benchmark is more than sufficient to account for the demands of network reinforcement, new customer connections, asset replacement, safety and environmental obligations and the installation of a significant number of interval meters. The Commission’s Final Decision will result in average price reductions of 12 per cent across the industry in 2006, with a further 1.2 per cent reduction per annum over the following four years.2 This compares to initial price reductions averaging 23 per cent in the Draft Decision. The adjustment to the initial price reductions between the Draft and Final Decisions has been made in light of further information that supports increases in forecast operating and capital expenditures, a reduction in forecast demand and an acceleration of the depreciation profile for some distributors. In developing the price controls for the 2006-2010 regulatory period the Commission has deliberately adopted a longer term view with a focus on locking in the performance gains made to date as well as providing incentives to improve reliability and customer service to levels consistent with the values placed on them by customers. Substantial increases in both the rewards and penalties imposed under the broadened service incentive scheme will provide distributors with strong financial incentives to improve service performance. These incentives are accompanied by an enhanced system of guaranteed service level payments to bring about improvements in those areas that are currently worst served. 1 2 Gross capital expenditure including metering. Including metering charges. October 06 1 Essential Services Commission, Victoria Final Decision The introduction of strategic initiatives such as the interval meter rollout will also provide a platform for the delivery of improved demand management outcomes and greater efficiency in distribution services and related markets. The interval meter roll out will be managed so that distributors are provided with adequate compensation for the cost of the rollout whilst providing incentives to achieve efficiencies in the cost and volume of installations. Focus of this review The Commission recognises that the distributors have achieved a marked improvement in service performance for virtually all customers over the last ten years. In the time since the industry was restructured, privatised and placed under formal economic regulation, all key indicators of network reliability have shown significant improvement. The broadest indicator of reliability, average customer minutes off supply per annum (or SAIDI), has fallen from 199 in 1997 to 132 in calendar year 2004. The proportion of customers experiencing more than five hours of supply outages (or 300 minutes off supply) has reduced from 20.5 to 11.6 percent over the same period. The annual incidence of interruptions (as indicated by SAIFI) has also reduced significantly.3 Services have not only improved in terms of average network performance, but they have also improved for customers located in those parts of the electricity distribution network that have historically experienced poor performance. There has been significant improvement in the minutes off supply for worst served customers (ESC 2004g, p. 30). For example, Powercor reports that the worst served 15 per cent of customers in its network area have experienced an improvement of 41 per cent since 2000, from an average of 738 minutes off supply in 2000 to 434 minutes off supply in 2004. Notwithstanding this picture of strong performance overall, there remain some pockets where the level of service has not kept pace with the demands of customers in a growing economy, particularly in some regional areas. As explained below, an important focus of this review has been to establish arrangements that will address these areas of concern. Instrumental in delivering the widespread improvement in services has been the improved operational and investment focus of the distributors. Accountability for delivering services in line with customer expectations ultimately lies with the distributors, and will continue to remain so. Nevertheless, the Commission’s experience over two regulatory periods is that the detailed regulatory arrangements governing service performance play a significant role in securing that focus by the distributors, and rewarding it appropriately. The Commission’s highest priority for this review is to secure and enhance this recent performance record into the future. This goal has defined the two main areas of attention for this review: • 3 augmenting the monitoring and incentive framework applying to service performance, with a particular regard to strengthening the distributors’ accountability for delivering reliable distribution network services, including for those customers where service is still not matching reasonable expectations; and SAIFI is the system average interruption frequency index. October 06 2 Essential Services Commission, Victoria Final Decision • undertaking a careful evaluation of the future operating expenditure and investment requirements proposed by the distributors, and ensuring that sufficient revenue is available to finance expected changes in the cost of delivering services at current levels, as well as incentive arrangements that ensure continued improvements in service and reliability. These two areas are closely related. A continued emphasis on maintaining and enhancing the distributors’ current performance can only be achieved if expected revenues (and so the prices that customers pay) are sufficient to finance the necessary expenditure to deliver that service. Nevertheless, it is also recognised that irrespective of how much money is made available through the price controls, there is no guarantee that the distributors will undertake the investment necessary to secure and enhance network reliability or indeed the investment that they have proposed to make. Intrinsic to a strengthened accountability framework is the principle that some portion of distributors’ expected revenues should be conditional on the achievement of desired levels of reliability. Importantly, customers should not be expected to pay for reliability improvements promised but not delivered. Enhanced accountability In developing its approach to increasing the accountability of the distributors, the Commission has drawn a distinction between establishing capital expenditure and operating and maintenance expenditure forecasts sufficient to maintain the delivery of current service performance in line with ‘business as usual’ and the arrangements for identifying and funding opportunities to invest in further service improvements. Business as usual expenditure has been provided for within the ‘building block’ revenue requirements that underpin the principal price controls which are outlined in more detail in the following sections. This expenditure does not include an allowance for improvements to existing average service reliability levels but does allow for improvements in quality of supply. The targeted levels of service reliability for the purpose of reporting and monitoring in the 2006-10 regulatory period have been set equal to the 2005 targets, except where a distributor has been consistently outperforming this target. In this case, the current level of performance has been considered in deciding a new target The most significant measure in this Decision for ensuring that the distributors deliver the services that they are paid to deliver is an increase in the rewards and penalties under the service incentive scheme (the ‘S-factor’ in the price controls). These rewards and penalties will apply for any improvements or shortfalls in service performance outcomes through changes to the distributor’s allowed revenue. These adjustments are symmetric: not only will distributors receive additional income when service enhancements are achieved but also they may incur penalties of a similar magnitude if service performance is not delivered. Under these arrangements the distributors — rather than the Commission — will be responsible for identifying and deciding upon initiatives that will bring about service improvements, with the rewards then flowing once those service improvements are delivered. This will facilitate delivery of the optimum level of service, given the value customers place on service and the cost to deliver this level of service. October 06 3 Essential Services Commission, Victoria Final Decision The main improvements made to the incentives for service provision include: • increases in the incentive rates; • adopting a uniform incentive rate for all distributors; • broadening the range of indicators that are subject to the financial incentive; • substantial increases in the value of Guaranteed Service Level (GSL) payments; • broadening of the monitoring regime; and • a quantitative rather than qualitative approach to excluding supply interruptions from the calculation of the S-factor and the obligation to make GSL payments. The incentive rates for the current price control period were set by reference to the estimated marginal cost of delivering service improvements. These costs were inherently uncertain and varied significantly from one distributor to another. For the 2006-10 period, the incentive rates will increase based on a uniform $30,000 per MWh or 1000 times the average selling price of distributed energy4. This value is based on the cost that poor service imposes on customers and is known as the Value of Customer Reliability (VCR) and increases the value up to six times compared to the value that has applied during the 2001-05 regulatory period. The Commission is also broadening the range of indicators that are subject to the S-factor incentive scheme. For the coming regulatory period, the scheme will include new incentives for unplanned minutes off supply, momentary interruptions and call centre performance while also retaining the existing incentive for the frequency of unplanned interruptions. Planned minutes off supply has been removed from the scheme because of the concerns expressed by some stakeholders that it would create an incentive for more ‘live line’ work, potentially resulting in a greater incidence of unsafe work practices. Nevertheless, distributors will continue to report planned minutes off supply on a regular basis. In addition to incentives provided through the S-factor, the Commission has increased substantially the payments that are to be made to customers where service performance does not meet a guaranteed minimum level. All customers will automatically receive these Guaranteed Service Level (GSL) payments when they experience more than 20 hours, 30 hours and 60 hours of cumulative sustained unplanned interruptions in a year with the GSL payment increasing for each threshold. Customers will also receive a GSL payment where the number of sustained interruptions is more than 10, 15 and 30 in a year, or the number of momentary interruptions is more than 24 and 36 in a year, again with increasing payments for each threshold. A further measure to be introduced for the 2006-10 period is a broadened of the monitoring regime. This includes: • additional reporting associated with quality of supply; • reporting the annual duration and frequency of interruptions (planned and unplanned) experienced by the worst served 15 per cent of customers; • reporting the causes of unplanned interruptions and the actions the distributor proposes to undertake to improve its performance; 4 With the exception of CitiPower’s CBD customers, where the incentive rates will be based on $60,000 per MWh October 06 4 Essential Services Commission, Victoria Final Decision • reporting customer service measures, including call centre performance; and • reporting other measures of performance that are less amenable to specification in a financial incentive regime. The Commission is confident that, taken together, these arrangements will significantly increase the accountability of distributors for delivering reliable quality services. Importantly, the distributors will be able to control the value of the impact of these arrangements. The expected value of the penalties and rewards associated with the S-factor incentive scheme is approximately zero where the distributors do not respond to the arrangements but distributors stand to earn considerable rewards where they respond by investing in their network to achieve service improvement outcomes. This is because the rewards under the scheme have increased significantly whilst the costs of achieving them have reduced as a result of changes to the efficiency carry-over mechanism discussed in later sections. The Commission anticipates that this will cause distributors to pursue the rewards that will be delivered by carefully targeted and innovative programs to benefit all customers and particularly worst served customers. This will include placing greater emphasis on undertaking investment and operational measures that reduce network outages and their associated inconvenience to all customers. However, customers will only pay for these improvements once they are delivered. These revised service performance measures should encourage distributors to shift their business focus away from short term cost minimisation and the payments available under the efficiency carryover mechanism towards longer term network planning and management and investment, to avoid the penalties imposed when services are not provided. Establishing forecast revenue requirements In addition to enhancing the accountability of distributors for the delivery of services and reliability, the regulatory framework is also focused on the establishment of forecast revenue requirements for each distributor over the forthcoming regulatory period. These revenue requirements are intended to be sufficient for each distributor to recover the efficient costs of operating its network business, including a commercial return on invested capital for “business as usual” service levels outlined in the previous section. The service delivery and out-turn expenditure performance of the distributors during the 2001-05 regulatory period can be characterised as having achieved more in terms of service delivery, but with significantly less expenditure than the distributors considered necessary in their proposals to the last price review. On readily available measures of industry performance, this combination of outcomes can only be described as virtuous — more has been delivered, for a cost less than expected. However, the sustainability of the expenditure and service performance outcomes during this regulatory period was not apparent in the expenditure projections contained in the distributors’ submissions to this review. As a group, the distributors proposed average increases in capital expenditure and operating and maintenance expenditure allowances for October 06 5 Essential Services Commission, Victoria Final Decision the 2006-10 regulatory period of 54 per cent and 45 per cent respectively5 over their average capital expenditure in 2001-2005 and their average operating and maintenance expenditure in 2001-2005 (see Figures A.1 and A.2). Figure A.1: Capital expenditure (gross), industry aggregate, actual expenditure 1996-2004a and distributor’s proposed forecast expenditure 2005-10, $million, real $2004 900 800 700 600 500 $M 400 300 200 100 0 1996 1997 1998 1999 2000 2001 Actual capex (inc meters) a 2002 2003 2004 DB proposed CAPEX (ex meters) 2005 2006 2007 2008 2009 2010 DB proposed CAPEX (inc meters) Out-turn gross capital expenditure includes prescribed distribution use of system and metering costs Figure A.2: Operating and maintenance expenditure, industry aggregate, actual operating and maintenance expenditure 2001-04a and distributors’ proposed expenditure, 2005-10, $million, real $2004 600 500 400 $M 300 200 100 0 2001 2002 2003 2004 2005 2006 Actual opex a 5 2007 2008 2009 2010 Distributor proposed Exclusive of operating and maintenance expenditure associated with prescribed metering services. This is exclusive of the cost of metering. Including metering the distributors’ proposals represent 69 and 62 per cent increases over the average capital expenditure in 2001-05 and their average operating and maintenance expenditure in 2001-05 respectively.. October 06 6 Essential Services Commission, Victoria Final Decision The Commission’s task of reconciling this seemingly inconsistent combination of historical expenditure requirements and projected expenditure has been far from straightforward. At one end of the spectrum, the distributors’ proposals might be characterised as ‘ambit claims’ in what they take to be a process of negotiation. In this case, an important priority for the Commission is to protect the interests of customers who would otherwise bear the cost of excessive expenditure proposals. At the other end of the spectrum, the distributors may well have identified opportunities where capital expenditure scheduled for the last period was efficiently deferred, but now needs to be undertaken in the coming regulatory period. Reconciliation of these two extremes has been a key challenge for the Commission in reaching its Final Decision. In its Draft Decision the Commission adopted forward looking capital and operating expenditure forecasts that, at an industry aggregate level, represented real increases in capital and operating and maintenance expenditure of around 5 and 22 per cent respectively6 over the level of expenditure for the 2001-05 period. These increases reflected the impact of a number of step changes in operating and maintenance expenditure to account for new or changed functions and regulatory obligations, and increases in the capital expenditure forecasts reflecting the priority accorded by the distributors and the Commission to investing in network renewal, capacity augmentation to meet peak load growth and to comply with regulations regarding electrical safety. Since releasing its Draft Decision the Commission has had regard to further information provided by the distributors and other stakeholders and the advice that it has received from its technical consultants in relation to the distributors’ expenditure requirements for the 2006-10 regulatory period. As a result of this the Commission has revised its position with respect to a number of assumptions underpinning capital and operating cost forecasts as outlined in the following sections. Capital expenditure forecasts The Commission has adopted forward looking capital expenditure forecasts that, at an industry aggregate level, represent a real increase in capital investment of around 30 per cent over the level of expenditure for the 2001-05 period (see Figure A.3).7 This increase reflects the information before the Commission that indicates that there are reasons why future investment will need to be undertaken at greater than historic levels, for example the ageing of assets, growth in peak demand and improved compliance with safety obligations. The Commission has recognised that the allowance is less than the allowance claimed to be required by the distributors, and the recommendations from its technical consultants. However, the Commission is satisfied that taking into account the incentives at the time of a price review to over-state expenditure requirements and then within the regulatory period to minimise expenditure this allowance is sufficient for the obligations of the distributors with regard to service provision and safety. Further, the Commission has taken into account the removal of the efficiency carryover mechanism which has reduced the cost to the distributors of undertaking investment where required and the significant increase in the rewards where investment delivers reliability and customer service improvements. 6 7 Excluding metering expenditure. When expenditure for metering is included, this increases to 43 per cent, at an industry level. October 06 7 Essential Services Commission, Victoria Final Decision Figure A.3: Total gross capital expenditure, industry aggregate, out-turn capital expenditure 2001-04a and Final Decision 2006-10, $million, real $2004 900 800 700 600 500 $M 400 300 200 100 0 1996 1997 1998 1999 Actual capex (inc meters) a 2000 2001 2002 2003 2004 Commission Final Decision CAPEX (ex meters) 2005 2006 2007 2008 2009 2010 Commission Final Decision CAPEX (inc meters) Out-turn gross capital expenditure includes prescribed distribution use of system and metering costs Operating and maintenance expenditure forecasts The Commission has adopted forward looking operating and maintenance expenditure forecasts that, at an industry aggregate level, represent a real increase in operating and maintenance expenditure of around 21 per cent8 over the normalised level of expenditure undertaken during the 2001-05 period (see Figure A.4).9 This increase reflects the impact of a number of step changes (due to new or changed functions or regulatory obligations) after making adjustments for matters such as provisions, changes in capitalisation policies and contractual arrangements reported during the 2001-04 period. Increases in labour costs reflecting recognised skills shortages and the cost associated with growth have also been reflected in operating and maintenance forecasts. The Commission is satisfied that, although these expenditure forecasts are less than the distributors proposed, they nevertheless provide adequately for future operating needs, and take account of relevant changes in the safety standards to which the industry must work, as well as the continuing need to train apprentices. 8 9 Excluding metering expenditure This calculation assumes that 2005 operating and maintenance expenditure is consistent with the Commission’s Final Decision. October 06 8 Essential Services Commission, Victoria Final Decision Figure A.4: Total operating and maintenance expenditure,a industry aggregate, outturn operating and maintenance expenditure 2001-04 and Commission Final Decision 2006-10, $million, real $2004 600 500 400 $M 300 200 100 0 2001 2002 2003 2004 2005 2006 Commission Final Decision a 2007 2008 2009 2010 Actual opex Exclusive of operating and maintenance expenditure associated with prescribed metering services. Forecast revenue requirement In addition to the operating and capital expenditure forecasts established, the building blocks approach adopted for this price review includes allowances for: • return on capital, comprising a market-based estimate of the weighted average cost of capital applied to a regulatory asset base that incorporates new net capital expenditure less allowed depreciation and disposals over the previous regulatory period; • an efficiency carryover allowance that extends the reward for out-performance against the capital and operating expenditure benchmarks established at the last review; and • depreciation and corporate taxation payments. To determine the return on capital component of the revenue requirement, the Commission has applied a real after-tax weighted average cost of capital of 5.9 per cent to the rolled forward values of the regulatory asset base. The change in the weighted average cost of capital from that used in the last price review is due principally to the decline in long term real interest rates which, for ten year CPI-linked Commonwealth government bonds, from 3.5 to 2.64 per cent.10 The building blocks described above have then been aggregated to establish forecast revenue requirements for each of the distributors over the five year period of this review. These revenue requirements are set out in Table A.1. From 1 January 2006, prescribed metering services will be regulated under a separate price control mechanism from distribution use of system services. In this Decision, the Commission has determined a separate revenue requirement and price control for the regulation of these services which includes the expenditure associated with rolling out 10 These rates are based on the last 20 trading days to 31 July 2005. October 06 9 Essential Services Commission, Victoria Final Decision interval meters. This revenue requirement has been developed using the Commission’s building blocks approach and is then translated into a set of prescribed metering charges using forecasts of growth over the period. Table A.1: Building blocks revenue requirement, 2006-10, $million, real $2004 Distributor AGLE 2006 2007 2008 2009 2010 129.7 123.2 127.3 135.0 132.5 5.1 6.9 8.7 10.6 12.3 Total 134.8 130.1 136.0 145.6 144.8 DUoS 182.7 171.3 160.1 161.1 169.4 4.6 7.2 9.7 11.6 13.4 Total 187.2 178.5 169.8 172.6 182.8 DUoS 320.0 326.0 331.7 340.2 348.0 Metering 14.3 18.8 24.5 29.9 35.1 Total 334.3 344.8 356.1 370.1 383.1 DUoS 289.7 279.5 290.8 289.3 307.6 Metering 18.0 20.5 25.6 30.2 34.6 Total 307.7 300.1 316.4 319.4 342.2 DUoS 271.7 251.9 257.0 243.5 230.2 7.9 10.5 14.5 18.0 20.9 279.6 262.5 271.5 261.5 251.2 DUoS Metering CitiPower Metering Powercor SP AusNet United Energy Metering Total Looking ahead, the experience from the 2001-05 regulatory period highlights the difficulties in distinguishing enduring efficiency gains in implementing capital expenditure programs (such as would arise from establishing more efficient capital expenditure project management arrangements) from temporary efficiency gains (such as arise from the deferral of planned expenditure that does not threaten service performance). For the 2006-10 regulatory period, the Commission has removed the additional payment for capital expenditure efficiencies although the efficiency carryover mechanism will continue with respect to operating and maintenance expenditure. One ancillary benefit of this change is that any network investment required in addition to the forecast will not attract a penalty. When combined with the revised service incentive scheme, the Commission expects that the distributors will actively pursue further capital investment where this delivers improvements in services. Real price reductions The revenue requirements outlined earlier have been developed having regard to forecasts of growth in customer numbers, peak demand and energy delivered so as to develop a set of price controls that, when applied to existing prices, will deliver expected revenue over the following five years that is equal in net present value terms to the revenue requirement determined by the Commission. October 06 10 Essential Services Commission, Victoria Final Decision The combination of favourable capital market conditions, efficiencies achieved in the current period, and the expectation of growth in customer numbers and energy delivered means that these revenues can be recovered at prices lower than those applying in the current period. The benefits that flowed to the distributors over the current period are being returned to customers to ensure that customers share in the benefits of these efficiency gains as intended by the Commission’s regulatory framework and as is required by the Tariff Order’s requirements for a fair sharing of efficiency gains. These price reductions will manifest through initial larger reductions followed by ongoing smaller real reductions as set out in Table A.2. Table A.2: P0 and X-factors — prescribed services, 2006-10, per cent Prescribed services (DUoS and Metering) Prescribed services (DUoS) P0 X1-X4 P0 X1-X4 AGLE 3.1 1.2 3.8 2.5 CitiPower 7.7 1.5 8.7 2.5 Powercor 16.4 1.1 17.3 2.5 SP AusNet 7.8 0.8 9.3 2.5 United Energy 15.6 1.4 14.7 2.5 Consultation process The Commission has engaged in an extensive process of consultation with distributors, customer groups and other industry stakeholders in reaching this Final Decision. It has also sought expert advice on the forecasting of demand, on the review of the distributors’ expenditure proposals, and on a range of economic and legal issues more generally. In summary, the process has involved: • consultation on the framework and approach for the review, over an extended period beginning in March 2004; • the submission by distributors of comprehensive price-service proposals in October 2004; • several consultation papers and workshops; • the review by independent consultants of the distributors’ growth forecasts and expenditure proposals; • numerous requests for further clarifying information; • the publication in March 2005 of a Position Paper which set out the Commission’s preliminary thinking on a range of key issues for the review and submissions from stakeholders to the Position Paper; • the Draft Decision and extensive submissions by the distributors and other stakeholders in relation to the Draft Decision; and • this Determination. October 06 11 Essential Services Commission, Victoria Final Decision Issues arising from the review Whilst there has been a marked improvement in the service performance of electricity distributors since the industry was restructured in 1995, the role of economic regulation in guiding further improvements has never been more important. The privatisation of an industry that displays monopoly characteristics will often give rise to tensions between a firm seeking to maximise returns to shareholders and the expectations and objectives of customers. The task of economic regulation is therefore to design incentives that align the commercial interests of the distributors with the interests of society at large, namely securing a reliable supply at an optimal price and quality. However, regulators must overcome a number of not insubstantial hurdles when implementing effective regulatory controls. The most notable of these relates to the information asymmetry that exists between the regulator and the utility. The combination of the reliance on the information provided by the utility and a focus on shareholder value means that utilities have a clear incentive to “talk up” the future operating cost and investment requirements of their networks and to “talk down” their future sales potential, in order to secure more generous price controls. Designing and managing regulatory processes that recognise these incentives and address the asymmetry of information is a well recognised and fundamental challenge for monopoly infrastructure regulators. The regulatory controls that were introduced by the Office of the Regulator-General in 2001 were specifically designed to address these hurdles. The implementation of a building block revenue requirement along with an efficiency carryover mechanism was designed to provide distributors with an incentive to reveal their efficient costs over the course of the first regulatory period. The central proposition of the framework was that under-spending against the expenditure benchmarks would be rewarded equally irrespective of the year in which the under-spending occurred. Under this framework it was assumed that the distributors would have a reduced incentive to defer efficiency improvements or allow expenditure to increase towards the end of one regulatory period so as to obtain more generous expenditure forecasts in the following regulatory period. Given this, it was expected that revealed costs from the first regulatory period could be given greater weight in establishing efficient expenditure forecasts for the next regulatory period. In hindsight the Commission underestimated the challenges that would present themselves in relying on the reported costs of the distribution businesses. One of the main factors complicating the Commission’s task has been the considerable restructuring of the distribution businesses since the implementation of the current price controls, including arrangements entered into by the distributors with entities with common ownership that are not directly covered by the regulatory regime. In the period since the last review, many of the distributors have entered into or extended existing arrangements under which other parties provide services to the legal entity responsible for distribution services under the Distribution Licence. Where there is an incentive to enter into an arrangement that is not arm’s length, the potential effect of such arrangements is to inflate or obscure the reported costs of the distributor. Outsourcing arrangements, multi jurisdictional operations and other integrated organisational arrangements have accentuated the challenges with respect to obtaining transparent cost data and unravelling complex and changing cost allocations. This has raised issues in reconciling October 06 12 Essential Services Commission, Victoria Final Decision historic information with current forecasts and therefore the ability to determine reasonable forecasts and the efficiencies to be shared with customers. Throughout the price review the Commission faced considerable difficulties with obtaining information to enable a proper assessment to be made of the costs incurred in providing distribution services. In some instances the difficulties were confined to delays, whilst in others the information was withheld entirely. In one instance, where information was not voluntarily provided by a significant service provider to a licensed distributor, the Commission issued notices under section 37 of the Essential Services Act 2001. The notices were subsequently appealed on the grounds that they were not made in accordance with the law and were unreasonable. The Appeal Panel upheld the appeal in part on the basis that the period of time within which the service provider was required to provide the documents and information specified in the notices was not sufficiently long. This was in spite of the fact that the information had been sought over a long period of time. Although the Appeal has highlighted aspects of the law which will require clarification, and some procedural improvements which will need to be made in relation to the issue of section 37 notices, the Appeal Panel clearly accepted that the Commission could serve such a notice on parties other than regulated distributors and that the Commission did have the power to obtain the details of industry costs from sub contractors. The entry by distributors into outsourcing arrangements, particularly where those outsourcing arrangements have not or are not capable of being appropriately market-tested, and the regulatory treatment of such outsourcing arrangements, is an issue that has been the subject of much consideration by the Commission. In this, the Commission is not alone — regulators in other industries and jurisdictions face similar challenges. However, it is critical to the integrity of the regulatory framework that regulators are able to investigate these arrangements and ensure that their existence does not prejudice the delivery of the benefits to customers under the regulatory framework. As a result of the difficulty that the Commission has had in obtaining information on the costs of providing distribution services from at least some of the distributors, the Commission has been forced to either directly estimate relevant out-turn costs or make a number of adjustments to the information reported to derive their relevant costs for the 2001-04 period. The necessity for such adjustments arises in the context of all forms of monopoly regulation that rely on business-specific cost information, because of the associated incentive to report or represent costs as being greater than they are. This is particularly the case where the benefits of efficiencies are required to be shared between distributors and customers, in which case there is a greater incentive for a distributor to enter into arrangements or adopt practices that distort the sharing of the benefits. Whilst the Commission is satisfied that the expenditure allowances which it has made are more than sufficient for the distributors to meet their obligations and future investment needs, the Commission notes that an approach that relies on adjustments to reported expenditure may not be sustainable over the longer term. Looking ahead An important backdrop to this review is the planned transfer of responsibility for rule making and for regulation of energy distribution businesses to the new national framework for October 06 13 Essential Services Commission, Victoria Final Decision regulation of energy markets, administered by the Australian Energy Market Commission (AEMC) and the Australian Energy Regulator (AER). Although the detailed transition path is still to be finalised, the working presumption is that the price controls applying to Victorian electricity distributors from 2011 will be determined by the AER, under a framework of rules to be reviewed and implemented by the AEMC. It is inevitable that this framework will involve some change to the legal and regulatory environment that governs this review. The Commission believes it important to note that its approach to this review has not been altered by the prospect of change that the new national framework involves. Rather, the Commission has approached this review, first, by applying the existing legal framework as it best sees fit and, second, by articulating the principles it has applied and the facts it has considered as clearly as possible. In the Commission’s view, this not only represents good regulatory practice, but it also means that, once the transfer of responsibilities does take place, it will be relatively easy for the AER to understand what was done and why, and for the appropriate transition arrangements to be put in place. Over the past year or more, the Commission has also sought to invigorate debate on the potential for greater use of index-based approaches to regulating monopoly services, including electricity distribution. The Commission’s principal motivation for this work is to seek refinements that can improve both the process and the incentives arising in the conduct of regulatory reviews. The Commission is particularly interested in regulatory approaches that either reduce or eliminate the role of forecasts in regulatory reviews as well as the role played by company specific reported costs in determining efficiency outcomes, both of which give rise to regulatory burdens and distorted incentives. To this end the Commission has published a major report investigating and comparing the incentive power of alternative regulatory regimes (PEG 2005b). The combination of positive stakeholder responses, conclusions from the incentive power work and the continuing challenge of determining forward looking building blocks in the face of strong information asymmetries, has strengthened the Commission’s resolve to make progress in this area. The Commission recognises that further work and consultation is essential to ensure that an indexed-based approach to regulation can be established as a viable option for determining price controls from 2011. Irrespective of which regulatory body is responsible for taking forward the regulation of Victorian and other electricity distributors, it will remain an inescapable challenge for the economic regulation of long lived infrastructure assets to provide the optimum incentives for efficient asset management and investment while also delivering appropriate price-service outcomes for customers. Although there is considerable debate over how company specific cost data is used in regulation the ability for a regulator to have access to, and rely on, reliable, consistent and robust information on the provision of regulated services is critical to the effective implementation of all forms of regulation, including indexing and price monitoring. October 06 14 Essential Services Commission, Victoria Final Decision 1 INTRODUCTION This is the second review of the electricity distribution price controls to apply to the five Victorian distributors undertaken by an independent regulator. The first review was undertaken by the Office of the Regulator-General (the Commission’s predecessor) in 2000 for the 2001-05 regulatory period. The initial price controls and related arrangements for the 1995-2000 regulatory period were established by the Victorian Government in the context of restructuring and privatising the electricity distribution industry in the mid-1990s. This review has provided an opportunity for Victorian customers to consider their servicerelated requirements and the prices that they are willing to pay for those services. It has also provided an opportunity for the Commission and stakeholders to review the current regulatory approach and identify areas that could be improved based on the experience to date. The Commission has undertaken extensive consultation with stakeholders and information gathering and analysis in reaching this Determination.11 Consultation began in March 2004 and has taken the form of consultation papers, workshops, public information sessions in Melbourne and regional centres and submissions from the distributors and other stakeholders. A Draft Decision was released in June 2005 that provided stakeholders with the opportunity to comment on the Commission’s views before it made its Determination. Advice has also been obtained from technical consultants. The Commission sought feedback on the services and service levels Victorian customers are receiving and considered opportunities to further improve the regulatory arrangements to ensure that they provide balanced incentives for distributors to deliver services at least long term cost. This Determination sets out the price controls to apply for the use of the electricity distribution system and to prescribed metering services over the period from 1 January 2006 to 31 December 2010. It also sets out the service levels that the distributors will be required to deliver over the period. 1.1 Legislative framework The Commission has undertaken this price review in an environment of change. The Council of Australian Governments (COAG) is currently working towards national regulation of the electricity industry. Once this national regulatory framework and the institutions to administer it have been agreed and established, it is intended that State Governments will transfer responsibility for the regulation of electricity distribution services to a new energy regulatory body — the Australian Energy Regulator (AER). This means that the Commission is unlikely to undertake the next review of the electricity distribution price controls. 11 The Determination comprises Final Decision Volume 1 — Statement of Purpose and Reasons and Final Decision Volume 2 — Price Determination October 06 15 Essential Services Commission, Victoria Final Decision While the Commission has been conscious of the changes that are occurring, it has been required to undertake this price review under the current Victorian statutory framework for the regulation of the electricity distribution businesses. The legal framework that has guided the 2006 price review includes the Essential Services Commission Act 2001, the Electricity Industry Act 2000 and the Tariff Order. In making its Determination, the Commission has had regard to the objectives specified by this legal framework and has made its Determination in accordance with this legal framework. The Essential Services Commission Act sets out the objectives of the Commission in performing its functions and exercising its powers. It also sets out the powers the Commission has in relation to the regulation of electricity distribution charges, the matters it must have regard to and requirements with which the Commission must comply in making a Determination that regulates such charges.12 The Commission’s primary objective is to protect the long term interests of Victorian consumers with regard to the price, quality and reliability of essential services. This includes services provided by the electricity distribution industry. In seeking to achieve this primary objective, the Act requires the Commission to have regard to the following facilitating objectives: • to facilitate efficiency in regulated industries and the incentive for efficient long-term investment; • to facilitate the financial viability of regulated industries; • to ensure that the misuse of monopoly or non-transitory market power is prevented; • to facilitate effective competition and promote competitive market conduct; • to ensure that regulatory decision making has regard to the relevant health, safety, environmental and social legislation applying to the regulated industry; • to ensure that users and consumers (including low-income or vulnerable customers) benefit from the gains from competition and efficiency; and • to promote consistency in regulation between States and on a national basis. In addition, the Electricity Industry Act requires the Commission to promote: • a consistent regulatory approach between the electricity and gas industries; and • the development of full retail competition. Apart from these two Acts, the other principal statutory instrument that has guided the Commission in this review is the Tariff Order issued under the Electricity Industry Act. Clause 2.1 of the Tariff Order requires the Commission to utilise price based regulation adopting a CPI-X approach, and not rate of return regulation. Other elements of clause 2.1 require the Commission to have regard to the need to: • 12 provide each distributor with incentives to operate efficiently; Essential Services Commission Act 2001, s. 8, 14, 30, 32, 33 and 35 October 06 16 Essential Services Commission, Victoria Final Decision • ensure a fair sharing of the benefits achieved through efficiency gains between customers and the distributors; • ensure appropriate incentives for capital expenditure and maintenance in the distributors’ distribution systems; and • have regard to the level of executive remuneration in each distributor by reference to any relevant interstate and international benchmarks for such remuneration. Clause 2.1 also specifies the manner in which the Commission is to value the distributors’ fixed assets, which were in existence as at 1 July 1994, and requires the Commission to adopt a regulatory period of no less than 5 years. Clause 2.2 of the Tariff Order is also particularly relevant to this price review. It specifies the criteria to be applied by the Commission in determining, and the manner for determining, whether a distribution service is an excluded service. An excluded service is a service the charge for which is excluded from the price controls. The terms and charges for these services are regulated by the Commission in accordance with the distributors’ distribution services. The Commission is expressly required to adopt an approach and methodology in regulating prices which the Commission considers will best meet its statutory objectives referred to above.13 However, within these constraints, the Commission is empowered to regulate the relevant prices in any manner it considers appropriate.14 Within its legal framework, the Commission has broad discretion in determining the regulatory approach adopted. As the Victorian Supreme Court stated with respect to the Office of the Regulator-General in TXU Electricity v Office of the Regulator-General:15 The wording of cl.5.10,16 the purposes of the legislation and the objectives of the Office set out in the legislation, together with any relevant matters found in s.25(4)17 which were not inconsistent with the Tariff Order, establish that the task left to the Office involved the Office making its own decision with respect to the most appropriate methodology to achieve the incentive objectives of the price fixing exercise. This involved the Office making its own investigations of material that it could, and making its own judgment as to relevant factors, the methodology used and the weight that should be attached to the various relevant factors. The task was entrusted by Parliament to the Office. … In the final analysis, it was a matter for the Office to investigate and obtain what information it could, relevant to its assessment, to select relevant matters to take into account and to determine the proper methodology. The choice of techniques for estimation and analysis, and the utility of certain matters that should be taken into 13 14 15 16 17 Essential Services Commission Act 2001, s. 33(2) Essential Services Commission Act 2001, s. 33(5)&(6) [2001] VSC 153, at par.314, 315 & 317 The equivalent provision of clause 5.10 in the old Tariff Order is now clause 2.1 in the new Tariff Order. The equivalent provision of s. 25(4) of the Office of the Regulator-General Act 2004 is now s. 33(3) of the Essential Services Commission Act 2001. October 06 17 Essential Services Commission, Victoria Final Decision account were all properly left, in my view, to the expert discretion of the Office. The Office employed and engaged consultants in the fields of price regulation and economics, and the Parliament and the framers of the Tariff Order intended that these matters should all be left to the good judgment of the Office. In this price review, as it did in the last price review, the Commission has consulted widely with stakeholders in developing its framework and approach and in making this Determination. Having given detailed consideration to the submissions, feedback and information received from stakeholders and the requirements under its legislative framework, the Commission has made its Determination. In doing so, the Commission has exercised the discretion allowed to it under its legal framework, while also complying with the objectives and requirements of this framework. 1.2 The Commission’s consultation process The Commission began consultation on the 2006-10 Electricity Distribution Price Review in March 2004 with the release of Consultation Paper No. 1: Framework and Approach. In this paper, the Commission indicated its intention to follow a consultation process that was open and transparent and provided stakeholders with sufficient opportunity to present their views. To achieve this aim, the Commission indicated that it would consult widely and ensure all interested stakeholders had access to sufficient information on the process being followed and the issues being considered (ESC 2004b, p. 4-5). The Commission has undertaken extensive consultation and analysis, including: • The release of Consultation Paper No. 1 which set out for comment the proposed framework for, and approach to, reviewing the existing price controls and establishing a new set of price controls for the regulatory period commencing 1 January 2006. • A series of public information sessions held in Melbourne and several regional centres to communicate the commencement of the price review and the content of Consultation Paper No. 1 to Victorian stakeholders (March-April 2004). • Further consultation papers, discussion papers, open letters and workshops on: • y the service incentive arrangements (papers in April 2004 and August 2005 and workshops in May 2004 and July 2005); y excluded services (paper and workshop in May 2004); y the efficiency carryover mechanism (workshop in June 2004); y metering issues (paper in June 2004 and workshops in June 2004 and July 2005); y pricing issues (discussion papers in May, July and September 2004 and workshops in June, July, August, September and November 2004 and March 2005); and y expenditure issues (open letter and workshop in July 2005). The release of Final Framework and Approach: Volume 1, Guidance Paper in June 2004. This set out the framework and approach that the Commission would follow in making its decision on the price controls. Together with Final Framework and Approach: Volume 2, Information Templates, Volume 1 also provided guidance to the distributors for the preparation of their price-service proposals. October 06 18 Essential Services Commission, Victoria Final Decision • The release of a Summary of the Victorian Electricity Distributors’ Price-Service Proposals to provide a broad overview of the distributors’ price-service proposals and assist stakeholders to understand the content of these documents (November 2004). • The release of an Issues Paper which raised several major issues arising from the Commission’s initial analysis of the distributors’ price-service proposals (December 2004). • The release of a Position Paper that aimed to provide an earlier opportunity to respond to the Commission’s preliminary views in advance of its Draft Decision (March 2005). • The release of a Draft Decision that provided an opportunity for stakeholders to comment and discuss the Commission’s views before the final determination (June 2005). • Further public information sessions in Melbourne and regional centres to communicate the Commission’s Issues Paper, Position Paper and Draft Decision to stakeholders and provide an opportunity for stakeholders to discuss the issues raised and the Commission’s preliminary views (December 2004, April 2005 and June 2005). The Commission’s consultation process, including the publications released, submissions received and public forums and workshops held, is set out in further detail in Appendix A. The appendix also lists the technical consultancy advice that the Commission has received. 1.3 The Commission’s broad framework and approach In Consultation Paper No. 1, the Commission indicated that it proposed to adopt a framework and approach for the 2006 price review that was similar to that used in the 2001 price review, while also enhancing and refining it where this was considered appropriate based on experience to date (ESC 2004b, p. 8). As required by the Victorian Tariff Order, the Commission has maintained a CPI-X approach to the 2006-10 regulatory period and has utilised the ‘building blocks’ approach (with an efficiency carryover mechanism) to determine the forward-looking revenue requirements for each distributor. The building blocks approach is characterised in Box 1.1. In making this Determination, the Commission has used as its starting point reported (adjusted) out-turn information on expenditure, financing requirements, service performance, energy consumption, customer numbers and peak demand growth for the current period. With the performance over the current period as a starting point, the onus has been on the distributors to provide sufficient supporting information on why their forecasts for the 2006-10 regulatory period of costs, growth and/or service performance should vary from those achieved over the current period. Such justifications may include, for example, any changes in obligations or functions that would cause costs to change over the next period and evidence of customers’ willingness to pay for any proposed improvements in service performance. October 06 19 Essential Services Commission, Victoria Final Decision Box 1.1: Building blocks approach to setting the price controls The building blocks approach can be characterised by three steps — determining outputs/outcomes; determining the revenue requirement necessary to finance these output/outcomes; and translating the revenue requirement into a price control that would permit recovery of the required revenue. Step 1: Determining outputs/outcomes The first step to determining the price controls is to decide upon the service outcomes that the distributors are required to deliver over the period. These outcomes will reflect the service standards that are set as part of this price review (see Chapter 2) as well as legislative and functional obligations that the distributors must meet in accordance with licensing or legislative requirements. In setting these service outcomes, it is also necessary to consider anticipated future peak demand and customer numbers (see Chapter 4). October 06 20 Essential Services Commission, Victoria Final Decision Box 1.1 (cont.): Building blocks approach to setting the price controls Step 2: Determining the revenue required Having determined the outcomes that must be delivered, the revenue requirements are then determined that are sufficient to enable the distributors to deliver these outcomes efficiently. The building blocks approach involves building up the distributors’ revenue from key components that reflect their operating and maintenance costs (Chapter 6) and financing requirements (Chapter 9). The distributors’ financing costs (return on and of capital) are built up with reference to the rolled forward value of their regulatory asset bases (Chapter 8) and the capital expenditure that they must undertake (Chapter 7). The Commission’s approach also incorporates an efficiency carryover amount into the revenue requirement that allows the distributors to carry over benefits of any efficiency gains achieved against the expenditure forecasts in the prior regulatory period into the next regulatory period (Chapter 10). Step 3: Translating the revenue requirement into a price control Having determined the revenue required (Chapter 11), it is then translated into unit prices using forecasts of energy consumption and customer numbers (Chapter 4). This is then translated into specific tariff proposals in accordance with a price control mechanism which specifies how prices will be adjusted annually (Chapter 12). Relying on actual costs incurred in providing distribution services as the Commission’s starting point for assessing the distributors’ proposed changes to expenditure going forward requires an accurate record of the costs incurred in carrying out each distributor’s functions presented on a basis that is consistent with the 2001-05 building blocks benchmarks and the distributors’ expenditure proposals for the 2006-10 regulatory period. For the purposes of this price review, the Commission has made adjustments to the expenditure reported by the distributors to ensure that current costs and future estimates are presented on a ‘like-for-like’ basis which permits valid comparisons. The Commission’s framework and approach for determining the distributors’ growth forecasts had anticipated that it could rely on the distributors obtaining independent verification that their forecasts, assumptions, key input data and forecasting methods are reasonable and that the forecasting method had been applied appropriately. However, in the course of the price review, the Commission identified a number of issues with the distributors’ growth forecasts that led it to undertake a more detailed review. These issues included apparent inconsistencies in the assumptions used and between forecast and historic data. For metering, the Commission’s framework and approach indicated that standard metering services for small customers (those who consume less than 160 MWh per annum and do not have a remotely read meter) would be regulated as prescribed services, with the charges for these services set separately to distribution use of system charges. The framework and approach also stated that the Commission would build up a revenue requirement for prescribed metering services under an approach similar to that used for prescribed distribution use of system services. Metering services for customers who consume more than 160MWh per annum or have a remotely read interval meter installed will be regulated by the Commission as an excluded service. The Commission has maintained its current approach to the regulation of excluded service charges, although it has set out more detailed information requirements and clarified the policies and definition of each excluded service charge. October 06 21 Essential Services Commission, Victoria Final Decision 1.4 Structure of the Decision This volume is structured in four parts. Part A provides an Overview of the decision and Part B provides the Commission’s decision on prescribed distribution services — both distribution use of system (DUoS) and metering services. • Part B1 sets out the Commission’s decision on service standards (Chapter 2), the service incentive arrangements (Chapter 3) and growth forecasts (Chapter 4). • Part B2 sets out the decision on the components of the distribution use of system (DUoS) revenue requirement: y relevant costs (Chapter 5); y operating and maintenance expenditure (Chapter 6); y capital expenditure (Chapter 7); y the value of the regulatory asset base (Chapter 8); y cost of capital financing requirements (Chapter 9); and y the efficiency carryover mechanism (Chapter 10). • Part B3 sets out the decision on the revenue requirements (including P0s and X-factors) for each distributor and the price control arrangements applying to DUoS. • Part B4 sets out the Commission’s decision on prescribed metering services. Part C discusses the Commission’s decision on the arrangements applying to excluded services and Part D provides a summary of the Commission’s decision by distributor. October 06 22 Essential Services Commission, Victoria Final Decision PART B1: SERVICES PROVIDED AND ENERGY DELIVERED In this Part, the Commission sets out its Final Decision and reasons on the targeted levels for the service reliability, quality of supply and customer service measures, the distributors’ reporting requirements, the service incentive arrangements and the growth forecasts that underpin the Final Decision on the revenue requirements for each distributor. The revenue requirements and X-factors set out in this Final Decision have been established with reference to a set of targeted levels of service that each distributor is expected to achieve over the period. The Commission sets targeted levels to ensure that any reductions in expenditure that distributors achieve over the period are not achieved to the detriment of the standards of service that they provide. The distributors are held accountable for their performance through monitoring and publicly reporting on their performance against the targeted levels as well as through the financial incentive arrangements that the Office of the Regulator-General (ORG) set in place at the last price review. Under the S-factor scheme, the distributors have been financially rewarded or penalised for their relative service reliability performance through an adjustment to the price control mechanism. That is, distributors can earn more (or less) revenue by improving (or reducing) their service performance. The ORG also set in place a Guaranteed Service Level (GSL) payments scheme that aimed to ensure that individual customers, particularly worst-served customers, received a minimum level of service reliability. Under the GSL payments scheme, the distributor is required to make automatic payments to customers who receive a level of service reliability that is worse than a pre-determined threshold. Average reliability levels In the 2001-05 price review, the ORG decided upon service reliability targets that anticipated improvements in the average reliability of supply over the 2001-05 regulatory period. At the time, the ORG (2000a, p. 14) concluded after extensive consultation that customers valued improvements in reliability. Expenditure amounts were incorporated into the revenue requirements to achieve those improvements. With the exception of SP AusNet,18 the distributors have improved their service reliability performance over the period and, in a number of cases, are outperforming the average reliability targets while also improving the level of service reliability to worst-served customers. As a result, the distributors have earned additional revenues through the S-factor scheme and paid out fewer GSL payments to worst-served customers than was anticipated at the last price review. Conversely, SP AusNet has been financially penalised for its performance through lower revenues. While in this price review customers have emphasised the importance that they place on a reliable electricity supply, the Commission has received little indication that customers value further improvements in average reliability levels. 18 Formerly TXU October 06 23 Essential Services Commission, Victoria Final Decision Consequently, for reporting and monitoring purposes, the Commission has set the targeted levels of service for the 2006-10 regulatory period equal to the 2005 targets, except where a distributor is consistently outperforming this target. In this case, the current level of performance is considered in deciding the new targeted level. This means that, unlike in the last price review, no allowance is being made in the expenditure forecasts for further improvements in average reliability levels. Rather, any further improvements will be funded through the S-factor scheme after the improvement in reliability has been delivered. For the purposes of the S-factor scheme, the reliability targets are the same as the 2005 targets which ensures that distributors are not rewarded for improvements already achieved and already paid for by their customers. That is, they will only receive additional revenue for improvements when further improvements in outcomes are delivered and customers receive the service they then pay for. Worst-served customers, quality of supply and customer service Despite general satisfaction with current average reliability levels, customers have indicated that pockets of poor reliability remain and that quality of supply and customer service have both become increasingly important. The Commission received feedback from customers situated in heavily wooded areas such as Lavers Hill and the Mt Dandenong region that suggests that current reliability levels in these areas are not sufficient. For other customers, the voltage that they receive is either insufficient for their equipment to operate effectively or is too high, thereby causing damage to their equipment. In public information sessions, customers also indicated their dissatisfaction with the performance of call centres and the quality of information that is provided by these call centres. The Commission has addressed these concerns in its Final Decision by expanding the range of measures and targets against which the distributors are required to publicly report. Distributors must continue to report upon their performance against the service reliability targets but must now also report on the following: • The annual duration of interruptions (planned and unplanned) experienced by the 15 per cent of customers in their area that experience the longest time off supply in that year. • A breakdown of the causes of unplanned interruptions and the actions the distributor is proposing to undertake to improve its performance. • Low reliability feeders for which the average minutes off supply (for planned and unplanned interruptions) is above a threshold which is reduced relative to the existing threshold. • Low reliability feeders for which the frequency of momentary interruptions is above a threshold and zone substations and feeders which are not compliant with the standards as set out in the Electricity Distribution Code. • Where a zone substation (for quality) or feeder (for reliability or quality) is reported, the distributor will be required to provide comments regarding its plans for that zone substation or feeder. October 06 24 Essential Services Commission, Victoria Final Decision The Commission has also adjusted the thresholds at which the GSL payments scheme begins to operate, and increased the size of the required payments to customers. These adjustments aim to increase the incentive that distributors have to improve reliability to worst-served customers and to customers who are not worst-served but who receive a level of supply reliability less than the average. An improvement in reliability to those receiving less than the average level of reliability may also improve a distributor’s performance against the average reliability targets. Hence, distributors may have an additional incentive to improve reliability to those receiving less than the average because of the potential to earn an additional financial reward under the S-factor scheme. In its Final Decision, the Commission is requiring the distributors to continue to report against the quality of supply measures that they currently report against. The focus for the 2006-10 regulatory period is on providing an accurate picture of the quality of supply and improving compliance with the Electricity Distribution Code for all customers. The magnitude of the expenditure required to ensure all customers’ supply is compliant with the Code is such that the expenditure will span multiple regulatory periods. Distributors will therefore be required to prioritise their spending during the next regulatory period. While the Commission would prefer that quality of supply expenditure is linked financially to the achievement of outcomes, the minimal historical data available and the fact that the data that is available is only from a sample of points on some feeders may result in perverse outcomes where a financial incentive is applied. Accordingly the Commission has decided not to include quality of supply measures in either the S-factor scheme or the GSL payments scheme for the 2006-10 regulatory period. In this Final Decision, the Commission has also set targeted levels for the proportion of calls answered by a call centre within 30 seconds and the number of overload events occurring during the 2006-10 regulatory period. The distributors are required to publicly report against these levels on an annual basis and a call centre performance measure has been included in the S-factor scheme. Growth forecasts Forecasts of growth in customer numbers, energy consumption and peak demand are central to translating the revenue requirements into the average price changes implied by the CPI-X form of price control. They are also used in establishing estimates of load-related capital expenditure. The distributors have earned higher revenues over the current regulatory period than forecast by the ORG at the last price review due to higher than anticipated growth in customer numbers and energy consumption. This outcome has been compounded by the restructuring of tariffs in a manner that has caused revenue to be higher than forecast for any given volume growth, for example by increasing the variable component of tariff charges. The Commission has not accepted the forecasts of customer numbers and energy consumption submitted by the distributors. The distributors’ forecasts factor in assumptions on Victorian Gross State Product, energy conservation policies and downside risks to Victorian manufacturing activity that appear overly conservative when compared to other available sources of information. October 06 25 Essential Services Commission, Victoria Final Decision October 06 26 Essential Services Commission, Victoria Final Decision 2 SERVICE STANDARDS A key element of incentive-based regulation is to provide adequate incentives for distributors to achieve the level of service that is valued by customers. Mechanisms to ensure sufficient incentives exist for distributors to achieve service levels valued by customers, and for which they are accountable, are discussed in detail in this Chapter. Incentive-based regulation provides incentives for distributors to achieve efficiencies in the provision of services by allowing them to retain any savings in the cost of service provision for a period. To ensure that any reductions in expenditure are due to efficiencies and not a deteriorating level of service, the Commission and regulators in other jurisdictions have recognised the importance of clearly specifying service standards for the regulatory period, and monitoring and publicly reporting against the targeted levels, so that distributors are accountable for achieving those standards.19 Measures of service standards usually distinguish between those for reliability of supply, quality of supply and customer service. Whilst reliability of supply is concerned with the availability of supply, quality of supply is concerned with the characteristics of the electricity supply delivered to customers’ premises, specifically whether there are short term or transient voltage increases (voltage surges) or reductions (voltage sags) and harmonic distortions. Customer service relates to the distributors’ performance in meeting customer requirements such as responding to queries, providing information and meeting timelines. One of the key features of the Commission’s decision on the price controls to apply for the 2006-10 regulatory period is to ensure that customers receive the service that they pay for. This is to be achieved through identifying and measuring the level of service that is expected to be provided, and outlining clear reporting requirements, and by providing financial rewards and penalties for the service outcomes delivered. This Chapter provides the Commission’s decision on the service levels customers should receive and the reporting requirements in respect of those services. Reporting on the service delivered plays an important role in service provision. It provides: • information to customers on the distributors’ performance against the level of service that customers should expect; • a focus on the performance standards to be met; and • information to enable further service measures to be incorporated into the financial incentive arrangements over time. The Commission’s decision on service standards is set out in Section 2.1, while in Section 2.2 the reasons for the decision on service standards are set out. Reliability measures, quality of supply measures and customer service measures are discussed in Sections 2.2.1, 2.2.2 and 2.2.3 respectively. 19 Targeted levels are used as the basis for reporting purposes to monitor whether customers are getting the service they are paying for. Generally, distributors should be able to meet or exceed the targeted levels in most years. Targeted levels are different from the S-factor targets that apply to the service incentive mechanism described in Chapter 3. October 06 27 Essential Services Commission, Victoria Final Decision To encourage distributors to maintain and improve service provision, where efficient to do so, a service incentive mechanism has been provided. This is discussed in detail in Chapter 3. 2.1 Final Decision 2.1.1 Reliability measures The distributors will continue to report against the following average reliability measures, by network type: annual duration of unplanned interruptions (unplanned SAIDI), annual frequency of unplanned interruptions (unplanned SAIFI), annual duration of planned interruptions (planned SAIDI), annual frequency of planned interruptions (planned SAIFI) and frequency of momentary interruptions (MAIFI). MAIFI will continue to be defined as an interruption of duration less than one minute. The targeted level for each of these reliability measures during the 2006-10 regulatory period is provided in Table 2.1. The targeted levels do not incorporate any improvement in the average measures of reliability over the 2006-10 period. Rather, incentives to improve reliability are provided to distributors through the service incentive arrangements, through increased revenues when improved outcomes are delivered (see Chapter 3). Table 2.1: Annual targeted levels of reliability, by distributor, 2006-10 regulatory period Network Type AGLE CitiPower Powercor SP AusNeta United Energy a Annual targeted levels of reliability, 2006-10 Unplanned Planned interruptions interruptions SAIDI SAIFI SAIDI SAIFI MAIFI Urban 73 1.27 6.0 0.03 0.8 Short rural 113 2.25 14.0 0.08 2.6 CBD 14 0.25 5.9 0.02 0.03 Urban 35 0.80 9.9 0.03 0.3 Urban 98 1.63 16.0 0.09 1.5 Short rural 118 1.80 35.0 0.15 3.1 Long rural 297 3.30 70.0 0.25 9.0 Urban 109 1.82 16.0 0.09 3.5 Short rural 185 2.73 35.0 0.15 4.0 Long rural 300 4.28 70.0 0.30 10.8 Urban 59 1.06 16.0 0.10 1.4 Short rural 96 2.03 35.0 0.15 3.4 Formerly TXU The distributors will also report the annual minutes off supply (SAIDI for planned and unplanned interruptions) experienced by the 15 per cent of customers in their area experiencing the longest time off supply in that year. Table 2.2 sets out the targeted levels of SAIDI for the worst served 15 per cent against which the distributors are to report. October 06 28 Essential Services Commission, Victoria Final Decision Table 2.2: Targeted levels of reliability experienced by the worst served 15 per cent of customers Total minutes off supply (SAIDI) for worst served 15 per cent AGLE 267 CitiPower 138 Powercor 535 SP AusNet United Energy 734 231 Additionally, the distributors will provide a breakdown of the causes of unplanned interruptions on an annual basis into the following categories: • weather (for example, storms, rainfall, wind blown debris); • equipment failure; • operational error; • vegetation (for example, trees); • animals (for example, possums, birds); • third party impacts, including vehicle collisions, vandalism, dig-ins, bushfire, etc; • transmission failure; • load shedding; • inter distributor connection failure; and • other, which is to be clearly specified. The distributors must provide an explanation for any significant, adverse year on year changes, and identify any actions to address these changes. Distributors will continue to report, on an annual basis, low reliability feeders for which the average minutes off supply (for planned and unplanned interruptions) is above a threshold. The thresholds for reporting these feeders during the 2006-10 regulatory period are as set out in Table 2.3. October 06 29 Essential Services Commission, Victoria Final Decision Table 2.3: Network Type Thresholds for low reliability feeders, by network type, 2006-10 regulatory period Average annual minutes off supply (SAIDI) for planned and unplanned interruptions Momentary Interruptions (MAIFI) 70, where number of interruptions is greater than 1 n/a Urban 270 5 Short rural 600 12 Long rural 850 25 CBD Additionally, the distributors will report, on an annual basis, low reliability feeders for which the frequency of momentary interruptions is above a threshold. The thresholds for reporting low reliability feeders with respect to MAIFI are as set out in Table 2.3. Where a feeder is reported as a low reliability feeder, the distributor will be required to provide comments regarding its plans for that feeder. 2.1.2 Quality of supply measures The distributors will continue to report quality of supply against the following measures: • Number of over-voltage events – due to high voltage injection; • Number of customers receiving over-voltage – due to high voltage injection; • Number of over-voltage events – due to lightning; • Number of customers receiving over-voltage – due to lightning; • Number of over-voltage events – due to voltage regulation or other cause; • Number of customers receiving over-voltage – due to voltage regulation or other cause; • Number of voltage variations – steady state; • Number of voltage variations – one minute; and • Number of voltage variations – ten seconds. The number of voltage variations will be broken down and data provided as measured at the zone substation level, and as measured at the feeder level. Additionally, for the zone substation level only, a breakdown of ten second voltage variations will be provided based on the minimum voltage during that voltage variation (less than 70 per cent of nominal voltage, less than 80 per cent of nominal voltage and less than 90 per cent of nominal voltage). Given the level of non compliance with the quality of supply standards, as set out in the Electricity Distribution Code, by Powercor, SP AusNet20 and United Energy, reasonable expenditure has been provided to them to improve their compliance (refer Chapter 7). The cumulative numbers of customers of these distributors who are expected to receive an improvement in their quality of supply as a result of such improved compliance are provided 20 Formerly TXU Networks. October 06 30 Essential Services Commission, Victoria Final Decision in Table 2.4. The distributors will report on an annual basis the number of customers who have received an improvement in the quality of supply. Table 2.4: Improvement in quality of supply, cumulative number of affected customers, Powercor, SP AusNet and United Energy, 2006-10 regulatory period Year Powercor SP AusNet United Energy 2006 9,200 12,988 200 – 400 2007 22,800 27,600 400 – 800 2008 35,400 43,837 600 – 1,200 2009 2010 47,400 59,000 61,697 81,181 800 – 1,600 1,000 – 2,000 Additionally, United Energy will improve the quality of supply at one zone substation per annum. The rural distributors (Powercor and SP AusNet) will increase the number of voltage monitoring devices installed at the end of high voltage distribution feeders by 20 per cent by the end of 2006. A plan is to be provided to the Commission by 31 December 2005 explaining where and when the additional voltage monitoring devices are to be installed. These plans will be made available on the Commission’s website when received. Additionally, the distributors will report, on an annual basis, zone substations and feeders which are not compliant with the standards as set out in the Electricity Distribution Code. Where a zone substation or feeder is reported, the distributor will be required to provide comments regarding its plans for that zone substation or feeder. Residential and small business customers will continue to be entitled to compensation, on a like for like basis, for damage due to voltage variation (surges and brown outs). 2.1.3 Customer service measures Call centre performance Distributors will continue to report on the proportion of calls to their fault line answered within 30 seconds and the number of occasions where the fault line is overloaded. The calls to the fault line answered within 30 seconds will: • include telephone calls answered by an IVR (interactive voice response) within 30 seconds where the IVR provides substantive information and the customer does not request to be connected to an operator; and • include telephone calls abandoned by the customer within 30 seconds of the telephone call being queued for response by a human operator. Where the time in which a telephone call is abandoned is not measured, then an estimate of the number of calls abandoned within 30 seconds will be determined by taking 20 per cent of the total number of abandoned calls. Additionally, the total number of calls to the fault line excludes missed calls where the fault line is overloaded. October 06 31 Essential Services Commission, Victoria Final Decision Distributors will also report on the number of overload events that occur in their call centres each year. Where an overload event occurs, the distributor will provide an explanation of the events that lead to the overload event occurring. The targeted levels for the proportion of calls answered within 30 seconds and the number of overload events per year during the 2006-10 regulatory period are provided in Table 2.5. Table 2.5: Annual targeted level of call centre response, by distributor, 2006-10 regulatory period Proportion of calls to the fault line to be responded to within 30 seconds (per cent) Number of overload events AGLE 75 0 CitiPower 80 0 Powercor 81 0 SP AusNet 70 0 United Energy 72 0 Metering related measures The distributors will report against the following metering-related measures: • Number of interval meters installed during the year (by meter type); • Number of accumulation meters installed during the year (by meter type); • Number of scheduled meter reads; and • Number of reads estimated where meter is not read when scheduled. Other customer service measures The distributors will continue to report on the existing customer service measures for complaints, street light repairs, appointments, new connections and planned interruptions for which four days notice is not given. Where the Commission identifies additional relevant customer service measures through its existing end-to-end (E2E) project, these measures will be incorporated into the annual reporting by distributors. The Commission will work with distributors and retailers to develop a “report card” on the B2B capability and performance of the parties they interface with and, when completed, will provide such reports on a regular (six monthly) basis. 2.2 Reasons for the Decision 2.2.1 Reliability measures Reliability of supply is typically considered to be the most important characteristic of distribution services. In its simplest terms, reliability of supply concerns whether electricity is available when sought by a customer. Reliability measures typically focus on the extent of availability, or non-availability, of electricity to customers. October 06 32 Essential Services Commission, Victoria Final Decision Reliability was also a key focus of the 2001-05 price review. As a result, better reliability information is available in Victoria than in any other jurisdiction, and reliability has improved over the last four years. For the 2006-10 regulatory period, the Commission has reviewed whether the appropriate measures are being reported and that the level of service is appropriate. The reliability measures on which the distributors have reported during the current regulatory period include: • CAIDI21 (customer average interruption duration index), which is the average time taken for supply to be restored to a customer when a supply interruption (of duration equal to or longer than one minute) occurs. • SAIFI (system average interruption frequency index), which is the number of occasions when a customer could expect, on average, to experience a supply interruption (of duration equal to or longer than one minute) in a year. • SAIDI (system average interruption duration index), which is the total minutes, on average, that a customer could expect to be without electricity in a year due to supply interruptions (of duration equal to or longer than one minute). • MAIFI (momentary average interruption frequency index), which is the total number of momentary supply interruptions (of less than one minute duration) that a customer could expect, on average, to experience in a year. These measures are disaggregated by network type — central business district (CBD), urban, short rural and long rural feeders — and, with the exception of MAIFI, for unplanned22 and planned23 supply interruptions. With the exception of United Energy, the distributors do not currently include in their reporting of the measures, supply interruptions which occur during fault finding.24 Conversely, United Energy includes these supply interruptions in their reporting. From 2006, the Commission will require all distributors, including United Energy, to report interruptions on the same basis. United Energy advises that this change will not materially affect its reporting of reliability performance. Appropriateness of reliability measures The Commission sought proposals from the distributors for service measures that may have become more important to customers over the current regulatory period, or for measures that may provide an early indication that issues are emerging with the reliability or security of the electricity supply. 21 22 23 24 CAIDI is equal to SAIDI divided by SAIFI Unplanned interruptions are those supply interruptions which are not planned by the distributor and for which a customer does not receive prior notice. Planned interruptions are those supply interruptions which are planned by the distributor and for which a customer should receive prior notice. When tracing faults on their networks, distributors seek to restore supply to customers as quickly as possible. Sometimes this results in a faulty section of the network being joined to a healthy section, resulting in a short outage of the healthy section. October 06 33 Essential Services Commission, Victoria Final Decision None of the distributors proposed any additional service measures against which their service provision should be measured during the 2006-10 regulatory period. While reliability outcomes reported over the period indicate that average reliability has improved, the Commission has received a number of submissions throughout the price review from customers that indicate that pockets of poor reliability remain. Customers’ concerns about supply reliability are supported by the performance data reported by the distributors by feeder. This data indicates that the unplanned minutes off supply experienced by the worst served 15 per cent of customers is approximately 3 to 4 times greater than that experienced by the average customer. Although no additional measures were proposed regarding reliability to customers with worse than average reliability, the Commission considered options to provide greater visibility in this area given these submissions. The Essential Services Commission of South Australia (ESCOSA) commissioned KPMG to undertake a willingness to pay study in South Australia. The results of ESCOSA’s commissioned study indicated that approximately 85 per cent of customers were satisfied with their existing level of supply reliability, but around 15 per cent of customers were dissatisfied with the level of their reliability (ESCOSA 2005, p. 41). Anecdotally, similar results have been experienced in other jurisdictions with, on average, between 80 and 85 per cent of customers satisfied with their existing level of supply reliability, the proportion tends to be higher in urban areas and lower in rural areas. Very little customer research has been undertaken on willingness to pay in Victoria. Assuming a similar proportion of Victorian electricity customers are satisfied with their electricity supply as in South Australia, the Commission set out in its Position Paper two options to provide greater visibility of the performance experienced by the worst served customers and against which targeted levels could be set: • Option 1: Reporting of the minutes off supply and number of supply interruptions (sustained and momentary) experienced by the worst served 15 per cent of customers for each distributor. Such measures are simple but do not illustrate the range of reliability experienced by these worst served customers, although some of this information can be obtained on the basis of the Guaranteed Service Level (GSL) payments made and the low reliability feeders reported. • Option 2: Reporting of the proportion of customers (rather than the feeder averages) who experience less than 2 hours, 2 – 4 hours, 4 – 8 hours, 8 – 12 hours and more than 12 hours off supply per annum, the proportion of customers who experience less than 2 interruptions, 2 - 4 interruptions, 4 – 8 interruptions, 8 – 12 interruptions and more than 12 interruptions per annum, and the proportion of customers who experience less than 5 momentary interruptions, 5 – 10 momentary interruptions, 10 – 15 momentary interruptions, 15 - 20 momentary interruptions and more than 20 momentary interruptions per annum. These measures are more complex to interpret than those under Option 1 but illustrate more readily the range of reliability experienced by these worst served customers. Additionally, this method of reporting is similar to that currently provided in the Comparative Performance Report. October 06 34 Essential Services Commission, Victoria Final Decision Stakeholders varied in their responses — from support for reporting the worst served customers (SP AusNet 2005b, p. 24, Johanna Seaside Cottages 2005b, p. 2), to concern that any measure of the worst served customers would be problematic because distributors do not have a precise picture of the connectivity of all customers (with the result that measures relying on interruptions should be aggregated at the high voltage feeder level) (AGLE 2005b, p. 15, CitiPower 2005b and Powercor 2005b).25 CUAC (2005c, p. 5) did not think that either of the two options presented would give adequate information on performance in the worst served areas. The Energy and Water Ombudsman of Victoria (EWOV) (2005b, p. 2) supported Option 2 as it would appear to far more readily allow customers to compare their experiences with other customers’ experiences. Option 2 was also supported by the Energy Users Coalition of Victoria (EUCV) (2005b, p. 62) as it would provide a sound trend basis for concerns about the “health” of the network. The Commission notes that the data is currently available to analyse the data at a feeder level as per Option 2, but not on a per customer basis. Given that Option 1 is a simpler measure to report on and that reporting on option 2 on a per customer basis is not currently possible, the Commission has decided to require reporting on Option 1 rather than Option 2. However, while reporting of both SAIDI and SAIFI is required, targeted levels of performance have been set for SAIDI only. This is because SAIDI is a measure of both interruption duration and interruption frequency and the Commission does not wish to constrain distributors from adopting improvement strategies that target either measure, when deciding how to improve reliability performance to worst served customers. The Commission will require distributors to continue to report against the average reliability measures for the 2006-10 regulatory period by network type — that is, unplanned SAIDI, unplanned SAIFI, planned SAIDI, planned SAIFI and MAIFI. In addition, distributors will be required to report the annual minutes off supply experienced by the 15 per cent of customers who are experiencing the longest time off supply in that year. This will measure and focus accountability for the service reliability levels experienced by these customers. Where connectivity information is not available, this measure will be based on reliability at the feeder level. Together with the GSL payments and reporting of low threshold feeders, this measure will illustrate the range of reliability service levels experienced by customers, and enable customers to compare their experience to others. In addition, the Lavers Hill & District Progress Association (2005, p. 5) suggested that: The Commission could consider a “cause” measure. Such a measure would indicate what action was necessary to improve reliability. A “cause” measure would enable the Commission to monitor any trends in the causes of unplanned interruptions which may provide early indications of a factor leading to deteriorating reliability over the longer term. The Commission proposed a breakdown of primary causes against which unplanned minutes off supply could be categorised. The cause measures were proposed to identify issues that can be controlled by the distributors which 25 Historically, distributors have recorded the connection of each customer against the distribution transformer supplying that customer. Hence, individual customers affected by faults on high voltage feeders supplying distribution substations can be determined. However, individual customers affected by the impact of certain faults on the low voltage network cannot be determined without a site inspection. Outages of high voltage feeders account for a high proportion of the supply interruptions experienced by customers. October 06 35 Essential Services Commission, Victoria Final Decision may impact on reliability in the longer term. For example, if the minutes off supply due to vegetation increases this may indicate insufficient vegetation management or if the minutes off supply due to equipment failure increases this may indicate emerging issues with asset replacement. EWOV (2005b, p. 2) and CUAC (2005c, p. 2) supported the breakdown of unplanned minutes off supply by primary cause as it provides useful comparative information for customers, customer representatives, distributors and the Commission. CitiPower (2005b, p. 2) and Powercor (2005b, p. 2) suggested additional causes for unplanned minutes off supply. The Commission agrees that these additional causes would improve the focus of the measure on causes for which distributors can reasonably be considered accountable. CitiPower (2005t, p. 5) and Powercor (2005aa, p. 9) also suggested that the ‘operational error’ category be widened to capture events caused by operating the network such as interruptions resulting from operational procedures. This would avoid the need to wait on the outcome of investigations to determine if an error had occurred. However, the Commission notes that this would capture normal operational activities and would not separately identify those supply interruptions caused through error. It is also inconsistent with the national reporting framework agreed through the Utility Regulators Forum. Given that this information is required once per year, distributors should be able to correctly classify events within the required reporting timeframe. The Commission therefore requires that the distributors provide a breakdown of unplanned interruptions on an annual basis, by the primary causes, as set in Section 2.1.1. The distributors are to provide an explanation for any significant year on year changes, and identify any actions to address these changes, where the movement is adverse. Proposed improvements in reliability With the exception of CitiPower, each of the distributors initially proposed expenditure over the 2006-10 regulatory period to improve reliability. • AGLE proposed $1.3 million to improve areas of poor reliability. • Powercor proposed approximately $11 million to improve the overall reliability performance to customers/areas currently receiving the lowest level of service and improve the ability to automatically detect outages through automated fault indicators, and approximately $6.6 million to continue existing reliability programs which will maintain the 2005 average reliability over the 2006-10 regulatory period. • SP AusNet proposed $23 million to address reliability in its worst-served areas (Murrindindi, Kinglake, Newmerella, Cann River, Mount Dandenong, Sassafras and Upwey). • United Energy proposed $12 million to, among other things, reduce the frequency of momentary interruptions and improve its performance in its worst served areas. Additionally, in its enhanced offering, CitiPower proposed $28 million over the 2006-10 regulatory period to, among other things, increase the number of customers who remain served during planned or unplanned transmission network contingencies and to place network assets on the CBD fringe underground. In its enhanced offering, Powercor proposed October 06 36 Essential Services Commission, Victoria Final Decision $54 million over the 2006-10 regulatory period to, among other things, improve reliability performance by targeting key feeders and reducing the impact and incidence of pole fires (thereby resulting in a reduction in SAIDI of four minutes per annum), and $38 million to improve the security of supply. Powercor has indicated that the improvement to the security of supply will reduce the probability of a sustained outage, but the probability of a sustained outage is so low that there is no quantifiable improvement in reliability. Typically, improvements in reliability require expenditure. While improved management practices through better information and procedures can impact reliability, these are likely to be small, and it is the avoidance of a decline in reliability through poor management that is of importance. Expenditure on reliability improvement projects may be provided for in a number of ways — through the distributor’s revenue requirement; or through improvements in service that is rewarded through a service incentive arrangement (see Chapter 3); or through a direct contribution by a customer. Except in the latter case, the additional costs incurred are passed through to a distributor’s customers in the prices they pay for electricity and necessarily involve those customers who do not receive a reliability improvement paying more so that other, worse served customers can receive an improvement. Where the costs are passed through in the revenue requirement, the distributor receives the revenue regardless of whether the required outcomes are delivered (less any penalties through the service incentive arrangements). Hence, under a pass through arrangement, distributors have an incentive to under-invest against the forecast expenditure levels and it is uncertain whether appropriate investments in reliability will be made. However, where the costs are recovered through the service incentive arrangements, the distributor receives the revenue only when the required outcomes are delivered, avoiding the incentive to under-invest. The Commission consulted on whether expenditure for reliability improvements should be provided, that is, whether customers were prepared to pay more to improve the levels of supply reliability. Although many stakeholders, particularly customers experiencing poor reliability, expressed dissatisfaction with the levels of reliability currently experienced, they did not indicate that they were prepared to pay more for the proposed improvements in reliability. In submissions and public information sessions held by the Commission, stakeholders indicated that, in their opinion, they were already paying for a certain level of reliability that is not being delivered and should not pay more to realise that level of reliability. South Gippsland Shire Council (2005b, p. 1) considered it was inappropriate to improve reliability only where customers are prepared to pay more, as this would severely disadvantage rural and regional Victoria: The consequence of poor reliability to a 300 head dairy farm should not be given the same weight as a single family household. However, some customers indicated their support for paying for reliability improvements through the S-factor scheme. Under this approach, all customers pay more but only when reliability improvements are actually delivered rather than through the revenue requirement, which would require customers to pay more regardless of whether the reliability improvement is delivered or not. For example, CUAC (2005b, p. 9): … strongly believes that the service improvements should be funded through the service incentive mechanism as opposed to claiming revenue requirements. Only the service October 06 37 Essential Services Commission, Victoria Final Decision incentive arrangements can ensure that the expenditure has been targeted to actually improve the service levels. SP AusNet (2005b, pp. 3-4) expressed a different view and considered that the regional forums had demonstrated that the community expects that all customers should receive an acceptable level of service reliability and are willing to pay for reliability improvements. It considered that specific funding would be required to provide adequate investment in reliability for worst served customers and, unless separate funding is to be provided, separate monitoring was not needed. Further, business stakeholders such as the Geelong Manufacturing Council and Bruck Textiles considered that improvements in reliability and system security are valued and funding of these activities should be considered, although at minimum cost to industry. In support of its view, SP AusNet indicated that customer consultations it had undertaken demonstrated that customers were willing to pay to improve the reliability of the worst served customers. However, in the Commission’s view, these consultations were based on too small a number of interviews and customer focus groups and do not directly establish how much customers are willing to pay or cross-subsidise worst served customers for such improvements. It is also unclear how SP AusNet would guarantee the delivery of these improvements. CitiPower and Powercor engaged an independent market research firm to research the extent to which customers are willing to pay for the improvements in reliability proposed by them. CitiPower and Powercor consider that the research results indicate there is some customer support for reliability improvements. While the results presented indicated that service improvements were valued, the research did not clearly identify how much the customers were willing to pay for these improvements. In addition, it is unclear how CitiPower and Powercor would guarantee that the improvements would be delivered. The Commission also notes that, where it is claimed that the improvements could not be measured, it is difficult to assume customers would still be willing to pay for them. According to CUAC (2005b, p. 2), customers in certain parts of Victoria believe that they are already paying very high prices for a poor service and could simply not afford to pay more for household electricity usage: Without the capacity to pay they would have “to choose” to retain poor supply reliability. Some stakeholders, including CUAC, were of the view that further customer research is required to determine customers’ willingness to pay for improvements. The distributors have informally indicated that this will be done during the next regulatory period and the Commission supports such an initiative. Electricity distribution tariffs are currently not differentiated based on the level of service received and the costs of providing that service, despite the significant variation in costs for serving different geographical areas. Generally all customers of the same classification (residential, small business, large business) pay the same rate for electricity within a distribution area, regardless of location within that area. Under these tariffs, where reliability is to be improved in a particular area, all customers of that classification will pay for that improvement. October 06 38 Essential Services Commission, Victoria Final Decision The Minister for Energy Industries, Hon. Theo Theophanous (2005, p. 2) urged the Commission and the distributors to ensure that adequate measures are implemented to provide significant improvements to the reliability of supply to customers in the worst served areas, without detriment to existing overall reliability target levels, suggesting that a schedule of works be prepared to address the worst served areas of rural and regional Victoria. The Commission considers that, at this stage, the evidence provided to support the proposition that all Victorian customers are prepared to pay for improvements in reliability in worst served areas is difficult to respond to in practice as it does not reveal what level of reliability customers are prepared to pay for. Importantly, for the purpose of the price review, the Commission needs to be confident that customers are willing to pay the amounts proposed by the distributors for the level of improvements proposed. In the absence of support for the payment of the amounts proposed, the Commission finds it difficult to require customers to pay for these specific projects, particularly when the impacts on the level of service are uncertain or not measurable. During the 2001-05 regulatory period, the distributors improved service on average and to worst served customers. However, the cost of achieving these service improvements does not appear to have been as much as was estimated by the distributors during the 2000 price review. Four out of five distributors have spent less than they estimated whilst continuing to improve the level of service, despite increasing demand. In some cases, improvements beyond the service targets have been achieved resulting in some distributors receiving even more revenue, despite actual costs remaining below the estimated costs. This demonstrates that distributors can and do find more efficient means of addressing service improvement issues. Importantly, the Commission acknowledges that it is neither practical nor possible for a regulator to assess the scope of individual reliability improvement projects or to evaluate their costs and benefits. It therefore has not sought to establish a list of suitable projects or to impose an economic test that distributors might be required to apply. The Commission has provided an incentive through financial rewards and penalties (see Chapter 3) that ensures distributors have incentives to deliver service improvements where it is efficient to do so. The Commission considers that customers should not pay for reliability improvements that cannot be measured or cannot be guaranteed to be delivered. Further, customers should not pay more for the service improvements than the value they place on them. Therefore, for the 2006-10 regulatory period, the Commission considers customers should only pay for reliability improvements through the service incentive arrangements. The service incentive arrangements provide additional revenue to the distributors when service improvements are delivered. Under the S-factor scheme, the revenue received is based on an estimate of the average value that customers place on reliability. Accordingly, the Commission will rely upon the service incentive arrangements (the S-factor scheme and the reduction in GSL payments under the GSL payments scheme) to provide revenue to distributors once reliability improvements are delivered. Improvements in reliability will therefore be decided by the distributors directly, taking into account the incentive arrangements. Where these services are not delivered, customers will not be required to pay higher distribution prices and may receive a GSL payment. Indicative examples of the type of cost-benefit trade off that a distributor may make are set out in Attachment 1 to this chapter. October 06 39 Essential Services Commission, Victoria Final Decision The Commission has therefore excluded expenditure amounts for reliability improvements from the revenue requirements. The Commission’s analysis indicates that some of the projects for worst served customers proposed by the distributors may be economically efficient and proceed under the service incentive arrangements and some may not. SP AusNet and Powercor have indicated that, under these arrangements, proposals to improve reliability in locations such as the Mt Dandenong area and Lavers Hill may not be financially viable under the service incentive scheme. The Commission notes that distributors will not undertake the investments unless the improvements can be economically achieved, otherwise they will not receive sufficient benefits under the incentive scheme to offset the expenditures required. In these cases, the cost of achieving the improvements is greater than the average value assumed to be placed on reliability by customers. To provide these distributors with the expenditure proposed through the revenue requirement rather than the service incentive arrangements would result in price increases greater than the average value customers place on the improvements (as determined by CRA’s study on the value of customer reliability for VENCorp). That is, all other customers would pay more and there would be no guarantees that the service improvements would result or even that the investment would be undertaken. Where service levels remain worse than the service thresholds that trigger GSL payments, these customers will receive these payments. The annual cost of making these payments to customers, in addition to the increased incentive rates in the S-factor scheme to deliver improved services, will provide distributors with the incentive to continue to seek ways of addressing the issues more efficiently without customers being required to pay more than the value they place on the improvement in reliability. If specific groups of customers wish to have their service improved and are willing to pay for it, they can agree a payment and outcome with the distributor separate from the price control arrangements. Under this scenario, the customers who benefit from the improvement would pay for the improvement rather than the cost of the improvement being spread across all of a distributor’s customers. However, EUAA (2005a, p. 10) notes that some distributors are reluctant to establish an enduring guarantee to those customers who have made investments in the distributor’s infrastructure. The Commission notes that such reluctance is contrary to the intent of the Electricity Distribution Code, which states that customers and distributors may seek written agreement to expressly vary their rights and obligations under the code. This right includes matters relating to quality of supply and reliability of supply. If a customer has a concern in this regard, it is able to raise it with the industry’s Ombudsman or with the Commission. Additionally, the Commission notes that there is scope for the specifications for items of customers’ electrical equipment to be amended so that they are able to withstand momentary interruptions. Such an approach would be expected to be more economically efficient than reducing the frequency of momentary interruptions at the network level. In response to the Position Paper, Ron Brons (2005, p. 3) proposed that: October 06 40 Essential Services Commission, Victoria Final Decision SP AusNet sell a cheap digital alarm clock with a built-in battery-powered back-up system which will enable the clock to keep running properly during momentary power outages. Whilst the Commission’s role is not to regulate such an activity by the distributors, it does expect the distributors to contribute to changing equipment standards to recognise the practical limitations of the electricity supply system. Of course, customers can also seek out options for addressing specific issues for themselves that best meet their individual needs. Appropriateness of proposed targeted levels of reliability Targeted levels of reliability are required for reporting and monitoring purposes. They reflect the reliability that customers should expect to experience over the 2006-10 regulatory period, based on historical performance and the prices paid. Targeted levels are different from the S-factor targets that apply to the service incentive mechanism described in Chapter 3. In its Final Framework and Approach, the Commission proposed that the 2005 reliability targets be adopted as the targeted levels for the 2006-10 regulatory period. However, two issues have since arisen: • distributors are, in some areas, proposing variations to the 2005 targets; and • actual performance during the current regulatory period suggests that the 2005 targets should be reviewed. For some reliability measures, the targeted levels proposed by the distributors for the 2006-10 regulatory period reflect improvement or deterioration relative to the 2005 targets. The distributors’ proposals are also based on experience gained by them during the current regulatory period and/or due to proposed expenditure to improve reliability. For example, SP AusNet and United Energy have proposed a deterioration in the targeted levels for planned SAIDI for the 2006-10 regulatory period compared to their 2005 targets in response to concerns regarding the potential for safety incidents associated with live line work practices, and due to the increased capital expenditure that they have proposed. Both of these factors would result in more planned outages whilst work is undertaken. The Commission is of the view that, where customers have paid through the current S-factor scheme for improvements in reliability beyond the existing service targets, and these improvements have been sustained through the regulatory period, these improvements should be reflected in the targeted levels going forward. Origin Energy was of the view that reliability should not deteriorate unless there was strong consumer support for this, whilst CUAC believed there was merit in improving service in certain areas but any decision to do so should be based on feedback from customer consultations. SP AusNet (2005b, p. 25) considered it was appropriate to base future reliability targets on current performance. However, the Commission notes that SP AusNet’s current performance is worse than the targeted levels. In its Draft Decision, the Commission accepted the targeted levels proposed by the distributors except where: • a distributor has improved its performance against the reliability measures during the 2001-05 regulatory period, in which case the Commission’s decision was that the October 06 41 Essential Services Commission, Victoria Final Decision targeted levels for the 2006-10 regulatory period should reflect this improved performance; or • the improvement in the reliability measure proposed was dependent on specific expenditure, and the Commission did not include that expenditure in the distributor’s revenue requirement. This approach resulted in changes to some of the targeted levels proposed by CitiPower (planned CBD, unplanned CBD and MAIFI measures); Powercor (unplanned short rural, planned rural and MAIFI measures); SP AusNet (planned urban, and planned short rural measures); and United Energy (planned urban and planned short rural measures). AGLE’s targeted levels were unchanged. In submissions to the Draft Decision, CitiPower (2005t, p. 3), Powercor (2005aa, p. 6) and SP AusNet (2005f, p. 10) commented that the targets proposed for them for planned SAIDI were too onerous. CitiPower noted its capital works program is forecast to increase above 2001-05 levels and that, together with the interval meter roll-out, this will place increased pressure on planned outages to accommodate planned works. Powercor accepted the targeted levels proposed for its rural areas, but contended that a reduction in its urban targeted level from 16 minutes to 10 minutes did not adequately recognise increasing pressures relating to safe work practices and its works program (including the interval meter roll out). SP AusNet commented that the significant increases in capital expenditure planned by all distributors, in addition to more safety conscious work practices, would put significant upward pressure on planned SAIDI. Taking into account these comments, the Commission has reviewed the proposed targeted levels for planned SAIDI and planned SAIFI measures to better align them with 2004 performances and the distributors’ assessment of the impact of changes in safe work practices and the interval meter roll out program. The Commission also considered the consistency of targeted levels across distributors. Changes to targeted levels, as set out in Attachment 2, have been made from those proposed in the Draft Decision as follows: CitiPower (up 7 per cent in CBD area), Powercor and SP AusNet (up 60 per cent in urban and 17 percent in short rural network areas) and United Energy (up 23 per cent and 67 per cent in urban and short rural network areas respectively). No change has been made to AGLE’s targeted levels. CitiPower did not agree to the proposed reduction in its targeted performance for unplanned SAIDI in its CBD area from 16 minutes in 2005 to 14 minutes in 2006-10, because of the expected volatility in this measure. However, the average performance over the 2001-04 period of 11.4 minutes is substantially better than the proposed targeted level and does not support CitiPower’s proposal. The targeted performance level of 14 minutes has been retained. CitiPower notes that MAIFI in the CBD area is small due to the infrequent momentary interruptions that occur on the sub-transmission system supplying such areas, but was not zero as assumed by the Commission. It requested a targeted level of 0.05 interruptions per customer, being a small increase above average levels to account for expected volatility in this measure. Given the inclusion of MAIFI into the scheme from 2006, the targeted levels for MAIFI have been set based on the expected value. Notwithstanding that MAIFI for the CBD area has not been included in the service incentive scheme, the Commission considers that the targeted level should be based on the average performance and therefore has set the targeted level to the 2001-04 average of 0.03 interruptions per customer. October 06 42 Essential Services Commission, Victoria Final Decision Powercor commented that the targeted levels proposed for it for unplanned SAIDI and SAIFI in rural areas were acceptable overall, but suggested relaxing targeted levels on short rural feeders and tightening targeted levels on long rural feeders to better reflect historical performance. Powercor accepted the tightened targeted levels for long rural feeders, and proposed that the short rural targeted level for SAIFI and SAIDI be relaxed so that levels of CAIDI would be more reasonable. A SAIFI of 2.0 and a SAIDI of 118, as set out in the Draft Decision, results in a CAIDI of 59 minutes, which is less than Powercor’s 2005 targeted level for urban CAIDI (66 minutes). Powercor proposed that SAIDI be increased to 145 and SAIFI to 2.1 to provide a CAIDI of 69 minutes which is higher than the 2005 targeted level. Given that Powercor has out-performed its CAIDI targeted levels in four of the five years to 2004, the Commission expects that the 2005 targeted level is achievable. As the improvements to achieve the 2005 targeted levels have been funded under the 2001-05 price decision and there is no evidence to suggest that the targeted levels were set inappropriately, the Commission has adopted the 2005 targeted levels for short rural feeders for the 2006-10 regulatory period. The long rural feeder targeted level has been maintained at the level proposed in the Draft Decision. Powercor claimed that historical data on MAIFI is unreliable leading to proposed targeted levels that are too aggressive. It sought to relax its targeted levels by an average of 12 per cent. The Commission notes that reporting on MAIFI has been required since 2001 and Powercor has had several years to develop appropriate recording systems. It considers that Powercor’s recorded performance is sufficiently accurate to allow targeted levels to be set and has retained the targeted performance based on the trend in 2001-04 performance, as proposed in the Draft Decision. The targeted performance levels to the worst served 15 per cent of customers set out in the Draft Decision were based on 2003 performance, taking into account that the GSL payments scheme has acted to improve performance to the worst served customers over the period. SP AusNet thought that the targets proposed for it were appropriate, while CitiPower and Powercor thought that the targets proposed for them were inconsistent with other distributors and did not take into account the volatility in this measure, proposing increases of 21 per cent and 14 per cent respectively. They suggested that the targeted level be set slightly above the 2001-04 average. The Commission accepts that using an averaging of performances would provide an appropriate allowance for volatility, but considers that the 2000 year should be excluded from the average. This is because the service incentive schemes introduced in 2001 provided incentives to distributors to improve reliability to worst served customers. If 2000 was to be included in the average, the average would reflect the volatility in this measure but would also exclude the improvements made that customers have already paid for. The targeted levels have therefore been recalculated, based on the average of the 2001-04 performance for each distributor. This results in a tightening of the targeted performance levels for AGLE and SP AusNet and a relaxation of the targeted performance levels for CitiPower and Powercor, whilst United Energy remains at about the same level as that proposed in the Draft Decision. The Commission’s decision on the appropriate targeted levels for unplanned SAIDI, unplanned SAIFI, planned SAIDI, planned SAIFI and MAIFI is provided in Table 2.1 and Attachment 2 to this Chapter. For SP AusNet, these targets have been adjusted where appropriate for a change in methodology for counting customers — disconnected customers October 06 43 Essential Services Commission, Victoria Final Decision are to be excluded from the calculation of reliability measures from 1 January 2006 — and movement of customers between network types. The Commission’s decision on the appropriate targeted levels for the total minutes off supply for the worst served 15 per cent of customers is provided in Table 2.2. Definition of momentary interruptions For the purposes of reporting statistics on momentary interruptions in Victoria, a momentary interruption has been defined as an interruption that is less than one minute in duration. CitiPower, Powercor and United Energy have proposed that the definition be amended so that it includes all interruptions of duration less than three minutes. These distributors consider that an amended definition would be consistent with the definition adopted in other countries and would encourage development of semi automated distribution switching responses to an interruption of duration three minutes thereby avoiding the costs of going to fully automated systems, which would be necessary to achieve operational responses of less than one minute (CitiPower 2005b, p. 3 and Powercor 2005b, p. 3). Whilst these distributors supported the change in definition of momentary interruptions from one minute to three minutes, SP AusNet (2005b, p. 41) considered it inappropriate to change the MAIFI definition at this time due to various concerns, including: • the necessity to reset network and S-factor targets, which would require a recalculation of historic data; and • the creation of an incentive for work crews to attempt to conduct certain maintenance work within three minutes to ensure the outage is defined as momentary rather than sustained, with a corresponding impact on safety. Stakeholders representing customer interests did not support a change in the definition of momentary interruptions. The historical information on MAIFI has been collected and the targeted levels have been set on the basis of an interruption of a duration less than one minute. In addition, willingness to pay information regarding MAIFI is based on a one minute definition. Further, the current S-factor scheme for improvements in reliability encourages a reduction in the duration of interruptions. If the definition was changed, there would be no consistent data and introducing a financial incentive for an improvement in MAIFI would need to be postponed again whilst data based on a three minute definition were collected. In its Position Paper, the Commission proposed that if the definition was to change, the information should be reported for both definitions during the next regulatory period. This would provide historical data as the basis for amending the definition. However, United Energy (2005c, p. 13) expressed concern regarding the cost effectiveness of collecting data on the number of momentary interruptions based on both definitions over the next regulatory period. The Commission remains of the view that momentary interruptions should be defined as interruptions of less than one minute duration to be consistent with the current definition and the national regulatory reporting framework. This assists with comparing performance over time and setting targets for the service incentive scheme. October 06 44 Essential Services Commission, Victoria Final Decision The Commission will not require distributors to collect data based on a three minute definition of MAIFI during the next regulatory period. However, if distributors continue to support a change in the definition of MAIFI, they should collect data during the next regulatory period based on a three minute definition. They should also undertake customer research to demonstrate that customers would support a change in definition and to ascertain the difference in customers’ willingness to pay for reductions in the frequency of three minute interruptions compared to one minute interruptions. Reporting low reliability feeders The Comparative Performance Reports, published annually by the Commission, list the feeders with reliability worse, in terms of greater annual minutes off supply, than threshold limits set for each feeder type. The low reliability threshold limits were set based on levels experienced by the worst served five per cent of customers in 1997 and 1998. Given the improvements in reliability for the worst served customers, the proportion of customers who experience reliability at these levels has fallen. The Commission therefore proposed revised thresholds in its Position Paper, including with respect to MAIFI, based on performance data to 2003. Stakeholders generally supported ongoing reporting of low reliability feeders. Customers attending the Commission’s public information forums conveyed the dissatisfaction of those reliant on the worst served feeders, and the view that the service reliability of the worst served feeders and the relevant distributors’ plans to improve these feeders should be transparent to their customers. The Commission concurs with this view and with therefore require the distributor to provide comments, for inclusion in the Comparative Performance Report, or its plans for each low reliability feeders. Distributors supported the Commission’s proposed revision of thresholds but suggested amendments to some thresholds based on additional data. The Commission subsequently reviewed the thresholds for reporting low reliability feeders, incorporating the performance data for 2004, so that they reflect the service reliability and MAIFI currently experienced by the worst served five per cent of customers. Based on feeder performance data for 1999 to 2004, the threshold for MAIFI for long rural feeders has been increased from 24 interruptions proposed in the Position Paper to 25 interruptions. CitiPower (2005t, p. 8) suggested that the targets for CBD areas should include a SAIFI threshold as well as the proposed SAIDI threshold, to avoid classifying a feeder as low reliability following a single sustained outage of 70 minutes. The key issue here is that any interruption on a predominantly underground supply system is likely to take a significant time to locate and repair. Incorporating a dual threshold is likely to provide a more balanced view of when CBD customers experience poor reliability. Accordingly, the threshold will include a requirement that only applies where more than one interruption has occurred. The thresholds for the reporting of low reliability feeders are provided in Table 2.3. 2.2.2 Quality of supply measures Whilst reliability of supply is concerned with the availability of supply, quality of supply is concerned with the characteristics of the electricity supply delivered to customers’ premises, October 06 45 Essential Services Commission, Victoria Final Decision specifically whether there are short term or transient voltage increases (voltage surges) or reductions (voltage sags) and harmonic distortions. Distributors are obliged to supply electricity that meets the standards for quality set out in the Electricity Distribution Code. Where the electricity supplied does not meet the relevant standards, electrical equipment may not operate as intended and/or damage to customers’ equipment may result. For the 2001-05 regulatory period, very little information was available on the quality of supply received by customers, despite this being recognised as an important issue. To enable distributors to better monitor voltage problems and proactively manage the quality of supply delivered to customers, they have been required, during the current regulatory period, to install quality of supply monitoring equipment at each zone substation and at the far end of one distribution feeder supplied from each zone substation. It was always considered that once this information was available, it would be possible to concentrate on improvements, where required. The distributors have provided performance data to the Commission in relation to the quality of supply since 1999. However, prior to the completion of the installation of the quality of supply monitoring equipment, the data have been incomplete.26 The Commission intends to continue collecting this data and commenced publishing this data in its 2003 Comparative Performance Report, when the data set was almost complete. The issues arising from the distributors’ price-service proposals in relation to the quality of supply measures are: • appropriateness of quality of supply measures; • targeted levels for quality of supply measures; • proposed improvements in quality of supply; and • increased costs associated with compensation for voltage variation claims. Appropriateness of quality of supply measures The distributors are currently required to report to the Commission on the following: • Number of over-voltage events – due to high voltage injection; • Number of customers receiving over-voltage – due to high voltage injection; • Number of over-voltage events – due to lightning; • Number of customers receiving over-voltage – due to lightning; • Number of over-voltage events – due to voltage regulation or other cause; • Number of customers receiving over-voltage – due to voltage regulation or other cause; • Number of voltage variations – steady state; • Number of voltage variations – one minute; and • Number of voltage variations – ten seconds. 26 By the end of 2003, AGLE, CitiPower, SP AusNet and United Energy had installed 100 per cent of the quality of supply monitoring equipment, and Powercor had installed 89 per cent of monitoring equipment at the zone substation level and 95 per cent of monitoring equipment at the feeder level. October 06 46 Essential Services Commission, Victoria Final Decision These reporting requirements are additional to reporting the number of customer complaints on quality of supply required by the national regulatory reporting requirements. Stakeholders generally supported the existing quality of supply measures, although the EUCV (2005b, p. 29) was of the view that there should be additional quality of supply monitoring: The service standards should record as basic standards, both the frequency and extent of transient voltage variations, the frequency and length of loss of supply (even if such loss is for less than one second) and the frequency of occurrences of voltage spikes. Whilst the Commission is aware of increasing community concerns regarding quality of supply and has considered improved monitoring of quality of supply, it is concerned about the feasibility of some of the proposals for additional measures. In its enhanced offer, CitiPower proposed improving the number of voltage variations of less than one second. It would be difficult to measure whether this would be achieved or not because voltage variations are currently only measured for periods less than one minute and less than ten seconds under the Electricity Distribution Code. The EUCV (2005b, p. 64) suggested that voltage variations be measured over this shorter time period, while CUAC (2005c, p. 2) questioned the appropriateness of the current standard for voltage quality: …[CUAC] recommends that the Commission initiate a dialogue about reasonable levels of quality, the present and future needs of rural communities and the appropriateness of the quality levels proposed in the Electricity Distribution Code. Given the level of non-compliance with the current standards in the Electricity Distribution Code, the Commission does not consider it appropriate at this stage to consider tightening these standards across the network and measuring voltage variations of less than one second. Where specific customers have different needs from the average customer, these should be addressed by that customer, as discussed further in the next section. CitiPower (2005b, p. 37) and Powercor (2005b, p. 37) have suggested that: There should be additional reporting where voltage variations lasting greater than one minute are segmented into those recorded at zone substation levels and those recorded at feeder extremity level. The Commission supports CitiPower’s and Powercor’s proposal to segment quality of supply monitoring at the zone substation and feeder level. SP AusNet and David Valentine also supported these proposed changes to reporting requirements. Discussions with customer groups indicated that voltage variations which result in a voltage level that is less than 70 per cent or 80 per cent of nominal voltage have a greater impact on equipment operation than smaller voltage variations. Accordingly, the Commission proposed in its Position Paper additional reporting at the zone substation level of ten second voltage variations, where a breakdown is provided of voltage variations which result in a voltage level that is less than 70 per cent, less than 80 per cent, and less than 90 per cent of nominal voltage. United Energy (2005c, p. 55) was supportive of such additional reporting, while Power Quality Solutions (2005, p. 4) proposed a further breakdown based on the duration of the October 06 47 Essential Services Commission, Victoria Final Decision voltage variations: 0.02-0.15 sec, 0.15-1.0 sec, and 1-10 sec. Subsequently, all distributors advised that monitors installed in their zone substations are capable of measuring on this basis. While the provision of such information might be helpful to inform the Commission in future reviews of voltage standards, it is not clear that the cost of collecting such information is warranted at this time. Hence the Commission encourages distributors to install voltage monitoring equipment that is capable of recording voltage variations in the time intervals proposed, and to make this information available to customers when requested, but does not intend to mandate a specific requirement at this time. Targeted levels for quality of supply measures The distributors will continue to report quality of supply against existing measures. Additionally, distributors will report on the number of voltage variations as measured at the zone substation level, and as measured at the feeder level. For zone substation level only, a further breakdown of voltage variations of less than ten seconds will be reported based on the minimum voltage during that voltage variation (less than 70 per cent of nominal voltage, less than 80 per cent of nominal voltage and less than 90 per cent of nominal voltage). Targeted levels for the quality of supply measures were not set during the last price review because the performance information was unavailable. However, such an approach was foreshadowed as part of the last Price Determination (ORG 2000a, p. 30). While stakeholders generally supported the setting of targeted levels for quality of supply measures against which the Commission could report and monitor distributors’ performance, some of the distributors did not, identifying a number of issues relating to: • a lack of clarity with the definitions of quality of supply (AGLE 2005b, p. 19, United Energy 2005c, p. 55); • the limited quantity and quality of historical data (SP AusNet 2005b, p. 43); and • current monitoring equipment which is orientated around reporting a sample of quality of supply information (Powercor 2005b, p. 2). CitiPower and Powercor considered that the accurate quantification of the number of customers receiving over-voltage events is difficult, and that voltage variation reporting proposed for zone substations is more reliable. Neither they nor United Energy (2005c, p. 55) supported targeted levels at feeder level but they did support targeted levels at zone substation level. The Commission notes AGLE’s and United Energy’s concern regarding a lack of clarity with the definitions of quality of supply — for example, United Energy reports voltage variations based on target voltage rather than nominal voltage. Power Quality Solutions (2005, p. 2) stated that, to ensure consistency of data over the 2006-10 period, all distributors should use nominal voltage when determining the voltage variation limits rather than target voltage. It also recommended that the Electricity Distribution Code should reference AS/NZ61000-4-30 as the required measurement methodology standard for all power quality parameters. The Commission notes that using variations from nominal voltage, rather than targeted voltage, provided a perverse incentive to lower voltage at zone substations, which could result in even lower voltages for customers at the end of feeders. The Commission recognises that clear definitions are required and will clarify these through consultation on changes to the Electricity Distribution Code. The Commission also October 06 48 Essential Services Commission, Victoria Final Decision recognises the limitations in setting the targeted levels associated with the partial historical data and the measurement of a sample of feeders. Given the variability in the data and the level of non-compliance with the Electricity Distribution Code, the Commission considers that the setting of targeted levels at this stage is problematic. Targeted levels have therefore not been specified for the next regulatory period because of the difficulties associated with the existing data, although the data are to be measured and reported (see below). For these purposes, improvements in quality of supply have been expressed as the number of customers for whom voltage quality will improve, rather than as improvements in the level of voltage variations per se. Proposed improvements in quality of supply The Electricity Distribution Code mandates the minimum standards for quality of supply. Where the quality of supply does not comply with the Electricity Distribution Code then the distributor is obligated to improve the quality of supply. During the current regulatory period the distributors have installed voltage monitoring equipment. The installation of this equipment has resulted in objective information on quality of supply being available for the first time. This has enabled the identification of distributors who are not compliant with the minimum standards for quality of supply in some areas. Data for 2003 and 2004 indicates a significant number of voltage variations, particularly for the rural distributors. The distributors made proposals for expenditure over the 2006-10 regulatory period to improve quality of supply: • Powercor proposed expenditure of approximately $26.4 million to improve the quality of supply to customers/areas receiving the lowest level of service where the requirements of the Electricity Distribution Code are not met, and to improve the proactive identification and rectification of supply quality issues. Powercor anticipated that a reduction of between 10 and 15 per cent in reported steady state voltage variations would be achieved. • SP AusNet proposed expenditure of $24 million to resolve quality of supply issues to ensure it complied with the Electricity Distribution Code and to install equipment to measure harmonics and flicker. • United Energy proposed $5.25 million to improve the quality of supply delivered to customers, such as voltage delivery and harmonics, so that it better complied with the Electricity Distribution Code. Non-compliance with the quality of supply requirements in the Electricity Distribution Code was raised during public information forums, particularly at Bendigo, Wodonga and Bairnsdale. Uncle Tobys (2005, p. 1) also observed a significant increase in the frequency of voltage dips. In its Draft Decision, the Commission included expenditure it considered to be reasonable for distributors serving rural areas — Powercor, SP AusNet and United Energy — to ensure that they became compliant over time with the minimum standards for quality of supply as set out in the Electricity Distribution Code. Ideally, the Commission would prefer that this expenditure was financially linked to the achievement of outcomes. However, the minimal October 06 49 Essential Services Commission, Victoria Final Decision historical data available and the fact that the data items that are available are only from a sample of feeders may result in perverse outcomes if quality of service were included under the service incentive arrangements. For example, monitoring equipment may be installed where compliance is most likely. This would result in a misrepresentation of the actual circumstances. Powercor, SP AusNet and United Energy have quantified the number of customers who can expect improvements in quality of supply over the 2006-10 regulatory period (see Tables 2.6, 2.7 and 2.8). Table 2.6: Improvement in quality of supply, Powercor, 2006-10 Year Cumulative number of customers 2006 9,200 2007 22,800 2008 35,400 2009 2010 47,400 59,000 Table 2.7: Year Improvement in quality of supply, SP AusNet, 2006-10 Cumulative number of customers brought within Code SWER systems Sags and swells Negative sequence voltage 2006 799 10,380 1,809 2007 1,698 22,058 3,844 2008 2,698 35,034 6,105 2009 2010 3,798 4,998 49,307 64,878 8,592 11,305 Table 2.8: Improvement in quality of supply, United Energy, 2006-10 Year Cumulative number of customers Cumulative number of zone substations 2006 200 – 400 1 2007 400 – 800 2 2008 600 – 1 200 3 2009 800 – 1 600 4 2010 1 000 – 2 000 5 The Commission will monitor the extent to which these distributors achieve the outcomes set out in Tables 2.6, 2.7 and 2.8. Additionally, the Commission notes that distributors currently must investigate all complaints regarding quality of supply where it is probable that the supply is not compliant with the Electricity Distribution Code. The Commission considers that the continuing focus on quality of supply for the 2006-10 regulatory period should be on providing an accurate picture of the quality of supply and improving compliance with the Electricity Distribution Code for all customers. The cost October 06 50 Essential Services Commission, Victoria Final Decision of further improvements and customer willingness to pay for the improvements can be considered for the next regulatory period when improved data are available and improvements can be objectively measured and quantified. Meanwhile, the Commission intends to closely monitor distributors’ compliance with quality of supply standards through monitoring of customers’ complaints, distributors’ annual reporting on quality of supply measures and the regulatory audit program. Given the concerns expressed in relation to the quality of supply in rural areas and the information that compliance with the Electricity Distribution Code is likely to be less in these areas, the Commission considers that reasonable expenditure proposed by the rural distributors for additional monitoring of the quality of supply should also be included in their revenue requirements. The Commission has considered a number of options including installing voltage monitoring equipment on all rural feeders, and additional monitoring in areas where there is evidence of non compliance. To ensure that the installation of additional voltage monitoring equipment is economically efficient, the Commission will provide expenditure for the number of units of voltage monitoring equipment installed by the rural distributors (Powercor and SP AusNet) to increase by an additional 20 per cent by the end of 2006. Powercor and SP AusNet have provided an estimated unit cost for installing sophisticated voltage quality monitors. Based on the costs provided by SP AusNet,27 the Commission has provided expenditure for: • an additional 27 sophisticated voltage quality monitors to be installed by Powercor at a cost of $648,000; and • an additional 17 sophisticated voltage quality monitors to be installed by SP AusNet at a cost of $408,000. The Commission requires Powercor and SP AusNet to provide it with a plan by 31 December 2005 explaining where and when the additional equipment is to be installed. These plans will be made available on the Commission’s website when received. Additionally, given the expenditure proposed to improve the quality of supply so that the distributors comply with the Electricity Distribution Code, the Commission requires that zone substations and feeders that do not comply with respect to quality of supply be reported. Where a zone substation or feeder is reported, the distributor must provide comments regarding its plans for that zone substation or feeder. There are a number of customers for whom the quality of supply complies with the Electricity Distribution Code but does not meet the quality of supply required by them. Representatives of the dairy industry indicated that minimum quality of supply standards defined in the Electricity Distribution Code are inadequate to meet their needs — especially “dips” or “sags” in supply of electricity to sensitive food processing plants such as milk powder driers. The Dairy Processing Power Quality Project (2005, p. 2) estimated that $23 million of expenditure would be needed to upgrade seven dairy processing plants to provide for adequate quality of supply. 27 SP AusNet quoted $24 000 per unit for a sophisticated voltage quality monitoring unit whilst Powercor quoted $2 000 per unit for a basic voltage monitoring unit and $32 500 per unit for a sophisticated voltage quality monitoring unit. October 06 51 Essential Services Commission, Victoria Final Decision In its enhanced offering, CitiPower proposed expenditure of $28 million over the 2006-10 regulatory period to, among other things, reduce the number of voltage sags of duration less than 1 second in commercial/retail areas.28 Whilst CitiPower currently complies with the Electricity Distribution Code in this regard, it indicated that it will reduce the number of customers who experience voltage sags of duration less than one second by 50 per cent to 144 000 per annum. In its enhanced offering, Powercor also proposed expenditure of $54 million over the 2006-10 regulatory period to, among other things, reduce the extent and impact of voltage fluctuations. Where the quality of supply complies with the Electricity Distribution Code, the customer has the option to pay for improvements to the quality of supply where the customer considers it is economically efficient to do so. This may be achieved through a network solution where the incremental costs are paid for by the customer or through an individual solution implemented at the customer’s premises and paid for by the customer. Therefore, the Commission has not included the expenditure proposed under CitiPower’s and Powercor’s enhanced offerings. United Energy (2005c, p. 56) supported this approach. In addition, CitiPower (2005b, p. 5) and Powercor (2005b, p. 5) noted that they were not aware of any regulatory barriers to customers buying improved quality of supply from their distributor, and this is clearly contemplated as an excluded service. Compensation for voltage variation claims The Commission codified the circumstances in which residential and small business customers are entitled to compensation for damage due to voltage variation (surges and brown outs) in the Electricity Industry Guideline No. 11: Voltage Variation Compensation. The Commission recently clarified that this guideline does not negate the insurance companies’ rights to subrogation under the law. Each of the distributors proposed additional expenditure to cover claims made by insurance companies, in anticipation that this clarification will increase the number of claims by insurance companies. This issue is discussed further in Chapter 6. Additionally, CitiPower and Powercor, in their enhanced offerings, proposed operating expenditure over the 2006-2010 regulatory period of $3.2 million and $17.9 million respectively, for enhancements to the management and settlement of voltage variation claims. This additional expenditure represents: • an increase to the current level of compensation based on a “new for old” policy, which allows customers to be compensated for the cost of a new replacement item, instead of being compensated for an item of the same age; and • a “new for old” compensation policy to be available for all domestic customer claims, and for all business customer claims under a specified value, if repair is not economical. 28 Proposed commercial/retail areas to be targeted by CitiPower include Armadale, Camberwell Junction, Prahran/Richmond, Collingwood, South Melbourne, Albert Park and Port Melbourne. October 06 52 Essential Services Commission, Victoria Final Decision AGLE also proposed operating expenditure of $3.6 million to, among other things, increase the level of compensation based on a “new for old” policy where appliances are less than ten years old. Some distributors indicated during meetings with the Commission and the Commission’s technical consultant that the benefits to distributors in terms of fewer complaints and EWOV cases may outweigh the costs of the enhanced scheme. If this is the case, it would represent an efficiency gain for the distributor and should not also be paid for by customers. In response, EWOV considered that the approach to voltage variation claims should be consistent across the distributors. SP AusNet (2005c, p. 26) considered that the benefits of a “new for old” policy were significantly less than its costs, but indicated that it was prepared to enhance the management and settlement of voltage variation claims. United Energy advised that it would require an additional $1 million per annum to settle the voltage variation claims as proposed by AGLE, CitiPower and Powercor. CitiPower (2005b, p. 38) and Powercor (2005b, p. 38) provided further support for their proposals: The key concern for customers is that distributors are currently required to compensate the customer with “like for like” property. In many cases this does not meet customer expectations about the appropriate level of compensation. [CitiPower] [Powercor] believes that increasing the allowed compensation for “new for old” will result in a lower level of complaints both to [CitiPower] [Powercor] and EWOV. Furthermore, CitiPower and Powercor engaged an independent market research consultancy to survey customers on this issue. The results indicate there is some support for a “new for old” compensation policy. However, it was not clear how much customers are prepared to pay or the extent to which this might already be addressed through customers’ individual insurance choices. Stakeholders to this review did not indicate that they were willing to pay for enhancements to the management and settlement of voltage variation claims. Some stakeholders expressed concern during public information forums about the potential for spiralling costs of this scheme as customers install more expensive digital equipment. The objective of the industry scheme is to ensure that distributors accept responsibility for overvoltages, to provide an incentive to minimise them, and to return equipment to the condition it would have been in had the overvoltage not occurred. This is an industry scheme rather than an insurance policy. Where a customer requires a “new for old” replacement, that customer has the option to seek compensation through an insurance claim. The Commission continues to consider expenditure for a voltage compensation scheme based on “like for like” replacement rather than “new for old” is sufficient. The Commission notes that distributors may choose to introduce a “new for old” scheme where they consider the benefits exceed the costs. 2.2.3 Customer service measures Customer service relates to the distributors’ performance in meeting customer requirements such as responding to queries, providing information and meeting timelines. October 06 53 Essential Services Commission, Victoria Final Decision Call centre performance measure Stakeholders’ submissions to the price review have raised two issues in relation to distributors’ call centre performance: • the accuracy of the information provided; and • the timeliness of the response, with some stakeholders indicating they currently wait considerably more than 30 seconds for a call to be answered, including where calls were made on a special number for life threatening situations. Stakeholders noted their concern regarding accuracy of information provided by call centres in the Commission’s public information sessions, and proposed that a dedicated business line may be required (Wodonga and Lilydale). Powercor also identified the accuracy of information provided as an important element of customer service (Comments by Mr Damien Batey of Powercor on ABC Radio Western Victoria, 6 April 2005). The Commission acknowledges that the accuracy of information provided is of concern to customers. Whilst the Commission would also like to monitor the accuracy of information provided to customers when they call the fault line, it recognises that it is difficult to do so on an objective basis.29 Distributors observed that the inclusion of call centre performance in the S-factor scheme (see Chapter 3) will provide an incentive to improve the accuracy of information provided by call centres through their interactive voice response (IVR) so fewer customers elect to speak to an operator (SP AusNet, CitiPower and Powercor). The Commission will continue to monitor the accuracy of information provided by call centres through customer feedback during annual public information sessions and benchmarking surveys. In relation to the timeliness of response, distributors are currently required to report on: • Number of calls to the fault line; • Number of calls to the fault line that are forwarded to an operator; and • Number of calls to the fault line that are forwarded to an operator and answered within 30 seconds. SP AusNet (2005b, p. 45) noted that: The percentage of calls answered within 30 seconds is a measure currently monitored by all distribution businesses in Victoria, in addition to being a standard call centre measure in most industries worldwide. As such, SP AusNet Networks believes this to be an appropriate measure of performance for the call centre. There is currently no targeted level against which the distributors’ performance is monitored and reported. CitiPower and Powercor proposed a targeted level of 70 per cent of calls to be responded to within 30 seconds (including those responded to by their IVR) as an appropriate call centre 29 In the UK, Ofgem surveys customers to provide a subjective assessment of information accuracy. October 06 54 Essential Services Commission, Victoria Final Decision performance measure for the service incentive arrangements. Further, in their enhanced offerings, they proposed expenditure of $6.8 million and $7.8 million respectively over the 2006-10 regulatory period to increase the targeted level from 70 per cent to 85 per cent. SP AusNet proposed a targeted level of 75 per cent of calls to be responded to within 30 seconds (at an expenditure of $3.6 million) or, reflecting current performance, a target of 68 per cent. CUAC believed it reasonable to require that 80 per cent of calls to be responded to within 30 seconds. Origin Energy recommended that the same targeted level apply to all distributors. In its Position Paper, the Commission proposed that a targeted level of 75 per cent be set for each of the distributors. However, CitiPower and Powercor were of the view that there is insufficient data to determine a true underlying performance level, and AGLE noted its concern that the call centre data previously reported to the Commission may not be accurate as there was no financial incentive connected to the results. The Commission reviewed call centre data from 1999 to 2004 for each distributor and considers it sufficient to determine a targeted level for each distributor. In its Draft Decision, the Commission proposed that the targeted levels be set to the actual performance achieved by each distributor in 2003, on the basis that 2003 was representative of future performance. In response, AGLE thought its targeted level was too high while CitiPower and Powercor provided revised data for 2004 that they claim showed 2003 performance was unrepresentative of future performance. Taking into account these comments, the Commission has reviewed the proposed targeted levels to better align with actual performance over recent years. Except for CitiPower and Powercor, the targeted level has been determined using the mid point of the average over the period 2001-04 and the trend line based on the historical data, and projecting the expected response rate for 2005. This approach has been taken because, while the trend line showed a clear improvement over the period, it is based on a small number of data points. Incorporating the average performance provides a conservative approach in setting the targets. In setting SP AusNet’s target, the Commission noted that its call centre performance in 2002 was substantially worse (29 per cent) than the average for 2001-04. The poor performance coincided with a period of underspending and returned to average levels from 2003. The Commission considers that the call centre performance in 2002 does not represent volatility in performance and is not representative of future performance levels. Hence, for SP AusNet, 2002 has not been considered in setting the targeted level. Both Powercor and CitiPower’s call centre performances improved substantially in 2004 when compared to the 2001-03 period. The Commission notes that in May 2004, Powercor announced the completion of a $3 million upgrade to its Bendigo call centre and that the centre would field calls from ETSA Utilities in South Australia and CitiPower (Bendigo Advertiser, 27/5/2004). While CitiPower’s performance shows an approximate 20 per cent improvement from 2003 to 2004, Powercor’s performance shows a more gradual improvement over three years, achieving 85 per cent in 2004. Because these distributors now employ a common call centre, the Commission considers that their future call centre performances are likely to be similar and that targets should be set on a different basis to the other distributors. October 06 55 Essential Services Commission, Victoria Final Decision CitiPower and Powercor’s operating and maintenance expenditure has increased substantially in the 2002-04 period (see Chapter 5). They claim that this increase in expenditure reflects the cost of service improvements including call centre performance. If the targeted level was to be determined from historical averages, than the target would include the poorer performance in previous years and customers would be effectively paying for this service improvement twice; through S-factor rewards because of the lowered target and through the revenue allowed for operating and maintenance expenditure. The Commission considers that the targeted level of call centre performance should reflect the likely service level thorough the 2006-10 period. Accordingly, it has set targeted levels for Powercor based on the trend 2001-04 of Powercor’s actual performance (81.5 per cent). The Commission also considers that CitiPower’s future call centre performance is likely to be closer to its 2004 performance of 80 per cent of calls answered in 30 seconds rather than the trend over the preceding period. Accordingly, the Commission considers that CitiPower’s call centre performance target should be no more than its 2004 performance of 80.1 per cent and should reflect the potential shown in Powercor’s performance target of 81.5 per cent. Accordingly, a targeted level of 80 per cent has been set for CitiPower. Distributors noted that the proposed call centre measure did not indicate how missed calls due to an overload event and how abandoned calls should be treated. United Energy (2005d, p. 9) suggested that the measure should include missed calls due to call centre overload events and Powercor (2005aa, p. 10) suggested that the measure should exclude abandoned calls. In setting the targeted levels, the Commission has included telephone calls answered by an IVR (interactive voice response) within 30 seconds where the IVR provides substantive information and the customer does not request to be connected to an operator. With regard to abandoned calls, the measure will include calls abandoned by the customer within 30 seconds, that is, where the call has been terminated within 30 seconds of being queued for response by a human operator. Only CitiPower (25 per cent) and Powercor (12 per cent) provided the percentage of calls abandoned within 30 seconds, for a single year (2004). The average of these, rounded to 20 per cent, has been applied to other distributors and to CitiPower and Powercor’s data prior to 2004 to derive an appropriate number of abandoned calls in 30 seconds for use in setting the targeted level. This approach provides a lower targeted level than if abandoned calls are not considered in years prior to 2004. To reflect the method used to develop the targeted level, where the time in which a call is abandoned is not measured, distributors will estimate the number of calls abandoned within 30 seconds by taking 20 per cent of the total number of abandoned calls. With regard to missed calls, the Commission notes that most distributors’ systems are not capable of recording the number of missed calls when an overload event occurs. Accordingly, missed calls will not be included in the overall number of calls to the fault call line. CitiPower and Powercor proposed that call centre performance should be normalised by reliability performance when examining historical trends. An examination of available data on network performance and call centre performance across all distributors, however, shows little correlation between call centre performance and daily SAIDI or SAIFI measures. Accordingly, the Commission has set targeted levels for the proportion of calls responded to within 30 seconds based on the above discussion. The targeted levels (as set out in Table 2.5 October 06 56 Essential Services Commission, Victoria Final Decision of Section 2.1.3) are consistent with current levels of performance for each distributor. Therefore, the Commission has not included the additional expenditure proposed by SP AusNet (2005f, p. 11) and by CitiPower and Powercor in their enhanced offerings to increase the proportion of calls responded to within 30 seconds. The distributors will be rewarded for any improvements in the timeliness of the call centre response through the S-factor scheme (see Chapter 3). While AGLE was concerned about the performance of the call centre during electricity network outages in particular, SP AusNet (2005b, p. 26) supported the reporting and monitoring of overload events which are most likely to occur during outages. Accordingly, the Commission will require reporting on the number of overload events that occur in each distributor’s call centre each year. This measure is also consistent with national regulatory reporting requirements (URF 2002, p. 41). The Commission has set a targeted level of zero for the number of overload events for each distributor because the number currently experienced is zero or close to zero, but understands that distributors may not be able to achieve this targeted level under all operating conditions. For example, United Energy (2005d, p. 10) noted that to guarantee a targeted level of zero would require additional expenditure of $600,000 to increase the number of ports available to its call centre. Where the targeted performance has not been achieved, distributors will be required to report the reasons for not meeting the targeted level. Metering related measures Distributors’ accountability for the level of customer service provided to customers in relation to metering will become increasingly important as interval meters are rolled out. In recent submissions to the ACCC’s National Electricity Rules metering derogation process, a number of complaints were raised regarding current service levels provided by the distributors. In addition, following the joint jurisdictional regulators’ review of metrology procedures, this situation may be exacerbated as distributors will continue to have exclusive responsibility for metering services for all ‘small’ customers (defined by the Commission as those who consume less than 160 MWh per annum and have a manually read meter installed). As Origin Energy (2005, pp. 4&7) stated: Given the pending investment of significant capital in interval metering, monitoring the performance of the metering component (prescribed services) is becoming even more important. … Origin is seeking inclusion of interval metering performance standards as these are clearly linked to the requests for additional capital and operating expenditure. Given the classification of most metering services as prescribed services, the distributors’ exclusivity over manually read meter provision (discussed in Chapter 13), and the significant expenditure approved for the interval meter roll out, the Commission indicated in the Position Paper that it will require reporting on some metering-related measures. Customers should be able to understand the service they are paying for and be able to monitor the performance of distributors with exclusive responsibility to provide these services. The Commission’s preliminary view, set out in its Position Paper, was that the distributors should report on the following metering-related measures: October 06 57 Essential Services Commission, Victoria Final Decision • Number of interval meters installed (by meter type); • Number of accumulation meters installed (by meter type); • Number of scheduled meter reads; • Number of reads estimated where meter not read when scheduled; • Number of scheduled reads (including estimates where meter not read) forwarded to the other parties (NEMMCO, retailers) within required timeframes; • Number of special meter reads; • Number of special meter reads not read by requested date; • Number of special meter reads forwarded to the other parties (NEMMCO, retailers) within required timeframes; • Number of meter investigations; • Number of meter investigations completed within required timeframes; • Number of meter investigations where meter not within accuracy range; • Number of families of meters sample tested; • Number of families of meters sample tested outside accuracy range; • Number of requests for a non standard meter to be installed; • Number of non standard meters installed; and • Number of non standard meters installed by requested date. However a number of stakeholders’ submissions to the Position Paper suggested that not all of the measures proposed were appropriate. Whilst these measures were supported by EUCV (2005b, p. 53), the distributors raised a number of concerns. SP AusNet (2005b, p. 27) identified demarcation issues with the use of accredited and audited metering service providers, whereas United Energy (2005c, p. 58) queried the costs of this reporting relative to the benefits. Conversely, AGL Retail (2005, p. 2) indicated that it was concerned about meter changes, however these were not addressed in the measures proposed. United Energy (2005c, p. 59) also suggested that the Commission rely on audits conducted on metering service providers to address issues in this area. After considering all of these submissions, the Commission has decided to require the distributors to report on four measures only against which the Commission will monitor their performance: • Number of interval meters installed (by meter type); • Number of accumulation meters installed (by meter type); • Number of scheduled meter reads; and • Number of reads estimated where meter is scheduled to be read. October 06 58 Essential Services Commission, Victoria Final Decision These four aspects of the distributors’ performance are fundamental to the delivery of prescribed metering services and the data should be readily available for reporting. The Commission will monitor any concerns during the regulatory period through the B2B report card, which is discussed in the following section, and its operational audits. Additional measures may be introduced in the next regulatory period if significant systemic issues are identified. Other customer service measures Retailers have previously raised concerns regarding the timeliness and accuracy of information provided by distributors which is required for the transfer of a customer to a new retailer. There are currently no customer service measures that measure distributors’ performance against this aspect of service. The timeliness and accuracy of information provided by distributors required for the transfer of a customer to a new retailer will become increasingly important to the competitiveness and efficiency of electricity supply to small customers. This factor, and the concerns raised regarding distributors’ customer service, warrants investigating the introduction of additional customer service measures. Distributors were invited to submit proposals on an appropriate measure and indicate how they have considered input from stakeholders on this matter. No distributor proposed an appropriate measure. In general, they did not support any measures regarding the timeliness and accuracy of information relating to transfers of customers to a new retailer. CitiPower and Powercor indicated they do not have system reporting in place to capture their performance in this regard, and that distributors are not wholly in control of the transfer process. Conversely, SP AusNet identified a number of existing industry initiatives to address standing data issues. Other stakeholders, however, identified possible customer service measures. EWOV suggested measuring the number of transfer delays attributable to the distributor (for example, where a delay resulted from a failure to take an actual reading of an accessible meter), measuring the timeframes for special meter reads and meter accuracy tests, and measuring the timeframe for providing results to the retailer. AGL Electricity Sales and Marketing also observed that some distributors may be impacting on the completion of transfers through delays in effecting requested meter changes in a reasonable timeframe. The Commission is concerned that the measurement of transfer delays attributable to a distributor may not be practicable, but proposed the measurement of response times to service orders as an alternative in its Position Paper. In particular, it proposed that the distributors report on the following customer service measures: • Number of service orders (except special meter reads and meter investigations) received, by service order type; • Number of service orders (except special meter reads and meter investigations) processed by due date, by service order type; • Reasons for not processing service orders (except special meter reads and meter investigations) by due date: y Insufficient notice provided by retailer/customer; October 06 59 Essential Services Commission, Victoria Final Decision y Inaccurate information by retailer/customer; y Operator error; y Scheduling of service order by distributor; and y Other. Whilst EWOV (2005b, p. 3) supported the greater level of transparency provided through additional reporting of B2B service standards, a number of stakeholders doubted the net benefit of introducing additional reporting on the proposed customer service measures: • United Energy (2005c, p. 58) questioned whether the benefits to retailers of the additional proposed reporting would warrant the heavy cost of reporting incurred by distributors, and suggested as an alternative that the Commission make greater use of existing NEMMCO reports on timeliness and completeness of data, and regular audits of distributors. • AGL Electricity Sales and Marketing (2005c, p. 2) considered the measures proposed in the Position Paper would not target the typical issues associated with customer transfers. Rather the relevant issues are related to data that follows transfer, and not to the distributor processing the transfer itself. • SP AusNet and United Energy considered that short term initiatives undertaken by the industry and the Commission targeted at resolving issues across the electricity market — such as the current end-to-end (E2E) project — would be more effective in addressing any impediments to transferring a customer to a new retailer than the proposed measures. The Commission’s E2E project (2005, ref to issues paper) is seeking to address the core issues that impact customer transfers. Therefore, any requirement to report on significant transfer related issues will be in response to recommendations arising from that project rather than through the price review process. The Commission also proposed in its Position Paper that distributors and retailers would complete a six monthly “report card” on the B2B capability and performance of the retailers and distributors with whom they had dealt. AGL Electricity Sales and Marketing regarded this as a positive step. AGLE, CitiPower and Powercor considered the report card should be developed with industry over the longer term, recognising the current transition to a national governance framework. The B2B report cards will be developed in consultation with industry for use by the Commission as the basis for investigating and seeking resolution on systemic issues and recurring non compliance issues. The Commission expects the report card to evolve further in response to the E2E project and ongoing national developments. October 06 60 Essential Services Commission, Victoria Final Decision ATTACHMENT 1: EXAMPLES OF WORST SERVED FEEDERS Assume a distributor with annual revenue of approximately $250 million undertakes capital works with a depreciation period of 40 years and a rate of return of 6.5 per cent per annum. Example 1: Capital works - $10 million Saving in GSL payments - $500,000 per annum S-factor impact - 0.3 per cent NPV 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Revenue requirement 250 250 250 250 250 250.4 250.4 250.4 250.4 250.4 Capital works 10 Return on capital 0.7 Depreciation 0.25 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 GSL payments saveda Efficiency carryover 0.3% S-factor impact -0.3% S-factor revenue impact a 0.75 0.75 0.75 0.75 0.75 0.75 -0.75 Total revenue – works done 1920 250.0 250.0 250.5 251.3 251.3 251.7 251.7 251.2 251.2 249.7 Total revenue – works not done 1914 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 These are therefore excluded from the revenue requirement from 2011. In this example, the NPV of revenue if the works were undertaken does not exceed the NPV of revenue if the works were not undertaken by more than the cost of the works. It is therefore not economically efficient to undertake the works in this scenario. October 06 61 Essential Services Commission, Victoria Final Decision Example 2: Capital works - $5 million Saving in GSL payments - $500,000 per annum S-factor impact - 0.5 per cent NPV Revenue requirement 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 250 250 250 250 250 250.4 250.4 250.4 250.4 250.4 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 5 Capital works Return on capital 0.3 Depreciation 0.1 GSL payments saveda Efficiency carryover 0.5% S-factor impact -0.5% S-factor revenue impact a 1.25 1.25 1.25 1.25 1.25 1.25 -1.25 Total revenue – works done 1920 250.0 250.0 250.5 251.8 251.8 251.7 251.7 251.2 251.2 248.7 Total revenue – works not done 1914 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 These are therefore excluded from the revenue requirement from 2011. In this example, the NPV of revenue if the works were undertaken exceeds the NPV of revenue if the works were not undertaken by more than the cost of the works. It is therefore economically efficient to undertake the works in this scenario. October 06 62 Essential Services Commission, Victoria Final Decision Example 3: Capital works - $3 million Saving in GSL payments - $500,000 per annum S-factor impact - 0.3 per cent NPV Revenue requirement 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 250 250 250 250 250 250.4 250.4 250.4 250.4 250.4 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 3 Capital works Return on capital 0.2 Depreciation 0.08 GSL payments saveda Efficiency carryover 0.3% S-factor impact -0.3% S-factor revenue impact a 0.75 0.75 0.75 0.75 0.75 0.75 -0.75 Total revenue – works done 1918 250.0 250.0 250.5 251.3 251.3 251.0 251.0 250.5 250.5 249.0 Total revenue – works not done 1914 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 250.0 These are therefore excluded from the revenue requirement from 2011. In this example, the NPV of revenue if the works were undertaken exceeds the NPV of revenue if the works were not undertaken by more than the cost of the works. It is therefore economically efficient to undertake the works in this scenario. October 06 63 Essential Services Commission, Victoria Final Decision ATTACHMENT 2: Table 1: Targeted levels for unplanned SAIDI Network type AGLE CitiPower Powercor SP AusNet TARGETED LEVELS — RELIABILITY MEASURES 2005 targeted level 2006 targeted level – as proposed by the distributor 2006 targeted level – Commission’s Final Decision Urban Short rural CBD 73 113 73 113 As proposed by distributor 16 16 Reduced to 14 minutes based on historical performance Urban 35 35 As proposed by distributor Urban Short rural Long rural 98 118 98 145 As proposed by distributor 2005 target 297 297 As proposed by distributor Urban 107 109 Short rural 187 185 a Long rural 298 300 a As proposed by distributor a As proposed by distributor for 2006 – no change over period As proposed by distributor for 2006 – no change over period As proposed by distributor for 2006 – no change over period Urban 2005 targeted level – no change over United 59 58 period (expenditure for reliability Energy improvement not provided) Short 2005 targeted level – no change over 96 95 rural period (expenditure for reliability improvement not provided) a Changes in the targeted level between 2005 and 2006 arise from a change in methodology for counting customers and movement of customers between network types October 06 64 Essential Services Commission, Victoria Final Decision Table 2: Targeted levels for unplanned SAIFI Network type AGLE CitiPower Powercor SP AusNet 2005 targeted level 2006 targeted level – as proposed by the distributor 2006 targeted level – Commission’s Final Decision Urban Short rural CBD 1.27 1.27 As proposed by distributor 2.25 2.25 As proposed by distributor 0.25 0.25 As proposed by distributor Urban 0.80 0.80 As proposed by distributor Urban Short rural Long rural 1.63 1.63 1.80 2.10 As proposed by distributor 2005 targeted level 3.50 3.30 As proposed by distributor Urban 1.78 1.82 Short rural 2.75 2.73 a Long rural 4.26 4.28 a a As proposed by distributor for 2006 – no change over period As proposed by distributor for 2006 – no change over period As proposed by distributor for 2006 – no change over period Urban 2005 targeted level – no change over United 1.06 1.04 period (expenditure for reliability Energy improvement not provided) Short 2005 targeted level – no change over 2.03 2.04 rural period (expenditure for reliability improvement not provided) a Changes in the targeted level between 2005 and 2006 arise from a change in methodology for counting customers and movement of customers between network types October 06 65 Essential Services Commission, Victoria Final Decision Table 3: Targeted levels for planned SAIDI Network type AGLE CitiPower Powercor SP AusNet United Energy 2005 targeted level 2006 targeted level – as proposed by the distributor 2006 targeted level – Commission’s Final Decision Urban Short rural CBD 6.0 6.0 As proposed by distributor 14.0 14.0 As proposed by distributor 5.9 5.9 As proposed by distributor Urban 9.9 9.9 As proposed by distributor Urban Short rural 16.0 16.0 As proposed by distributor 32.0 32.4 Increased to 35 mins based on historical performance and consistency of the target for short rural feeders Long rural 71.0 73.5 Reduced to 70 mins based on historical performance and consistency of the target for long rural feeders Urban 9.0 20.0 Increased to 16 mins relative to 2005 targeted level based on historical performance and consistency of the target for urban feeders. Short rural 21.0 60.0 Increased to 35 mins relative to 2005 targeted level based on historical performance and consistency of the target for short rural feeders. Long rural 60.0 72.0 Urban 13.0 22.0 Short rural 21.0 45.0 Increased to 70 mins relative to 2005 targeted level based on historical performance and consistency of the target for long rural feeders. Increased to 16 mins relative to 2005 targeted level based on historical performance and consistency of the target for urban feeders Increased to 35 mins relative to 2005 targeted level based on historical performance and consistency of the target for short rural feeders. October 06 66 Essential Services Commission, Victoria Final Decision Table 4: Targeted levels for planned SAIFI Network type AGLE CitiPower Powercor SP AusNet United Energy 2005 targeted level 2006 targeted level – as proposed by the distributor 2006 targeted level – Commission’s Final Decision Urban Short rural CBD N/A As proposed by distributor N/A 0.03 0.08 N/A 0.02 As proposed by distributor Urban N/A 0.03 As proposed by distributor Urban Short rural N/A 0.09 As proposed by distributor N/A 0.14 Increased to 0.15 relative to distributor’s proposal based on historical performance Long rural N/A 0.25 As proposed by distributor Urban N/A 0.13 Reduced to 0.09relative to distributor’s proposal based on historical performance and consistent with target for Powercor’s urban feeders Short rural N/A 0.29 Reduced to 0.15 relative to distributor’s proposal based on historical performance Long rural N/A 0.34 Urban N/A 0.11 Short rural N/A 0.23 Reduced to 0.30 relative to distributor’s proposal based on historical performance Reduced to 0.10 relative to distributor’s proposal based on historical performance Reduced to 0.15 relative to distributor’s proposal based on historical performance October 06 67 As proposed by distributor Essential Services Commission, Victoria Final Decision Table 5: Targeted levels for MAIFI Network type AGLE CitiPower Powercor SP AusNet United Energy 2005 targeted level 2006 targeted level – as proposed by the distributor 2006 targeted level – Commission’s Final Decision Urban 0.4 0.8 As proposed by distributor, based on historical performance Short rural 1.8 2.6 As proposed by distributor, based on historical performance CBD 0.0 0.05 Increased to 0.03 relative to targeted level based on historical performance Urban 0.3 0.3 As proposed by distributor for 2006 – no change over period Urban 5.3 2.0 Reduced to 1.5 based on historical performance and consistency with target for urban feeders for other distributors (except SP AusNet) Short rural 12.6 3.5 Reduced to 3.1 relative to targeted level based on historical performance Long rural 20.1 9.7 Reduced to 9.0 relative to targeted level based on historical performance Urban 3.6 3.5 As proposed by distributor, based on historical performance Short rural 8.6 5.9 As proposed by distributor, based on historical performance Long rural 15.7 13.5 As proposed by distributor, based on historical performance Urban 1.2 1.4 As proposed by distributor, based on historical performance Short rural 3.3 3.4 As proposed by distributor, based on historical performance October 06 68 Essential Services Commission, Victoria Final Decision 3 SERVICE INCENTIVE MECHANISMS A key element of incentive-based regulation is to provide adequate incentives for distributors to achieve the level of service that is valued by customers. Mechanisms to ensure sufficient incentives exist for distributors to achieve service levels valued by customers, and for which they are accountable, are discussed in detail in this chapter. Financial incentives on service are also designed to achieve an appropriate balance with incentives to minimise expenditure. The experience to date suggests that, in most cases, the distributors have been able to improve service performance while also undertaking less expenditure than was forecast at the last price review. The Commission is keen to ensure that these benefits are sustained into the future. The Commission’s decision on the service incentive arrangements aims to ensure that the services valued by customers are identified, measured and provided where the value of these services is more than or at least equal to the cost of providing them. Therefore, the Commission has reviewed the measures that are linked to the service incentive arrangements and the value of the incentives provided to distributors under the arrangements to ensure that they align with the value that customers place upon those services. The Commission is of the view that this, in combination with the expanded reporting requirements being placed on the distributors (see Chapter 2), ensures that distributors are held sufficiently accountable for the services they provide and for which customers pay. The service incentive mechanisms for the 2006-10 regulatory period consist of the following elements: • the service incentive scheme, or S-factor scheme; and • the Guaranteed Service Level (GSL) payments scheme. Under the S-factor scheme, a distributor’s allowed revenue (through average prices for all customers) is increased (or decreased) based on changes in average performance from year to year. Under the GSL payments scheme, payments are made directly to customers where the performance received by those customers is worse than a specific threshold. This Chapter sets out the Commission’s decision on service incentive mechanisms for the 2006-10 regulatory period in Section 3.1, while the decision is explained in Section 3.2. The S-factor scheme, GSL payments scheme and other service incentive arrangements — the directors’ sign off on regulatory accounts and the health card — are discussed in Sections 3.2.1, 3.2.2 and 3.2.3 respectively. Exclusions from the service incentive scheme are set out in Section 3.2.4. October 06 69 Essential Services Commission, Victoria Final Decision 3.1 Final Decision 3.1.1 S-factor scheme The price control formula for the 2006-10 regulatory period includes a service adjustment or S-factor term (St), which is calculated in accordance with the following formula: St = (1 + S t' ) (1 + S t' −6) where St' = St'' − Sbank ,t + S bank ,t −1 * (1 + pretaxWACCD ) r ,n r ,n r ,n '' S t = ∑∑ st (GAPt − 2 − GAPt −3) r St' − 6 (a) n if calendar year t is prior to the calendar year ending 31 December 2012: St' − 6 = St − 6 1 − X 0, S where: S t −6 is the value of S t calculated for the calendar year t − 6 in accordance with clause 2.3.8(ii) of the price controls dated September 2000; and X 0, S is the value of X t for the calendar year 2006, calculated exclusive of the impacts of the S-factor, as set out in clause 2.3.9(iii) of Volume 2; (b) r if calendar year t is after the calendar year ending 31 December 2011, is the value of S t' calculated for the calendar year t − 6 in accordance with this clause. refers to the following indicators for 2006 and 2007: unplanned interruption frequency, unplanned interruption duration, and planned minutes off supply; and from 2008: unplanned interruption frequency, unplanned minutes off supply, momentary interruption frequency and call centre performance. October 06 70 Essential Services Commission, Victoria Final Decision refers to the following network types: CBD, urban and rural. n pretaxWACCD refers to the pretax value of the weighted average cost of capital for prescribed distribution use of system services as set out in Chapter 9. r ,n is the incentive rate for indicator r and network type n in year t as set out in Tables 3.1 and 3.2. st r,n GAP t − 2 is the performance gap for indicator r and network type n in year t-2 and is calculated as follows: GAPt − 2 = TARt − 2 − ACT t − 2 r ,n r ,n r ,n where r ,n is the distributor’s S-factor target for indicator r and network type n in calendar year t-2 as set out in Tables 3.3 and 3.4. TAR t − 2 r ,n ACT t − 2 r ,n GAPt −3 is the distributor’s actual performance for indicator r and network type n in calendar year t-2, excluding the impact of excluded events.30 is the performance gap for indicator r and network type n in year t-3 and is calculated as follows: GAPt −3 = TARt −3 − ACT t −3 r ,n r ,n r ,n where: r ,n is the distributor’s S-factor target for indicator r and network type n in calendar year t-3 as set out in Tables 3.3 and 3.4. TAR t −3 r ,n ACT t −3 is the distributor’s actual performance for indicator r and network type n in calendar year t-3, excluding the impact of excluded events. and: (a) 30 If calendar year t is the calendar year ending 31 December 2008, and if indicator r is unplanned interruption frequency, unplanned interruption duration or planned minutes off supply, and the distribution business is Excluded events are events approved by the Commission in accordance with Clauses 2.3.13 and 2.3.14 of Volume 2, as discussed in Section 3.2.4. October 06 71 Essential Services Commission, Victoria Final Decision SP AusNet,31 then ACTt −r ,3n is the value of ACTt −r ,2n determined in the calendar year ending 31 December 2007 multiplied by 1.022;32 (b) S bank ,t If calendar year t is the calendar year ending 31 December 2008, and if indicator r is momentary interruption frequency or call centre performance, then GAPt r−,3n is zero. is the amount of the service adjustment that is deferred from one year to the next. The amount deferred in year t must be applied in year t+1. S bank ,t must have the same sign as S t'' and the absolute value of S bank ,t must be equal to or less than the absolute value of S t'' . S bank ,t −1 is the value of S bank calculated in year t-1. The incentive rates str ,n for incentive rate r and network type n for 2006 and 2007 are provided in Table 3.1, and the incentive rates str ,n for incentive rate r and network type n from 2008 are provided in Table 3.2. The S-factor targets for 2003 to 2005 that apply to the calculation of the S-factor in 2006 and 2007 are provided in Table 3.3 and the S-factor targets for 2006 onwards that apply to the calculation of the S-factor from 2008 are provided in Table 3.4. Table 3.1: Incentive rates, by distributor and network type, 2006-07 Network type AGLE CitiPower Powercor SP AusNet United Energy 31 32 Unplanned interruption frequency Unplanned interruption duration Planned minutes off supply (%/ 0.01 interruption) (%/minute) (%/minute) Urban 0.0240 0.0371 0.0101 Rural 0.0014 0.0041 0.0006 CBD 0.0289 0.0073 0.0113 Urban 0.0343 0.0360 0.0146 Urban 0.0400 0.0655 0.0148 Rural 0.0266 0.0635 0.0078 Urban 0.0161 0.0338 0.0067 Rural 0.0244 0.0905 0.0089 Urban 0.0324 0.0515 0.0136 Rural 0.0021 0.0075 0.0011 Formerly TXU Networks. In 2008 only, SP AusNet’s actual reliability performance for the calendar year 2005 will be adjusted by 2.2 per cent to account for a change in the methodology for counting customers – see Section 2.2.1 October 06 72 Essential Services Commission, Victoria Final Decision Table 3.2: Incentive rates, by distributor and network type, from 2008 Network type Unplanned interruption frequency (%/ 0.01 interruption) AGLE CitiPower Powercor SP AusNet United Energy Unplanned minutes off supply (%/minute) Momentary interruption frequency (%/0.01 interruption) Urban 0.0486 0.0865 0.0042 Rural 0.0079 0.0113 0.0007 CBD 0.0524 0.1057 0.0000 Urban 0.0276 0.0479 0.0024 Urban 0.0207 0.0393 0.0017 Rural 0.0294 0.0421 0.0025 Urban 0.0200 0.0333 0.0017 Rural 0.0271 0.0446 0.0023 Urban 0.0515 0.0889 0.0043 Rural 0.0026 0.0037 0.0002 Call centre (%/per cent) AGLE -0.0380 CitiPower -0.0441 Powercor -0.0398 SP AusNet -0.0325 United Energy -0.0360 October 06 73 Essential Services Commission, Victoria Final Decision Table 3.3: AGLE S-factor targets, by distributor and network type, 2003-05 Network type Year Unplanned interruption frequency Unplanned interruption duration (minutes) Planned minutes off supply Urban 2003 1.32 59 6 2004 1.30 58 6 2005 1.27 58 6 2003 2.25 50 14 2004 2.25 50 14 2005 2.25 50 14 2003 0.25 63 5.9 2004 0.25 63 5.9 2005 0.25 63 5.9 2003 0.89 51 9.9 2004 0.85 48 9.9 2005 0.80 44 9.9 2003 1.67 64 18 2004 1.66 62 17 2005 1.63 60 16 2003 2.89 84 56 2004 2.76 82 53 2005 2.64 81 51 2003 1.86 60 9 2004 1.82 60 9 2005 1.78 60 9 2003 3.56 69 39 2004 3.39 69 39 2005 3.22 69 39 2003 1.26 58 13 2004 1.17 57 13 2005 1.06 56 13 2003 2.40 49 21 2004 2.24 48 21 2005 2.03 47 21 Rural CitiPower CBD Urban Powercor Urban Rural SP AusNet Urban Rural United Energy Urban Rural October 06 74 Essential Services Commission, Victoria Final Decision Table 3.4: AGLE CitiPower Powercor SP AusNet United Energy S-factor targets, by distributor and network type, 2006-10 Network type Unplanned interruption frequency Unplanned minutes off supply Momentary interruption frequency Urban 1.27 73.0 0.8 Rural 2.25 113.0 2.6 CBD 0.25 15.5 n/aa Urban 0.80 35.0 0.3 Urban 1.63 98.0 1.5 Rural 2.64 213.8 5.6 Urban 1.78 107.0 3.5 Rural 3.22 222.2 8.5 Urban 1.06 59.0 1.4 Rural 2.03 96.0 3.4 Call centre performance, 2006-10 (per cent) a AGLE 75 CitiPower 80 Powercor 81 SP AusNet 70 United Energy 72 Momentary interruption frequency for the CBD network has not been included in the S-factor scheme 3.1.2 GSL payments scheme As a minimum, distributors are required to make a Guaranteed Service Level (GSL) payment where: • the customer experiences more than 20 hours of unplanned sustained interruptions33 in a year ($100) or more than 30 hours of unplanned sustained interruptions in a year ($150) or more than 60 hours of unplanned sustained interruptions in a year ($300), excluding the impact of excluded events;34 • the customer experiences more than 10 unplanned sustained interruptions in a year ($100) or more than 15 unplanned sustained interruptions in a year ($150) or more than 30 unplanned sustained interruptions in a year ($300), excluding the impact of excluded events; 33 34 A sustained interruption is an interruption of duration longer than one minute Excluded events are events approved by the Commission (see Section 3.2.4). October 06 75 Essential Services Commission, Victoria Final Decision • the customer experiences more than 24 momentary interruptions in a year ($25) or more than 36 momentary interruptions in a year ($35), excluding the impact of excluded events; • the distributor is more than 15 minutes late for an appointment ($20); • the distributor does not supply electricity to a customer’s supply address on the day agreed ($50 per day to a maximum of $250); or • a person reports a faulty public light and that public light is not repaired within 2 business days of being notified, and the person is the occupier of the immediately neighbouring residence or business ($10). Where a distributor makes an appointment with a customer, the distributor must specify a window: • no greater than 2 hours where the customer or their representative is required, or chooses, to be in attendance; and • no greater than 1 day where the customer or their representative is not required, and does not choose, to be in attendance, unless an alternative appointment window has been agreed to by the customer or their representative. A request from a retailer for a special meter read relating to the move in of a new customer to an existing premise is not considered to be an appointment for the purposes of the GSL payments scheme unless the customer or their representative is required, or chooses, to be in attendance. The appointment window must be specified to the customer or their representative by no later than 5 pm on the day prior to the appointment. Where a connection request has been made to the distributor by a customer or their representative, and no date for connection has been agreed between the distributor and the customer or their representative, the distributor must connect the supply address within 10 business days. The annual expenditure that has been included in the distributors’ revenue requirements for the 2006-10 regulatory period for GSL payments is set out in Table 3.5. Table 3.5: Annual expenditure for GSL payments, by distributor, real $2004 AGLE CitiPower Powercor SP AusNet United Energy 17,250 1,000 1,283,000 4,314,500 254,000 3.1.3 Other service incentive arrangements Long term reliability On an annual basis, the Commission will include a “health card” on each distributor in the Comparative Performance Report. The structure of the “health card” intended for the first October 06 76 Essential Services Commission, Victoria Final Decision Comparative Performance Report in the 2006-10 regulatory period is provided as an attachment to this chapter. When submitting the regulatory accounting statements for the distributor, the distributor’s directors must also confirm in writing that the distributor will, for at least the next twelve months, have available to it the financial resources and facilities and management resources required to meet its obligations under the Electricity Distribution Code to: • meet reasonable customer expectations of reliability of supply; • use best endeavours to meet or exceed the targeted reliability levels required by the Price Determination; and that the underlying risks of a deterioration in reliability (that is, an increase in the probability of an interruption) are not materially increasing. At any time a distributor’s directors become aware that the underlying risks of a deterioration in reliability (that is, an increase in the probability of an interruption) are materially increasing, they must advise the Commission. Distribution losses The distributors must include a specific statement in each of their annual Distribution System Planning Reports and Transmission Connection Planning Reports confirming that the cost of distribution losses has been considered in identifying the least cost options for network augmentations. Further, during the annual process to approve distribution loss factors, the Commission will continue to monitor the levels of distribution losses to ensure that they remain within an appropriate range, and assess the reconciliation between actual losses and forecast losses as required by the National Electricity Rules. 3.1.4 Operation of the service incentive mechanisms Distributors may apply to have the impacts of the following events excluded from the calculation of the S-factor and from the requirement to make certain GSL payments: • for the reliability measures of the S-factor scheme and for the GSL payments for poor reliability: y supply interruptions made at the request of the distribution customer affected; y load shedding due to a shortfall in generation, but not a shortfall in embedded generation that has been contracted to provide network support except where prior approval has been obtained from the Commission; y supply interruptions caused by a failure of the shared transmission network; y supply interruptions caused by a failure of transmission connection assets, to the extent that the interruptions were not due to inadequate planning of transmission connections; and October 06 77 Essential Services Commission, Victoria Final Decision y where prior written approval has been obtained from the Commission, load shedding due to a shortfall from demand side response initiatives. • for the reliability measures of the S-factor scheme calculated in years 2006 and 200735, widespread supply interruptions due to rare events, which were not reasonably able to be foreseen, to the extent that the distribution business was not reasonably able to mitigate their impact; and • for the GSL payments scheme from 2006 and the S-factor scheme from 2008,36 supply interruptions on a day where the unplanned sustained interruption frequency, summed across all network types, exceeds the threshold as set out in Table 3.6. On these days, when calculating the reliability measures of the S-factor scheme, the mean frequency and duration of interruptions as set out in Table 3.6 must be substituted for that day’s actual frequency and duration of interruptions. On these days, when calculating the call centre performance measure of the S-factor scheme, the call centre performance data for that day is excluded. Table 3.6: Daily unplanned interruption frequency threshold and mean daily duration and frequency of interruptions, by distributor Daily unplanned sustained interruption frequency threshold a Mean daily unplanned sustained interruption frequency Mean daily unplanned sustained interruption duration Mean daily momentary interruption frequency Urban CBD/ Rurala Urban CBD/ Rurala Urban CBD/ Rurala AGLE 0.120 0.003 0.013 0.207 0.682 0.003 0.007 CitiPower 0.066 0.002 0.001 0.085 0.028 0.001 0.000 Powercor 0.110 0.004 0.007 0.287 0.582 0.004 0.015 SP AusNet 0.190 0.006 0.010 0.363 0.748 0.016 0.017 United Energy 0.100 0.003 0.005 0.141 0.272 0.004 0.008 CBD for CitiPower, rural for AGLE, Powercor, SP AusNet and United Energy 3.2 Reasons for the Decision 3.2.1 S-factor scheme To encourage the distributors to meet or exceed the targets set for unplanned CAIDI, unplanned SAIFI and planned SAIDI37, the Office of the Regulator-General (ORG) introduced a financial 35 36 37 Based on actual performance prior to 2006. Based on actual performance from 2006. CAIDI, SAIFI and SAIDI have been defined in the Glossary and Abbreviations and described in Chapter 2. October 06 78 Essential Services Commission, Victoria Final Decision incentive scheme by the addition of an S-factor into the price control formula from 2001. The S-factor rewards distributors with additional revenue through higher average prices where actual performance improves relative to the reliability targets, and penalises them with lower revenue through lower average prices where actual performance deteriorates relative to the reliability targets. The Commission has sought to refine the current scheme in light of stakeholder comments and experience to date. It has incorporated the following measures into the S-factor scheme for the 2008-12 period, based on performance during the 2006-10 period: • minutes off supply measure (unplanned SAIDI); • sustained supply interruption measure (unplanned SAIFI); • momentary supply interruption measure (MAIFI); and • call centre performance measure (proportion of calls responded to within 30 seconds). The S-factor that is calculated in 2006 and 2007, based on the performance during 2004 and 2005, will use the existing measures as set out in the Price Controls dated September 2000. The reasons for including these measures in the S-factor scheme, the incentive rates and weightings to apply to the measures, and the targets for the measures are discussed in this section. Measures for inclusion in the S-factor scheme The Commission consulted on a number of refinements to the measures in the S-factor scheme: • Replace unplanned CAIDI with unplanned SAIDI — the Commission was concerned to ensure that the incentive rate for a given interruption remained constant over the regulatory period. • Include planned SAIDI in a total SAIDI measure — the Commission was concerned that the inclusion of planned SAIDI as a separate measure may adversely impact line worker safety by creating demands for increased live line work. The Commission also recognised the balance between planned and unplanned interruptions.38 • Include a MAIFI measure — the Commission considered sufficient historical data on momentary interruptions was now available to establish appropriate targets for this measure and include it within the S-factor scheme, as foreshadowed in the last price review. • Include a customer service measure — the Commission considered this addition would provide an incentive for the distributors to meet or exceed the targets set for the customer service measure. • The inclusion of other measures. 38 An increase in the number of planned interruptions may lead to a decrease in unplanned interruptions, and vice versa, noting that customers generally value a reduction in the number of unplanned interruptions more than a reduction in the number of planned interruptions. October 06 79 Essential Services Commission, Victoria Final Decision Unplanned SAIDI measure to replace CAIDI measure Each of the distributors supported replacing unplanned CAIDI with unplanned SAIDI although CitiPower (2005b, p. 33) and Powercor (2005b, p. 34) noted that the inclusion of SAIDI has the effect of amplifying the incentive and therefore the risk of this measure compared to CAIDI. This is because SAIDI is a function of both interruption frequency (the fixed component) and interruption duration (the variable component), while CAIDI is a measure of interruption duration only. Hence the inclusion of SAIDI and SAIFI measures in the modified incentive scheme provides an increased focus on interruption frequency when compared to the existing scheme based on SAIFI and CAIDI. The Commission notes this concern and considers that this is addressed through the appropriate weighting of the interruption frequency and interruption duration measures. This is discussed later in this section. The Commission has retained its Draft Decision that unplanned CAIDI will be replaced by unplanned SAIDI in the S-factor scheme for the 2006-10 regulatory period. Planned SAIDI measure None of the distributors supported the Commission’s proposal to include planned SAIDI in the S-factor scheme as a total SAIDI measure. CitiPower, Powercor, SP AusNet and United Energy were of the view that planned SAIDI should be removed from the S-factor scheme to avoid tension with safe work practices and increasing safety initiatives. However, given the Commission’s proposal to combine planned SAIDI and unplanned SAIDI into a total SAIDI measure, CitiPower (2005a, p. 39) and Powercor (2005a, p. 39) stated their preference to include planned SAIDI as a separate indicator rather than a combined measure as the customer impact of planned interruptions is significantly less than for unplanned interruptions, and therefore the incentive rate for planned SAIDI should be less than for unplanned SAIDI. On the other hand, CUAC and Origin Energy disagreed with the exclusion of planned SAIDI from the S-factor scheme. Origin Energy (2005, p. 8) stated: The distributors’ capex proposals should include the cost of conducting all planned work safely as well as cost effectively. Origin is concerned that without a financial incentive on planned SAIDI the distributors may be able to artificially lower their costs by taking longer and more frequent outages in support of planned works rather than organising their work plans to (safely) deliver projects while minimising supply interruptions. CUAC (2005b, p. 1) stated that, as rural customers rely on electricity for water pumps, it was of the view that planned SAIDI should continue to be included in the S-factor scheme. However, the Commission notes that where there is a planned interruption, notice of that interruption is required to be provided to customers and so customers are able to store water in advance for use during the interruption. Conversely, unplanned interruptions are more inconvenient for customers as they are unable to plan for the interruption in advance. Moreover, planned interruptions are required to undertake works in the electricity network, which may lead to a October 06 80 Essential Services Commission, Victoria Final Decision reduction in unplanned interruptions. Accordingly, the Commission considers that customers value a reduction in unplanned interruptions more than planned interruptions. Given the concerns raised that an incentive on planned SAIDI may create a tension with safe work practices and evidence that customers value a reduction in unplanned interruptions rather than planned interruptions (KPMG 2003), the Commission’s decision is that planned SAIDI should not be included in the S-factor scheme but that unplanned SAIDI should be included as a separate measure. In its Position Paper, the Commission did, however, propose that it would continue to monitor the distributors’ actual performance against planned SAIDI targets over the 2006-10 regulatory period. The Position Paper further stated that, should a distributor’s performance against planned SAIDI deteriorate significantly (more than 20 per cent above the targeted level), the Commission would reserve the right to include the measure in the S-factor scheme at any time during the regulatory period for that distributor(s). However, the Commission recognises that there are a number of problems and difficulties in implementing the proposal contained in its Position Paper, for example: • determining the extent to which changes in planned SAIDI are appropriate responses to changed work practices or growth in capital works; • the size of the potential penalty that is sufficient to act as an efficient deterrent; • the added complexity of the price control formula that would be required to allow the additional measure to be introduced within a regulatory period; and • the regulatory uncertainty that would result from the threat to introduce such an arrangement within a regulatory period. Further, the Commission already has regulatory processes in place to deal with a distributor’s systemic non-compliance with the conditions set out in its distribution licence. These processes can be appropriately applied in respect of the specific circumstances that might arise in the future. Given these problems and difficulties in implementing the proposal contained in the Position Paper, the Commission has decided not to proceed with that proposal. However, the Commission will continue to monitor and report on planned SAIDI during the 2006-10 regulatory period, and if any of the concerns identified by Origin Energy materialise, the Commission will address them through its compliance program. Momentary interruptions (MAIFI) measure Each of the distributors supported including MAIFI in the S-factor scheme, although CitiPower and Powercor’s support for including MAIFI was predicated on a change in the definition of MAIFI from a less than one minute duration interruption to a less than three minute duration interruption. As discussed in Chapter 2, the Commission has retained the one minute definition of MAIFI. October 06 81 Essential Services Commission, Victoria Final Decision The Commission considers there is sufficient historical data on which to set targets and therefore has included MAIFI in the S-factor scheme. Customer service measure In relation to customer service, the Commission proposed to include a measure of call centre performance in the S-factor scheme. No other measure of customer service was suggested by stakeholders. CitiPower, Powercor, and SP AusNet supported the proposal. Conversely, United Energy (2005c, p. 57) supported the inclusion of a call centre performance measure only if: first, the scheme delivers symmetrical outcomes; second, the values placed on rewards and penalties are appropriate; third, that performance is measured in an appropriate manner and at appropriate intervals; and fourth, stakeholders see it as beneficial. AGL ES&M and AGLE expressed concern that the historical data is not sufficiently robust to support a financial incentive. Similarly, CitiPower and Powercor were of the view that the targets and incentive rates should be set conservatively given the shortage of data. The Commission is of the view that call centre performance should be included in the S-factor scheme. Stakeholders generally support its inclusion, and the Commission considers that its inclusion increases the distributors’ accountability for providing the required call centre performance. As discussed in Section 2.2.3, historical data is available for the period 1999 to 2004, which is sufficient to set targets. Accordingly, the Commission has included a call centre measure in the S-factor scheme. Reliability experienced by the worst served customers measure In the 2001-05 period, the S-factor scheme provides an incentive to maintain average reliability, while the GSL payments scheme provides an additional incentive to improve reliability to the worst served customers. The distributors were invited to propose an alternative S-factor scheme for the 2006-10 regulatory period that includes service measures based on customers who receive worse than average reliability, rather than measures based on average reliability. None of the distributors proposed such a scheme. Although SP AusNet provided in principle support, distributors in general did not support a service incentive scheme based on the worst served customers. CitiPower (2005b, p. 40) and Powercor (2005b, p. 40) were of the view that such an approach would: … result in a cross subsidy, broadly from urban to rural customers, and establish a perverse incentive to sacrifice the average performance of the majority of customers who are not in the target group. Conversely, Origin Energy supported such an approach if it could be demonstrated that all customers are willing to pay more to increase reliability to the worst served customers. The Energy Users Coalition of Victoria (EUCV) (2005d, p. 71) and CUAC (2005b, p. 11) also disagreed with CitiPower and Powercor, and supported an S-factor scheme based on worst served customers: October 06 82 Essential Services Commission, Victoria Final Decision CUAC does not believe that cross-subsidies are inherently problematic. Rather we see cross-subsidising as a legitimate tool to improve the services to particular groups of customers. Although the GSL scheme targets the worst served customers we do not believe that the GSL payments are a strong enough incentive for the DBs to improve the service levels in some of the state’s worst served areas. CUAC would therefore support a S-factor scheme that targeted the worst served 15 per cent of customers (as in South Australia) because we believe that a scheme based on averages does not rightly reflect the discrepancy in service received by customers in East Gippsland compared to, for example, West Gippsland. The South Australian service incentive scheme mentioned by CUAC, based on worst served customers, is supported by a willingness to pay study that indicated South Australian customers are prepared to pay more to improve the reliability to others.39 In contrast, no such research has been undertaken in Victoria. As noted in Chapter 2, reliability for worst served customers has generally improved (over 1999 to 2004), indicating that the GSL payments scheme has been effective in delivering improvements. However, reliability experienced by the worst served customers remains significantly worse than the reliability experienced on average by customers in Victoria. Given the higher cost to serve some customers, it is expected that there will always be some customers who are substantially worse served than others. In the absence of evidence that Victorian electricity customers are prepared to pay more to improve the reliability of the worst served customers, the Commission has not included a measure for the worst served customers in the S-factor scheme, but notes that the use of the Value of Customer Reliability (VCR) in setting the incentive rates implies a cross subsidy between customers who receive improved reliability by those who do not.40 However, notwithstanding the GSL payments to the worst served customers (refer Section 3.2.2), the Commission remains concerned at the level of accountability that the distributors should have for reliability provided to the worst served customers. The Commission proposed in its Position Paper to continue to monitor the performance of the reliability experienced by the worst served 15 per cent of customers. The Position Paper further stated that, should the reliability for these customers of a distributor deteriorate significantly (more than 20 per cent above the 2003 level), the Commission would reserve the right to include reliability measures for the worst served 15 per cent of customers in the S-factor scheme at any time during the regulatory period for that distributor. However, CUAC (2005b, p. 2) indicated that it: 39 40 A scheme targeting worst served customers was introduced into South Australia from 1 July 2005, based on the total minutes off supply experienced by the worst served 15 per cent of customers (ESCOSA 2004, p. 43). All customers will pay through increased tariffs for the cost of service improvements to those customers supplied from areas of the distributors’ networks demonstrating the highest benefits for improvement projects. October 06 83 Essential Services Commission, Victoria Final Decision … would like to see more reasoning for why significant deterioration (defined as 20 per cent) is regarded as the requirement for regulatory intervention. In our view, a much lower level of deterioration should warrant the introduction of regulatory incentive mechanisms … We do not think the ESC should expect proof that all customers are willing to pay more to improve reliability (of the 15 per cent worst served), before taking action. Conversely, some distributors (SP AusNet, CitiPower and Powercor) were uncertain about how reliability measures for the worst served customers would be incorporated. CitiPower (2005b, p. 3) and Powercor (2005b, p. 3) considered the proposed approach would introduce considerable uncertainty and financial risk and noted that additional measures would double the weight on reliability for the worst served and might be imposed on a distributor notwithstanding that it was providing better average reliability than another distributor They further queried whether any measures imposed would be removed subsequently if poor performance improved. The Energy Networks Association (ENA) (2005, p. 8) considered the Commission’s proposal would introduce regulatory uncertainty. The Commission’s proposal to leave open the potential for effectively retrospective penalties in the S-factor regime if service declines by more than twenty per cent in some areas introduces asymmetric risk for distribution businesses and adversely affects regulatory certainty. The ENA considers that regulatory certainty is best delivered through a clear ex ante articulation of the regulatory regime that will apply at the outset of the regulatory period, without post hoc penalties applied outside of an incentive regime. The Commission recognises the benefit of incentivising distributors to avoid an increasing deterioration in performance to worst served customers and has addressed this through introducing multiple thresholds for, and increasing the level of, GSL payments. It recognises that there are a number of problems and difficulties in implementing the proposal contained in its Position Paper, for example: • determining the size of the potential penalty that is sufficient to act as an efficient deterrent; • the added complexity of the price control formula that would be required to allow the additional measure to be introduced within a regulatory period; and • the issues identified by distributors above. Further, the Commission already has regulatory processes in place to deal with issues of systemic non-compliance with the conditions set out in distributors’ licences. Accordingly, the Commission has not included a mechanism for introducing a reliability measure for the worst served customers into the S-factor scheme. However, the Commission will continue to monitor and report on the reliability experienced by the worst served customers during the 2006-10 regulatory period. If there is a significant deterioration in the reliability for these customers, the Commission will address this through its regulatory compliance program. October 06 84 Essential Services Commission, Victoria Final Decision Other measures Origin Energy suggested that the distributors should be held accountable for the service they provide with respect to metering and have incentives to meet or exceed service targets via an expanded S-factor and GSL payments scheme. As considered in Section 2.2.3, the information available to the Commission does not indicate that significant, systemic issues exist in the distributors’ provision of metering related services. Additionally, the Commission does not have the historical data to include metering-related measures in the S-factor scheme at this stage. Uncle Tobys (2005, p. 1) and EUCV (2005b, p. 48) considered that the quality of supply ought to be guaranteed and adequate compensation paid when supply targets are not reached. However, as discussed in Section 2.2.2, there is insufficient data relating to quality of supply available at this stage to incorporate it in the S-factor scheme in any meaningful way. Even if such a measure could be included, it is important to note that GSL payments are not intended to compensate customers. Rather, they provide an acknowledgement to the customer of poor service and an incentive for distributors to improve. Accordingly, the Commission has not included measures for metering or quality of supply in the S-factor scheme. Weightings and incentive rates In the 2001-05 price review, the ORG established a set of incentive rates for each distributor that converted the distributor’s actual performance against its reliability targets into an S-factor for that distributor. The incentive rates were set for each distributor based on the estimated marginal cost of bringing about service improvements for that distributor. The ORG also established weightings for each of the measures. The weightings were 100 per cent for unplanned SAIFI, 65 per cent for unplanned CAIDI and 25 per cent for planned SAIDI. Weightings The weightings in the 2001-05 S-factor scheme were based on surveys undertaken by the distributors. PB Power (2000, p. 10) reviewed these surveys and concluded that: There is no clear indication of customer preference with respect to outage duration or frequency of outages. … While there is much evidence to suggest that unplanned interruption frequency is generally of more concern to customers than unplanned interruption duration, it is not clear that this applies across all customer groups or to all interruption durations. It is therefore proposed that the weighting given to unplanned interruption duration be increased to 75 per cent of the full marginal cost estimate for each distributor. Since the 2000 review, customer research has been undertaken in South Australia which determined the willingness to pay for a reduction in the number of interruptions (the fixed component of an interruption) and the duration of interruptions (the variable component of an interruption). The weighting between the variable component and the fixed component can be October 06 85 Essential Services Commission, Victoria Final Decision quantified for South Australian electricity customers from this data. While no similar customer research has been undertaken in Victoria, several stakeholders referred to this study in their submissions. Prior to the release of the Commission’s Position Paper, AGLE and United Energy proposed retaining the existing weightings, whilst SP AusNet proposed a weighting of 1 to 1 for SAIDI to SAIFI. AGLE, SP AusNet and United Energy proposed a weighting of 10 to 1 for SAIFI to MAIFI based on the results of the willingness to pay research that has been undertaken in South Australia. SP AusNet (2005b, p. 14) supported the use of data from the South Australian study to weight the performance measures in the absence of Victorian data. Conversely, United Energy did not believe that it was appropriate to adopt the South Australian research until such time as sufficient consultation has taken place to determine whether it is appropriate for Victoria. Given the inconclusive nature of the survey data underpinning the existing weightings and the absence of any new Victorian-specific data, the Commission’s view is that the weightings of the reliability measures from the South Australian customer research are likely to provide a better indication of appropriate weightings. In its Draft Decision, the Commission proposed weightings based on the results from the South Australian customer research, varying by distributor and by network type. No further comments were made by stakeholders about these weightings, and so the Commission has adopted the proposed weightings as set out in Table 3.7. Table 3.7: Weightings of reliability measures in the S-factor scheme Network type AGLE CitiPower Powercor SP AusNet United Energy Ratio of unplanned SAIDI to unplanned SAIFI Ratio of MAIFI to unplanned SAIFI Urban 1.02 0.086 Rural 0.72 0.091 CBD 1.13 0.086 Urban 0.76 0.086 Urban 1.14 0.083 Rural 1.12 0.084 Urban 1.00 0.084 Rural 1.14 0.084 Urban 0.96 0.084 Rural 0.68 0.082 Incentive rates for reliability measures In the 2001-05 period, where there is an improvement in reliability, the ORG considered that the incentive rates should reflect the cost of reliability improvements, but be no greater than the value that customers place on reliability. It put in place incentive rates based on each distributor’s marginal cost of reliability improvements, varying between approximately October 06 86 Essential Services Commission, Victoria Final Decision $4,000 per MWh and $11,000 per MWh, depending on the distributor. At that time, the ORG did not have any robust information regarding the level of reliability valued by customers and the cost to achieve that reliability. In their price-service proposals, AGLE and United Energy supported continuation of the existing incentive rates. Conversely, CitiPower and Powercor indicated that they would work with the Commission and stakeholders to determine an appropriate incentive rate. SP AusNet supported using the Value of Customer Reliability (VCR) as the basis for setting reliability incentive rates, as it is derived from a robust study conducted in Victoria. The study was undertaken by Charles River Associates (CRA) for VENCorp and indicates that the value Victorian customers place on reliability on average is the state-wide VCR of $29,600 per MWh (CRA 2002). Its results remain current, and they are similar to a Monash study conducted in 1997 at a state-wide level. ERAA (2005, p. 2) strongly supported the strengthening of incentives. Conversely Origin Energy supported maintaining the current approach of setting incentive rates based on the marginal cost of raising or lowering performance on a particular measure. EUCV (2005b, p. 34) recommended: … there be different reliability incentives related to each feeder as this would tend to reflect the types of consumer connected. The Commission notes EUCV’s suggestion regarding different reliability incentives for each feeder, but as discussed in the Commission’s Final Framework and Approach paper, such an approach is impractical at this stage (ESC 2004g, p. 40). The Commission is concerned that there is a strong incentive in the short term for distributors to maximise returns to shareholders which may increase the risk in the longer term that reliability might deteriorate, and that this increasing risk is unobservable in the short term. The Commission’s view is that distributors should be accountable for any deterioration in reliability. In its Position Paper, the Commission proposed that the incentive rate for a deterioration in reliability should be greater than current rates, to more closely reflect the value that Victorian customers place on reliability. The Commission considered that VCR was an appropriate basis for determining the incentive rate for a deterioration in reliability under the S-factor scheme. VCR is already accepted as an industry standard. Distributors and others use it to assess investments in the network (for reinforcements and augmentation). For example, in its submission justifying expenditure to improve the security of supply in the CBD, CitiPower based the benefits of the project on the VCR for commercial customers (of $56,625 per MWh). However, such an approach is likely to result in the penalty for deterioration in reliability being greater than the reward for improvement, if the reward continues to reflect the cost of reliability improvements. Distributors and stakeholders did not support a scheme which would result in a net penalty for symmetrical year on year changes due to weather conditions. October 06 87 Essential Services Commission, Victoria Final Decision Therefore, the Commission has decided that the incentive rates should be symmetrical and that VCR is an appropriate basis for determining the incentive rates for the S-factor scheme where there is an improvement or a deterioration in reliability. The Commission notes that, even if incentive rates are symmetrical (same for rewards and penalties), the potential opportunities provided by the incentive scheme may be asymmetrical. That is, depending on a distributor’s current performance there may be a natural ceiling for improvements, but penalties may be limited only by the quantitative exclusion criterion that applies (see Section 3.2.4). Therefore, the scheme provides a strong incentive to distributors to reduce their downside exposure by undertaking investment to reduce the risk of a deterioration in reliability. In its Draft Decision, the Commission proposed to round the value of the state-wide VCR from $29,600 per MWh to $30,000 per MWh, except for CitiPower’s CBD customers. Given that CitiPower has justified its expenditure in the CBD on a VCR for commercial customers of $56,625 per MWh, the Commission was of the view that this VCR should be applied for CitiPower’s CBD customers through the S-factor scheme, rounded to $60,000 per MWh. SP AusNet (2005f, p. 15) noted that the VCR was determined in 2002 and suggested that it should be escalated to 2004 dollars. However, given the intended use of the value and the long term planning decisions which are expected to be based on the value, the Commission considers a single value over the period based on VCR is appropriate. Hence rounded values of $30,000 and $60,000 per MWh seem reasonable for use in the S-factor scheme as they do not imply an inappropriate level of precision and take account of a moderate level of escalation between 2002 and 2004. The Commission has considered whether the incentive rates for reliability measures should be set to VCR from 2008 or whether there should be a transition to VCR over a number of years. Any transition period may lead to perverse incentives in the year prior to transition. For example, if a distributor’s performance is worse that year, it would benefit from higher incentive rates when performance improves the following year. Moreover, if the incentive rates were transitioned over a period, this would provide a number of years in which this perverse incentive applied. The Commission has therefore increased the incentive rates based on VCR from 2008. The incentive rates to apply from 2008 (based on performance from 2006) are provided in Table 3.2. Incentive rates for the call centre performance measure Only SP AusNet proposed an incentive rate for the call centre performance measure in its priceservice proposal. It proposed an incentive rate of 0.021 per cent (of revenue), which it stated is consistent with the results from the South Australian willingness to pay study. SP AusNet’s proposed incentive rate is based on the number of months in which the call centre performance target was met less the number of months in which the call centre performance was not met. October 06 88 Essential Services Commission, Victoria Final Decision SP AusNet proposed to incorporate the call centre performance in the price control formula in the form: (1 +C t ) (1 +C t −1 ) where Ct = (NMt - NFt) * c and where: NMt NFt is the number of months, in year t, that the target was achieved is the number of months, in year t, that the target was not achieved c is the incentive rate on call centre performance The Commission is concerned that SP AusNet’s proposed formula does not ensure an incentive for call centre performance is retained throughout the year. The proposed formula provides the same reward (or penalty) regardless of whether the performance is close to the targeted level or substantially better (or worse) than the targeted level. Given the absence of information on the marginal cost of improvements in call centre performance and the absence of Victorian specific data in relation to customers’ willingness to pay for improvements in call centre performance, the Commission has used the South Australian customer research (by customer type) as the basis for determining the incentive rate. In the absence of information regarding the current average time to respond to a call, the Commission has assumed calls not responded to within 30 seconds are responded to between 30 seconds and 2 minutes, for the purposes of applying the research to Victoria. To ensure an incentive is retained throughout the year, the Commission has included the measure in the S-factor in a similar way to the reliability measures — that is, measured as the actual performance over the year less the targeted level of performance for the year. CitiPower, Powercor and AGL ES&M supported the use of the South Australian data to determine the incentive rate for call centre performance, although CitiPower and Powercor noted that the incentive rates derived by the Commission and set out in its Position Paper appeared relatively high compared to the current rates for reliability. SP AusNet stated that no more or less than 0.25 per cent of revenue should be placed at risk. Origin Energy was of the view that the incentive rates should be based on marginal cost and should only apply where they are less than customers’ willingness to pay. The specific call centre performance incentive rates for each distributor have been calculated based on the South Australian willingness to pay study, the forecast annualised revenue and breakdown of energy consumption by customer type (residential, small business and large business), and are provided in Table 3.2. These incentive rates apply during the period 2008-12, based on performance during the period 2006-10. The Commission notes that a distributor would only have more than 0.25 per cent of its revenue at risk if there was a deterioration in call centre performance of between 5.7 and 7.7 percentage points, depending on the distributor and its incentive rate. October 06 89 Essential Services Commission, Victoria Final Decision Targets for the measures in the S-factor scheme During the 2001-05 regulatory period, reliability performance targets were set to improve over time and capital expenditure was provided for the distributors to achieve these improvements. Rewards (or penalties) have been provided through the S-factor scheme where these targets have been outperformed (or not achieved). The Commission’s Final Framework and Approach was that there would be no targeted improvements in the average measures of reliability during the 2006-10 regulatory period, unless it was demonstrated that customers were willing to pay for these improvements. No robust evidence has been provided that customers are willing to pay for improvements in the average reliability, although discontent was expressed during public information forums in relation to the reliability experienced by the worst served customers. Accordingly, as discussed in Section 2.2.1, the targeted levels of reliability for the purposes of monitoring and reporting will remain unchanged over the 2006-10 regulatory period, except where a distributor has consistently outperformed its targets. Moreover, no expenditure has been included in the revenue requirement for improvements in reliability. The expenditure on reliability improvements will instead be provided through financial rewards from the S-factor scheme and by avoiding the payment of GSL payments, when improvements are delivered. Initially, each of the distributors indicated that the targeted levels for the service measures for the purposes of reporting and monitoring, as provided in Chapter 2, should also apply to the S-factor scheme. However, in response to the Issues Paper, SP AusNet (2005a, p. 50) stated: In order to minimise the transitional issues arising from changes to the scheme, SP AusNet Networks believes that the S-factor targets should be maintained at their current levels, except where adjusted for issues such as revenue-funded improvements, as well as changes in reporting and exemption methodologies. … There is no reason why these targets need to be the same as the general network performance targets. Additionally, United Energy (2005p, p. 13) noted that any adjustment to the targets from one regulatory period to the next would curtail rewards. The S-factor scheme is currently an incremental scheme based on: [(Target – Actual) in year t - 2] – [(Target – Actual) in year t – 3]. Moreover, as stated above no improvement in average reliability has been targeted during the 2005-10 period. As the targets are unchanging, the target in year t-2 will be the same as the target in year t-3 and the S-factor scheme becomes: [Actual in year t – 3] – [Actual in year t – 2]. The targets for the purposes of the S-factor scheme thus become redundant and the S-factor is based on the change in performance from one year to the next. Under such a scheme, distributors would choose to improve reliability where it is efficient to do so. Customers would pay for these improvements when the outcomes are delivered, through the S-factor scheme. This approach minimises transitional issues other than to account for changes to service reliability measures, as October 06 90 Essential Services Commission, Victoria Final Decision it is based on relative performance from year to year rather than performance relative to targets. It thereby avoids adjustments that would otherwise be required to ensure that adjustments to targets do not result in windfall gains or losses. The Commission has decided to adopt this approach and has therefore set the S-factor targets for the next regulatory period at the 2005 target level. The targets for unplanned SAIFI for 2006 are the same as the targets for 2005. A transition is required from the unplanned CAIDI measure in the existing scheme to the unplanned SAIDI measure in the new scheme to enable the roll forward of the S-factor scheme from the current regulatory period to the 2006-10 regulatory period. The transition will occur in 2008 by adopting the 2005 unplanned SAIDI targets and actuals. The 2005 unplanned SAIDI target have been calculated by multiplying the unplanned CAIDI target by the unplanned SAIFI target. The 2006 targets for MAIFI and call centre performance are the same as those established for reporting and monitoring purposes (see Section 2.2.1). Consistent with the current price controls, targets for the reliability measures have been set for CBD, urban and rural feeders. There will continue to be no distinction made, for the purposes of the S-factor scheme, between short and long rural feeders so that there is no disincentive for distributors to shorten long feeders as a reliability improvement measure. United Energy has indicated that, under such an approach, it will be penalised for meeting its targets. However the Commission notes that, excluding the impact of the St-6 factor, this will only occur if the reliability during 2006-10 is worse than that experienced in 2005. The targets for reliability and customer service measures are set out in Table 3.3, for the calculation of the S-factor in 2006 and 2007 based on the performance in 2004 and 2005, and in Table 3.4, for the calculation of the S-factor during the period 2008-12 based on the performance during the 2006-10 period. Volatility In the 2001-05 regulatory period, some distributors experienced substantial volatility in their S-factors. SP AusNet’s S-factors were the most volatile varying from +2.30 per cent in 2003 to -2.56 per cent in 2004 and –2.73 per cent in 2005. United Energy’s S-factor has varied from +1.95 per cent in 2003 to –1.39 per cent in 2004 to +0.31 per cent in 2005. The Commission, in its Final Framework and Approach, invited distributors to propose options for addressing any volatility in the S-factor scheme, and suggested options which included: • smoothing rewards and penalties over a two or three year period; • a deadband around the target (that is, rewards and penalties do not apply for performance within a certain percentage of the target); or • a lower incentive rate around the target. October 06 91 Essential Services Commission, Victoria Final Decision Retailers expressed concern with volatility in distribution tariffs arising from the S-factor. Origin Energy supported some degree of averaging and was interested in the trade off between the number of years over which averaging takes place and the effect on the sharpness of the service incentive. Distributors suggested that the increased incentive rates proposed from 2008 may lead to greater volatility in S-factors and were concerned, therefore, that natural variations in reliability performance from year to year may lead to large fluctuations in revenues. CitiPower and Powercor supported smoothing to reduce the volatility in tariffs. CitiPower (2005b, p. 44) and Powercor (2005b, p. 44) proposed: … an alternative model for smoothing which gives distributors limited discretion to select the degree of smoothing desired by “banking” S-factor. … The distributor should be given discretion, within prescribed limits, to manage the amount “banked” or the “overdraft” drawn as part of this buffering process. In this way distributors could design their own smoothing profile providing they remain within any prescribed limits. The “S bank” should be indexed to reflect the time value of money. The Commission consulted on the concept of an “S-bank” that would permit distributors to defer part or all of the S-factor from one year to the next. Such an approach is simpler operationally for dealing with the higher incentive rates than a deadband or a “normal” operating range, as proposed in the Final Framework and Approach, and provides distributors a flexible method of smoothing out the impact of normal variations in service performance from one year to the next attributable to changes in weather conditions. The concept of an “S-bank” was supported by EUCV (2005b, p. 58), AGLE (2005b, p. 15), CitiPower (2005b, p. 12), Powercor (2005b, p. 12) and SP AusNet (2005b, p. 21). Options to limit the amount banked each year and in aggregate or to allow averaging for one year only were not supported by distributors, who sought maximum flexibility in the operation of the bank. Based on the comments received by stakeholders, the Commission expressed concern in its Draft Decision that distributors may inappropriately bank the S-factor if provided with a high degree of flexibility. The Commission’s analysis indicates that volatility is substantially reduced when the S-factor is averaged over two years compared to one year (that is, performance is averaged over three years). Volatility is not significantly reduced when the S-factor is smoothed over three years compared to two years. SP AusNet questioned this finding. It is certainly possible to get two bad (or good) weather years consecutively…creating unnecessary volatility. …Whilst SP AusNet understands the Commission’s view that there is little extra benefit in extending this, there appears to be no cost and, therefore, any cost benefit analysis must conclude that allowing companies to spread rewards and penalties over additional years is desirable. October 06 92 Essential Services Commission, Victoria Final Decision The Commission notes that an averaging of the S-factor over more than two years further separates the reward/penalty from the year of reliability performance, blunting the action of the service incentive. An “S-bank” has been introduced into the price control from 2006 which allows a distributor to bank all or part of the S-factor from one year to the next, but not for more than one year. Further, to ensure that the value of the change in revenue from the “S-bank” amount remains the same as when the penalty (or reward) was incurred, and to reduce the incentive to bank negatives, the “Sbank” amount will be multiplied by the pre tax weighted average cost of capital. Asymmetry The current S-factor scheme is not entirely symmetric. Distributors supported adjusting the S-factor formula to remove this asymmetry, and SP AusNet proposed an alternative formula to do so: n (1 + CPI t )(1 − X t )(1 + At ) ≥ (1 + At −1 ) m ∑∑ p i =1 j =1 n ij t qtij− 2 , i = 1,...n; j = 1,...m m ∑∑ p i =1 j =1 ij ij t −1 t − 2 q where: 5 At is calculated as At = ∑ S t −i i =0 In its Position Paper, the Commission was of the view that the asymmetry is immaterial — a one per cent decrease followed by a one per cent increase results in an immaterial variation (0.99 * 1.01 = 0.9999 or $20,000 on a revenue base of $200 million). Additionally, for each S-factor the asymmetry exists only for six years, when it is removed by the St-6 term of the price control. The Commission therefore proposed to not adjust the S-factor formula to remove the asymmetry. SP AusNet (2005b, p. 20) viewed the Commission’s decision to ignore an identified asymmetry as a dangerous precedent and did not accept that it is immaterial, especially given the proposed higher incentive rates. CitiPower (2005b, p. 13) and Powercor (2005b, p. 13) considered that immateriality was an insufficient reason to reject correction. In contrast, EUCV and Origin Energy did not support such an adjustment, stating that asymmetry reflects outcomes in a competitive market (EUCV) and that the asymmetry is not material (Origin Energy). The Commission notes that the formula proposed by SP AusNet does not entirely remove the asymmetry and that a considerably more complex formula would be required to do so. The Commission would be reluctant to introduce further complexity to the formula when some stakeholders are currently of the view that the formula is already too complex. October 06 93 Essential Services Commission, Victoria Final Decision AGLE (2005b, p. 14) also recognised the difficulty in developing an understandable S-factor formula that removes the inherent asymmetry. It proposed that an explicit allowance be included in the weighted average cost of capital to address this matter. However, any additional risk that may be introduced by the asymmetry is asset specific and therefore diversifiable and does not affect the cost of capital. For these reasons, adjustment to the weighted average cost of capital would be inappropriate. In a further submission (2005h, p. 8), SP AusNet showed that the impact of the asymmetry could be about 0.1 per cent of revenue in the current period and, given increased incentive rates, could be as high as one per cent in the 2006-10 period. The Commission notes that changes of this magnitude could only be associated with a significant deterioration in reliability performance, as experienced by SP AusNet in the 2003-04 period. Natural variations in performance from year to year due to weather impacts would be unlikely to result in changes in performance, and revenue, of this magnitude, given that the impacts of extreme events are removed through exclusion criteria and that variations can be smoothed under the “S-bank”. The Commission notes that the asymmetry in the formula can result in a net financial benefit or a net financial loss to the distributor depending on the change in performance from year to year. For example, if there is an improvement year on year or a deterioration year on year there is a net financial benefit to the distributor, but if there is an improvement in one year followed by a deterioration or vice versa, there is a net financial loss to the distributor. The year on year changes are impacted by weather events but are also subject to the actions of the distributor. All else being equal, the increased incentive rates, together with the removal of the efficiency carryover mechanism on capital expenditure (which is likely to reduce the marginal cost of improvements to all distributors), has the potential to provide significant rewards where distributors are able to improve their service levels. Therefore, the Commission expects that distributors will actively seek reliability improvement projects to increase their profitability through the S-factor scheme. The potential benefits available to the distributor are likely to be far greater than any losses arising from the asymmetry inherent in the formula. Given all of these considerations, the Commission has decided not to adjust the S-factor formula to remove the existing asymmetry. Transitional issues There are a number of changes to the service incentive scheme that will commence in the 200610 regulatory period. There are transitional issues associated with these changes which are considered in the following sections. October 06 94 Essential Services Commission, Victoria Final Decision Change in incentive rates CitiPower and Powercor are of the view that any new S-factor scheme should take into account any structural break with the current S-factor scheme. In particular, CitiPower’s and Powercor’s agreement to any new S-factor scheme was stated to be predicated on resetting the starting values of the performance base so that GAPt r−,3n is set to zero when calculating the S-factor for the calendar year 2008. In their view, it is necessary to “restart” the scheme (with the increased incentive rates and new performance measures) so as to avoid any perverse incentive to do poorly in 2005. If the scheme was reset as proposed by CitiPower and Powercor by setting GAPt r−,3n to zero, the reliability data for 2005 would not be considered in determining the S-factor for 2008. The S-factor for 2008 would be based on the difference between actual measures and target measures, rather than on the incremental change from the previous year’s performance, effectively delivering additional rewards for improvements already delivered and additional penalties for deteriorations previously penalised. The Commission is therefore of the view that the S-factor scheme should roll through into the 2006-10 regulatory period. United Energy (2005p, p. 17) was concerned that should the scheme not be reset, a distributor could face a significant penalty during this transitional period following a symmetrical change in performance due to random variations in its reliability performance. This situation could arise, for example, where a distributor out performs against its targets in 2005 (gaining a reward under the current S-factor incentive scheme), followed by a return to target in 2006 (incurring a penalty under the modified scheme in which higher incentive rates apply). United Energy provided to the Commission worked examples to demonstrate the penalties that may be payable as a result of the difference in incentive rates between one period and the next. • Example 1: Penalty of $36 million over 6 years if current outperformance against target continues until 2005 and performance is on target in 2006. The Commission notes that the performance in 2006 is a deterioration in performance relative to 2005, and therefore it is appropriate that a penalty is incurred. • Example 2: Net penalty of $40 million over 6 years if an improvement in performance in 2005 is followed by an equal and opposite (symmetrical) deterioration in performance in 2006. The Commission notes that in this case the change in performance in United Energy’s example was substantial — a 50 per cent change in performance from year to year. To address the potential net penalty that arises with symmetrical changes in reliability performance during the transitional period, United Energy (2005p, p. 38), CitiPower (2005s, p. 12) and Powercor (2005k, p. 18) have proposed that in 2008 the old incentive rates be applied to GAPt r−,3n and the new incentive rates be applied to GAP tr−, n2 . Under such an approach, there is a penalty (or reward) at the old incentive rates based on the difference between the performance in 2005 and the target, and then a reward (or penalty) at the new incentive rates based on the difference between the performance in 2006 and the target. October 06 95 Essential Services Commission, Victoria Final Decision For example, if the target for a measure is 100 minutes, the performance in 2004 is 100 minutes, the performance in 2005 is 110 minutes and the performance in 2006 is 102 minutes, then the distributor would incur a penalty at the old incentive rates. This penalty would be based on the difference between the performance in 2005 and in 2004 (10 minutes) and a reward at the new incentive rates based on the difference between the performance in 2006 and in 2005 (8 minutes). With the increase in the incentive rates, the distributor would receive a reward for the deterioration in performance from 2004 to 2006 in this example. Under the approach, the distributor will effectively be rewarded for improvements already delivered and penalised for deteriorations previously penalised. Additionally, where there is no change in performance from 2005 to 2006, the distributors’ proposal would result in a reward if the distributor’s performance is better than target and a penalty if the distributor’s performance is worse than target. The Commission considers this to be a retrospective change as the decision to allow performance to improve or deteriorate during the current regulatory period would have been made by the distributor based on the old incentive rates. The Commission discussed these issues at length with United Energy, who agreed that no single mathematical solution could negate the transitional issue without creating other issues. United Energy also identified that, under a roll through arrangement with increased incentive rates, there may also be a perverse incentive for distributors to delay investments in reliability improvements in the last year of the regulatory period, so as to benefit from the increased incentive rates in the new period. Given that the 2005 year is largely completed, the Commission considers that a distributor’s ability to deliberately choose to affect its reliability outcome by altering its investment or operating strategy is small. It is also likely that such action would be readily evident to the industry and hence subject to a degree of public scrutiny and regulatory sanction. Furthermore, if the scheme was to be modified in such a way as to remove this perverse incentive, then under some circumstances, this will effectively delay the introduction of the new incentive rates. This results in a perverse incentive over a longer period and provides the opportunity to the distributor to choose to affect its reliability outcome. For these reasons, the Commission has decided that the modified incentive scheme will operate from 2008, based on the reliability performance that existed in 2005, rewarding or penalising a change in performance as the scheme is designed to do. The Commission accepts that the modified scheme places an increased amount of revenue at risk, however, this is the intended outcome of increasing the incentive rates and is discussed further in a later section. Additionally, when calculating the S-factor for 2008, to ensure performance is compared on a like-for-like basis between 2005 and 2006, the distributor’s performance for 2005 will be determined based on the exclusion criteria that apply to performance in the 2006-10 regulatory period. October 06 96 Essential Services Commission, Victoria Final Decision For those indicators introduced into the S-factor scheme in 2006 (MAIFI and call centre performance), GAPt r−,3n will be set to zero when calculating the S-factor to apply in 2006. Incentive rate adjustment for 2006 and 2007 The incentive rates that apply in 2006 and 2007, based on the performance in 2004 and 2005, were set as part of the last price review. These incentive rates were based on the marginal cost of reliability improvements and are expressed as a function of revenue. The distributors’ revenue requirements will be less in 2006 and 2007 than in the 2001-05 regulatory period with the P0 adjustment that applies in 2006. To ensure that the incentive rates that will apply in 2006 and 2007 have the same impact in dollar terms as they were intended to have when they were calculated as part of the last price review, they will be adjusted by the P0 (exclusive of the S-factor impacts) as follows: s' r ,n t = s tr , n 1 − X 0, s The revised incentive rates for 2006 and 2007 are provided in Table 3.1. A similar adjustment has also been made to the S-factor for 2003-05 which are incorporated in the distributors’ tariffs. This adjustment is made in calculating the P0 inclusive of the S-factor impacts. This is discussed further in Chapter 11. Adjustment to SP AusNet’s customer count SP AusNet advised the Commission that disconnected customers are currently included in the number of customers when calculating its reliability measures. It was agreed that disconnected customers would be excluded from the calculation of its reliability measures from 1 January 2006. This, and a change to account for movement of customers between network types, will result in a change to the calculated reliability performance of 2.2 per cent from 2006. Because the S-factor targets are to remain at the 2005 levels, this change has not been reflected in increased targets. Instead, an adjustment will be made to the actual performance measures for 2005 when calculating GAPt-3 in 2008. This offsets the corresponding increase in the GAPt-2 values in 2008 that will arise from the change in customer count methodology in 2006, and has the same net effect as increasing the target. Price control formula The price control formula for 2001-05 period is of the form: (1 +CPI t )(1 − X t )(1 + S t ) (1 + S t −6 ) where St is the service adjustment to the distribution price control in year t and St-6 is the service adjustment to the distribution price control in year t-6. October 06 97 Essential Services Commission, Victoria Final Decision The formula has been updated to reflect the inclusion of the “S-bank”. The price control formula is now of the form: (1 +CPI t )(1 − X t ) S t where St is defined in Section 3.1.1 Additionally, the incentive rate s within the St formula is no longer constant across the regulatory period, changing in 2008 (based on performance in 2006). Hence, a t term has been added to give it the form str ,n . The indicators and the incentive rates used in calculating St and St-6 have also been updated based on the earlier discussion and are set out in Table 3.1 and Table 3.2. As the targets for the performance measures will not be changing from year to year, the service incentive scheme effectively rewards or penalises incremental changes in performance. United Energy (2005v, p. 19) has stated that: The Commission is wrong in adopting a new flawed principle of ‘rewarding sustained improvement’, that is demonstrated to deliver outcomes inconsistent with the Commission’s primary objective, in order to justify retaining the original scheme. United Energy considers that a more appropriate service incentive scheme should reward distributors on the basis of the difference between performance and target. Under such a scheme, a distributor would receive a net financial benefit for an improvement in performance in one year, even if this improvement was due to weather and could not be sustained. The Commission’s primary objective under the Essential Services Commission Act 2001, in performing its functions and exercising its powers, is to protect the long term interests of Victorian consumers with regard to the price, quality and reliability of essential services. This objective requires the Commission to balance the quality and reliability of supply against the price of providing those services. The Commission is of the view that the S-factor scheme is consistent with its primary objective because it is designed to provide an incentive to distributors to improve reliability to customers where it is efficient to do so. Customers, through all public forums, strongly valued sustained improvements in performance, and generally recognise variability in performance for year to year based on weather effects. Furthermore, the scheme as proposed by United Energy relies on the setting of appropriate targets for the S-factor scheme. No customer research has been undertaken in Victoria to demonstrate that the current targets are appropriate. An advantage of the scheme as proposed is that it provides an incentive to the distributor to deliver the optimum level of performance, given the cost to deliver this performance and the value that customers place on this performance. Over time this will reveal the most appropriate targets. October 06 98 Essential Services Commission, Victoria Final Decision United Energy (2005c, p. 47) has also criticised the St-6 factor in the price control formula because, in its view, it penalises the distributor. The Commission notes that the St-6 removes a reward after 6 years rather than introduces a penalty. Additionally, the Commission notes that any decisions made by the distributor to improve performance during the current period, and thereby receive a reward through an increase in average prices paid by customers, would have been made with the knowledge that this reward only applied for 6 years. Service incentive risk All distributors raised concerns about the risk associated with the modified S-factor scheme. United Energy (2005c, p. 47) indicated that the increase in the incentive rates would expose it to the possibility of substantial penalties with only a limited prospect of reward given the improvements in reliability it has achieved over the current regulatory period. Following the release of the Draft Decision, SP AusNet (on behalf of all five distributors) elaborated on the distributors’ concerns over the modified S-factor scheme.41 The concerns set out by SP AusNet were as follows:42 • Increasing the incentive rates increases the volatility of the S-factor rewards and penalties. • There is a greater exposure to extreme weather events due to the change in the exclusion criteria. • There is limited potential to earn rewards because of the economic limitations to further improvements in reliability levels whilst penalties are only constrained by the exclusion criteria. • The inclusion of MAIFI and fault call centre response into the S-factor scheme exposures distributors to additional risk. The Commission commissioned Mercer Finance and Risk Consulting (Mercer) to assist it in analysing the variability in the S-factor and how this variability would change with the new measures and incentive rates outlined in the Draft Decision. The analysis sought to identify whether the changes to the S-factor scheme may result in asymmetry in the expected value of the rewards and penalties that a distributor may earn. The Commission set out the results of Mercer’s analysis in its Service Incentive Risk Issues Paper (2005d). This paper also set out the Commissions’ views on the issues raised taking into consideration the results of Mercer’s analysis. In principle, the Commission considered that where there is an expectation that the value of rewards and penalties under the service incentive arrangements outlined in the Draft Decision is something other than zero, that this should be recognised in determining the revenue 41 42 These risks were outlined in a letter to the Commission from SP AusNet on 22 July 2005. SP AusNet also raised an issue that was discussed in the previous section about the effect of the new incentive rates in the transition on symmetrical changes in performance. October 06 99 Essential Services Commission, Victoria Final Decision requirement. However, the Commission must be satisfied that the estimation of that value is reasonable and that the inclusion is consistent with standard finance theory, although the Commission recognised that this will involve a degree of judgement rather than the use of an empirical formula. The Commission’s principle is that distributors should be funded for the value of asymmetric risk which is non-diversifiable but should not be funded for normal business risks which are symmetrical and diversifiable. Mercer’s analysis (2005a to 2005e), which includes the impact of the new quantitative exclusion criterion (see Section 3.2.4), supported the proposition that there is increased volatility in the Sfactor under the arrangements outlined in the Draft Decision when compared to the existing service arrangements. Notwithstanding, it also concluded that the expected value of the rewards and penalties for each distributor, based on the actual performance data for 2000-04, is approximately zero. On the basis of this information, the Commission concluded that the expected value of the rewards and penalties for each distributor is approximately zero and that this would continue to be true if there was an equal probability that 2005 was a good performance year or a bad performance year. Mercer’s analysis also addressed concerns that there is a greater exposure to extreme weather events. The analysis excludes both events that meet the quantitative exclusion criteria and events (based on experience in 2000 to 2004) with an impact that is not significant enough to meet the exclusion criteria, as appropriate. In the analysis, excluded days were replaced by average values. The conclusion that the expected value of the risk for each distributor is approximately zero stands. Although Mercer’s analysis did not include the impact of MAIFI and fault call centre measures, the impact on the S-factor of these measures is expected to immaterial. In response to the Issues Paper (2005d), all the distributors reiterated the view that the increased value of the incentives would increase the volatility of the incentive scheme and that this increased volatility in revenues increases risk. CitiPower (2005z, p. 4-5) and Powercor (2005v, p. 4-5) also noted that the increased volatility would lead to greater diversifiable risk which is valued by debt investors. They stated that, because the S-factor scheme is not assured to exist past the next regulatory period, this risk may not even out over time. They therefore suggested that the Commission should be conservative with regard to the likely outcome of the scheme and should not accept it is likely that the expected value of the risk faced by distributors under the modified incentive scheme would be zero. SP AusNet (2005t, p. 2) stated that it would cost more for the business to diversify against increased symmetric risk. It stated that, given the increased risks under the modified incentive scheme, it would require increased revenue to compensate it for the extra hedging it must undertake. October 06 100 Essential Services Commission, Victoria Final Decision United Energy (2005t, p. 4) was concerned that the approach taken by the Commission in the Draft Decision was inconsistent with other decisions taken by the Commission about symmetrical, diversifiable risks, including allowing hedging in retail energy tariffs, setting the benchmark level of gearing in its 2003 gas access review decision with reference to the volume risk to which gas distributors are exposed and assuming regulated businesses use fixed rate rather than floating rate finance. Distributors also commented on their preferences for costing increased risk. AGLE (2005h, p. 3) proposed that this risk be costed on the same basis as an insurance product while CitiPower (2005z, p. 6) and Powercor (2005v, p. 6) proposed a methodology based on the value placed on risk in the stock market. The Commission is of the view that the distributors have not given sufficient weight to the mitigating action of the “S-bank” when assessing the impact of increased volatility on the value of debt investors. Analysis shows that volatility is significantly reduced though the “S-bank” mechanism. The “S-bank” provides a vehicle to manage the volatility. Additionally, the symmetric risk referred to by SP AusNet is business specific. There is no evidence to suggest that investors cannot diversify this risk or that it is more costly for them to do so. CitiPower and Powercor are concerned that the action of the scheme cannot be assured in the next regulatory period. This is true. Decisions taken now cannot bind a future regulator’s pricing determination. The Commission notes the current intention for the effect of any S-factor or volatility between S-factors in adjacent years to net out to zero over a 6 year period. Nevertheless, this does not result in increased risk. SP AusNet also noted the limited potential to earn rewards because of the economic limitations to further improvements in reliability levels whilst penalties are only constrained by the exclusion criteria. The Commission acknowledges that there may be a natural ceiling to reliability improvements where the marginal cost of making the improvement is not justified by the value that customers place on that improvement. However, all else being equal, the increased incentive rates, together with the removal of the efficiency carryover mechanism on capital expenditure (which is likely to reduce the marginal cost of improvements to all distributors), has the potential to provide significant rewards where distributors are able to improve their service levels. SP AusNet (2005h, p. 3) also stated that the increase in volatility could result in a downgrade in its credit rating, which would increase the cost of debt. The Commission understands that creditratings are driven by the perceived ability of a business to pay its debts on time. While volatility in revenues might impact short term cash flows, it is difficult to see how a symmetrical event with equal probability of a positive or negative impact, and with only a small impact on revenues, will affect a business's ability to pay on time. Hence, it is not apparent that the decision to increase the rewards and penalties available under the service incentive scheme will affect a business's credit rating. Additionally, the cost of capital should not be affected unless there is a material increase in the risk of bankruptcy, which has not been evident in rating agencies’ literature. October 06 101 Essential Services Commission, Victoria Final Decision Importantly, the scheme is an incentive scheme. It is designed so that distributors respond to the incentives and pursue the rewards. Therefore, although the expected value of this risk is approximately zero where distributors do not respond, the expected value is significantly higher and positive where the distributors respond and invest in the network to achieve service improvement outcomes. This is because the value of the rewards under the scheme has increased significantly whilst the costs of achieving them have reduced (through the removal of the efficiency carryover mechanism on capital expenditure). With regard to the additional risk that might be imposed on the distributors under the service incentive scheme, the Commission considers that: • the expected value of rewards and penalties is approximately equal to zero; • that the combination of the increase in the incentive rates and the removal of the efficiency carryover mechanism on capital expenditure will be more likely to result in the distributors realising significant rewards. Therefore, there will be no adjustment in relation to this issue. 3.2.2 GSL payments scheme An important feature of the reliability measures and the existing S-factor scheme is that the reward to the distributors from improving average reliability is the same for all customers, irrespective of the level of service being provided to particular customers. The purpose of the GSL payments scheme is to provide an additional incentive to the distributors to improve reliability to the worst served customers. Payments are already made automatically to customers. The Electricity Distribution Code requires distributors to make a GSL payment to a customer where: • the customer experiences an interruption of duration greater than 12 hours ($80); • the customer experiences more than 9 interruptions in a year (urban customer) or 15 interruptions in a year (rural customer) ($80); • the distributor is more than 15 minutes late for an appointment ($20); or • the distributor does not supply electricity to a customer’s supply address on the day agreed ($50 per day to a maximum of $250).43 In addition, the Public Lighting Code requires distributors to make a GSL payment of $10 to the first person reporting a faulty public light where a public light is not repaired within 2 business days of being notified and that person is the occupier of the immediately neighbouring residence or business. 43 The GSL payments for supply restoration time and frequency of interruptions are only payable for sustained interruptions (that is, interruptions of duration longer than one minute) and to customers who consume less than 160 MWh per annum. October 06 102 Essential Services Commission, Victoria Final Decision In its Final Framework and Approach, the Commission sought proposals from the distributors for a GSL payments scheme to apply in the next regulatory period. The Commission indicated that it would not consider additional customer service measures in the GSL payments scheme unless information was provided to support the proposal. The Commission further indicated that it would consider a reduction in the targets for the GSL payments scheme, the introduction of multiple threshold levels at which GSL payments apply, the inclusion of MAIFI and an increase in the magnitude of the payments. The Commission stated that it would agree to changes in the targets or thresholds for GSL payments where they are consistent with the following principles: • The GSL payments for reliability should target those customers with the worst reliability. • It may not be efficient to improve the reliability for particular customers. Where reliability is not improved, the GSL payments are an acknowledgement to these customers that this may be the case. • GSL payments should reflect, where possible, variations in customers’ willingness to pay based on their current level of service. • The distributors’ IT systems must be able to identify the customers to whom payments are to be made and ensure that the payments are made. • The administrative costs of the GSL payments scheme must not exceed the benefits of the scheme. The GSL payments schemes proposed by the distributors in their price-service proposals are summarised in Table 3.8. Following consultation on these proposals, the Commission has decided to revise the GSL payments so that: • payments for long duration interruptions are based on the aggregate minutes off supply per year, rather than the length of each interruption, and for multiple thresholds; • payments for an excessive number of interruptions per year are based on multiple thresholds that are the same for all customers; • payments for late appointments are based on an agreed appointment window; • payments for late new connections are based on a reduced standard connection timeframe of 10 business days; and • payments for late public lighting repairs are not changed. Additionally, the amount payable for each GSL has been reviewed and a new GSL payment based on momentary interruptions has been introduced. The reasons for the Commission’s decision on the GSL payments scheme are discussed in the following sections. October 06 103 Essential Services Commission, Victoria Final Decision Table 3.8: GSL payments schemes proposed by the distributors Description of GSL payments measure Current GSLs AGLE CitiPower Powercor √a √a SP Aus Net United Energy >4 unplanned interruptions (urban) $40 >7 interruptions (urban) $80 >9 interruptions (urban) $80 >9 unplanned interruptions (rural) $40 >11 interruptions (rural) $80 >13 interruptions (rural) $80 >15 interruptions (rural) $80 Interruption longer than 10 hours $80 Interruption longer than 12 hours $80 Interruptions >10 hours per annum $40 >15 minutes late for appointment $20 √ $40 √ √ √ √ $50/day, $250 max. √ √ √ √ √ √ Public light not repaired within 2 days $10 √ $20 √ √ √ √ 4 days notice not given for planned interruption $20 Connection not made on day agreed a Payment √ √ √ √ √ √ √a √ √ √ √ √ √ √ √ √ √ √ √ √ √ Proposed in enhanced offer only GSL payments for poor electricity supply reliability Currently, customers consuming less than 160 MWh per year receive payments for poor supply reliability when: • the customer experiences an interruption of duration greater than 12 hours ($80); • the customer experiences more than 9 sustained interruptions in a year (urban customer) or 15 sustained interruptions in a year (rural customer) ($80). AGLE and United Energy proposed reductions to the threshold at which these reliability GSL payments are payable. AGLE proposed that the threshold for the GSL payment for rural customers be reduced from 15 interruptions to 11 interruptions per annum. United Energy proposed that the threshold for the GSL payment for urban customers be reduced from 9 interruptions to 7 interruptions per annum and the threshold for the GSL payment for rural customers be reduced from 15 interruptions to 13 interruptions per annum. CitiPower, Powercor and SP AusNet proposed additional GSL payments of $40 for: October 06 104 Essential Services Commission, Victoria Final Decision • urban customers experiencing more than 4 interruptions per annum (CitiPower and Powercor, enhanced offerings); • rural customers experiencing more than 9 interruptions per annum (Powercor, enhanced offering); and • an interruption longer than 10 hours (SP AusNet). None of the distributors proposed a GSL payment for MAIFI. EWOV (2005, p. 1) supported a high level of consistency in the GSL payments of distributors but identified that: ... differences in geographical areas covered by each electricity distributor may warrant some differences in the supply restoration payment GSL and the low reliability payment GSL. In contrast, during public information forums, stakeholders queried why thresholds for rural customers are higher than those for urban customers. Origin Energy submitted that the minimum level of service proposed and the quantum of GSL payments should be referenced to willingness to pay studies. The thresholds for GSL payments were set for the 2001-05 regulatory period on the basis of the reliability experienced by the worst served one per cent of customers. The Commission has examined data on feeder performance data for 1999 to 2004 and observes that the performance experienced by the worst served customers has improved — there were very few interruptions longer than 12 hours and far fewer than one per cent of customers experienced reliability worse than the GSL payment thresholds. The Commission’s view is that GSL payments should continue to be made on the basis of reliability experienced by the worst served one per cent of customers and thresholds should therefore be reduced accordingly. In its Position Paper, the Commission proposed new thresholds for the worst served one per cent on the basis of feeder performance data to 2003. Noting stakeholders’ comments that the same thresholds should apply to rural and urban customers and that the proposed thresholds were similar to the existing thresholds for urban customers, the Commission also proposed that the same thresholds would apply to urban and to rural customers. Moreover, the Commission proposed a GSL payment based on the annual aggregate duration of interruptions consistent with the GSL payment proposed by SP AusNet. In this regard, the Commission notes that stakeholders had expressed concern regarding the annual aggregate duration of interruptions, but not where the duration of each interruption was less than 12 hours. CUAC (2005c, p. 3) strongly supported a GSL payment based on the total duration of interruptions over a year. However, AGLE (2005b, p. 11) opposed a GSL payment based on the cumulative interruption duration over a year rather than the duration of a single interruption. It claimed that its systems are not capable of providing this information and that it had not allowed for expenditure on its October 06 105 Essential Services Commission, Victoria Final Decision systems to provide this functionality. AGLE has since advised that the cost will be $100 000 to provide this functionality plus $110 000 per annum to administer this GSL payment. This expenditure has been considered as a step change in operating and maintenance expenditure (see Chapter 6). Distributors also noted that the proposed thresholds would be likely to capture more than one per cent of customers. The Commission also consulted on the amount of each GSL payment. Given the Commission’s view that the accountability of the distributors for service outcomes should be increased, the Commission proposed to increase the GSL payments for the duration and frequency of sustained interruptions from $80 to $100. This would enhance the incentive for the distributors to improve reliability for those customers in pockets of poor reliability. Further, the Commission considered that a multi-level GSL payment would more closely reflect study results that show customers’ willingness to pay increases as the number of interruptions increases or the duration of interruptions increases. Additionally, given the level of concern raised during public information forums at Lilydale and Colac regarding outlier performance, the Commission proposed three levels of payment, with the second level of payment being an additional $50 and the third payment (an additional $150) being double the payments at the lower thresholds combined. AGL Retail (2005, p. 1) supported an increase in payments for GSLs for poor reliability and considered that an extra $50 payment provides further incentive to contain supply failure. In contrast, CitiPower (2005b, p. 5-6) and Powercor (2005b, p. 5-6) considered there was no evidence for willingness to pay for GSLs and therefore no foundation for increasing the payment level. Customers also proposed extensions of the GSL scheme. Johanna Seaside Cottages (2005b, p. 1) proposed an additional threshold of 72 hours off supply ($450) to provide increased compensation for prolonged power outages. Gilbert (2005, p. 1) proposed that GSLs should cover power interruptions that last all night through the off-peak electricity period (generally between 11pm and 7am for hot water heating) to reflect the greater inconvenience caused. Gilbert also proposed that a payment should be made for not adhering to scheduled planned interruption times. The Commission notes the specific nature of these proposals. Importantly, the GSL payments scheme is not intended to provide compensation to customers receiving poor reliability. The value of payments would not be sufficient to achieve this outcome. Similarly, given that different customer groups are likely to place different values on the impacts of various types and timing of supply interruptions, the Commission considers that the GSL payments should not be focused on the impacts on particular customers or groups of customers. Rather, the reliability-based GSL payments provide an incentive to distributors to improve reliability to worst served customers. Nevertheless, these proposals support that a three level GSL payment is preferred over a two level payment. Additionally, United Energy (2005c, p. 47) considered that planned interruptions should be excluded from reliability GSL payment thresholds as these are not considered to be poor October 06 106 Essential Services Commission, Victoria Final Decision reliability by customers. The Commission understands that this concern arose because, if a customer experienced one planned interruption, a subsequent interruption could result in that customer exceeding the threshold for the annual duration of interruptions. CitiPower and Powercor also proposed that planned minutes should be removed from GSL payments for consistency with its removal from the S-factor scheme. Further discussions with ETU indicated support for this approach, given the incentives for the distributor to undertake unsafe work practices to avoid GSL payments. The Commission recognises the potential impacts on safe working practices of including planned interruptions in the service incentive mechanism and has removed planned interruptions from the S-factor scheme for this reason. While retaining planned interruptions in the GSL payments scheme encourages distributors to consider the impacts of planned work on worst served customers, it might also incentivise distributors to defer such work to avoid potential payments. The Commission has, therefore, based the GSL payments for the duration and frequency of sustained interruptions on unplanned interruptions only. EUCV was of the view that there should be an incentive to reduce the frequency of short term outages and voltage dips which cause production plant outages. Given stakeholders’ concerns on the number of momentary interruptions and the Commission’s view that the distributors’ accountability for service outcomes should be increased, the Commission has introduced a GSL payment for MAIFI. The Commission considered that distributors have sufficient data to define a MAIFI threshold and therefore proposed a GSL payment for MAIFI based on approximately a 9 to 1 ratio between SAIFI and MAIFI. Data provided by distributors confirms that thresholds of 24 and 36 momentary interruptions per year are appropriate to capture about one per cent of customers. The Commission considers that GSL payments should continue to be paid by distributors to customers experiencing the worst one per cent of reliability with respect to the duration and frequency of interruptions. Based on updated information provided by distributors the Commission has therefore decided that, as a minimum, the distributors are required to make a GSL payment to customers where: • the customer experiences more than 20 hours of unplanned sustained interruptions in a year ($100) or more than 30 hours of unplanned sustained interruptions in a year ($150) or more than 60 hours of unplanned sustained interruptions ($300), excluding the impact of excluded events; • the customer experiences more than 10 unplanned sustained interruptions in a year ($100) or more than 15 unplanned sustained interruptions in a year ($150) or more than 30 unplanned sustained interruptions ($300), excluding the impact of excluded events; and • the customer experiences more than 24 momentary interruptions in a year ($25) or more than 36 momentary interruptions in a year ($35), excluding the impact of excluded events. The Commission requires GSL payments to automatically be made to customers where their supply does not meet the thresholds specified. October 06 107 Essential Services Commission, Victoria Final Decision GSL payments to large customers for poor electricity supply reliability GSL payments for poor reliability are currently only made to customers with annual consumption less than 160 MWh. In its Final Framework and Approach, the Commission asked distributors to consider whether GSL payments for poor reliability should be made to all customers, not just those with an annual consumption less than 160 MWh. Only AGLE supported making GSL payments to customers with annual consumption greater than 160 MWh, but only to those without a specific supply agreement. CitiPower, Powercor, SP AusNet and United Energy did not support making GSL payments to customers with annual consumption greater than 160 MWh on the basis that: • $80 payments are not meaningful to large customers; • larger customers have scope to improve their reliability through an enhanced level of network connection or through equipment installed on the customer side of the meter; and • larger customers had indicated to the distributors that there would be greater benefit to them by the distributors concentrating on improving reliability rather than making GSL payments. EUCV (2005b, p. 37) did not support making GSL payments to customers with annual consumption greater than 160 MWh. It stated: The losses experienced by large industrial consumers for failure of the network supply are much greater than the GSLs. However, large customers are entitled to receive a quality of supply consistent with the network average, thus imposing an obligation on the businesses to upgrade the supply quality to reflect this right. EUCV (2005d, p. 74) also suggested that, as customers consuming more than 160 MWh per year are ineligible to receive reliability GSL payments, they should not fund these payments to other customers. However, at public forums held in Melbourne, some large business customers noted that not all customers consuming more than 160 MWh per year were able to negotiate effectively with distributors and that they would prefer to receive GSL payments for poor reliability so as to incentivise distributors to improve supply reliability to them. In seeking to clarify the extent to which GSL payments are not made to large customers who would otherwise be entitled to them, AGLE and CitiPower advised that no payments would have been made to larger customers if they were so entitled. In contrast, SP AusNet advised that it makes payments to all customers as it is cheaper than to exclude specific classes of customers. Given some support for GSL payments to large customers, that some distributors currently make payments to large customers, and that the determination of the expenditure for the GSL payments scheme did not exclude large customers, the Commission has decided to require GSL payments to be made to all customers including those with annual consumption greater than 160 MWh. October 06 108 Essential Services Commission, Victoria Final Decision GSL payments for appointments There is currently a $20 GSL payment made where a distributor is more than 15 minutes late for an appointment, although AGLE currently pays $40 rather than $20. Performance data for 2001 to 2004 indicate that few GSL payments for appointments have been made. Under the current GSL payment for appointments, there is no requirement on the distributor as to the length of the appointment window provided to the customer. The Commission therefore invited the distributors to propose an appointment window that it considered appropriate for customers. AGL Retail (2005, p. 1) supported the introduction of appointment windows as appropriate to manage customers’ expectations of timely service delivery. The length of the appointment window proposed by each distributor in response to the Commission’s request in its Final Framework and Approach is summarised in Table 3.9 along with the forecast cost impact of the proposal. Table 3.9: Proposed length of appointment window and cost impact, by distributor Appointment window Cost impact ($2004) AGLE 2 hour window Nil CitiPower Continue standard half day window, negotiated specific time appointments Nil Powercor Continue standard half day window, negotiated specific time appointments Nil SP AusNet Continue to nominate a specific appointment time Nil United Energy 15 minute or 1 hour window Nil CitiPower, Powercor and United Energy considered their current appointment windows to be appropriate. Furthermore, SP AusNet (2005a, p. 52) noted that: … appointments are appropriate where there is a requirement for customers or other contractors to be on site. There are a number of situations where co-ordination is not required and making specific appointments is both unnecessary and inefficient, for example, new connections where the site is open and all electrician work completed in advance. Origin Energy supported the short appointment windows, such as those proposed by United Energy and SP AusNet. EWOV supported a two hour appointment window, whilst AGL ES&M supported an appointment window no greater than half a day. In its Position Paper, the Commission therefore proposed an appointment window of: • a maximum of 2 hours where the customer or their representative is required, or chooses, to be in attendance; and • a maximum of one day where the customer or their representative is not required, and does not choose, to be in attendance. October 06 109 Essential Services Commission, Victoria Final Decision In response to the Commission’s Position Paper, CitiPower (2005b, p. 7) and Powercor (2005b, p. 7) expressed concern that a limited ability to fully utilise the flexibility many customers have in making appointments would reduce the efficiency and increase the costs of distributors’ resource management. They noted that they currently offer choice to customers for appointments for special meter reads or connection services between a 2 hour time-band of attendance for certain works, an am or pm band or an all-day time-band for certain works. Conversely, EUCV (2005b, p. 1) supported the Commission’s proposal regarding maximum appointment windows. Subsequently, distributors raised concerns about the types of activities associated with appointments, particularly same day fuse insertions and special meter reads, both associated with a change of occupancy. Normally, neither activity requires the customer to be in attendance, unless there are access problems, but the revised definitions would classify these activities as appointments. United Energy (2005d, p. 11) states: …United Energy supports same day fuse inserts being classified as same day appointments. However, the application of “day appointments” to Special Read Requests would have significant cost impact on UED. The Commission acknowledges the need to allow some flexibility, provided this is acceptable to the customer. Because special meter reads associated with a change of occupancy are usually requested by a retailer on behalf of a customer and are subject to agreed transfer arrangements, the Commission will not require this activity to be classified as a same day appointment for the purposes of the GSL payments scheme unless the customer or its representative is required, or chooses, to be in attendance. The Commission therefore requires distributors, as a minimum, to make a GSL payment where the distributor is more than 15 minutes late for an appointment ($20). Where a distributor makes an appointment with a customer, the distributor must specify a window to the customer or their representative by no later than 5 pm on the day prior to the appointment of: • no greater than 2 hours where the customer or their representative is required, or chooses, to be in attendance; and • no greater than one day where the customer or their representative is not required, and does not choose, to be in attendance; unless an alternative appointment window has been agreed to by the customer or their representative. A request from a retailer for a special meter read relating to the move in of a new customer to an existing premise is not considered to be an appointment for the purposes of the GSL payments scheme unless the customer or their representative is required, or chooses, to be in attendance. GSL payments for connections The Electricity Distribution Code currently requires the distributors to use best endeavours to connect a customer by the date agreed, or where no date has been agreed, within 20 business October 06 110 Essential Services Commission, Victoria Final Decision days. A GSL payment of $50 per day to a maximum of $250 is made where the customer is not connected on the date agreed. The Commission invited distributors to base their price-service proposals on a customer connection time that was shorter than the current 20 business days, and which could be demonstrated to be considered appropriate by their customers — for example, a standard 10 business day or 15 business day connection time. The Commission expected that this standard connection time may vary to cater for, for example, remote locations, complex connections and connections in inaccessible areas. The connection time proposed by each distributor in its price-service proposal, with the forecast cost impact of the proposal, is summarised in Table 3.10. Table 3.10: Proposed connection times and cost impact, by distributor Connection time Cost impact ($2004) 20 business days Nil 10 business days Connection fee 50 per cent higher CitiPower Enhanced offering – 10 business days $0.1 million per annum Powercor Enhanced offering – 10 business days $0.1 million per annum SP AusNet 15 business days for GSL payments, 20 business days in Electricity Distribution Code $0.2 million p.a. if GSLs based on 15 business days, $0.7 million p.a. if the Electricity Distribution Code is based on 15 business days 15 business days Additional GSL payments AGLE United Energy EWOV, AGL ES&M and Origin Energy were of the view that the standard connection time could reasonably be reduced, with Origin Energy noting that it would be difficult to accept that there should be a cost impact for moving to a tighter standard. The National Electrical and Communications Association (NECA) is an industry organisation representing approximately 1200 Victorian electrical contracting businesses which interact with the distributors and retailers on a daily basis, generally on behalf of the electricity customer. Based on its experience dealing with the distributors, NECA supported a 10 business day connection time. Based on comments from stakeholders, the Commission proposed a reduced standard connection time from 20 business days to 10 business days in its Position Paper. The Commission noted that information provided by the distributors in their regulatory audit reports indicates that 10 business days is reasonably achievable. As this timeframe is already being achieved, the cost of achieving it is already included in the out-turn expenditure. However, it was proposed that a small expenditure allowance be provided to the distributors to make the additional GSL payments that may arise from such a reduction. SP AusNet (2005b, p. 16) stated that it is not currently meeting the 10-day timeframe and would require an additional expenditure allowance to do so. CitiPower (2005b, p. 7), Powercor (2005b, p. 7) and United Energy (2005c, p. 48) considered the 10 day threshold to be achievable where supply is available adjacent to the site and connection is to a single-phase service at a single premise, but that a higher threshold or additional expenditure allowance would be required if October 06 111 Essential Services Commission, Victoria Final Decision more complicated services were included. The Commission notes that a 10 day connection timeframe applies only where an alternative date has not been agreed. The Commission expects that the distributors would largely be successful in obtaining customers’ agreement to a date for connection of more complex sites, rather than relying on the default timeframe. AGLE (2005b, p. 12) accepts the 10 day timeframe but expects that it will make GSL payments rather than improve its service delivery to customers. AGL Retail (2005, p. 2) and EWOV (2005b, p. 2) supported the proposed reduction, as did the Energy Action Group (2005, p. 2) and EUCV (2005b, p. 52), although they did not agree that a revenue allowance is required. Given that the Commission has not included expenditure in the revenue requirement for the distributors to reduce their standard connection times, the Commission is of the view that an amount should be included in the expenditure requirement based on the estimated number of GSL payments. The information available in the regulatory audit reports indicates that the number of GSL payments that will be made is likely to be small. The distributors can choose to connect customers within the required time or make the GSL payment. Accordingly, the Commission requires distributors, as a minimum, to make a GSL payment where the distributor does not supply electricity to a customer’s supply address on the day agreed ($50 per day to a maximum of $250). Where a connection request has been made to the distributor by a customer or its representative, and no date for connection has been agreed between the distributor and the customer or its representative, the distributor must connect the supply address within 10 business days. The Commission has included a small amount in the expenditure requirement for additional GSL payments that may arise. GSL payments for public lighting All distributors have proposed to continue to make a GSL payment where a public light is not repaired within 2 business days of being notified by the occupier of the immediately neighbouring residence or business. Whilst AGLE has proposed to continue to pay $20, the other distributors have proposed to continue to pay $10. The Commission notes that the distributors make very few GSL payments for public lighting. EWOV, the Streetlight Group of Councils (SLG) and EUCV supported an increase in the GSL payment to $20. Additionally, the SLG believed that the GSL payment for public lighting should be made accessible to all Victorians (not just to adjoining properties), and be reissued for each occasion that repairs are not completed within the required time frame. As a minimum, SLG recommends that payments be extended to Public Lighting Customers such as municipal councils and VicRoads. The SLG’s proposals seek to bring the Victorian GSL payment into line with the South Australian scheme. However the schemes are not directly comparable as there is a fundamental difference between the operating environments in Victoria and South Australia. In Victoria, the Public Lighting Code, developed in conjunction with the councils, requires that public lights are replaced under a bulk replacement program or are patrolled on a regular basis to identify faulty lights. In South Australia the payment scheme is the primary method for identifying faulty lights October 06 112 Essential Services Commission, Victoria Final Decision (at least on minor roads, where the majority of lights are located) and therefore has to provide sufficient incentive for people to identify and report faulty lights. Accordingly, the Commission does not propose to amend the scheme as suggested by the SLG. Origin Energy was of the view that the GSL payment was anomalous given that the activity is now contestable. However, while the repair of public lighting could be a competitive activity, the recent review of public lighting-excluded service charges indicates that the market for the repair of public lighting is not effectively competitive and there is an insufficient threat of potential competition to mitigate the monopoly power of the distributor. Indeed, the distributors generally supported continuation of the public lighting GSL payment. The number of lights maintained by alternative service providers is currently small and they are able to differentiate payments for lights maintained by them. United Energy (2005c, p. 17) identified that: … as public lighting becomes more contestable, the Commission through regulation must transfer responsibility for the GSL to the owner of the assets. If the market for public lighting becomes more competitive over the 2006-10 regulatory period, it may be appropriate to remove the obligation for the distributors to make a GSL payment for public lights that are not repaired. Given the high proportion of public lights maintained by the distributors, the Commission has therefore decided that the public lighting GSL payment should continue to be paid — by the distributor where it is responsible for operating and maintaining the public lights — to a person who reports a faulty public light in circumstances where that public light is not repaired within 2 business days of the distributor being notified and the person is the occupier of the immediately neighbouring residence or business. Given the transition to a more contestable market for public lighting, the Commission does not support an increase in the minimum GSL payment from $10, as a minimum standard, at this stage. However, distributors may choose to pay more, as AGLE has done. Other GSL payments proposed United Energy proposed an additional GSL payment of $20 where four business days notice is not given for a planned interruption. This was proposed in conjunction with removing planned SAIDI from the S-factor scheme on the basis that: • planned interruptions affect less than 5 per cent of its customers each year; and • few complaints are received when the current four-business-day notice period for planned interruptions is adhered to (United Energy 2004e, p. 47). The Commission sought comment as to whether customers would value the inclusion of a GSL payment where four business days notice is not given for a planned interruption. Whilst United Energy and AGL ES&M supported the introduction of a GSL payment for not providing notice of planned interruptions, CitiPower, Powercor, SP AusNet and Origin Energy October 06 113 Essential Services Commission, Victoria Final Decision did not. EWOV was of the view that, if it was introduced, then it needed to be introduced by all distributors. The Commission has decided not to introduce a GSL payment for not providing notice of a planned interruption. This is because firstly, customers do not appear to have a consistent view as to an appropriate notice period for planned interruptions; secondly, the customer’s concern relates to receiving the notice rather than the distributor giving the notice, and this is difficult to measure; and thirdly, it has not been demonstrated that customers would value the introduction of this GSL payment. However this does not preclude the distributors choosing to introduce this GSL payment as a show of good faith or to demonstrate customer service. Additionally, Origin Energy (2005, p. 7) suggested that there should be GSL payments for metering: As the Commission has decided to continue to define metering for small customers as a prescribed service, it is appropriate that the distributors be held accountable for the service that they provide and be incentivised to meet or exceed the service targets (via expanded S-factor and GSL payment schemes). Participants in the Commission’s Information Forums held in December 2004 also raised this issue. As discussed in Chapter 13, metering services for customers who consume less than 160 MWh per annum and have a manually read meter will be a prescribed service during the 2006-10 regulatory period. In its Position Paper, the Commission proposed to introduce two new GSL payments of $20 where the distributor is the Responsible Person and: • a special meter read is not undertaken on the scheduled date for reasons within the control of the distributor; or • a customer requests that a meter be tested and it fails the meter test. CitiPower, Powercor and United Energy opposed these proposed GSL payments and highlighted the significant practical difficulties in apportioning responsibility between the distributor, retailer and customer where a meter read has not occurred. Distributors also raised the issue of access to a meter as a major barrier to obtaining a special meter read on time. CitiPower (2005b, p. 8) and Powercor (2005b, p. 8) noted that in 2004, only 15 and 19 of their meters respectively failed a meter test, and that in this event, they waive the meter testing charge. United Energy (2005c, p. 48) noted that there is little effective action a distributor could undertake to reduce the number of failed meter tests. The Commission notes that very few meters fail meter tests, and considers that the proposed GSL payments of $20 would be insufficient relative to the cost of a meter test if it passes. The Commission has therefore decided not to introduce GSL payments for metering. The Commission also considered the introduction of a GSL payment based on a quality of voltage measure. However, it has concluded that this is currently infeasible as the existing voltage monitoring is based on a sample of feeders only, rather than all feeders. The Commission October 06 114 Essential Services Commission, Victoria Final Decision has provided expenditure for distributors to improve the quality of supply over the next regulatory period so that they improve the level of compliance with the Electricity Distribution Code. At the next review, consideration may be given to the introduction of a GSL payment in relation to one or more measures of quality of supply. Forecast expenditure on GSL payments In the 2001-05 regulatory period forecast expenditures for GSL payments were included in the distributors’ revenue requirements in the first year and scaled to zero (for urban distributors) or 50 per cent (for rural distributors) in the last year of the regulatory period. Capital expenditure was also provided to improve reliability, including to worst served customers. In its Position Paper, the Commission indicated that forecast expenditure for making GSL payments in the 2006-10 regulatory period would be included in the distributors’ revenue requirements. Under the Commission’s proposed approach, distributors would be provided with sufficient revenue to make GSL payments that are implied by the existing standards of service. Because costs associated with improving performance can be recovered through foregone payments, an incentive is provided to improve service standards, where the cost of improvement is less than the level of GSL payments that would otherwise be made. It reflects an assumption on the Commission’s part that customers receiving average levels of service are ‘willing to pay’ for service improvements for the worst served customers. Information gained at public forums indicated that, whilst not all customers agreed that they should pay more, strong support was shown for improving service to worst served customers. Additionally, because expenditure for any additional GSL payments payable due to a deterioration from the current level of performance has not been included in the revenue requirement, an incentive is also provided to at least maintain service levels to worst served customers. EUCV (2005b, p. 55) did not support the distributors receiving any such funding. However, the Commission notes that if no funding was provided to the distributors for GSL payments, funding to enable the distributors to deliver a minimum level of service implied by the GSL payments would need to be provided. For the reasons outlined, the Commission has decided to include expenditure for making GSL payments in the revenue requirement. The forecast expenditure associated with the modified GSL payments scheme, based on information provided by distributors about the expected number of payments, is set out in Table 3.5. 3.2.3 Other proposed service incentive arrangements Other proposed service incentive arrangements discussed in this section, are incentives to protect reliability in the long term and a loss incentive mechanism. October 06 115 Essential Services Commission, Victoria Final Decision Incentives to protect reliability in the long term The distributors were required to demonstrate that the service incentive arrangements proposed by them will provide the appropriate incentives in both the short term, that is, within the regulatory period, and the long term, for example, a 20 year horizon. The Commission is concerned that the impact of decisions taken now by the distributors may not be evident in the short term, but may affect the reliability of the network in the longer term through an increase in the probability that an interruption occurs. In particular, the average reliability measures are lagging measures, that is, a change in outcome lags a change in behaviour. EUCV (2005b, p. 55) also expressed concern regarding the “short termism” of the distributors: Over recent years, the life time of a CEO in Australian business has becoming shorter, the mobility of senior executives has increased and the level of ownership of public companies by fund managers has also increased. These factors all point towards a need of stakeholders, CEOs and senior executives to look at performance over a shorter time horizon, and particularly they lead to focusing on short term profits at the expense of longer term viability of the enterprise. None of the distributors addressed the long term reliability issue in their price-service proposals. To address long term reliability, and in the absence of proposals from the distributors to address this issue, the Commission considered the inclusion of leading measures in the service incentive mechanisms, that is, the inclusion of measures that will identify a change in behaviour which may lead to a deterioration in reliability over time. One option raised by the Commission in its Issues Paper was the inclusion of an operational measure. The operational measure would be based on the plans already developed by the distributors to support their business, and their adherence to the plans over time. In response to criticisms about the practicality of such an operational measure, the Commission modified its approach and proposed the introduction of a “health card” for each distributor that would be included in the annual Comparative Performance Report in a traffic light form — measures would be displayed as green (highest rating), orange or red (lowest rating). The “health card” would consist of measures to provide an indication where a distributor may not necessarily be implementing its long term strategy and/or plans. It would seek to identify changes that may indicate a deteriorating “health” of the business which may lead to an increase in the underlying risks assumed by the distributor. In response, SP AusNet (2005b, p. 17) reiterated that it considered the proposed price control and S-factor scheme were sufficient to ensure long term network health. Further, SP AusNet warned of the risk that management focus would turn from delivering desired efficient outcomes to obtaining a “green light” and considered the benefits of the health card to be unclear, at best. CitiPower (2005b, p. 9) and Powercor (2005b, p. 9) also considered the identification of effective indicators problematic and were not convinced of the benefits from the more intrusive reporting implied. October 06 116 Essential Services Commission, Victoria Final Decision The Commission is aware of the need to retain an output focus in the measures proposed and to avoid attempts to micro-manage the distributors’ businesses. However, the Commission remains of the view that measures to provide an indication to the Commission that a distributor may not necessarily be implementing its long term strategy and/or plans are necessary to maintain accountability for reliability of the network in the longer term. The Commission has discussed the measures and ratings that should be included in the ‘health card’ with the distributors. The aim of these discussions was to ensure that, where possible, the measures and ratings adopted were a reasonable indicator that the distributors’ plans are effective and being implemented, including asset management plans, network augmentation plans, electricity safety management plans, vegetation management plans, asset maintenance plans, inspection and condition monitoring plans and workforce plans. Additionally, the Commission sought to ensure that, where possible, the proposed measures were able to be based on currently reported and available data. With regard to specific measures proposed, EWOV noted that, for the purposes of the health card there is a need for consistency in how ‘complaints’ is defined by the distributors. The Commission shares this concern and is therefore proposing to define complaints in terms of the number of complaints referred to EWOV. EWOV also considered that the thresholds proposed for complaints were too low and suggested a green light be set at an increase in complaints of less than 50 per cent, orange light at an increase of between 50 and 100 per cent and red light at an increase of greater than 100 per cent. The Commission concurs with this view and has amended the “health card” accordingly. In meetings with the Commission, the ETU recommended new measures based on the number of electrical incidents notified to Energy Safe Victoria (ESV)44 and the number of incidents reported to the Victorian WorkCover Authority. The Commission is of the view that such measures should be included in the health card and will discuss suitable measures with ESV and the Victorian WorkCover Authority in due course. The Commission has discussed the other proposed safety related measures with ESV and has updated them to reflect the type of information provided by distributors to ESV. CitiPower (2005s, p. 9) and Powercor (2005k, p. 14) were concerned about the inclusion of the regulatory and safety audit scores as measures. The Regulatory Audit and the OCEI (ESV) Audit adhere to a prescriptive process whereby the audit results provide a clear independent assessment of the distributors’ compliance to the various licence conditions… It is not helpful to provide further assessment on Audit scores that have already evolved through the application of stringent assessment criteria. In the event that audit scores remain as a measure in the “health card”, it is important there is a transparent process for consultation with stakeholders on the methodology used for developing audit scores. Such weightings would also need to be reviewed each year as the audit scope changes. 44 Energy Safe Victoria incorporates the former Office of the Chief Electrical Inspector. October 06 117 Essential Services Commission, Victoria Final Decision CitiPower and Powercor also commented on the proposed measure for the Bushfire Mitigation index. … the Commission has proposed that a result of zero at the start of the bushfire season will obtain a “green light” on the “health card” and any other result other than zero will obtain a “red light”. Such a target is simply unbeatable and any other result, however small, results in a “red light”. Also, the draft decision proposes that the indicator must be zero “at the start of the bushfire season”. This is problematic as the bushfire season is not uniformly declared across the regions of Victoria. The Commission considers that the health card is best structured by aggregating available information and that the use of audit scores and distributors’ reporting on Bushfire Mitigation is an appropriate way of assessing distributors’ long term performance capability. Considering distributors’ comments, the measures for audits and bushfire mitigation have been altered to reflect ESV’s assessment of the level of compliance against the audited items. This approach allows a graduated assessment for bushfire mitigation, depending on the successful completion of each component of the distributors’ mitigation plans. The Commission has decided that, from 2006, it will include a health card for each distributor in the annual Comparative Performance Report. The Commission may review the health card annually. The health card intended for the first Comparative Performance Report in the next regulatory period is provided in the attachment to this chapter. In its Position Paper, the Commission also proposed that the distributors’ directors sign off on an annual basis that nothing had come to their attention that would reasonably lead them to believe that: • the distributors’ plans and processes will not ensure that the reliability of the network will be maintained or improved over the next 20 years; and • the underlying risks of a deterioration in reliability are increasing. It was also proposed that, when submitting the regulatory accounts for a distribution business, the distributor’s directors would be required to sign off that nothing had come to the directors’ attention that would reasonably lead them to believe that expenditure incurred will not ensure that the reliability of the network will be maintained or improved over the next twenty years and that the underlying risks of a deterioration in reliability are increasing. In response, the distributors stated it was unreasonable to expect a sign off based on a 20 year horizon. CitiPower and Powercor considered that directors simply would not have a view in relation to such a long time frame, and SP AusNet noted that such a statement would require material caveats so extensive that the sign-off would become meaningless. Stakeholders were also confused by the negative assurance that was sought. The Commission notes these concerns and also notes that, as part of their financial statements, UK water companies are required to submit a certificate signed by the directors stating that the company has sufficient financial resources and facilities, management resources and systems of planning and control to comply with its investment program. However, such a certification is based on a shorter period than the 20 year period proposed by the Commission. October 06 118 Essential Services Commission, Victoria Final Decision In its Draft Decision, the Commission therefore modified its proposed requirement based on a shorter timeframe, and clarified what it meant by an increasing underlying risk of a deterioration in reliability. Thus, in its Draft Decision, the Commission proposed to require the distributors’ directors to sign off on an annual basis that the distributors’ plans and processes will, for at least the next twelve months, ensure that the reliability of the network will meet or exceed the targeted reliability levels and that the underlying risks of a deterioration in reliability (that is, the probability of an interruption) are not materially increasing. Additionally, the Commission proposed that at any time a distributor’s directors became aware that the underlying risks of a deterioration in reliability (that is, the probability of an interruption) are materially increasing, they must advise the Commission accordingly. Distributors were of the view that the requirement to meet or exceed reliability targets was unreasonable because variability about average performance means that out performance of targets cannot be assured in every year. Additionally, CitiPower (2005s, p. 11) stated: Should ESC decide to proceed with the sign-off arrangement, prudent directors would increase the scope of audit and compliance programs to provide assurances to them prior to these sign-offs. The ESC should allow further operational costs of at least $100,000 in its Final Decision to allow distribution businesses to fund such programs. The Commission notes these issues arise from the wording relating to achieving a certain level of reliability performance and has therefore decided that the sign-off should adopt the same wording in (and therefore refer to the existing obligations of the distributors under) the Electricity Distribution Code. In summary, the Commission requires that, when submitting the regulatory accounting statements for the distributor, the distributor’s directors must also confirm in writing that the distributor will, for at least the next twelve months, have available to it the financial resources and facilities and management resources required to meet its obligations under the Electricity Distribution Code to: • meet reasonable customer expectations of reliability of supply; and • use best endeavours to meet or exceed the targeted reliability levels required by the Price Determination; and that the underlying risks of a deterioration in reliability (that is, an increase in the probability of an interruption) are not materially increasing. At any time a distributor’s directors become aware that the underlying risks of a deterioration in reliability (that is, an increase in the probability of an interruption) are materially increasing, they must advise the Commission. Distribution losses The Commission has also been concerned about distribution losses. Distribution losses consist of electrical losses, metering errors and theft. Distribution Loss Factors (DLFs) are used in the October 06 119 Essential Services Commission, Victoria Final Decision National Electricity Market to assign a share of distribution losses to each connected customer. Concerns in relation to the DLF are in regard to: • the loss levels; and • the accuracy with which the DLF is estimated. In relation to loss levels, distributors currently have an obligation under the Electricity Distribution Code to consider the cost of distribution losses in identifying the least cost options for network augmentations. The Commission notes that there is a trade off between utilisation and losses — as assets are driven harder and asset utilisation improves, losses will increase. In its Position Paper, the Commission therefore proposed that the distributors provide a specific statement in each of their annual Distribution System Planning Reports and Transmission Connection Planning Reports that the cost of distribution losses was considered in identifying the least cost options for network augmentations. The Commission considered the inclusion of a loss incentive mechanism, similar to that proposed in the UK and Ireland. Under such a scheme, the distributor would have an incentive to maintain losses at the target level. Additionally, if the actual losses are higher or lower than the DLF target, the distributor would be penalised. Whilst AGLE and SP AusNet initially supported an incentive regime on DLF in principle, distributors opposed the proposed scheme. They identified a range of issues, including: • a nationally accepted approach to estimating DLF is not yet agreed; • the efficient level of losses should be revealed through the incentive mechanism; • the UK scheme is an incentive on actual losses rather than an incentive on ex-ante loss estimates and therefore should be not be transposed directly; and • distributors should not be penalised on the difference between actual and target as the actual losses are largely outside the control of the distributor. PB Power reported to the Commission on the loss levels of other countries in 2000 (PB Power 2000b). Based on the findings of this report, the Commission considers that the economic levels of distribution losses for Victorian distributors should be in the range of 3 to 5 per cent of sales for urban-based networks and could be as high as 10 per cent of sales for distributors with predominantly rural networks. The Commission notes that distribution loss levels in Victoria are consistent with the information provided by PB Power about distribution losses levels in other countries with similar network characteristics. The Commission therefore considers there is no evidence that distribution loss factors are at inappropriate levels, and so has not set targets for distribution losses for the 2006-10 regulatory period. With regard to the accuracy with which the DLF is estimated, the National Electricity Market is currently settled on the basis of the forecast DLF. The local retailer bears the risk associated with any error in the DLF forecast. The risk to the local retailer increases when customers transfer October 06 120 Essential Services Commission, Victoria Final Decision away from it. Hence, the risk is small at the early stages of competition in the retail energy market but increases as the market becomes more competitive. Retailers (AGL ES&M and Origin Energy) supported an incentive for the distributors to accurately forecast DLFs, as it would decrease the risk faced by local retailers. Origin Energy suggested consideration of the equivalent loss incentive scheme in the gas industry. EUCV (2005b, p. 57) supported such a mechanism on the basis that accurate forecasting of losses is an essential step in identifying the optimal solution to the level of losses. AGLE (2005b) and SP AusNet (2005b, p. 19) strongly opposed the loss incentive mechanism. They stated that the risk under the scheme is asymmetric and that this extra risk needed to be provided for through the weighted average cost of capital or cash flows. United Energy (2005c, p. 49) considered it unlikely that distributors would systematically underestimate or overestimate DLFs year after year. Similarly SP AusNet stated that, if the forecast inaccuracy is symmetric over time, the host retailer is not disadvantaged. United Energy (2005c, p. 49) was also concerned that methodologies for forecasting DLFs not be constrained by the Commission if penalties apply and that a reward should exist to encourage distributors to invest to improve DLF forecasting. Further, SP AusNet (2005c, p. 3) was concerned that the proposed mechanism may create incentives to ensure investment decisions do not change actual losses from those forecast or even to avoid investment decisions, which would lead to a loss reduction, being taken before the DLFs can be re-forecast. Distributors also commented that any variance between actual and forecast losses is largely driven by exogenous factors rather than factors within the distributors’ control. The Commission notes that the actual variances between the distributors’ forecast DLFs and actual DLFs have been immaterial over the last few years. There has only been one distributor who has had a material variance between its forecast and actual DLF and that issue was discovered and corrected through the processes set out in the National Electricity Rules. The Commission therefore considers that there is no evidence to suggest that the reconciliation between actual losses and forecast losses as required by the National Electricity Rules is not sufficient to ensure distributors make accurate forecasts of losses. Taking all of these considerations into account, the Commission has accordingly decided not to introduce a loss incentive mechanism. However, the Commission does require a specific statement in each of the distributors’ annual Distribution System Planning Reports and Transmission Connection Planning Reports that the cost of distribution losses has been considered in identifying the least cost options for network augmentations. Further, during the annual approval process, the Commission will continue to monitor the levels of distribution losses to ensure that they remain within an appropriate range, and to assess the reconciliation between actual losses and forecast losses as required by the National Electricity Rules. October 06 121 Essential Services Commission, Victoria Final Decision 3.2.4 Exclusion criteria An important feature of the existing service incentive arrangements is the ability of the distributors, with the approval of the Commission, to have the impact of certain events excluded from the calculation of the S-factor and from the requirement to make certain GSL payments. The distributors can currently apply to have the impacts of the following events excluded: • supply interruptions made at the request of the distribution customer affected; • load shedding due to a shortfall in generation; • supply interruptions caused by a failure of the shared transmission network; • supply interruptions caused by a failure of transmission connection assets, to the extent that the interruptions were not due to inadequate planning of transmission connections; and • widespread supply interruptions due to rare events, which were not reasonably able to be foreseen and, to the extent that the distributor was not reasonably able to mitigate their impact. In its Final Framework and Approach, the Commission proposed to continue to allow interruptions caused by transmission and generation to be excluded from the calculation of the financial incentives, with the exception of load shedding due to a shortfall in embedded generation. Widespread supply interruptions due to rare events The Commission noted that the criteria for the qualitative exclusion (that is, the widespread, rare and unforeseeable exclusion) were somewhat broad and that there remained a level of subjectivity in their application. The Commission’s preferred approach was to continue to exclude abnormal events, including force majeure events, but add clear quantitative criteria to facilitate the assessment of these events and to limit the distributors’ risk exposures. The Commission also proposed to exclude all events, not just those outside the control of the distributor, but to set the quantitative criterion sufficiently high to limit the events to those that are abnormal. This recognises that the existing scheme is administratively complex and costly for distributors and the Commission. The distributors generally supported a quantitative exclusion criterion rather than the existing qualitative criterion for widespread, rare and unforeseeable events. However, EUCV (2005b, p. 38) submitted that: Rare events have the same impact on consumers as frequent events and so should not be excluded. Origin Energy (2005a, p. 11) also noted that: … the main criteria should be to hold the distributors accountable for events that were within their control or direct influence or can be better managed (in terms, say, of time of interruption) with the appropriate balance of approved capital and operating expenditure. While it may be pragmatic to exclude events based on a statistical outlier analysis, it does October 06 122 Essential Services Commission, Victoria Final Decision not follow that just because an event is extreme that it is also outside a distributor’s control. Whilst AGLE, CitiPower, Powercor and SP AusNet proposed a quantitative criterion based on SAIDI, United Energy (2004c, p. 46) was of the view that a criterion based on SAIDI could wrongly exclude poor fault response times. It proposed that the criterion be based on the proportion of customers affected or the proportion of customers off supply for 1 hour. SP AusNet proposed a more statistical approach, adopted by Ofgem as part of its recent price review for the UK distributors. SP AusNet proposed to calculate the mean and standard deviation of the daily unplanned SAIDI, exclude any day where unplanned SAIDI is greater than 4 standard deviations from mean unplanned SAIDI, and replace all reliability measures for the excluded day with the mean result for each measure. The Commission notes, however, that the Ofgem scheme is based on SAIFI for severe weather events (Ofgem 2004a, p. 21) or SAIDI, but includes a qualitative assessment that the distributor must have taken all appropriate steps to prevent the event and to mitigate the impact. In its Position Paper, the Commission proposed to base its quantitative criterion on SAIFI. However, SP AusNet (2005f, p. 20), CitiPower (2005b, p. 11) and Powercor (2005b, p. 11) proposed that daily SAIDI not SAIFI should be the trigger as SAIFI does not follow a lognormal distribution and therefore the application of a statistical approach may not be appropriate. In addition, SP AusNet (2005b, p. 20) claimed that with SAIDI, outages of lengthy duration but low frequency are excluded, and CitiPower and Powercor noted that SAIDI included both numbers of customers affected and duration. Distributors also noted that national reporting requirements agreed by the Utility Regulators Forum are based on excluding events using a SAIDI threshold. As a member of the forum, the Commission accepted this exclusion threshold, but notes the exclusion is for a different purpose — comparing reliability performance on a nationally consistent basis. National reporting requirements also require that the excluded events be itemised so that users of the information can assess the relevance when making performance comparisons. The Commission considers that the quantitative exclusion criterion should be based on SAIFI rather than SAIDI. As pointed out by United Energy, a criterion based on SAIDI could wrongly exclude events where there was a poor response time. In the Commission’s view, SAIFI, rather than SAIDI, is a better indicator that a large number of events have occurred which will stretch the distributors’ resources to restore supply. Additionally, it is consistent with Ofgem’s approach for severe weather events. Having decided that the qualitative exclusion criterion will be based on SAIFI, the exclusion criterion must be quantified. The principle applied by the Commission in quantifying all exclusion criterion is that it should exclude outlier events. Prior to the Draft Decision, the Commission considered: • using a lognormal distribution of the distributors’ daily SAIFI data over the 2000-04 period, with a threshold that was 2.7 standard deviations from the mean; and • the impact of the February 2005 storms. October 06 123 Essential Services Commission, Victoria Final Decision The distributors were concerned that thresholds set on the basis proposed by the Commission were too high and were inconsistent in application. CitiPower and Powercor proposed that the thresholds should be set by considering the number of customers affected — 25,000 customer interruptions or 2 million customer minutes,45 with the exclusion proposed in the Draft Decision being equivalent to 90,000 customer interruptions for Powercor. AGLE proposed that the modified scheme should provide a similar level of exclusions as the current scheme. United Energy proposed that the exclusion should be based on a 2.5 beta SAIDI methodology. Powercor noted that there have been no days in the last five years that would have triggered its threshold, proposed in the Draft Decision, whereas seven days were approved by the Commission for exclusion from the calculation of the S-factor in the 2001-05 period . However, the Commission notes that of these exclusions, five related to a single pole fire event that occurred over a period of months; one related to storms over Melbourne where the impact of the event on other distributors was the prime consideration; and one related to localised damage due to a tornado. In all of these events, the SAIFI impact on Powercor’s network was small. While these events met the exclusion criterion that applied to them at that time, they are not significantly different from other events that did not meet the exclusion criterion. The Commission considers that the quantitative exclusion criterion is unlikely to result in the same outcomes as the criterion that applies to the 2001-05 regulatory period due to the different basis of the criterion. In assessing the risk of the new S-factor scheme, Mercer developed a complex distribution function to model the daily SAIFI for each distributor over the 2000-04 period. Subsequent to the Draft Decision, the Commission engaged Mercer to assist it to quantify the exclusion criterion by determining the daily SAIFI for a one-in-five year event and a two-in-five year event using the distribution function for each distributor. Mercer’s reports (2005f to 2005j) are published on the Commission’s website. Mercer’s analysis indicated that CitiPower and SP AusNet had experienced outlier events during the 2000-04 period, whilst AGLE, Powercor and United Energy did not. The location of the Powercor and United Energy distribution areas is such that these distributors do not generally experience storms that impact a large proportion of their customers. Therefore, a one-in-five year event and a two-in-five year event based on the distribution function of the 2000-04 daily SAIFI data is likely to understate an appropriate exclusion criterion for AGLE, Powercor and United Energy and may over-state it for CitiPower and SP AusNet. The results of the Commission’s analysis based on a lognormal distribution of daily SAIFI, the impact of the storms on 3 February 2005 and a one-in-five event using the distribution function to model the daily SAIFI during the 2000-04 period, are provided in Table 3.11. The Commission has exercised its judgement to quantify the exclusion criterion (or threshold) using this information. For those distributors that have not experienced an outlier event during 2000-04 (AGLE, Powercor and United Energy), the threshold is set above the SAIFI corresponding to a 45 The Commission notes that Ofgem use these thresholds for certain events such as transmission-related events, but not for severe weather events. October 06 124 Essential Services Commission, Victoria Final Decision one-in-five year event. For CitiPower and SP AusNet, the threshold is based on the lognormal distribution consistent with the Draft Decision. Table 3.11: Daily unplanned interruption frequency threshold, by distributor Lognormal distribution Storms on 3 February 2005 Mercer – 1-in-5 year event Final Decision Threshold AGLE 0.243 0.139 0.109 a 0.120 CitiPower 0.066 0.135 0.154 0.066 a 0.110 Powercor 0.140 0.056 0.098 SP AusNet 0.190 0.430 0.208 0.190 United Energy 0.337 0.163 0.085 a 0.100 a Given that AGLE, Powercor and United Energy did not experience any outlier events during the 2000-04 period, a one-in-five year event based on this period will understate an appropriate exclusion criterion. When the SAIFI for a particular day exceeds the threshold, that day’s reliability data will be substituted with the mean annual reliability data for the purposes of the S-factor scheme and GSL payments scheme. The call centre performance data for that day will be excluded from the calculation of the S-factor. In its Draft Decision, the Commission set out the mean daily unplanned interruption duration and frequency based on daily data provided by the distributors for 2000 to 2004 which was to be substituted on an excluded day. The data provided by AGLE was incorrect at that time as it included both planned and unplanned interruptions. The mean daily unplanned interruption duration and frequency has subsequently been recalculated and the revised data is set out in Table 3.6. The Commission also notes that the exclusion criterion would apply to all events, not just those outside the distributors’ control as is the intent of the exclusion criteria that apply in the current period. EUCV (2005b, p. 58) did not support such an approach as it is not: …in keeping with the expectation that the DBs should be penalized for not performing their tasks correctly. However, to do otherwise would re-introduce a subjective element and may incentivise a distributor to “gold plate” its network, with consequential inefficient funding requirements, to ensure no major events would occur which could be considered to be within its control. The quantitative criterion for widespread and rare events will apply to events that occur from 1 January 2006. The criterion set out in the 2001-05 Volume II — Price Controls will continue to apply in the calculation of the S-factors in 2006 and 2007, based on events in 2004 and 2005. Accordingly, distributors will be able to apply to have the impacts of the following events excluded from the calculation of the S-factor and from the requirement to make certain GSL payments: October 06 125 Essential Services Commission, Victoria Final Decision • for the S-factor scheme calculated in the years 2006 and 200746, widespread supply interruptions due to rare events, which were not reasonably able to be foreseen, to the extent that the distributor was not reasonably able to mitigate their impact; and • for the GSL payments scheme for 2006, and for the S-factor scheme calculated from 200847, supply interruptions on a day where the unplanned interruption frequency exceeds the threshold as set out in Table 3.6. On these days, the mean frequency and duration of interruptions, as set out in Table 3.6, must be substituted for that day’s actual frequency and duration of interruptions. On these days, when calculating the call centre performance measure of the S-factor scheme, the call centre performance data for that day is excluded. Shortfall in embedded generation or demand side response initiatives In its Final Framework and Approach, the Commission proposed that the impact of supply interruptions due to a shortfall in embedded generation should not be excluded from the service incentive mechanism. By exempting these supply interruptions, reliability to customers could worsen without the distributor or generator being held accountable. The Commission was of the view that distributors should be accountable for delivering targeted reliability, including when seeking to address required network augmentations by entering into network support agreements with generators. Customers’ reliability should not be negatively affected by how the distributor chooses to augment its network. AGLE and United Energy did not support that these supply interruptions could not be excluded from the service incentive scheme. United Energy (2004e, p. 46) indicated that the penalty associated with the S-factor scheme is too great for embedded generation to be commercially viable. United Energy considered this to be inconsistent with the Commission’s encouragement for distributors to consider embedded generation as an alternative to traditional network solutions. Whilst the distributors and demand side response proponents supported the exclusion of supply interruptions due to a shortfall in embedded generation, other stakeholders did not. EUCV did not believe that a lack of embedded generation should be an excuse for failure to deliver service. Origin Energy was of the view that the distributor should be held accountable for its procurement decision and its ongoing management of the arrangement with the embedded generator. The Commission continues to be of the view that supply interruptions due to a shortfall in embedded generation should not be excluded. The distributors should continue to be held accountable for delivering the targeted levels of reliability, including when seeking to address required network augmentations by entering into network support agreements with generators. Customers’ reliability should not be affected by how the distributor chooses to provide distribution services. However, following discussions with demand side response proponents and distributors, the Commission better understands the tension between trialling demand side response initiatives 46 47 Based on actual performance prior to 2006 Based on actual performance from 2006 October 06 126 Essential Services Commission, Victoria Final Decision and the operation of the service incentive mechanisms. The Commission also understands the importance of demand side initiatives to reduce peak demand which will in turn reduce expenditure required to provide the capacity for these peak demands for a relatively short period each year. Therefore, for a trial period only, an exclusion criterion for embedded generation or other demand side initiatives has been included. The Commission will require approval to be provided by it prior to the commencement of the period during which load shedding due to a shortfall in embedded generation or other demand side initiative is to be excluded from the service incentive mechanisms. When seeking approval, the proponent must demonstrate that customers likely to be impacted have been appropriately identified and have agreed to an exclusion over a defined period. The Commission may provide initial approval for a three month or longer period as agreed by the Commission and a distributor is required to apply for an exclusion on each occasion an event occurs. This period may be extended to a maximum of three years where customers have agreed to a longer period and subject to the administrative burden placed on the Commission and distributors during the initial three month period. That is, if the exclusion does not place an administrative burden on the Commission or the distributor the trial will be extended, but if the exclusion places an administrative burden on the Commission or the distributor, the trial period will not be extended. Therefore, the exclusion criterion enables distributors to apply to have the impacts of the following events excluded from the calculation of the S-factor and from the requirement to make certain GSL payments: • load shedding due to a shortfall in generation, but not a shortfall in embedded generation that has been contracted to provide network support, except where prior approval has been obtained from the Commission; and • where prior approval has been obtained from the Commission, load shedding due to a shortfall from demand side response initiatives. These exclusion criteria apply to the calculation of the S-factor scheme for the reliability measures from 2008 (based on the performance from 2006) and to the GSL payments scheme from 2006. Additional exclusion criteria Distributors proposed a number of additional exclusion criteria in their original price-service proposals: • failure of national carrier (priority 13 phone services); • inability to access Melbourne (CitiPower) or Bendigo (Powercor) contact centre building; • state of emergency; • supply interruptions caused by a failure of inter distributor services; • industrial relations force majeure; and October 06 127 Essential Services Commission, Victoria Final Decision • terrorist activity. In relation to these, CitiPower (2005b, p. 43) and Powercor (2005b, p. 43) agreed that: … the failure of the national telephone carrier, failure of inter-distributor services and inability to access a call centre can be influenced by commercial arrangements with suppliers. The alternative proposal that these events are not excluded is acceptable provided that adequate consideration is given in setting the allowable revenue and service targets. United Energy supported all these exclusion criteria whilst SP AusNet supported all of them, with the exception of the inability to access contact centre control buildings. EUCV and Origin Energy did not support these exclusion criteria. The Commission considers that setting exclusion criteria for industrial relations force majeure and terrorist activity is problematic. For instance, how is vandalism separated from terrorist activity? The Commission notes that where such events have a large impact, they would be excluded under the quantitative exclusion criterion for widespread and rare events. Given the comments from stakeholders and given the need to avoid administrative complexity in the scheme, the Commission has not adopted the additional exclusion criteria proposed by distributors. The Commission is of the view that the targeted levels have been set considering all data and not data that excludes these events. To do so would remove the incentive for the distributors to mitigate their risks through commercial agreements with suppliers. October 06 128 Essential Services Commission, Victoria Final Decision ATTACHMENT: ANNUAL HEALTH CARD Measure Green lighta Orange lighta Red lighta Reliability Equal or better than targeted level of reliability for unplanned SAIFI and unplanned SAIDI Worse than targeted level of reliability for unplanned SAIFI or unplanned SAIDI during the year Worse than targeted level of reliability for unplanned SAIFI or unplanned SAIDI during the last two years Voltage quality Decreasing or flat trend in the total number of voltage variations (steady state, 1 minute and 10 seconds) over the five year period, or part thereof where records are available (flat trend represents a less than 5 per cent increase in the number of voltage variations over the period) or voltage quality improvement projects implemented as forecast Increasing trend in the total number of voltage variations (steady state, 1 minute and 10 seconds) over the five year period, or part thereof where records are available (increasing trend represents a 5 per cent or more, but less than 50 per cent, increase in the number of voltage variations over the period) or more than 20 per cent but less than 50 per cent of cumulative forecast voltage quality improvement projects not implemented Increasing trend in the total number of voltage variations (steady state, 1 minute and 10 seconds) over the five year period, or part thereof where records are available (increasing trend represents a 50 per cent or more increase in the number of voltage variations over the period) or 50 per cent or more of cumulative forecast voltage quality improvement projects not implemented Planning Decreasing or flat trend, over a 5 year period or part thereof, in the annual load at risk due to late completion of projects which were planned by the distributor to provide capacity to meet the expected maximum demand in winter or summer (flat trend represents a less than 5 per cent increase in the annual load at risk) Increasing trend, over a 5 year period or part thereof, in the annual load at risk due to late completion of projects which were planned by the distributor to provide capacity to meet the expected maximum demand in winter or summer (increasing trend represents a 5 per cent or more, but less than 50 per cent, increase in the annual load at risk) Increasing trend, over a 5 year period or part thereof, in the annual load at risk due to late completion of projects which were planned by the distributor to provide capacity to meet the expected maximum demand in winter or summer (increasing trend represents a 50 per cent or more increase in the annual load at risk) Service orders Based on the B2B report card completed by the distributors and retailers – to be developed after B2B report card developed Based on the B2B report card completed by the distributors and retailers – to be developed after B2B report card developed Based on the B2B report card completed by the distributors and retailers – to be developed after B2B report card developed Complaints Number of complaints referred to EWOV no greater than 1.5 times the average annual number of complaints referred during the period 2002-2004 Number of complaints referred to EWOV greater than 1.5 times but no greater than 2 times the average annual number of complaints referred during the period 2002-2004 or number of complaints referred to EWOV equal to or greater than 0.20 per 1,000 customers and less than 0.30 per 1,000 customers Number of complaints referred to EWOV greater than 2 times the average annual number of complaints referred during the period 20022004 or number of complaints referred to EWOV equal to or greater than 0.30 per 1,000 customers A direction issued under section 141 of Electricity Safety Act is outstanding for more than 3 months A direction issued under section 141 of Electricity Safety Act is outstanding for more and number of complaints referred to EWOV less than 0.20 per 1,000 customers Safety regulations No directions issued under section 141 of Electricity Safety Act are outstanding for October 06 129 Essential Services Commission, Victoria Final Decision Measure Green lighta more than 3 months during the year Orange lighta but no more than 9 months during the year Red lighta than 9 months during the year Bushfire mitigation plan No work outstanding at the start of the bushfire season One of the seven categories of work reported on is not completed at the start of the bushfire season More than one of the seven categories of work reported on is not completed at the start of the bushfire season Regulatory auditsb Score of more than 75 per cent for audit, based on level of non-compliance reported and the likely impact of that noncompliance Score of more than 50 per cent, but 75 per cent or less, for audit, based on level of non-compliance reported and the likely impact of that noncompliance Score of 50 per cent or less for audit, based on level of non-compliance reported and the likely impact of that non-compliance Safety audits (if undertaken) No significant areas of non-compliance as determined by Energy Safe Victoria Of the areas audited, one significant area of noncompliance as determined by Energy Safe Victoria Of the areas audited, more than one significant area of non-compliance as determined by Energy Safe Victoria Environmental (EPA) No infringement notices for environmental regulations during the year One infringement notice for environmental regulations during the year Two or more infringement notices for environmental regulations during the year Excluded service charges No occasions where excluded service charges are revised by the distributor following contact by the customer with the Commission No more than five occasions where excluded service charges are revised by the distributor following contact by the customer with the Commission More than five occasions where excluded service charges are revised by the distributor following contact by the customer with the Commission Electrical Incidents relating to a distributor’s distribution system Number of incidents reported to ESV is less than 1.25 times the number of incidents reported in the previous year and number of incidents reported to ESV is less than 0.5 per 1,000 customers Number of incidents reported to ESV is equal to or greater than 1.25 times but less than 1.5 times the number of incidents reported in the previous year or number of incidents reported to ESV is equal to or greater than 0.5 per 1,000 customers and less than 1.0 per 1,000 customers Number of incidents reported to ESV is equal to or greater than 1.5 times the number of incidents reported in the previous year or number of incidents reported to ESV is equal to or greater than 1.0 per 1,000 customers Green light (only) Quality systems certification (AS9000 series) Distribution business and/or its related party (where that related party undertakes a significant proportion of the distribution business’s obligations under its licence) certified with no major non compliances from most recent audit Environmental systems certification (AS 14000) Distribution business and/or its related party (where that related party undertakes a significant proportion of the distribution business’s obligations under its licence) certified with no major non compliances from most recent audit a The Commission may use its discretion to improve a rating from orange to green or red to orange, but may not move a rating from green to orange or orange to red. The “health card” will include a comments column which will explain the reasons for an orange light or a red light, and where the rating has been improved at the discretion of the Commission, will provide the rationale for this improvement. b Each compliance item is to be rated on a scale of 1 to 5 for compliance and a scale of 1 to 5 for the impact of non-compliance. Score for each compliance item is the product of the compliance rating and the impact rating. October 06 130 Essential Services Commission, Victoria Final Decision 4 GROWTH FORECASTS Energy consumption, peak energy demand and customer numbers are important inputs into the derivation of the new price controls. Future expenditure requirements are driven partly by expected growth in peak demand and customer numbers while the translation of the revenue requirement into a cap on distribution prices relies on forecasts of energy consumption, customer numbers and contract demand. The distributors have an incentive to understate the prospects for future growth since out-turn growth above that forecast will result in higher revenue than anticipated in setting prices. Over the current regulatory period, the distributors earned higher than expected revenues partly as a result of higher than forecast growth in energy consumption and customer numbers. The Commission has therefore undertaken an assessment of the distributors’ proposed growth forecasts so as to ensure that prices reflect a best estimate of those necessary to deliver the distributors’ revenue requirements. This Chapter sets out the Final Decision on the growth forecasts that have been used to determine the distributors’ revenue requirements and price controls, and the reasons for that decision. 4.1 Final Decision The Final Decision in relation to energy consumption, customer numbers and peak demand is set out in Tables 4.1, 4.2 and 4.3. These forecasts use National Institute of Economic and Industry Research’s (NIEIR’s) alternative base case growth scenario as revised by NIEIR in August 2005. October 06 131 Essential Services Commission, Victoria Final Decision Table 4.1: Energy consumption forecasts by distributor (GWh), including compound annual growth rate, 2004-10 AGLE CitiPower Powercor SP AusNet a United a 2005 2006 2007 2008 2009 2010 2004-10 growth rate (per cent) Residential 1,156 1,169 1,191 1,211 1,228 1,248 1.45 Non-residential 3,028 3,044 3,073 3,091 3,098 3,109 0.49 Residential 1,212 1,237 1,271 1,310 1,342 1,367 2.21 Non-residential 4,433 4,465 4,532 4,590 4,618 4,647 0.83 Residential 3,271 3,308 3,355 3,415 3,462 3,500 1.40 Non-residential 6,551 6,716 6,873 7,004 7,143 7,304 2.14 Residential 3,094 3,165 3,251 3,326 3,390 3,472 2.58 Non-residential 4,086 4,209 4,337 4,459 4,577 4,701 2.70 Residential 2,790 2,814 2,863 2,906 2,936 2,972 0.81 Non-residential 4,755 4,851 4,954 5,037 5,109 5,189 1.70 Formerly TXU Table 4.2: Total customer number forecasts by distributor, including compound annual growth rate, 2004-10 2005 2006 2007 2008 2009 2010 2004-10 growth rate (per cent) Residential 256,649 260,822 265,156 269,170 273,260 277,641 1.70 Nonresidential 29,771 30,245 30,763 31,276 31,752 32,234 2.22 Residential 234,712 238,469 244,194 248,749 252,331 255,603 1.65 Nonresidential 46,693 46,786 47,089 47,116 47,142 47,174 0.48 Residential 538,254 547,727 557,949 568,808 578,908 588,422 1.77 Nonresidential 101,129 102,140 103,116 103,959 104,761 105,610 0.91 Residential 496,855 506,184 515,781 526,000 536,312 547,005 1.56 Nonresidential 70,780 71,844 72,603 73,514 74,385 75,253 0.90 United Residential 548,414 553,894 559,974 566,286 571,934 577,245 1.06 Energy Nonresidential 61,425 66,342 66,607 67,426 68,132 68,867 2.15 AGLE CitiPower Powercor SP October 06 132 Essential Services Commission, Victoria Final Decision Table 4.3: Peak demand (non coincident) forecasts at the zone substation level by distributor (MVA), including compound annual growth rate, 2005-10 2005 2006 2007 2008 2009 2010 2005-10 growth rate (per cent) AGLE 1,106 1,151 1,193 1,224 1,254 1,285 3.05 CitiPower 1,699 1,732 1,758 1,794 1,833 1,874 1.98 Powercor 2,394 2,477 2,481 2,508 2,559 2,610 1.74 SP AusNet 1,777 1,846 1,922 1,987 2,050 2,120 3.58 United Energy 2,392 2,471 2,550 2,617 2,682 2,754 2.86 4.2 Reasons for the Decision In preparing their October 2004 price-service proposals, each distributor commissioned NIEIR to develop four sets of growth forecasts. These scenarios were referred to as a base case, an alternative base case, a high case and a low case. The NIEIR reports provided the key factors underlying the projections for the base scenario. However, the information provided on the high and low scenario was limited to a high level qualitative description and the variation in forecast GSP for each scenario. The base and alternative base cases had the same economic and non-economic assumptions underlying them, except that the base case factored in a downside risk to manufacturing that resulted in slower growth rates in energy consumption than forecast by the alternative base case. NIEIR considered that it was appropriate to include a downside risk to manufacturing in the base case due to a combination of higher land prices and falling rates of return on the capital stock invested in Victorian manufacturing creating an incentive for manufacturing production to shut down and sell land and seeing the industry relocate operations to Asia and China in particular. The base and alternative base case scenarios factored in a slowing in the rate of growth in energy consumption over the period. The historic and forecast growth rates for energy consumption for both scenarios are set out in Table 4.4. October 06 133 Essential Services Commission, Victoria Final Decision Table 4.4: Electricity consumption growth rates (per cent per annum), 2000-04 historic, alternative base case forecasts and base case forecasts (pre-Draft Decision) Alternative base case Base case 2000-04 2004-10 2004-10 AGLE 0.75 0.88 0.37 CitiPower 1.95 0.82 0.62 Powercor 2.05 2.15 1.61 SP AusNet 2.90 2.65 2.42 United Energy 1.89 1.61 1.15 Note: 2000-04 historic growth rates based upon historic data made available through the annual tariff approval process, the distributors’ audited regulatory accounts and the Comparative Performance Reports. 2004-10 forecast growth rates are based on the NIEIR forecasts prepared in September 2004. Following the receipt of the distributors’ proposals in October 2004, the Commission engaged MMA to review the distributors’ forecasts. MMA reviewed the distributors’ forecasts, NIEIR forecasts and supporting information set out in the NIEIR reports and historic information, and reached the following conclusions: • While MMA considered the NIEIR customer number forecasts a reasonable basis for the distributor’s forecasts, it noted that none of the distributors had translated NIEIR forecasts directly into its own forecasts. • MMA had reservations about the methodology and quantification of the downside risk to manufacturing and Victorian Government 5-star standard. • NIEIR’s energy consumption forecasts prepared for the distributors appeared inconsistent with those it had prepared for VENCorp in June 2004 (MMA 2005, pp. i-xii) The Commission had some reservations over MMA’s findings. While MMA noted concerns over some of the methodology and quantifications that NIEIR had used, it was not always clear what information or considerations MMA had relied on to make its judgement. For example, MMA stated that NIEIR’s economic assumptions appeared reasonably consistent with those of other economic forecasters and Governments and with the NIEIR forecasts used for VENCorp. However, it was not clear what other economic forecasters and Governments MMA had relied on to make this conclusion nor did they provide a comparison of the estimates. MMA also developed its own forecasts to assess the reasonableness of the distributors’ forecasts. However, the forecasting techniques used by MMA were reasonably simplistic (employing simple regression methods based on a small set of historic data) when compared to the integrated model that it was understood NIEIR used. Due to these concerns, the Commission was not confident about placing a significant amount of weight on the forecasts that MMA prepared. As a result, the Commission undertook its own analysis of the distributors’ forecasts and the methodology and assumptions used by NIEIR. To inform this analysis, the NIEIR reports submitted in support of the NIEIR forecasts were reviewed, the consistency of the distributors’ October 06 134 Essential Services Commission, Victoria Final Decision forecasts with the forecasts set out by NIEIR in these reports was assessed and both NIEIR’s and the distributors’ forecasts (where these differed) were compared with the historic data that were available. This analysis confirmed that the forecasts provided by the distributors to the Commission were not always consistent with the forecasts prepared by NIEIR. Some distributors had different numbers, some distributors had different growth rates and others had both different numbers and different growth rates. Some distributors also revised their forecasts prior to the Draft Decision, which only increased the inconsistencies with NIEIR’s forecasts. As noted in the Draft Decision, CitiPower and Powercor submitted revised customer numbers due to an assumption of an increase in the number of embedded networks in their areas. While CitiPower and Powercor provided a verification letter from NIEIR, it was not clear that NIEIR was asked to verify the methodology and assumptions that CitiPower and Powercor used to derive their estimates of the proportions of their customers that would change to an embedded network tariff. Rather, it appeared that NIEIR was only asked to verify the methodology that CitiPower and Powercor applied to adjust their customer number and energy forecasts. The Commission did not allow any adjustments for embedded networks because the regulatory framework provides sufficient flexibility for the distributors to respond to competitive pressures by allowing them to rebalance their tariffs so that customers do not bypass the network (ESC 2005c, p. 138). CitiPower and Powercor did not comment on this issue in response to the Draft Decision and thus the Commission has not provided for any adjustments due to embedded networks in its Final Decision. On reviewing the reasons given for forecast lower growth over the next regulatory period, the Commission could not find information that corroborated those reasons. In particular, the Commission could not find evidence or information that supported an assumption of a downside risk to manufacturing. As a result, the Commission was of the view that the forecasts produced under the base case scenario (which incorporated the downside risk to manufacturing) were not a fair representation of likely growth over the next regulatory period. The Commission also noted that the forecasts of Victorian GSP under NIEIR’s high case scenario were consistent with those published in the Victorian State Budget Papers. The State Budget Papers indicated that, over the 2006-10 period, Victorian GSP was expected to grow by, on average, 3.3 per cent per year. This was consistent with the rate of GSP growth assumed in the high case growth scenario (on average, 3.3 per cent), and contrasted with the GSP forecast (2.6 per cent) underlying the alternative base case scenario. As a result, the Commission in its Draft Decision considered that NIEIR’s high case growth scenario would better reflect the most likely growth outcomes for the 2006-10 regulatory period than the alternative base case scenario. The high case scenario resulted in customer number and energy consumption growth over the 2005-10 period of 1.83 per cent and 2.58 per cent (unadjusted for elasticity effects) respectively. October 06 135 Essential Services Commission, Victoria Final Decision Following the Draft Decision, the distributors (CitiPower & Powercor 2005a) raised several issues with the use of the high case growth scenario, namely, in their view: • The reliance on the Department of Treasury and Finance’s (DTF) forecasts was unreasonable and the prevailing weight of expert opinion supported the NIEIR base case economic forecasts. • NIEIR unequivocally recommended use of the base case and NIEIR’s high case was optimistic on a range of economic and non-economic variables. • Rejection of the manufacturing downside scenario was unreasonable. • The forecasts were inconsistent with: y VENCorp and NEMMCO’s forecasts; y historic growth rates; y the use of base case forecasts in the last price review; and y the use of the base case forecasts by other Australian regulators. In response to these concerns, the Commission has undertaken further analysis and review of the NIEIR forecasts and forecasting methodology as well as the information that the distributors provided NIEIR to develop the forecasts. This further review has focused on: • identifying and reconciling the difference between the historic growth rates calculated by NIEIR and those calculated by the Commission; and • understanding the impact and variance of the different assumptions used in each scenario. 4.2.1 Historic growth rates When comparing forecasts to historic growth rates, the Commission has relied on the historic data available to it from the annual tariff approval models, regulatory accounts and Comparative Performance Reports. Using this information, the Commission calculated that the growth rate in energy consumption over the 2001 to 2004 period was 2.3 per cent. In contrast, NIEIR calculated that the growth rate over this period was 1.8 per cent (NIEIR 2005b). Similar discrepancies were found in the historic customer number data. This variation prompted the Commission to seek to reconcile the historic data available to the Commission and that made available to NIEIR. Table 4.5 sets out the 2000-04 growth rates in energy consumption for each distributor using the Commission’s historic data and that provided by NIEIR. October 06 136 Essential Services Commission, Victoria Final Decision Table 4.5: Total energy consumption growth rates, 2000-04 Commission historic NIEIR historic AGLE 0.75 0.76 CitiPower 1.95 1.59 Powercor 2.05 2.43 SP AusNet 2.90 3.13 United Energy 1.89 1.59 Note: Commission 2000 to 2003 historic data compiled from tariff approval models and 2004 historic data from regulatory accounting statements. NIEIR historic data compiled from information provided by NIEIR. NIEIR (2005c) stated that it believed the discrepancies in the data were due to: • separation and integration of information systems due to changing industry and organisational structure (for example full retail competition); • reliance on retail billing systems without distinct network billing functionality; • real world effects such as weather;48 and • differences between accrued positions and underlying positions for distinct periods. NIEIR’s historic data was provided to it by the distributors. The Commission understands that this data is derived from the distributors’ (non-weather normalised) customer billing data. However, NIEIR (2005b) indicated that it did not rely solely on the information provided by the distributors but tried to reconcile it with weather normalised VENCorp data (adjusted for losses, transmission customers and embedded generation). NIEIR (2005c) stated that the Commission should place more weight on the VENCorp data in its assessment of historic growth rates given the anomalies and inconsistencies that exist between the data that the Commission has available to it and the data made available to NIEIR. When making comparisons with the forecasts of energy consumption and customer numbers, the Commission has relied on the historic data available to it from the annual tariff approval models and regulatory accounting statements. These are the data that are provided by the distributors for regulatory purposes, principally to demonstrate their compliance with the price controls established at the last price review. The growth forecasts used to determine the price and revenue outcomes set out in this Determination should be consistent with the data provided to ensure compliance with those outcomes. 48 Energy consumption varies with the weather. For example, energy consumption in one year may be higher than the previous year because the weather may be hotter and thus greater use of air conditioning is made. In the short term, energy consumption data must be adjusted to remove the effects of abnormally hot or cold years so that it is more representative of the overall trend in energy consumption. Over the long term, weather effects will cancel themselves out — that is, abnormally hot years will be offset by abnormally cool years — and thus no adjustment is required. October 06 137 Essential Services Commission, Victoria Final Decision 4.2.2 Assumptions underpinning the different scenarios In response to the Draft Decision, the distributors commented that the high case growth scenario was an extreme case generated by factoring into the modelling optimistic assumptions on a range of economic and non-economic factors. The distributors (CitiPower & Powercor 2005a) stated that the high case assumes, for example, the following: • Iraq stabilising, peace in the Middle East and oil prices returning to $US15 to $US25; • EuroAsia expansionary monetary policies leading to above average European growth rates for 10 to 15 years; and • China opening up, becoming democratic and world trade expanding at 6-9 per cent per annum. These assumptions were not documented in the NIEIR reports submitted to the Commission prior to the Draft Decision. The only items of information available at the time of the Draft Decision on the high case scenario were the Victorian GSP forecasts underpinning the growth forecasts and a broad description of the economic circumstances assumed under the high case. This description was set out in the Commission’s Issues Paper and is as follows: In contrast to the base case, the high scenario expects strong Asian economic growth, including in China, over the projection period. The structural imbalances in the United States economy are gradually corrected without any further shocks to consumers, businesses and investor confidence. Stronger United States growth reduces their current account deficit. Global conflict, including terrorism, abates. Commodity prices remain high for a sustained period and that Australia secures a significant number of major resource processing projects in the mining and energy sectors. Business investment and Australian exports surge, supporting stronger growth in the Australian economy to 201314. In response to the distributors’ concerns over the use of the high case, the Commission has further reviewed the assumptions used under the high, alternative base and base case scenarios, the methodology that NIEIR used to develop these assumptions and how the assumptions were then factored into the growth forecasts. In undertaking this review, the Commission has met with NIEIR and visited its premises to view the NIEIR model and assessed the assumptions that NIEIR has used against other publicly available information sources. While a summary of the main economic forecasts used to develop the electricity forecasts is provided in the NIEIR reports, there does not appear be a similar description of the assumptions that were used to develop these economic forecasts. In order to understand the methodology, the Commission queried how assumptions such as peace in the Middle East were factored into the modelling. NIEIR indicated that these were the assumed circumstances needed for the oil price to return to the $US15 to $25 range. It does not appear that the assumptions underlying each scenario are documented, nor how the assumptions vary from one scenario to another. Instead, an understanding of the assumptions October 06 138 Essential Services Commission, Victoria Final Decision requires investigation of the values inputted into the model and investigation of how the assumptions made impact upon the outputs produced. NIEIR (2005b) indicated that, in their view, the high case is a high energy growth scenario. Under the high case, NIEIR increases the intensity at which electricity is used in the manufacturing, commercial and residential sectors relative to the base and alternative base scenarios and assumes that real electricity prices fall by some 20 per cent over the period to 2011, reflecting lower wholesale and distribution prices. As a result of the assumptions used in formulating the high case, NIEIR considers that there is only a 5 per cent chance that the forecasts produced under this scenario will be exceeded. The distributors (CitiPower & Powercor 2005a) noted that the high case growth scenario results in forecasts that are higher than historic outcomes. This is shown in the Table 4.6. Table 4.6: Total energy consumption growth rates — NIEIR high case scenario, September 2004 2000-04 2004-10 AGLE 0.75 1.80 CitiPower 1.95 1.67 Powercor 2.05 2.86 SP AusNet 2.90 3.47 United Energy 1.89 2.45 Note: Commission 2000 to 2003 historic data compiled from tariff approval models and 2004 historic data from regulatory accounting statements. The Commission is of the view that the high case growth scenario may over-estimate growth over the next regulatory period because it appears to adopt assumptions that may result in it being an extreme high case. As a result, the Commission has further reviewed the assumptions underlying the base and alternative base case to assess the appropriateness of using either of these scenarios as the basis for the growth forecasts. In reviewing these assumptions the Commission has focussed on the reasons that NIEIR has forecast a slowing in growth over the next regulatory period, namely: • a slowing of Victorian GSP growth relative to that experienced in the current period; • the impact of federal and state government energy conservation policies; and • a downside risk to Victorian manufacturing activity. Each of these assumptions is discussed in turn below. It should be noted that, in August 2005, NIEIR revised its forecasts under the base and alternative base case scenarios at the request of the distributors to reflect 2004 actual data rather than the estimate used in the 2004 forecasts (see Table 4.7). These revised forecasts replaced those produced in September 2004. October 06 139 Essential Services Commission, Victoria Final Decision Table 4.7: Total energy consumption growth rates — NIEIR base and alternative base case scenarios, August 2005 Alternative base Base 2000-04 2004-10 2004-10 AGLE 0.75 0.75 0.24 CitiPower 1.95 1.14 0.92 Powercor 2.05 1.90 1.54 SP AusNet 2.90 2.52 2.31 United Energy 1.89 1.49 1.17 Note: Commission 2000 to 2003 historic data compiled from tariff approval models and 2004 historic data from regulatory accounting statements. However, NIEIR did not revise the high case scenario. United Energy provided an explanation for the limited revision. According to United Energy:49 NIEIR has not been asked (nor have they provided) high and low case scenarios. Given the incorrect application of these scenarios in the draft decision, UED has limited NIEIR's scope of work to those scenarios that they consider to be the most appropriate outcome and have asked NIEIR to provide their independent recommendation as to the most appropriate. The revised forecasts produce slower growth rates than the growth rates implied by the forecasts produced in September 2004 (see Tables 4.4 and 4.7), despite the actual level of sales in 2004 being higher than the estimate for four of the five distributors. The Commission assumes that the 2005 high case forecast would also have produced slower growth rates than the high case forecast in 2004. GSP forecasts In their submissions in response to the Draft Decision, the distributors raised concerns over the reliance that the Commission had placed on DTF’s GSP forecasts. In particular, United Energy (2005, p. 4) commented that the reliance on Department of Treasury and Finance (DTF) GSP forecasts was a change of approach by the Commission: The Commission also markedly changed its approach regarding the relevance of the State Government’s DTF forecasts. In particular, in its Guidance Paper, the Commission did not make any reference to the State Government’s DTF’s macroeconomic assumptions or its forecast of Gross State Product. Instead, the Commission suggested that the distributors were free to adopt assumptions, key input data and forecasting methods providing that these were reasonable. The Commission did not provide any direction to use the DTF’s macroeconomic forecasts. 49 Email to Dianne Shields from Andrew Schille 1 September 2005. October 06 140 Essential Services Commission, Victoria Final Decision The Commission has always had regard to the key inputs and assumptions used to determine the components of the regulatory framework. The Commission is concerned to ensure that the assumptions used to determine each component are consistent with other available sources or, where assumptions do differ, to have sound reasons for why there should be differences. The distributors consider that DTF’s GSP forecasts are high in the short term and that DTF’s longer term estimates of GSP are ‘projections’ that are little more than a technical assumption that over those years of the forecasting horizon the Victorian economy will return to what DTF considers to be a long-run growth rate. Further, they claim DTF’s forecasts do not consider the impacts of economic cycles and imply that the Victorian economy will grow in line with the national average which is contrary to NIEIR and EconTech. The Commission has considered the accuracy of the short and long term GSP forecasts provided by a number of agencies, including DTF, NIEIR, Access Economics and Econtech. The distributors claim and the Commission concurs that, compared with NIEIR’s base case and Econtech, DTF’s short term GSP forecasts appear high. The Commission also notes that DTF’s short term forecast are high compared with Access Economics’ forecasts (see Table 4.8). Table 4.8: Annual average GSP growth rate — DTF, NIEIR base case, Econtech, Access Economics 2004-05 to 2005-06 GSP growth rate DTF 2.9% NIEIR base case 2.2% Econtech 2.1% Access Economics 2.4% Source: CitiPower & Powercor 2005a, p. 3; Access Economics 2005 However, to properly assess the credentials of an agency’s short term forecasts, the forecasts must be compared with historic outcomes rather than other available forecasts. Comparing one forecast against another will not provide an indication of which forecast is more accurate without considering the accuracy of past forecasts against historic outcomes. DTF’s and NIEIR’s base case short term GSP forecasts have been assessed against actual GSP growth. The Commission does not have this information for Access Economics and Econtech. This analysis suggests that DTF’s short term forecasts have been more accurate against actual growth in GSP when compared with the GSP forecasts included in the NIEIR base case scenario (see Table 4.9). The average bias in the short term forecasts prepared by DTF for these years is 0.42 percentage points while NIEIR’s average bias for these years is 1.47 percentage points. October 06 141 Essential Services Commission, Victoria Final Decision Table 4.9: Forecast and actual annual average GSP growth — DTF, NIEIR base case DTF NIEIR base case Forecast in 1999-2000 for 2000-01 3.00 1.00 Actual in 2000-01 2.50 2.50 Forecast in 2000-01 for 2001-02 3.50 1.70 Actual in 2001-02 3.90 3.90 Forecast in 2001-02 for 2002-03 3.75 2.60 Actual in 2002-03 3.30 3.30 Source: Victorian Government State Budget Papers and VENCorp Planning Reports 2000, 2001 and 2002. While the accuracy of a forecaster’s short-term forecasts needs to be considered, the Commission must make a judgement about expected growth over the medium to long term. Consequently, the Commission is more concerned with an agency’s medium to long term forecasting capabilities than with its short term credentials. The performance of DTF’s ‘projections’ and NIEIR’s ‘dedicated forecasts’ has been assessed against actual economic GSP growth over the last few years. The forecasts are compared with actual levels of Victorian GSP growth as published by the Australian Bureau of Statistics. The information available only allows comparisons to be undertaken for three year periods at a time. The results of the analysis suggest that NIEIR’s base case scenario under-estimated growth in Victorian GSP in two out of the three forecasting periods assessed (Tables 4.10, 4.11 and 4.12). Table 4.10: GSP forecasts prepared midway through the financial year 1999-2000 2000-01 2001-02 2002-03 Ave. over period Ave. biasa Rank DTF 3.00 3.25 3.25 3.17 -0.07 1 Econtech n.a. n.a. n.a. Access Economics 2.50 2.88 3.20 2.86 -0.38 2 NIEIR Base Case 1.00 1.60 3.20 1.93 -1.30 3 Actual growth 2.50 3.90 3.30 3.25 a This measures how much the estimates have, on average across the period, over or underestimated growth. It is calculated by taking the difference between the forecast and actual growth in each year and averaging across the period. Source:, Vencorp – Electricity Annual Planning Review 2000 (p. 19), Victorian Dept. of Treasury and Finance – 1999-2000 Mid-Year Budget Review (p. 13), ABS Cat. No. 5220.01 October 06 142 Essential Services Commission, Victoria Final Decision Table 4.11: GSP forecasts prepared midway through the financial year 2000-01 2001-02 2002-03 2003-04 Ave. over period Ave. biasa Rank DTF 3.50 3.50 3.50 3.50 -0.13 1 Econtech n.a. n.a. n.a. Access Economics 2.98 3.21 3.18 3.12 -0.51 2 NIEIR Base Case 1.70 2.40 3.70 2.60 -1.03 3 Actual growth 3.90 3.30 3.70 a This measures how much the estimates have, on average across the period, over or underestimated growth. It is calculated by taking the difference between the forecast and actual growth in each year and averaging across the period. Source: Vencorp – Electricity Annual Planning Review 2001 (p. 19), Victorian Dept. of Treasury and Finance – 2000-01 Budget Update (p. 17), ABS Cat. No. 5220.01 Table 4.12: GSP forecasts prepared midway through the financial year 2001-02 2002-03 2003-04 2004-05 Ave. over period Ave. biasa Rank DTF 3.75 3.50 3.50 3.58 0.33 2 Econtechb 3.20 2.30 n.a. 2.75 -0.75 4 Access Economics 3.60 2.40 2.20 2.73 -0.52 3 NIEIR Base Case 2.60 3.50 3.20 3.10 -0.15 1 Actual growth 3.30 3.70 2.75 c a This measures how much the estimates have, on average across the period, over or underestimated growth. It is calculated by taking the b c difference between the forecast and actual growth in each year and averaging across the period. Forecast significantly later than others. ABS data not yet available for 2004-05 actual growth, substituted with DTF latest estimate from Victorian Dept. of Treasury and Finance – 2005-06 Budget Paper No. 2 (p18) Source: Vencorp — Electricity Annual Planning Review 2002 (p 22), Victorian Dept. of Treasury and Finance — 2000-01 Budget Update (p31), EconTech — Australian State and Industry Outlook June 2002 (p13), ABS Cat. No. 5220.01 The Commission has also assessed DTF’s current long term projections of GSP against historic growth in GSP and GDP, GSP forecasts prepared by other forecasters and forecasts of GDP prepared by the Commonwealth Government. This is in response to statements made by the distributors that DTF’s long term forecasts do not consider the impacts of economic cycles and imply that the Victorian economy will grow in line with the national average which is contrary to NIEIR and EconTech. The results of this analysis indicate that: • Victorian GSP has grown, on average, 3.9 per cent per annum in the 10 years to 2003-04, 3.3 per cent per annum in the five years to 2003-04 and 3.6 per cent in the three years to 2003-04 (ABS cat. no. 5220.0). • Australian GDP has grown, on average, 3.9 per cent per annum in the 10 years to 2003-04, commensurate with the growth in Victorian GSP (ABS cat. no. 5220.0). October 06 143 Essential Services Commission, Victoria Final Decision • Commonwealth Treasury is forecasting GDP growth of 3.2 per cent over the next regulatory period (Commonwealth Government 2005). These results suggest that assuming that the Victorian economy will grow in line with the national average is not unreasonable. It is expected that Victorian GSP will grow broadly in line with Australian GDP over time given that Victoria is the second largest Australian state economy, comprising approximately a quarter of the national figure. The GSP forecasts included in the NIEIR base case have tended to under-estimate GSP growth under its base case scenario. The Commission also notes that NIEIR’s current base and alternative base case scenarios have assumed a GSP growth rate of 2.4 per cent over the 2006-10 regulatory period.50 This contrasts with DTF, Access Economics and Econtech who are forecasting average growth of 3.3 per cent, 3.16 per cent and 2.94 per cent respectively (Victorian Budget Papers 2005, Access Economics 2005, EconTech 2005). This information would suggest that the growth forecasts under the base and alternative base case scenarios have factored in an overly-conservative forecast of Victorian GSP which is likely to result in underestimation of growth over the period. Federal and state energy conservation policies The NIEIR (2005b) forecasts anticipate that electricity consumption growth over the next regulatory period will be slower due to the effects of the 5-star energy rating policy and the Natural Gas Extension Program. NIEIR also stated that their forecasts of energy consumption are impacted by the possible adoption of Recommendation 24 of the Mandatory Renewable Energy Target Review Panel by the Federal Government.51 This latter assumption has only been revealed since the release of the Draft Decision. The 5-star energy rating policy requires new homes to be built with a five star energy rating for building fabric and requires the installation of a rain water system or a solar hot water system. NIEIR lists the following areas in which electricity consumption will fall due to the 5-star policy — space cooling; space heating; water heating; cooking; lighting; refrigeration; other appliances and equipment. NIEIR (2004b, p. 41) indicates that the largest impact of the 5-star policy will be felt on energy consumption in water heating and space conditioning. NIEIR (2004b, p. 41) estimates that the policy will result in a fall in average annual electricity consumption of between 0.2 to 0.4 per cent per annum for metropolitan distributors, and a fall of between 0.4 to 0.8 per cent per annum for distributors with a mix of both metropolitan and rural customers. 50 51 Email to Dianne Shields from Tony O’Dwyer (NIEIR) 13 September 2005. The Mandatory Renewable Energy Target was established in 2001 by the Renewable Energy (Electricity) Act 2000 and is supported by the Renewable Energy (Electricity) (Charge) Act 2000 and the Renewable Energy (Electricity) Regulations 2001. The measures require the generation of 9500 GWh of extra renewable energy per year by 2010. Recommendation 24 stated that all solar water heater systems installed, including replacement systems, be eligible for renewable energy certificates to the full extent of their energy displacement capacity. Renewable energy certificates are tradeable and are earned by generators with each certificate equivalent to 1 MWh of renewable generation. October 06 144 Essential Services Commission, Victoria Final Decision The Commission has reviewed the information provided by NIEIR which includes the NIEIR reports prepared for the distributors in September 200452 and a Regulatory Impact Statement prepared by the Plumbing Industry Commission for the Plumbing (Water and Energy Savings) Regulations 2004. It is unclear why NIEIR has included efficiencies arising from appliance use in its modelling of the 5-star policy. The Sustainable Energy Authority of Victoria (SEAV) informed the Commission that the 5-star policy does not apply to appliances and is restricted to building fabric, energy saving tap ware, solar hot water or rainwater systems. SEAV engaged Energy Efficient Strategies (EES) to undertake a cost-benefit analysis of the policy. In contrast to NIEIR, EES estimated that the State-wide reduction in electricity usage would be between 26 000 and 37 000 Gigajoules per annum (EES 2002, p. 13) — 7 to 10 GWh per year or 0.09 per cent of residential usage in 2004. This impact is expected to occur in space conditioning. SEAV indicated to the Commission that large reductions in electricity usage in water heating as a result of the policy were not expected because most hot water usage is currently gas and the intent of the policy is to install gas boosted solar water heating in areas where reticulated gas is available. The EES cost-benefit analysis also only estimates electricity savings resulting from the policy impact on space conditioning and did not consider the impact on electricity used in water heating. The Regulatory Impact Statement accompanying the Plumbing (Water and Energy Savings) Regulations 2004 indicates that: • The 5-star policy for water heating only applies to new homes (PIC 2003, p. 4). • New home owners have the choice of installing either a rainwater tank to replace mains water flow to the toilet or a solar hot water system (PIC 2003, p. 4). The report stated that rainwater tanks are cheaper to install than solar hot water systems (PIC 2003, pp. 15 & 16). • Where new home owners choose rainwater tanks, there will be no effect on electricity usage because electricity will be needed to heat potable water supplies. • In regard to solar hot water systems, the report notes that 52 y the majority of Victorian homes currently use gas conventional water heaters (PIC 2003, p. 16); y for new homes built in gas-reticulated areas, solar hot water heaters will be largely replacing conventional gas heaters (PIC 2003, p. 16 & 23); y for new homes built in non-gas reticulated areas, solar systems will replace conventional electric heaters but these homes are allowed to install electric boosters to support their solar systems (PIC 2003, p. 23); The 2005 reports were not available prior to the release of this Final Decision. October 06 145 Essential Services Commission, Victoria Final Decision y • the requirement to limit households to gas-boosted solar systems in gas-reticulated areas represents an initial cost to householders because gas-boosted systems are more expensive than electric-boosted models (PIC 2003, p. 18). The impact of the policy will be lessened where households elect to install a rainwater tank rather than a gas boosted solar system (PIC 2003, p. 29). The unknown factor is how many of each system will be installed (PIC 2003, p. 28). This information suggests that, in gas-reticulated areas, solar hot water systems will largely be replacing conventional gas hot water systems, not electric. In non-gas reticulated areas where the majority of electric hot water systems are likely to be, new dwellings installing solar water heaters are permitted to use electric boosters and so the impact of the policy on electricity consumption is likely to be small. NIEIR told the Commission that it anticipated that households would choose to install solar hot water systems because of their lower running costs even though their installation is more expensive than a rainwater tank. The RIS (PIC 2003, p. 22) also noted that: Since the installation costs of a solar heated water appliance is more expensive than a conventional heated water appliance yet the consumption of gas or electricity for a solar heated water appliance is less, the householder who installed a solar heated water appliance receives an economic benefit within the lifetime of the solar water heater. SEAV informed the Commission that, given the similar pricing between installed solar hot water and rainwater tank, it is expected that the installation of solar hot water systems and rainwater tanks will be relatively evenly split. The Commission notes that EES did not estimate the impact of the policy on electric water heating when undertaking its cost-benefit analysis. The Productivity Commission (2005, p. 106) found that the initial capital cost of energy saving devices can act as a barrier to their take up: Energy-consuming fixtures — such as water heaters — are often selected by a building or landlord who is primarily concerned about the capital cost, whereas users also have an incentive to reduce running costs. EES estimated that the impact of the policy on electricity consumed in space conditioning would be around 0.09 per cent per annum. EES expected that the majority of the impact would be on gas used in space heating while the effect on electricity used in space cooling would be minor (EES 2002, p. 13). NIEIR (2004b, p. 41) factored in a reduction of 0.03 per cent per annum in electricity usage in space cooling and heating. While this is smaller than the impact on usage in space conditioning estimated by EES, NIEIR is factoring in a larger impact from the policy overall due to its view that the policy will also impact on water heating and use in electrical appliances. The impact that the 5-star policy will have on electricity consumption is uncertain because it is unclear how the 5-star policy will impact upon electricity usage in water heating. However, NIEIR appears to have assumed a much larger reduction in usage for space conditioning than the October 06 146 Essential Services Commission, Victoria Final Decision original cost-benefit study for the policy estimated suggesting that its assumptions in this regard are overly-conservative. On balance, the 5-star policy will impact on electricity consumption over the next regulatory period. However, the Commission is of the view that NIEIR may have over-estimated its impact primarily due to its overly-conservative estimate of the effect the policy will have on electricity usage in space conditioning. Over-estimating this impact is likely to result in the underestimation of growth in electricity consumption over the next regulatory period. Downside risk to Victorian manufacturing Under the base case scenario, the growth forecasts incorporate a downside risk to Victorian manufacturing activity. Information provided (CitiPower & Powercor 2005a) to the Commission since the Draft Decision indicated that NIEIR initially prepared forecasts incorporating a downside risk to manufacturing for the South Australia distribution price review by the Essential Services Commission of South Australia (ESCOSA). The downside risk was incorporated into the South Australian forecasts partly in response to the announced closure in 2004 of the Mitsubishi engine plant and Mobil refinery. According to NIEIR, these closures had a significant impact on electricity use. In 2004, NIEIR prepared a report at the request of the distributors entitled “An Assessment of the Downside Risk to Manufacturing in Victoria”. This report set out NIEIR’s analysis of the downside manufacturing risk in Victoria and the econometric analysis underpinning the incorporation of this risk into the distributors’ forecasts. NIEIR indicates that their modelling53 estimates that, as a result of the 1998-2004 house price boom, by 2010 manufacturing gross product (output less inputs) will be 14.5 per cent below the level that otherwise would have prevailed had the house price boom not occurred. NIEIR states that a reasonable estimate would be that approximately 5 percentage points of the 14.5 per cent adjustment would have already occurred at the time NIEIR prepared its report, leaving 9.5 per cent still to occur over the 2004 to 2010 period. NIEIR states that the current poor gross product outcomes are a good indicator of future lower electricity demand growth because gross product is a key driver of investment, capital stock growth and hence future electricity demand. Further, they conclude that the rate of return on capital has fallen over the last three years suggesting that the rate of growth in the Victorian manufacturing capital stock may fall to a low level over the 2005 to 2008 period. Combined with an ageing capital stock, the incentive for investors to continue investing in Victorian manufacturing will reduce and instead their activities will be transferred overseas. 53 NIEIR developed a non-linear regression equation that models manufacturing real gross product for all Australian states, including Victoria, based on a ratio of real manufacturing gross product and real net capital stock in manufacturing against, amongst other things, a ratio of real medium established house prices and gross rate of return for the manufacturing sector in a particular State. NIEIR indicated that the coefficient between these two ratios is high (-0.263) and highly correlated with a t-statistic of 22. NIEIR stated that this suggested that land prices have played an important role in explaining the decline in the share of manufacturing in GDP, both in Australia and Victoria (NIEIR 2004a, p. 13). October 06 147 Essential Services Commission, Victoria Final Decision The Commission contacted other agencies on the outlook for Victorian manufacturing activity over the next five years. DTF commented that, in developing its GSP forecasts, it undertakes extensive consultation with industry groups, including the manufacturing sector. Throughout this consultation, there has been no indication given to it of a downside risk to Victorian manufacturing activity.54 The Australian Industry Group also predicted that there would be continued growth in manufacturing, although lower than that experienced in previous years, and that any forecast of a decline in manufacturing would have to be premised on a significant recession in the economy. Forecasts of Australian manufacturing activity prepared by Access Economics also suggest that while manufacturing is expected to slow over the next couple of years, it is also expected to rebound over the 2006-10 regulatory period (see Figure 4.1). Figure 4.1: Actual and forecast Australian manufacturing growth — manufacturing income, 1996 to 2010 7.00% 6.00% 5.00% 4.00% 3.00% 2.00% 1.00% 0.00% 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Historic growth Source: Access Economic forecast Access Economics 2005; ABS Cat. No. 5676.0 While forecasting manufacturing activity will always contain some level of uncertainty, the Commission is not of the view that a downside risk to manufacturing should be factored into the growth forecasts. The other information available suggests that while manufacturing activity may slow, there is no alternative evidence to support the case that manufacturing in Victoria will decline over the next five years. As a result, the Commission has not accepted NIEIR’s base case growth forecasts (and hence the distributors’ growth forecasts which were based on the NIEIR base case). The distributors have pointed out that VENCorp in its latest Annual Planning Report has used NIEIR’s base case scenario which incorporates the downside risk to manufacturing in its 54 Email to Dianne Shields from Rob Brooker 22 July 2005. October 06 148 Essential Services Commission, Victoria Final Decision planning of the transmission network. The distributors state that the Commission should consider consistency with VENCorp when making its decision. VENCorp indicated to the Commission that its primary focus when forecasting electricity growth is on peak demand and that energy consumption is only a secondary concern. This is due to the continual worsening of the Victorian load factor. The Commission also understands that the manufacturing downside risk affects energy sales but not peak demand. Therefore, the inclusion of the manufacturing downside risk is of less importance to VENCorp. This is confirmed by NIEIR where the peak demand forecasts prepared for the distributors did not incorporate the downside risk to manufacturing. As the forecasts used for the price review directly impact revenue, the Commission considers that the assumptions that drive the forecasts require careful review. Although consistency with VENCorp’s forecast may be desirable, the Commission must be satisfied that the forecasts adopted for the price review are the best estimate of likely outcomes for growth at the distribution level. If the forecasts are too low, customers will pay more than they should. Conversely, if they are too high, distributors may not earn sufficient revenue. Conclusion An analysis of the assumptions used in the base and alternative base case suggests that there is support for a lower growth rate than has occurred over recent years. For example, the 5-star standard for housing suggests that energy consumption growth will be slower in the next regulatory period. The Commission must adopt forecasts that represent its best estimate of growth over the 2006-10 regulatory period. Although it considers the high case may over-estimate growth, it also considers that the base and alternative base case scenarios are likely to under-estimate growth. This is an issue that appears to arise as a result of the NIEIR high case being developed on the basis of an extreme high case. Nevertheless, the Commission must come to a view on the forecasts and considers that it would be difficult to rely on a simplistic methodology that considers a downward adjustment to historic growth rates, even though, in the Commission’s view, such an adjustment would be more reflective of the likely outcome on growth. Therefore, the Commission has decided to adopt forecasts that use NIEIR’s alternative base case scenario as revised by NIEIR in August 2005. In the Commission’s view, the alternative base case scenario may under-estimate growth and this is likely to provide the distributors with more revenue over the period than the revenue requirement — a similar outcome to this period. However, on balance, this is a more preferable outcome than not earning the revenue requirement, which might be the case if the Commission were to adopt NIEIR’s high case. October 06 149 Essential Services Commission, Victoria Final Decision 4.2.3 Price elasticity of demand The price elasticity of demand is a measure of the extent to which the quantity of a product demanded by customers responds to a price change, other things being equal. It is a unit-less coefficient, obtained by dividing the percentage change in quantity demanded by the percentage change in price. For almost all commodities, a price increase is accompanied by a decrease in the quantity demanded, resulting in the traditional downward sloping demand curve. Thus, the price elasticity of demand is a negative number. If the percentage changes in price and quantity demanded are exactly equal, the price elasticity equals -1. If the percentage change in quantity is less than the percentage change in price, the elasticity is between 0 and -1. Such commodities are considered to be relatively price inelastic. In general, the demand for electricity is relatively inelastic in the short run which is the period of time during which customers can modify their usage primarily through behavioural changes. In the long run, customers can change their appliance stock or install insulation to their homes and thus the price elasticity is greater than in the short run. Elasticity effects were not incorporated in NIEIR’s base and alternative base case scenarios for the 2006-10 regulatory period. Instead, NIEIR assumed that the price to both residential and nonresidential customers would stay approximately constant in real terms over the period. MMA (2005, p. 64) have suggested that: … the price assumptions made by NIEIR in its forecasting for the DBs […] may be somewhat high, implying an increase in forecast demand beyond that estimated by NIEIR. However, the high case included a response to a 20 per cent price reduction. In the Draft Decision, the Commission considered that the price elasticity impacts resulting from the price variations arising from the new price controls should be recognised. As a result, the Commission modelled the first order effects of each distributor’s P0 for DUoS services on the quantity of electricity consumed for residential and non-residential customers. Separate demand elasticities for residential and non-residential customers were applied because the price elasticity literature has demonstrated that elasticities are different for residential customers and small to medium business customers (ESC 2002a, p. 66). The quantities calculated from the price elasticity assumptions used were adjusted by forty per cent in recognition that distribution use of system charges were equal to approximately forty per cent of a customer’s total electricity bill. The Commission used the price elasticity estimates that were used in its cost-benefit analysis for the interval meter roll-out decision (ESC 2002a, p. 85), as set out in Table 4.13. October 06 150 Essential Services Commission, Victoria Final Decision Table 4.13: Price elasticities of demand used in the analysis Customer type Elasticity estimates resulting from Time of Use Pricing Residential -0.1 Non-residential -0.025 In submissions to the Draft Decision, the distributors raised concerns over the application of elasticities to the growth forecasts. The distributors did not consider that applying an elasticity effect was an acceptable regulatory approach because: • the adjustment assumes all retail tariffs will change immediately when distribution tariffs change. Retail price caps and market contracts will ensure that this does not happen; • the adjustment assumes no other components of retail tariffs will change. The distributors believe generation costs are facing significant upward pressure, which will reduce or even outweigh the effects of the distribution price review outcomes on retail tariffs; • the adjustment assumes that price elasticity is symmetrical and linear and evidence suggests that it is not; • the adjustment ignores a host of non-economic considerations such as the 5-star building standard which are likely to reduce not increase consumption; • the value of the elasticity used was inappropriate; • the adjustment may give distributors the incentive to adopt tariff strategies that mitigate any revenue risk as a result of the elasticity adjustment; and • the adjustment is unprecedented and unanticipated. The Commission recognises that there is a level of uncertainty over the extent to which price changes will impact upon energy consumption. The extent to which retailers pass through the changes in distribution prices to their customers is uncertain. However, with full retail competition as exists in Victoria, there is more likelihood now than in the past that price changes will be passed through. The Commission notes that distribution price reductions should be passed through immediately to non-residential customers. These customers are generally on retail contracts that require the immediate pass through of changes in distribution prices. Hence, 2006 distribution price changes are required to be passed through by retailers in 2006. In regard to residential customers, the high rate of switching amongst residential electricity customers suggests that the retail electricity market is effectively competitive and thus residential customers will be more likely to see the price change. At the end of December 2004, the annualised switching rate amongst residential electricity customers was 20 per cent. This represents a 91 per cent increase in transfers in the electricity market since 2003. By comparison, at December 2002, one year into full retail competition, less than five per cent of electricity customers were involved in transfers (ESC 2005e, p. 21-22). October 06 151 Essential Services Commission, Victoria Final Decision In addition, there is uncertainty over the quantum of the impact on consumption from any decline in prices. This uncertainty arises from the extent to which price changes in other sectors of the industry offset the distribution price change and the elasticity figure that is used. In this regard the distributors state that increases in generation prices will increase the generation costs and government policies designed to promote the use of renewable energy may increase retail electricity prices and thus mitigate any reduction in distribution prices. For example, SP AusNet55 (2005e, p. 2) commented that: … many concerns, global and local, environmental, social and economic are driving calls for greater internalisation of external costs, greater efficiency in the use of non-renewable energy sources and larger contributions to overall energy consumption from, often more costly, renewable sources. The majority of the developments touched upon above will drive up costs that determine much of the generation and retail costs making up the 60 per cent non-distribution related costs. In the Commission’s judgement, applying an elasticity adjustment to the growth forecasts is appropriate because elasticity impacts have a sound basis in economic theory and it is likely that a price change will have some impact upon consumption. Stakeholders have not questioned the fundamental principle that a price change will result in a change in consumption. However, stakeholders questioned the quantum of the elasticity impact. In particular, the distributors note that the elasticity estimates used in the Draft Decision measure the extent of the shift between peak and off-peak use and not the effect of a price change on total usage. The Commission has found it difficult to find an appropriate elasticity estimate to use. For this reason, the growth forecasts have not been adjusted for elasticity impacts. The Commission also notes that, while the adoption or otherwise of this approach elsewhere is of interest, this should not drive the Commission’s own approach. 55 Formerly TXU October 06 152 Essential Services Commission, Victoria Final Decision PART B2: REVENUE REQUIREMENT — DUOS In this Part, the Commission sets out its Final Decision and reasons regarding the components that go into determining the revenue requirements for the provision of distribution use of system services over the 2006-10 regulatory period. The revenue requirement for prescribed metering services is discussed in Part B4. The Commission uses a ‘building blocks’ approach to determine the revenue required by a distributor. Under this approach, the Commission builds up revenue from an assessment of the key cost components comprising operating and maintenance expenditure, cost of capital financing requirements (return on and of capital), forecast tax liability and any efficiency carryover amounts resulting from efficiency gains earned in the preceding regulatory period. The return on capital is determined by rolling forward the value of the regulatory asset base taking into account, among other things, capital expenditure requirements and then applying a weighted average cost of capital to the rolled forward asset value. The distributors have outperformed the building blocks benchmarks set at the last price review. The level of operating and maintenance expenditure undertaken has been below that forecast as has the level of capital expenditure. The rates of return that the distributors have earned on their invested capital have also been higher than forecast at the last price review. The level of underspending by the distributors has also provided them with further financial benefits in the form of efficiency carryover amounts that will be added into the revenue requirements for the 2006-10 regulatory period. The incentive-based framework that the Office of the Regulator-General (ORG) set in place at the last price review provided for these outcomes. The framework was designed to give the distributors incentives to achieve efficiency gains and so earn higher returns by outperforming the expenditure forecasts while also maintaining or delivering improvements in service levels (see Part B1). It was intended that customers would benefit from these efficiency gains in the medium to longer term as efficiency gains were passed through to them in the form of lower real prices which reflect the delivery of service standards that are maintained or improved over time at lower cost. The efficiency carryover mechanism (in combination with the service incentive arrangements) was a key feature of this incentive-based framework. It allows the distributors to retain the benefits of the efficiency gains they made in the current period for a limited time into the next regulatory period before those gains are passed through to customers. The intention was to maintain a continuous incentive for the distributor to achieve cost efficiencies throughout the period by allowing them to retain the benefits for five years irrespective of the years in which they are earned. These benefits would then flow through to customers in the form of lower real prices in the next regulatory period. However, in order to claim the efficiency carryover amounts, the distributors would be required to reveal the more efficient costs of providing the service and those revealed costs would then inform the Commission’s assessment of the expenditure proposals for the 2006-10 regulatory period. October 06 153 Essential Services Commission, Victoria Final Decision Assuming that it could rely on the incentive properties of the efficiency carryover mechanism, the Commission at the commencement of this price review considered that it could use the levels of expenditure reported by the distributors as a starting point for determining the expenditure forecasts for the 2006-10 regulatory period. Based on this assumption, the Commission gave weight to the level of expenditure reported for the year 2004 as its starting point for determining the requirements for the 2006-10 regulatory period. Having determined its starting point, the Commission’s assessment of the distributors’ price-service proposals could then focus on the reasons why future expenditure was likely to vary from the reported levels of expenditure that the Commission had available to it. This approach was the key to ensuring that the benefits of the efficiency gains achieved in the 2001-05 regulatory period were passed through to customers in the form of lower real prices in the 2006-10 regulatory period. It should also have allowed the Commission to be satisfied that real prices in the next regulatory period reflected the distributors’ efficient expenditure levels with any variation from 2001-05 expenditures due to changes in functions or legislative obligations or asset management policies. However, a review of the information contained in the distributors’ Regulatory Accounting Statements has raised concerns over the application of this approach in practice. The use of related party contracts, the outsourcing of a large proportion of services and sometimes substantial increases in expenditure reported in these accounts means that the Commission has had cause to question whether the information reflects the costs incurred in providing distribution services. The Commission is also concerned that its intended use of revealed 2004 cost levels as its starting point for assessing the 2006-10 expenditure proposals may have provided distributors with an incentive to ‘ramp up’ expenditure in 2004. For example, one distributor alone has increased reported expenditure in 2004 by 63 per cent over the level reported in 2003. This has led the Commission to make adjustments to the reported expenditure, and in some cases, produce estimates, particularly for 2004. This has been necessary to ensure that the regulatory framework operates as intended by enabling customers (as well as the distributors) to benefit from the efficiency gains made in the current regulatory period. Operating and maintenance expenditure and capital expenditure forecasts For the purposes of setting the expenditure forecasts for the next regulatory period, the Commission has made an assessment of the levels of operating and maintenance expenditure and capital expenditure during the 2001-05 period that it considers reflects the cost of service provision and therefore represents an appropriate starting point for determining the distributors’ revenue requirements for the next regulatory period. Specifically, the Commission made adjustments to the information contained in the distributors’ reported Regulatory Accounting Statements relating to, among other things, allocations of costs between retail and distribution services and between prescribed and excluded services, movements in provisions and contractual arrangements. The Commission’s reasons for and approach to making adjustments to this information are presented in Chapter 5. Having determined these starting points, the Commission then assessed the distributors’ proposed expenditure. For operating and maintenance expenditure, the Commission has had October 06 154 Essential Services Commission, Victoria Final Decision regard to the level of historical expenditure and the reasons the distributors have given for forecasting future expenditure requirements that differ from past trends (referred to as step changes) (see Chapter 6). For capital expenditure, the Commission considered a range of information, using historical information as a starting point in its analysis (see Chapter 7). The Commission has received assistance in making these assessments from its technical consultant Wilson Cook and Co. The forecasts of operating and maintenance expenditure and capital expenditure that the Commission has used to determine the revenue requirements for the next period represent real increases over the level of expenditure that was incurred in the 2001-04 period (see Figures B2.1 and B2.2). The increased levels of expenditure have been assessed by the Commission as being necessary to provide the distributors with sufficient revenue to meet changed functional and legislative obligations. Figure B2.1: Total gross capital expenditure, industry aggregate, out-turn capital expenditure 2001-04,a distributor proposed 2005-10 and Final Decision 2006-10, $million, real 2004 900 800 700 600 500 $M 400 300 200 100 0 1996 1997 1998 1999 Actual capex (inc meters) a 2000 2001 2002 2003 2004 Commission Final Decision CAPEX (ex meters) 2005 2006 2007 2008 2009 2010 Commission Final Decision CAPEX (inc meters) Out-turn gross capital expenditure includes prescribed distribution use of system and metering costs October 06 155 Essential Services Commission, Victoria Final Decision Figure B2.2: Total operating and maintenance expenditure, industry aggregate, out-turn operating and maintenance expenditure 2001-04,a distributor proposed 2005-10 and Final Decision 2006-10, $million, real 2004 600 500 400 $M 300 200 100 0 2001 2002 2003 2004 2005 2006 Commission Final Decision a 2007 2008 2009 2010 Actual opex Exclusive of operating and maintenance expenditure associated with prescribed metering services. Regulatory asset bases and cost of capital financing component The Commission has rolled forward the value of the distributors’ regulatory asset bases in accordance with the requirements set out under clause 2.1 of the Tariff Order. In determining the opening value of the asset bases, the Commission has not reviewed the prudency of the capital expenditure undertaken by distributors nor sought to identify and remove stranded or partly stranded assets. Instead, it has relied on the incentives of the regulatory framework. To roll forward the opening value of each distributor’s regulatory asset base, the Commission has used forecasts of capital expenditure, customer contributions, regulatory depreciation and disposals. The resulting estimated value of the regulatory asset base in each year is then used to determine the distributor’s return on and of capital components of the revenue requirements for the 2006-10 regulatory period. The Commission’s approach to determining the distributors’ regulatory asset bases is set out in Chapter 8. To determine the return on capital component of the revenue requirement, the Commission has applied a real after-tax weighted average cost of capital of 5.9 per cent to the rolled forward values of the regulatory asset base. The change in the weighted average cost of capital from that used in the last price review (6.8 per cent) is due in the main to a forecast decline in real interest rates from 3.5 to 2.64 per cent. Chapter 9 discusses the cost of capital financing requirements. October 06 156 Essential Services Commission, Victoria Final Decision The return of capital component (or regulatory depreciation) of the revenue requirement has been determined using the straight-line depreciation schedules set out by the distributors in their priceservice proposals (see Chapter 8). Efficiency carryover mechanism In calculating the efficiency carryover amounts to apply in the 2006-10 regulatory period, the Commission has applied a net present value approach to determining any net negative carryover amounts. In accordance with the Appeal Panel findings following the last price review, the Commission has adjusted the expenditure forecasts set at the last price review for the cost impacts arising from any differences between forecast and actual growth over the period. The benchmarks have also been adjusted to reflect variations in policies regarding the capitalisation of indirect overheads. The Commission has also changed the operation of the efficiency carryover mechanism in the 2006-10 regulatory period. The mechanism will continue to apply to operating and maintenance expenditure, but will no longer apply to capital expenditure. October 06 157 Essential Services Commission, Victoria Final Decision October 06 158 Essential Services Commission, Victoria Final Decision 5 RELEVANT COSTS The Commission's framework and approach for the 2006-10 price review is based on the presumption that distributors have an incentive to operate efficiently and that reported costs are properly due to the provision of distribution services. The robustness (or otherwise) of this presumption is important because, in determining the expenditure requirements of the distributors for the 2006-10 regulatory period, the Commission is seeking to place considerable weight on the distributors' historical expenditure and, particularly in the case of operating and maintenance expenditure, the distributors' 2004 expenditure. In addition to the need to establish forward looking expenditure requirements, the regulatory framework (as enshrined by the Tariff Order) requires there to be a fair sharing of the benefits of efficiency gains between customers and distributors. The question of whether reported costs accurately reflect the costs of providing distribution services is fundamental to the measurement of such efficiency gains and to decisions on the extent of their sharing. To calculate the efficiency carryover amounts that give effect to this sharing, the Commission must also be able to compare the out-turn costs during the 2001-05 regulatory period to the benchmark expenditure requirements established for the 2001-05 regulatory period. This requires the Commission to understand the basis on which the distributors’ out-turn costs have been calculated so that it is possible to compare out-turn costs on a like-for-like basis with the appropriate benchmarks. Given the Commission’s regulatory approach as described above, there is a risk that if a distributor's historical, reported expenditure is not efficient, or if it includes costs that are not properly due to the provision of distribution services, then: • any inefficiencies or misallocations will be carried forward into the revenue requirement for the 2006-10 regulatory period; and • the measurement, and therefore sharing, of efficiency gains will be distorted. The need to carefully review reported expenditure and make adjustments arises in the context of all forms of monopoly regulation that rely on business-specific cost information because of the associated incentive to report or represent that costs are greater than can properly be said to be the case. These incentives may manifest themselves in a number of ways: • the allocation of costs to prescribed distribution services where those costs are not properly associated with the provision of those services, for example, costs associated with any retail interests, excluded services and other activities; • changes in capitalisation policies so that the allocation of costs as between operating and maintenance expenditure, on the one hand, and capital expenditure, on the other hand, differs from the policy on which the corresponding expenditure benchmarks was based; • the use of accounting or operational adjustments that affect the timing with which costs are reported, such as through provisioning for future expenditure in such a way that the expenditure is reported for one year even though the cash outlay is to take place over October 06 159 Essential Services Commission, Victoria Final Decision several years, or the bringing forward or delaying of expenditure so that it falls into one accounting year or another; • where regulated distribution activities are conducted within the same legal entity as other activities, the use of methods that provide for a disproportionate allocation of joint or common costs to the regulated business; and • the establishment of prices or the entering into of contracts for the supply of services that have not been verified by reference to a market price for those services. Accordingly, the Commission has reviewed in detail the regulatory accounting information provided by the distributors for the 2000-04 period and has made a number of adjustments to the information for the reasons outlined above. Additionally, errors in the Regulatory Accounting Statements have been identified and corrected. The adjustments that the Commission has made means that the Commission can proceed with a greater degree of confidence that out-turn cost information (as adjusted) reflects the cost of providing distribution services and the economic circumstances of the distribution businesses and can be used for the determination of: • the efficiency carryover amount (as measured through the variation of actual expenditure compared to the benchmark) arising in respect of the 2001-05 regulatory period for capital and operating and maintenance expenditure; • the base operating and maintenance expenditure forecasts to apply for the 2006-10 regulatory period; and • the starting point for determining capital expenditure forecasts to apply for the 2006-10 regulatory period. This has also allowed the Commission’s review process to focus on the basis for, and cost impact of, any step changes or variations in the distributors’ functions or other obligations that are relevant for the forthcoming regulatory period, as well as the expected rate of change in operating and maintenance expenditure. 5.1 Final Decision The out–turn operating and maintenance expenditure and capital expenditure over the 2000-04 period to be relied on by the Commission are set out in Table 5.1. The adjustments by category and distributor are provided in Table 5.2. The information set out in these tables includes adjustments to reported expenditure to reflect the underlying costs incurred in providing distribution services and to ensure a like-for-like comparison with 2001-05 benchmarks. In addition, the Commission has made further adjustments to estimate the efficient recurrent operating and maintenance expenditure for United Energy, CitiPower and Powercor where the reported information could not be relied upon for on this purpose. October 06 160 Essential Services Commission, Victoria Final Decision Table 5.1: Historical operating and capital expenditure, 2000-04, all distributors, $million, real $2004 2000a 2000b 2001 2002 2003 2004 AGLE 53.7 49.6 43.3 44.5 50.0 48.4 CitiPower 36.4 31.3 30.2 20.5 24.9 31.7 99.2 89.7 81.7 87.6 101.1 103.5 96.8 93.1 86.9 90.3 86.1 93.4 79.4 73.4 76.8 72.6 74.6 74.9 AGLE 34.0 31.5 38.3 28.0 32.0 33.4 CitiPower 79.0 74.6 75.0 65.5 56.8 68.4 Powercor 132.9 128.7 132.7 107.2 110.9 124.9 SP AusNet 75.3 75.1 100.0 56.1 78.2 100.8 United Energy 90.7 90.0 65.0 77.8 79.3 77.3 Operating expenditure Powercor SP AusNet c United Energy Capital expenditure a Includes metering data services and public lighting which were classified as prescribed services prior to 2001. Excludes metering data services and public lighting which were classified as excluded services from 2001. c Formerly TXU b The following tables summarise the adjustments that have been made by category and distributor. Table5.2: Adjustments to reported operating and maintenance expenditure, 2000-04, all distributors, $million, real $2004 2000 2001 2002 2003 2004 Provisions -0.7 -1.9 -3.0 2.0 0.8 Excluded services 0.0 0.0 0.0 -0.1 0.0 Retail -1.4 -0.6 -0.1 -0.3 0.0 Capitalisation -0.5 -1.2 -1.5 -1.6 0.0 Contractual arrangements 0.0 0.0 0.0 0.0 -0.2 Provisions 0.0 0.6 -11.8 -0.3 0.1 Excluded services 0.0 -4.4 0.0 0.2 -0.1 Retail -4.2 -1.8 -1.3 0.0 0.0 Capitalisation 0.0 0.0 0.0 0.0 -6.6 Errors 0.0 0.0 0.0 0.8 -2.4 Contractual arrangements 0.0 0.0 0.0 -5.3 -6.5 AGLE CitiPower (continued next page) October 06 161 Essential Services Commission, Victoria Final Decision Table5.2: Adjustments to reported operating and maintenance expenditure, 2000-04, all distributors, $million, real $2004 2000 2001 2002 2003 2004 Provisions -2.4 -30.1 -6.0 1.1 3.8 Excluded services -0.1 -9.5 3.2 0.0 0.0 Retail -1.3 -0.6 0.0 0.0 0.0 Errors 0.0 0.9 0.0 0.0 0.0 Contractual arrangements 0.0 0.0 0.0 0.0 -5.0 Further adjustments 0.0 0.0 0.0 0.0 -5.5 Provisions -3.2 -0.3 1.4 -0.8 -0.6 Excluded services 0.0 -1.2 0.4 -6.8 0.0 Retail -3.6 -5.2 -6.2 -4.0 0.0 Errors 0.0 0.5 -3.8 -4.5 0.6 Contractual arrangements 0.0 0.0 0.0 0.0 -0.6 Provisions -4.7 4.7 -1.7 -1.1 1.6 Contractual arrangements 0.0 -6.6 -4.2 -8.9 -12.3 Powercor SP AusNet United Energy Table 5.3: Adjustments to reported capital expenditure, 2000-04, all distributors, $million, real $2004 2000 2001 2002 2003 2004 Excluded services 0.0 -1.4 -1.2 -0.9 -1.4 Capitalisation 6.2 9.7 5.9 1.0 1.4 Contractual arrangements 0.0 0.0 0.0 0.0 -0.1 Provisions 0.1 0.1 0.0 -0.5 -0.4 Excluded services 0.0 -1.7 0.0 0.0 0.0 Retail 0.0 0.0 -31.9 0.0 0.0 Capitalisation 0.0 0.0 0.0 0.0 8.3 Contractual arrangements 0.0 0.0 0.0 -5.0 -6.4 AGLE CitiPower (continued next page) October 06 162 Essential Services Commission, Victoria Final Decision Table 5.3: Adjustments to reported capital expenditure, 2000-04, all distributors, $million, real $2004 2000 2001 2002 2003 2004 Provisions -1.1 -0.3 -0.9 -0.3 -1.8 Excluded services 0.0 -3.8 -4.5 0.0 0.0 Errors 0.0 -9.2 0.0 -9.5 0.0 Excluded services 0.0 -0.9 -2.8 0.0 0.0 Errors -1.3 -0.7 1.8 -1.4 0.0 Excluded services 0.0 -3.5 -0.5 0.8 0.0 Errors 20.1 -22.2 -14.2 -8.5 -5.9 Powercor SP AusNet United Energy 5.2 Reasons for the Decision The distributors submit audited regulatory accounting statements to the Commission on an annual basis and these are prepared based on the Regulatory Information Requirements Guideline No. 3 (Regulatory Accounting Guideline). The Regulatory Accounting Guideline indicates that the information reported is to be used for a number of purposes by the Commission including to inform Electricity Distribution Price Determinations. The Guideline is a principle-based document requiring principles and policies to be disclosed in a manner which ensures the Commission understands the information and can make comparisons over time. The Regulatory Accounting Guideline provides considerable discretion to the distributors, particularly in terms of the allocation of shared costs, capitalisation, provisions and related party transactions. However, the requirement to disclose policies regarding the allocation or accounting treatment of costs incurred is designed to ensure that the information can be compared by making adjustments to account for variations in policies and procedures across distributors and over time. This approach provides flexibility to the regulator or distributor in terms of adopting an appropriate policy or procedure to apply for a particular purpose at any point in time, and it is considered preferable to prescribing rules for this purpose. Further, the Guideline requires that, where substance and form differ, the substance rather than legal form of a transaction or event must be reported and that, in determining the substance of a transaction, all its aspects and implications must be considered, including the expectations of and motivations for the transaction. In July 2004, the Commission commenced a review of the information provided in the distributors’ regulatory accounting statements for 2000, 2001, 2002 and 2003 to ensure that it understood the information and was in a position to make any appropriate adjustments for the purpose of the 2006-10 price review. The Commission has also reviewed the regulatory accounting statements submitted for 2004 at the end of April 2005. October 06 163 Essential Services Commission, Victoria Final Decision The Commission has identified a number of issues arising out of the distributors’ regulatory accounting statements and has made adjustments for matters such as variations in allocation policies, movements in provisions and for charges that may not have been established by reference to a market price. It has also considered variations in allocation policies across distributors and over time. These issues bear directly on the Commission’s ability to compare the costs of providing distribution services with the benchmark expenditure estimates established in 2000 for the 2001-05 regulatory period, and to establish future estimates against which future efficiencies can be assessed. The Appeal Panel considered that, to calculate the efficiency carryover amounts for the 19952000 regulatory period, the Office of the Regulator-General (ORG) should ensure that: • there is a consistent approach between distributors; and • the approach is as consistent as is feasible, given the available information, with regard to the benchmark forecasts of expenditure (ORG 2000c, p. 8). In its statement of reasons, the Appeal Panel made the following observations which are particularly pertinent to this matter: • to obtain a measure of efficiency for the purposes of incorporation in the efficiency carryover mechanism, it is necessary that accounts which are being compared are produced on a comparable basis, and that these accounts cover a comparable range of operations; • where actual amounts include or exclude items that are included in benchmarks, this is a serious problem which limits the accuracy of measuring efficiency; and • consistency between distribution businesses is also important since it should not be the case that some distribution businesses are credited with efficiency improvements whilst others are not, solely because of their fortuitous choice of accounting base (ORG 2000c, p. 8). In its re-determination, the ORG made adjustments to the calculation of the efficiency carryover amounts for the 1995-2000 regulatory period where the approach adopted by one or more distributors disadvantaged them relative to other distributors. These adjustments were for bad debts, shared costs, redundancy costs, and the proportion of management fees that related to a transfer of profits (rather than fees paid for corporate services provided). Such adjustments were made in preference to imposing a particular accounting methodology on all distributors. This highlights the importance of clearly establishing the basis for the estimated expenditure for the 2006-10 regulatory period. It is also consistent with the Commission requiring adequate disclosure so that adjustments can be made to compare information on a ‘like for like’ basis over time, across businesses and with benchmarks. The basis for the allocation underpinning the operating and maintenance expenditure benchmarks for the 2001-05 regulatory period was the KPMG (2000) and UMS (2000) reports and the basis of the capital expenditure benchmarks was the PB Power (2000) report. In considering the information reported in the Regulatory Accounting Statements during this October 06 164 Essential Services Commission, Victoria Final Decision current period, the Commission has therefore made adjustments where required to ensure consistency with these benchmarks and to clearly represent the costs of providing the services. 5.2.1 Allocation between retail and distribution services The review of the distributors’ regulatory accounting statements considered whether the basis of allocation between the retail and distribution businesses (where applicable) was consistent with the allocation assumed in the benchmarks for the 2001-05 regulatory period and provided a fair representation of the costs incurred for the provision of distribution services. This was a key issue at the time of the last price review and the operating and maintenance expenditure benchmarks established were based on the allocation outlined in the KPMG report. In fact, Powercor resubmitted its 1999 regulatory accounting statements in August 2000 to reflect these bases of allocation. This was referred to specifically by the Appeal Panel. Applying the allocation bases outlined in the KPMG report, the Commission has identified the following adjustments that need to be made to the information reported in the distributors’ regulatory accounting statements for the purposes of this price review. • For AGLE, the reallocation of some retail-related costs, particularly for billing and revenue collection. • For CitiPower, the Commission identified that, although the magnitude of costs allocated to the distribution business had remained consistent with the benchmark level outlined in the KPMG report, there had been a change in the allocation policy such that the policy became inconsistent with the allocation basis outlined in that report. Notwithstanding, CitiPower had stated that the basis of allocation was the KPMG report. • y The Commission requested CitiPower to demonstrate through its working papers why its allocation is consistent with the allocation in the KPMG report. CitiPower has not provided the information. The Commission has therefore made an adjustment to ensure consistency with the basis of allocation outlined in the KPMG report. y CitiPower considers that it is inappropriate to make adjustments to the information reported in 2000 because the allocation methodology only applied from 2001. Although the methodology did only apply from 2001, the purpose of these adjustments is to compare the costs of providing the distribution services over time on a like for like basis. Because the adjustment in 2000 is only relied on for comparison purposes and does not affect the calculation of the efficiency carryover amounts, the Commission continues to consider this adjustment to be appropriate to compare the information on a ‘like for like’ basis. For Powercor, some retail related costs were removed in years prior to it divesting itself of the retail activities, particularly for bad and doubtful debts. Powercor does not agree with the adjustments for bad and doubtful debts and considers these costs to be a reasonable cost for the distribution business to incur. The Commission notes that the benchmarks include a nominal amount for bad and doubtful debts (approx $40,000). However, these costs would be expected to directly attributable to the distribution business. Therefore, where the costs recorded result from an allocation rather than a direct attribution, they have been removed. October 06 165 Essential Services Commission, Victoria Final Decision • For SP AusNet,56 the removal of some retail costs that appeared to have been inappropriately allocated to the distribution business, particularly in relation to customer service. It should also be noted that, where errors in the Commission’s adjustments for the Draft Decision have been pointed out by the distributors, these have been corrected. The forecasts of the distributors’ expenditure for the 2006-10 regulatory period are exclusive of the costs associated with any retail functions. Therefore, the Commission anticipates that these adjustments may continue to be required for price review purposes to enable out-turn expenditure to be compared with estimates on a consistent basis in future regulatory periods where a distributor continues to operate a retail business (as is the case with, for example, AGLE). 5.2.2 Allocation between prescribed and excluded services Prior to 2001, metering data services and the repair, maintenance and replacement of public lighting were classified as prescribed services. However, these services were reclassified as excluded services as part of the last Price Review and were therefore not included in the 2001-05 expenditure benchmarks. During its review of the distributors’ Regulatory Accounting Statements, the Commission identified that some of the distributors had continued to allocate operating and maintenance expenditure for metering data services and public lighting, and capital expenditure for public lighting, to prescribed services during this current regulatory period. The Commission has therefore made adjustments to the information reported in the relevant distributors’ regulatory accounting statements to address these allocations. In response to the Draft Decision AGLE and United Energy identified some errors with the adjustments the Commission had made regarding this allocation of costs. These businesses have re-submitted work papers to support the allocation errors and the adjustments have been updated accordingly. 5.2.3 Capitalisation of indirect (corporate) overheads While the Commission does not prescribe the capitalisation policy adopted by distributors, it does require disclosure of that policy in the distributors’ regulatory accounting statements. The Commission notes that the capitalisation policy impacts the classification of these costs rather than their level, although it does impact the timing as to how these costs are recovered. Further, the different treatment of rewards for capital and operating efficiencies under the efficiency carryover mechanism requires consideration of changes in capitalisation policies compared to the capitalisation policy included in the 2001-05 benchmarks. 56 Formerly TXU October 06 166 Essential Services Commission, Victoria Final Decision The regulatory accounting statements submitted by the distributors indicate that they adopted different capitalisation policies to those assumed in the 2001-05 benchmarks and that, in the case of AGLE, the policy has varied over the 2001-05 regulatory period. In 2000-03, changes to AGLE’s capitalisation policy have resulted in a movement of operating and maintenance expenditure to capital expenditure. A specific issue relating to the distributors’ capitalisation policies is the capitalisation of indirect (corporate) overheads. Some distributors (namely, AGLE, CitiPower and Powercor) capitalise some of these costs whilst others expense them in total. The review of the distributors’ Regulatory Accounting Statements has revealed that the policy adopted by some distributors on the capitalisation of indirect (corporate) overheads differs from the policy assumed in the setting of their 2001-05 expenditure benchmarks. The benchmarks for the 2001-05 regulatory period were based on an assumption that all indirect (corporate) overheads would be expensed. Therefore, the Commission has made adjustments to the benchmarks for the purposes of determining the efficiency carryover amounts to correct for the variation in the capitalisation policies. In establishing the forecasts for the 2006-10 regulatory period, the capitalisation policies assumed in the forecasts need to be explicitly identified and, if a different approach is foreshadowed, incorporated in the forecasts. This is discussed further in Chapter 7. 5.2.4 Movements in provisions Provisions are taken by the distributors in order to recognise a future liability now. The distributors have a range of provision accounts for, for example, employee entitlements, environmental obligations, safety obligations, doubtful debts and obsolete stock. Each year the distributors assess the balance of these provisions. They pay liabilities from the provision accounts, increase the balance of the provision accounts through a charge to profit and make other adjustments to the provision accounts. In the Draft Decision, the Commission reversed all movements in provisions charged to the profit and loss statement and substituted the relevant cash outgoing. This resulted in expenditure being recorded in the year it is incurred rather than when the provision is changed. This regulatory adjustment has a significant impact on the year by year reported expenditure profile as some of the yearly movements in provisions are in excess of $10 million. In response to the Draft Decision, the distributors generally disagreed with the Commission’s approach to reversing movements in provisions because they considered that it may not provide sufficient levels of operating expenditure. For example, SP AusNet (2005f, p. 33) stated that, Under the Commission’s proposed treatment of provisions, the distributor faces the cost of meeting the obligation and is not funded. While provisions are a necessary aspect of accrual accounting, they may also be used to represent the reported accounts of the business differently from its underlying economic October 06 167 Essential Services Commission, Victoria Final Decision circumstances. Moreover, they may prevent and distort the comparison of distributors on a consistent basis from year to year and across distributors. In addition, the Commission notes that, if it were to factor provisions into forecasts of expenditure, compensating adjustments to the regulatory asset bases would also become appropriate to reflect the change in future liabilities that have been provided for. This would parallel the effect of movements in provisions on the balance sheet of entities under standard financial accounting practices. Thus, if a net increase in provisions was forecast, a downward adjustment to the regulatory asset base in each year would be required. Such an adjustment would be very complex and only change the timing of a distributor’s cash flow, not its value. Movements in provision amounts may also advantage one business over another. For example, Powercor and CitiPower have taken significant provisions for safety compliance obligations — $27.1 million in 2001 and $12.3 million in 2002, respectively (in nominal dollars). Other distributors have not taken similar provisions, even though they have similar liabilities. By reversing the movements in these provisions, expenditure for safety is accounted for in the year in which it is incurred. If these provisions are not reversed, expenditure appears higher for Powercor and CitiPower relative to the other distributors in 2001 and 2002 respectively, but comparatively lower in subsequent years. Further, movements in provisions can be affected by a change in accounting standards despite expenditure remaining the same. An example of this is the introduction of International Financial Reporting Standards (IFRS) which will affect the calculation of provisions for stock obsolescence, doubtful debts and other items. For some of the distributors, the changes have already occurred. By reversing the movements in provisions, the Commission is able to assess expenditure in a form that is not impacted by a change in accounting standards. The Commission is satisfied that its framework and approach for determining operating expenditure estimates takes such liabilities into account. For example, where there are expectations about changes in future expenditure requirements for safety compliance, these are included as step changes to the base operating costs. Equally changes in expenditure in employee entitlements are included in the approach to the rate of change. The rate of change is already influenced by the historic trend that has occurred in relation to employee entitlements and incorporates expected increases in labour costs and so, in adjusting base operating costs for the rate of change, expectations about movements in employee entitlements are taken into account. 5.2.5 The market price for services Regulatory Accounting Statements submitted by the five Victorian electricity distribution businesses reflect the fact that a number of the businesses have entered into contracts with other parties to provide a significant proportion of their distribution services. The use of these arrangements has also been increasing over time. Where these other parties are identified as related parties, the Regulatory Accounting Statements report the value of these contracts, rather than the costs incurred by the related service provider in providing the services. October 06 168 Essential Services Commission, Victoria Final Decision The proportion of operating and maintenance and capital expenditure that was reported as services provided by related parties by the Victorian distributors in 2003 and 2004 is set out in Table 5.4. Information relating to related parties was not collected prior to 2003. Table 5.4: Related party transactions as a proportion of operating and capital expenditure, all distributors 2003 2004 AGLE 94% 96% CitiPower 29% 69% Powercor 0% 9% TXU 1% 3% United Energy 55% 97% Note: This information is based on the information reported in the Regulatory Accounting Statements of the distributors. The United Energy information for 2003 and 2004 includes information that was provided in a letter from Alinta Ltd dated 26 July 2005. The role of related party contracts is an emerging issue across regulated industries and across jurisdictions as a result of the corporate restructuring and integration that has occurred in the last few years, and has been identified as such by the Productivity Commission (2004, p. 458-459). In some cases, service providers have contracted out the role of operating and/or managing the pipeline to an associate. Agility, for example, manages the distribution assets of AGL Gas Networks in New South Wales. Agility and AGL Gas Networks are both wholly owned subsidiaries of the parent company AGL. Under such a structure, the asset manager can engage in inappropriate transfer pricing, undermining the process of setting appropriate reference tariffs. Such transfer pricing occurs when a regulated service provider pays the associated asset manager an inflated price in order to raise its own cost structure, thus increasing the reference tariff for services provided by the regulated business. The affiliated asset manager makes inflated profits, which are ultimately passed through to the parent company. These arrangements have the potential to allow for a greater than intended proportion of the benefits of any efficiency gains to be retained within the corporate group that includes the regulated business and the related service provider. If inflated charges paid to the related party are accepted as representing the costs of providing the services, not only are any efficiency gains made in the provision of services by the related service provider not returned to customers, but customers will actually pay more for the services than otherwise would be the case. In the Draft Decision the Commission indicated that, where the reported information included additional fees or transfer prices that do not represent the cost of providing the distribution services, it would make an adjustment based on the costs incurred by the related party in providing distribution services. The Commission’s approach to considering the underlying costs incurred by related parties in providing services to the distributors is supported by various stakeholders. In its submission to October 06 169 Essential Services Commission, Victoria Final Decision the Position Paper, the Energy Users Coalition of Victoria (EUCV) (2005b, p. 19) stated that any efficiency gain that is earned must not be left to enhance the distributor’s or contractor’s profit margin and should be returned to customers. Similarly the Victorian Consumers’ Group (VCG) (2005, p. 7) stated that the distributors’ owners should not …be permitted to use a legal or accounting artifice to prevent consumers from obtaining benefits that the Commission is required by law to deliver to them. The appropriate identification and treatment of related party contracts and the impact of transfer pricing between related parties is recognised as a significant issue worldwide for regulators and government collection agencies. For example, revenue authorities around the world are developing their transfer pricing audit skills to capture what they regard as their proper share of tax on profits from the rapidly increasing volume of international trade, especially in services and intangibles. The Organisation for Economic Co-operation and Development (OECD) has proposed that related parties operate at “arm’s length” when establishing a reasonable transfer price and this approach has been agreed by its member countries including Australia. The Australian Tax Office (ATO) has devoted considerable resources to addressing the transfer of profits out of Australia, primarily through the mechanism of inter-company and intra-company transfer pricing. It considers that transfer pricing may have the effect of depressing assessable income or increasing allowable deductions. This issue also needs to be addressed in regulation. Regulated entities may enter into arrangements with unregulated entities that depress the assessable efficiency benefits or increase the magnitude of costs to be recovered to ensure any profits are retained in the unregulated entity rather than the regulated entity. The analysis undertaken in the lead up to the Draft Decision relied primarily on the Regulatory Accounting Statements from 2000 to 2003. However, the 2004 Regulatory Accounting Statements that were provided at the end of April 2005 and the information in these statements led to the Commission identifying that the issues associated with the use of related party service providers were more substantial than in the earlier years. To address these issues the Commission, in the Draft Decision, made adjustments to the reported expenditure of CitiPower, Powercor, AGLE and SP AusNet to reflect its estimate of the profit transfers that might exist in the arrangements they had entered into with related parties. For United Energy, the Commission signalled that it was investigating further. The Commission also signalled the importance of arm’s length tender processes to testing the market price. The regulatory approach adopted by the Commission in relation to the treatment of contracts for the provision of services to distributors, including where those services are provided by a related party, must have regard to the objectives of the Commission’s regulatory framework and approach – namely, to measure efficiencies for the purpose of establishing the efficiency carryover amounts and to identify the relevant costs for the purpose of establishing the distributors' forward-looking revenue. The achievement of those objectives requires the Commission to determine the costs that are incurred in providing the distribution services. In October 06 170 Essential Services Commission, Victoria Final Decision establishing the costs that are to be taken into account for this purpose, the Commission must reach a view on whether those costs should be established by reference to: • the price charged by any third party service provider to the distributor for providing those services; or • the costs incurred by that third party service provider in providing those services. It is not the Commission’s intention to prevent or prohibit arrangements between distributors and third parties for the supply of services but rather to ensure that they do not result in customers paying more because of them. Indeed, the Commission recognises that, in the normal course of providing distribution services, a distributor may find it beneficial to enter into arrangements with third parties for the supply of certain services. However, the Commission expects that such arrangements would only be entered into where the services could be provided more efficiently than if the distributor provided those services itself. It also expects that, in entering into any such arrangements, the distributor would seek to secure the best possible price from the market. In establishing whether to take into account the price charged or the underlying costs, the Commission must consider three fundamental questions: • Is there a competitive market for the services? • Is there an incentive for the distributor to enter into the arrangements on an other than arm’s length basis? • Was a competitive tender process conducted to establish the price for the service? The importance of each of these questions varies based on the answer to these questions as follows: • Competitive markets tend to generate benefits for customers. Competitive rivalry among suppliers creates strong incentives to produce and price efficiently. Choice amongst available alternatives allows customers to select the offered products that best satisfies their preferences. If the outsourced services in question were provided in a competitive marketplace, the Commission can have a high degree of assurance that the outsourced services are being provided efficiently and that the prices charged for these services reflect a competitive market price. • If the services are not provided in a competitive market, then there is no market price for the services and the only relevant consideration is the costs incurred. Any other approach would involve a subjective valuation of the services that may be influenced by the incentives of the parties involved. • If the services are provided in a market, then the incentives of the parties involved in the arrangements become important. If there are no incentives for the parties to enter into arrangements that are other than arm’s length, then the contracted price can be taken to be a good proxy for the competitive market price. However, if there is an incentive for the parties to enter into arrangements that are other than arm’s length, then the means by which the price was established become important. October 06 171 Essential Services Commission, Victoria Final Decision • Where there is an incentive for the parties to enter into arrangements that are other than arm’s length then, if the services have been subject to a competitive tender process the contract price can be taken to be a good proxy for the competitive market price. If a competitive tender has not been conducted, then the costs incurred in providing the services are the most practicable point of reference for determining the economic value of the services. In principle, it may also be possible to use direct market evidence, if it is established at the outset that sufficiently similar services are provided in a market. However, whether this is possible will depend on whether the direct market evidence is sufficiently comparable taking into account the nature of the services, their quantity, the terms of the transactions and the incentives of the parties. The following diagram is provided to illustrate these considerations: Are the services provided in a competitive market? Yes Contract price is relevant Yes Does an incentive exist to enter into an arrangement that is not arm’s length? No Yes Has an arm’s length open tender process been conducted? Yes No Costs are relevant Where the Commission must rely on costs (ie. where there is no market price either because there is no market for the relevant services or because such a price has not been established through an appropriate process), the building block cost components are taken to be the appropriate representation of the economic value of the services. These components include a reasonable return on capital consistent with this Determination. This means that where the service provider uses regulated assets to provide the services, this return should not be duplicated. October 06 172 Essential Services Commission, Victoria Final Decision A market for the services In considering the framework identified above, it is helpful to clarify that a market is the area of close competition between firms or the field of rivalry between them. Within the bounds of a market there must be the potential for substitution — between one product and another, and between one source of supply and another — in response to changing prices. The process of defining markets usually involves the specification of four dimensions: • a description of the product or service that is being or could be provided; • the functional level at which that product or service exists in the supply chain, which is important for distinguishing the different vertical stages of a production process at which alternative suppliers may potentially compete; • the geographic area over which the product or service is or could be bought or sold; and • the time frame over which the product or service is or could be provided. Economic principles define the boundaries of a market. At one end of the spectrum, for products or services to be provided in a market, there must be actual or potential transactions between multiple potential buyers or sellers of those products or services, with the potential for these transactions to be repeated over time. A single, one-off transaction between two specific parties is not sufficient to constitute a market. At the other end of the spectrum, the boundaries of a market are determined by the extent to which particular products or services form close substitutes for one another. If buyers are unwilling to substitute one product or service for another in response to a small but significant increase in the price of one of them, then those products or services are said to be in separate markets. In applying these principles to the analysis of services that may be outsourced by an electricity distributor, whether or not a particular set of services can be said to be provided in a market is also likely to depend on the extent to which potentially separate services are bundled together. By way of example, office stationery, billing systems, network maintenance services, call centre services and IT hardware might each be said to be provided in separate markets. However, the wider the range of services that is bundled together for provision under a single contractual arrangement, the less likely it is that such a bundle of services can be said to be provided in a market. This is because the more heterogeneous is the bundle of products or services, the narrower will be the field of potential buyers and sellers of that bundle. Evidence of whether or not there is a market for a particular set of services that has been or will be outsourced will depend upon: • the existence of transactions or evidence of potential transactions involving multiple potential buyers and sellers; and • the bundle of services being considered, and the extent to which those services are being sought or offered in a way that prevents them from being separated into a number of individual services. October 06 173 Essential Services Commission, Victoria Final Decision If services are bundled into an outsourcing contract in such a way that there is no market for the services encompassed by that contract, then: • market testing will not be possible, since there is not a sufficient number of alternative providers against which to test the price being proposed; and • for the same reason, there will be no ‘market’ price. Where there is no market price, then the economic value of the services being provided can only be properly determined by reference to the costs of the service provider. Incentives to enter into arrangements that are other than arm’s length The incentives to enter into arrangements that are other than arm’s length are most apparent where a distributor contracts with its related party. In this circumstance any variation between the charges and the costs incurred in providing distribution services represents a transfer of benefits from the regulated distributor to the related party. This transfer prevents these benefits from being returned to customers. However, there may be other circumstances that give rise to an incentive to enter into arrangements that are other than arm’s length. One such example may be the existence of a related transaction where the price for different parts within a set of transactions has been determined simultaneously. The Commission recognises that, as regulation evolves, businesses may become more sophisticated in seeking out arrangements that increase their share of any benefits achieved under the regulatory framework. It is likely to be difficult for a regulator to identify and address all of the possibilities. Where there is reasonable doubt as to whether or not there are incentives to enter into arrangements that are other than arm’s length, it may be appropriate that costs should be examined as a routine measure. Open competitive tender Where there are incentives to enter into non-arm’s length arrangements, the Commission considers that market testing can only be properly applied where the services are procured under an open competitive tender. In this circumstance the arrangements should be beyond reproach. It is only then that the Commission can be assured that the contract price represents the market price. Benchmarking or independent review, which typically involves subjective judgements, cannot provide the necessary degree of confidence where there is an incentive for the parties to achieve distorted outcomes. This is a view shared by Ofwat, the economic regulator for water and sewerage services in England and Wales. Its Regulatory Accounting Guideline on transfer pricing in the water industry includes principles that transfer prices for transactions between the regulated water business and the related party must be based on market price or less. For this purpose the Guideline also indicates that market testing is to be used to establish market prices for supplies, works and services provided to the regulated water business and discusses the principles for market testing. The principles outline that there are a number of methods of market testing including: • Competitive letting; October 06 174 Essential Services Commission, Victoria Final Decision • Comparison to published list prices; • Third party evaluation; and • Benchmarking. However, Ofwat found that market testing by all but competitive letting did not demonstrate arm’s length trading because a large element of subjectivity was involved and comparisons were not always made on the basis of the same type and volume of supplies, works or services. Ofwat concluded that competitive letting was the only means of market-testing which objectively tested and preserved the competitive market, and that all other methods tended to compare a predetermined price with the market, as a means of justifying the original price. Competitive letting avoids this problem as it inherently discovers the market price without interference in, or judgement of, the market. Ofwat recognised that there may be circumstances where competitive letting is impracticable but that in these cases documentation should be provided to satisfy Ofwat that transfer prices are at market rates (Ofwat 2005, p. 11). Where no market exists for particular supplies, works or a service, or the business does not choose to test the market for that service/good, Ofwat is of the view that the related party contract should be based on cost. Ofwat (2005, p. 10) deems the cost to be: The actual cost to the supplier of the goods, works or services plus a rate of return on capital. Ofwat made downward adjustments to declared costs at the 1999 and 2004 Price Reviews because companies were unable to demonstrate arm’s length trading due to weaknesses in their processes for market-testing related party contracts, or because the competitive contract letting process was not set down in advance of entering into the contract. In a confidential submission, CitiPower pointed out that the Commission’s Regulatory Accounting Guideline does not require market testing to be undertaken or specify the nature of the market testing. This is true. However, the purpose of the Regulatory Accounting Guideline is to require the provision of information which is necessary to achieve transparency and assist understanding of the Regulatory Accounting Statements. Its purpose is not to prescribe a regulatory methodology — that is a matter for the price review. CitiPower also raises the approach adopted by the Australian Taxation Office (ATO) which allows many ways of determining arm’s length prices between related parties. The arm’s length principle referred to by the ATO requires comparison of the conditions that exist in the commercial and financial relations between associated enterprises with the conditions that might be expected to operate between independent parties dealing wholly independently with each other. This is not dissimilar to the Commission’s approach which first seeks to understand if there is a market for the services (that is, can the services be provided by an independent party). The preference of the ATO is to compare the prices or margins achieved by associated enterprises in their dealings to those achieved by independent enterprises for the same or similar dealings, recognising that there are many matters that may influence the prices or margins. In these October 06 175 Essential Services Commission, Victoria Final Decision circumstances the dealings being compared and circumstances of the parties involved need to be closely examined. CitiPower itself sought information on the market for the services currently provided internally to CitiPower and Powercor. A report was prepared by PricewaterhouseCoopers (PwC) (and provided confidentially to the Commission). This report outlined a number of issues in determining a ‘market tested’ price for these services. These included: • limited service providers able to provide the service as specified; • limited ability to seek comparisons with the services; • lower prices may have been available when management costs are excluded; • the outsourced market has a ceiling of the current costs of providing the services; • robust data in relation to defined services is only obtainable under situations where the particular service is subject to tender for outsourcing; • it is important to consider the full impact of outsourcing services in the context of the risks that are transferred between the service provider and the company, and the service provider’s relative incentive to achieve the longer term corporate goals and strategies of the company. In conclusion, PwC was not able to make a meaningful comparison of the costs, risks and rewards available and without this comparison found it impossible to assess the merits of outsourcing services because the cost of outsourcing could not be assessed against the current cost of service provision. A number of the submissions by the distributors to the Draft Decision provided information on the market testing that is claimed to have been undertaken in relation to outsourcing contracts entered into by the distributors, and how the contract value had been established. In some cases the services provided are not provided in a market. In other cases, there is a clear incentive to enter into arrangements that are other than arm’s length due to the relationship of the distributor to the provider of the services. The situation of the individual distributors is discussed below. CitiPower and Powercor CitiPower and Powercor are owned by the same company. CitiPower purchases a range of services from Powercor including management, administration, back office, IT, telecommunication, construction, and maintenance services. Conversely, Powercor purchases services from CitiPower for back-office resources through a resource agreement. The relationship between CitiPower and Powercor means that there is a clear incentive for them to enter into arrangements with each other that are not arm’s length. This has led the Commission to assess the process undertaken to establish the contract price at which the services to each other are provided. October 06 176 Essential Services Commission, Victoria Final Decision CitiPower57 states that its agreements with Powercor were developed and approved by each party acting independently to comply with criteria established by CitiPower and Powercor. It claims that it is erroneous to equate market testing with competitive tendering. Instead, it states that the charges for these services have been market tested or are at market rates because they have been based on benchmarking or independent review. The benchmarking has been based on the work of KPMG which has aimed to estimate the efficient costs of providing the services. For back office costs particularly, the price has been established using the mid-point of the range for each possible service. CitiPower has also provided information which indicates that there is no single service provider capable of providing to CitiPower all of the services provided by Powercor and that this is a reason why competitive tendering was not adopted. The Commission considers this to be evidence that the services are not provided in a market, and that there is no market price for these services. In that circumstance, for the reasons discussed above, the Commission will only consider the costs of providing the services and has made consequential adjustments for this purpose to CitiPower’s reported information. In one instance, CitiPower pays a management fee for the use of an IT asset in Powercor’s nonregulated asset base. The fee charged is significantly greater than the financing costs associated with the asset. The Commission has therefore made an adjustment to CitiPower’s capital expenditure based on the cost of the asset and removed the fee charged from operating and maintenance expenditure. The Commission has sought information regarding whether there are any other non-regulated assets utilised by CitiPower or Powercor in providing services to each other. Correspondence indicates that there are none. Therefore, no return on capital has been included in relation to the cost incurred in providing any of these other services. Where regulated assets are utilised in providing services, a return on these assets is included in the revenue requirement. In so far as the services provided by CitiPower to Powercor are concerned, CitiPower has provided the Commission with the costs of providing back-office resources through the resource agreement. This information indicates that the charge reflects these costs. Therefore, no adjustment has been made to Powercor’s reported information in this regard. CitiPower and Powercor each purchase a Discretionary Risk Management Scheme from a related company, CKI/HEI Electricity Distribution (Services) Pty Ltd (CHED), reportedly to insure against the payment of an excess on existing insurance policies. The information provided by CitiPower and Powercor indicates that there is no market price for this service as it is not available in a market. The reason there is no market is that the availability of such a service would remove any incentive for the insured to manage their risk and would result in the insured claiming all incidences regardless of their significance. The Commission has therefore considered only the costs incurred by CHED in providing these services. However, an allowance for self-insurance has been incorporated in the forecast operating and maintenance expenditure as discussed in Chapter 6. 57 The views of CitiPower were outlined to the Commission in their confidential Related Party submission. October 06 177 Essential Services Commission, Victoria Final Decision CitiPower and Powercor have submitted that, in so far as they provide services to each other, the costs which the Commission should take into account are the payments made by each of them to the other. They contend that the failure to take into account any margin would mean that the Commission has not taken into account the costs and risks incurred by the shareholders of CitiPower and Powercor in making the multiple acquisitions that are the source of the cost savings reflected in the margins. The submission proposes that, where the strategies and actions of the shareholder mean that Powercor can lower the cost of service delivery to CitiPower, then that is a matter for the shareholders, not CitiPower, and that the shareholders’ gains should not be shared with CitiPower’s customers. The Commission notes that it is these cost savings that its approach is designed to return to customers after they are retained by the distributor for five years through the efficiency carryover mechanism. To do otherwise would result in the shareholders of CitiPower and Powercor retaining those savings indefinitely. AGLE The majority of services provided to AGLE are provided by Agility or other AGL companies. These services relate to all aspects of the provision of distribution services. This package of services is unlikely to be available in a market. Additionally, the joint ownership between AGLE and its service providers results in an incentive for arrangements to be entered that are not arm’s length. AGLE has indicated that the charges for the arrangements between AGLE and Agility, at least for 2003 and 2004, were based on the benchmarks established at the last price review. Since the Draft Decision, AGLE has provided information on the costs incurred by the AGL group in providing distribution services to AGLE. For the reasons given above, the Commission has made an adjustment to reflect the costs incurred by the AGL group in providing services to AGLE. SP AusNet SP AusNet has an arrangement in place with Tenix for the provision of construction and maintenance services. This arrangement accounted for nearly 40 per cent of the expenditure undertaken by SP AusNet in 2004. Tenix is one of many providers of these services and it also provides these services to other parties. This suggests these services are provided in a market. The Commission has considered the ownership structure of Tenix and notes there is no common ownership between Tenix and SP AusNet. Therefore, there appears to be no incentive for SP AusNet to enter into an arrangement with Tenix that is other than arm’s length. Accordingly, the Commission is satisfied that it is appropriate to take into account the contract price for these services. SP AusNet also purchased corporate services from its related entity, SP Energy in 2004. It is unlikely that these services are provided in a market and there is an incentive for the arrangements to be other than arm’s length. Therefore, for the reasons given above, the Commission has made an adjustment to reflect the costs incurred by SP Energy in providing these services. October 06 178 Essential Services Commission, Victoria Final Decision United Energy The United Energy group was restructured in July 2003 with Aquila exiting the Australian market. United Energy is now 100 per cent owned by a holding company (PPL) which in turn is 100 per cent owned by United Energy Distribution Holdings (UEDH). UEDH is owned by DUET (66 per cent), which is a listed entity managed jointly by AMP Capital Investors and Macquarie Bank, and Alinta (34 per cent). United Energy acquires most of its operating and maintenance services and capital expenditure service requirements from Alinta Network Services (ANS), a wholly owned subsidiary of Alinta. In this regard, it is noted that information provided in the Regulatory Accounting Statements of United Energy does not seem to accurately reflect the magnitude of the proportion of expenditure associated with services provided by ANS. The Draft Decision indicated that the proportion of operating and capital expenditure represented by charges to related parties (including ANS) was 52 per cent in 2004. Information provided later indicated that the actual proportion is closer to 100 per cent. United Energy also acquires management and corporate services from UEDH, which in turn acquires these services from Pacific Indian Energy Services (which is majority owned and controlled by DUET), AMP Capital Investors, Macquarie Bank and Alinta. United Energy itself has no employees. In the Draft Decision, the Commission referred to the arrangements between ANS and United Energy as a related party arrangement. The reference to ANS as a related party of United Energy reflected the identification of ANS as a related party in the Regulatory Accounting Statements submitted by United Energy. The Commission received a confidential submission from ANS indicating that it did not consider itself to be a related party of United Energy. However, United Energy has since confirmed that, for the purposes of the Regulatory Accounting Statements, ANS is a related party of United Energy. Nonetheless, United Energy has indicated that it considers that the definition of related party in the Regulatory Accounting Statements is a technical issue and of limited practical value because, even if ANS and United Energy are now related, they were not when the arrangements were entered into. In its view this definition is not relevant as to whether the Commission should accept the value of the contract rather than the costs incurred by ANS in providing the services under the contract, and that, even if it is incorrect in this regard, the relevant service provision arrangements have been market tested.58 United Energy has provided information to the Commission to the effect that59: • 58 59 The transaction, of which the arrangement between ANS and United Energy for the provision of distribution services was a part, involved an ownership reorganisation (by way of a scheme of arrangement) of United Energy, MultiNet and AlintaGas Networks. This transaction involved DUET and Alinta assuming ownership of the United Energy group. Disclosed in a letter from Hugh Gleeson of United Energy, 16 September 2005. Provided in a confidential submission by United Energy, 8 April. October 06 179 Essential Services Commission, Victoria Final Decision The cost to Alinta of acquiring its shareholding in the United Energy group was $570 million, and the entire transaction involved an investment of $1.5bn. United Energy has also indicated that the scheme of arrangement was approved by the Supreme Court. • The transaction between ANS and UED ultimately led the entire United Energy workforce (except the Chief Executive Officer) and a significant amount of related operating and maintenance costs to be transferred from United Energy to ANS. • Conducting an open competitive tendering process for the provision of the services required by United Energy was not practical because of the requirement for the service provider to acquire equity, the specific nature of the skills required from the service provider, the insufficient time available to undertake such a process and the confidential nature of the transaction. • However, the competitive pressures and commercial and governance drivers existing at the time of the reorganisation meant that the arrangements were market tested and were efficient. Further, support for the arm’s length nature of the United Energy/ANS arrangements is derived from the fact that the transactions required the approval of a number of other parties including directors and independent experts. In some respects, however, this information serves to demonstrate that these services are not provided in a competitive market: • The agreement for the provision of services by ANS to United Energy was not provided in a competitive marketplace and was itself not market tested but rather was entered into as part of a larger transaction. • The larger transaction involved the simultaneous determination of the price at which equity was to be transferred and the price for which the services were to be provided. • The larger transaction involved the simultaneous sale of, and acquisition of services for, electricity and gas network businesses. • The parties who approved the transactions had no responsibility to have regard to the interests of United Energy's electricity distribution customers. In particular the Commission notes that the interests of the shareholders in the United Energy group and of the customers of United Energy's distribution network business are not aligned where arrangements can be entered into under which the shareholders are able to retain those benefits that, under the regulatory framework, would otherwise be shared with the customers. • The reasons provided as to why a competitive tender was not practicable appear to support the proposition that there is no market for the services that were agreed to be provided by ANS to United Energy as part of the transaction. A one-off transaction that bundles both the provision of services and the acquisition of equity does not occur in a market. In that context, there is no reason to believe that the price at which the services are provided properly represents the underlying economic value of those services because: October 06 180 Essential Services Commission, Victoria Final Decision • the ‘price’ of one component of the transaction (the services) was determined simultaneously with the other (the equity); and • there is no market (within which prices can be observed) for the services component in its own right. In addition, the service provider ultimately acquired almost all of the employees (save one) that were previously employed at United Energy and related operating expenses. Because these costs were reallocated among related parties, the arrangements could be viewed as cost-shifting from United Energy to ANS rather than an outsourcing of services to an independent contractor. United Energy provided a submission to the Commission which included a report from Frontier Economics considering the question of whether United Energy’s acquisition of services from ANS occurred in a market. The report by Frontier Economics found that: … a central conclusion ….. that ‘there is no market for the services that were agreed to be provided by ANS to UED’ would be incorrect.60 To draw this conclusion, the report appears to rely on assumptions which may mis-characterise the nature of the arrangements: • that United Energy and ANS are autonomous independent entities; • that the services provided are asset management services, primarily managing contracts with third party providers, with ANS employing some resources to provide services directly; and • That the price paid for the supply of services is less than the prior cost of acquiring those services and there are savings through these arrangements. The Commission notes that the report has defined a market in such broad terms that it finds that even a price paid to a monopoly provider constitutes a market price. This approach to the definition of a market is not useful in the context of the framework for regulating Victorian distribution charges. Instead, given that the Commission’s regulatory function arises precisely because the electricity distributors are monopoly service providers and are, therefore, not subject to the competitive constraints that arise from a market, for its purposes, the Commission considers that a reasonable assumption is that a market should be workably competitive.61 Even if the United Energy/ANS arrangements provide for the provision of the services to be subsequently renegotiated independently of the continued holding of the equity stake (noting that United Energy has little capacity of its own to determine the merits of the pricing or service standards due to the absence of direct employees), the future price that may be struck for such services will only be capable of representing the underlying economic value of those services if there is a market for them. The requirement to provide substantially all of the services needed by 60 61 Frontier Economics, Did United Energy Distribution’s acquisition of service from Alinta Network Services occur in a market?, 10 October, Melbourne. (Confidential) See discussion on a workably competitive market: Re Dr Ken Michael Am; Ex Parte Epic Energy (WA) Nominees Pty Ltd & ANOR, WASCA 231, 2002. October 06 181 Essential Services Commission, Victoria Final Decision United Energy requires the provision of a bundle of services that is so heterogeneous it cannot be said to be provided in a competitive market. For these reasons, the Commission does not consider that there is a market for the services. In addition, there was an incentive to enter into the arrangements on an other than arm’s length basis due to the simultaneous transaction for equity, and the arrangements were not entered into through a competitive open tender process for the services. Accordingly, for the reasons given above, the Commission considers that the costs incurred by ANS in providing the services are the relevant costs to consider for the purpose of calculating the efficiency carryover amount and forecasting United Energy’s operating and maintenance requirements. Given this conclusion, the Commission would prefer to rely on information provided by the distributor and/or its service provider on the costs incurred for this purpose. The Commission therefore requested that ANS provide it with information on the costs incurred by ANS in providing services to United Energy. However, ANS indicated that it does not keep its accounting records in a manner that enables it to readily identify these costs, and refused the further requests of the Commission to provide any information on such costs that it may have. This is cause for further concern about the validity of the charge in representing the economic value of the services. In the absence of reliable information on the costs incurred by ANS in providing services to United Energy, the Commission must make an estimate of the costs that were incurred. For the purposes of measuring efficiencies over the 2001-05 regulatory period and estimating the costs for the 2006-10 regulatory period, the Commission considers that the most appropriate information to use to estimate the relevant operating and maintenance costs is that contained in the Regulatory Accounting Statements provided prior to 2003 (the year the ANS/United Energy contract was entered into) - that is, the Regulatory Accounting Statements for the period 2000 to 2002 – as such information has been adjusted by the Commission for the reasons given earlier in this Chapter. In arriving at its estimate, the Commission has used the average costs reported by United Energy over the period 2000 to 2002 to address the possibility that costs in any one year may be less representative than another. This average has then been rolled forward to 2006 based on the rate of change and impact of growth over the 2002 to 2006 period. This approach, as applied for 2005 to 2010 period, is outlined in Chapter 6. In response to this approach62, United Energy has indicated to the Commission that the information for 2000 to 2002 is unlikely to represent an appropriate estimate due to: • it including information from a previous regulatory period; • the existence of a cross subsidy from the non-distribution business to the distribution business during this period due to the requirements of the Regulatory Accounting Guideline; 62 The Commission received further information from United Energy on 14 October outlining the adjustments that they suggest would need to be made to the pre-2003 data for it to appropriately represent the 2003 and 2004 costs. October 06 182 Essential Services Commission, Victoria Final Decision • costs in previous years reflecting the lower costs of an integrated business; • the sale by Aquila which may have depressed the expenditure in 2001 and 2002; • the Aquila management fees representing fees for service rather than profit transfer; and • the increases in insurance and regulatory costs since 2002. The Regulatory Accounting Guideline does not prescribe any particular allocation methodology. As outlined earlier in this Chapter, it is a principle based guideline requiring disclosure. If any subsidisation was occurring, it would have represented the allocations considered reasonable by the regulated distributor, or have been addressed through the adjustments the Commission has made to the regulatory accounting information in this Chapter. The reason the Commission has considered information from the 2000 Regulatory Accounting Statements is because this information relates to a year that was estimated — not reported — at the time of the last review. Further, if there are issues with the information reported in 2001 and 2002, including information from an additional reporting period is likely to mitigate the impact. The Commission notes that United Energy has had opportunities to provide information on the costs incurred in providing distribution services. Given its inability to provide such information, it is unclear how United Energy has identified the cost increases they have claimed. The Commission recognises that the information for 2000-2002 may not be entirely representative of the costs incurred in providing distribution services to United Energy’s customers in 2003 and 2004 and that its approach is a second best approach. However, the Commission has been compelled to estimate these costs due to its inability to obtain information about the actual costs incurred – and inevitably, the process of deriving any such estimate will be subject to the vagaries of the information used for the purpose of making that estimate. It is for this reason that the Commission has purposely taken an average so as to mitigate the impacts of events that might have occurred in one year and not another. With regard to the Aquila management fees and assertions that costs have increased, the Commission considers that, in the absence of actual cost information, the 2000-2002 information (as adjusted) provides the best basis for arriving at its estimate of operating and maintenance expenditure. Estimating capital expenditure is complex and would not be amenable to the application of the relatively simple approach outlined above for operating and maintenance expenditure. The Commission understands that the majority of capital expenditure is undertaken under separate contracts that are reviewed individually by the Chief Executive Officer (CEO) of United Energy. It further understands that the charges to United Energy are based on a schedule of rates, the price previously charged for like work or direct costs incurred. The Commission has been provided with detailed information on the projects and charging basis and, for the purpose of this price review, it would be difficult for the Commission to arrive at a better estimate of these costs than the reported information (with the adjustments that have been made for the reasons outlined earlier in this Chapter). Accordingly, for the purpose of applying its regulatory framework, the Commission will adopt United Energy’s reported information on capital expenditure (as adjusted). October 06 183 Essential Services Commission, Victoria Final Decision Arrangements such as those entered into between United Energy and ANS result in ongoing concerns for the Commission which may not necessarily be addressed through its approach to assessing the costs incurred. The regulator considers the costs of these kinds of arrangements potentially result in higher costs to customers as a result of: • the transaction costs that are incurred that would not be incurred where the distributor provided the services itself; and • the limited incentives for efficiency where the arrangements result in the distributor being so dependent on the contractor that the threat of exiting the arrangements is no longer credible, and therefore the incentives to achieve efficiencies in service provision are reduced. There may well be very good reasons for a particular structure adopted by a distributor. However, the distributor's customers should not be required to bear any additional costs that might arise as a result of that structure being adopted. The Commission will therefore consider the existence of these arrangements in continuing to review its approach to collecting information and licensing, as well as its approach to price regulation. Summary Table 5.5 summarises the adjustments made by the Commission to reflect the approach set out above. Table 5.5: Adjustments in relation to contractual arrangements entered into by the distributors real $2004 Adjustment and reasons AGLE An immaterial adjustment has been made to operating and maintenance and capital expenditure for the difference between the contract charge and the costs incurred by Agility in providing services to AGLE in 2003. A $0.2 million reduction in operating and maintenance expenditure and a $0.1 million reduction in capital expenditure has been made in 2004. CitiPower The following adjustments have been made: − $5.8 million adjustment to operating and maintenance expenditure in 2004 and $5.2 million in 2003 for the difference in the charge paid to Powercor by CitiPower and the costs incurred by Powercor in providing services to CitiPower. − $5.0 million adjustment to capital expenditure in 2004 and $4.8 million in 2003 for the difference in the charge paid to Powercor by CitiPower and the costs incurred by Powercor in providing services to CitiPower. − $0.7 million adjustment to operating and maintenance expenditure in 2004 for the charge paid to CKI/HEI for self-insurance. Immaterial costs have been incurred in providing these services. − $2.8 million adjustment downwards to operating and maintenance expenditure and $4.5 million adjustment upwards to capital expenditure in 2004 to remove the charge paid to Powercor in providing the services relating to an IT asset, and to add the cost of the asset to CitiPower’s regulatory asset base. (continued over page) October 06 184 Essential Services Commission, Victoria Final Decision Table 5.5: Adjustments in relation to contractual arrangements entered into by the distributors real $2004 Adjustment and reasons Powercor An adjustment to operating and maintenance expenditure of $5.0 million in 2004 that represents fees paid for in fill insurance services to CKI/HEI Electricity Distribution Services for in fill insurance services that are in addition to the costs incurred. SP AusNet An adjustment to operating and maintenance expenditure of $0.6 million in 2004 to represent the difference between the fee paid by SP AusNet and the costs incurred in providing services by SP Energy. United Energy The following adjustments have been made: − $6.6 million to operating and maintenance expenditure in 2001 and $4.2 million in 2002 for the fees paid by United Energy to Aquila. These amounts represent the Commission’s best estimate of the difference between the charge paid and costs incurred in the absence of information on the costs. − $8.9 million adjustment to operating and maintenance expenditure in 2003 and $12.3 million in 2004 as a result of the Commission’s estimate of the costs incurred in providing distribution services in those years. 5.2.6 Other adjustments Through ongoing discussions with the distributors, errors have been identified in the Regulatory Accounting Statements submitted by the distributors. Adjustments, which have been supported by the distributors, have been made to correct for these errors. This includes an additional $2.4 million identified by CitiPower as a duplicated meter reading charge in its operating and maintenance expenditure in 2004. There have also been discrepancies between workpapers in the Regulatory Accounting Statements, and between the Regulatory Accounting Statements and the distributors’ price service proposals. These discrepancies have been resolved with the distributors and adjustments have been made to the Regulatory Accounting Statements where appropriate. 5.2.7 Further adjustments to CitiPower and Powercor In its Draft Decision, the Commission was of the view that the magnitude of the variation in the 2004 reported operating and maintenance expenditure for CitiPower (being 63 per cent above 2003 levels and 41 per cent above 2002 levels) was sufficiently anomalous that it may not be representative of recurrent levels of operating and maintenance expenditure or the efficient costs of providing its distribution services. The increase in Powercor’s expenditure over the 2001-04 period was also a concern. As noted in the Draft Decision, it was difficult for the Commission to review this historical information and ignore the magnitude of the increases in operating and maintenance expenditure incurred by CitiPower and Powercor over the 2001-04 period, especially taking into account the following factors: October 06 185 Essential Services Commission, Victoria Final Decision • CitiPower’s estimate of 2004 operating and maintenance expenditure provided to the Commission in October 2004 was more than 28 per cent below the reported full year result, despite already representing a significant increase when compared to 2003. This suggested that CitiPower incurred an additional and unanticipated $13 million in operating and maintenance expenditure in the last three months of 2004. • Although CitiPower’s operating and maintenance expenditure increased significantly compared to the estimate in October 2004, its estimate of 2004 total expenditure (operating and maintenance expenditure plus capital expenditure) was consistent with the full year result. This may be the result of a change in the application of CitiPower’s capitalisation policy, although CitiPower indicated that there was no change in its actual policy during the year or when compared to previous years. • CitiPower stated that it continued to manage and operate its network and that the majority of its functions continued to be managed by CitiPower, not Powercor (CitiPower 2005b). However, this appeared inconsistent with the information presented in the Regulatory Accounting Statements provided shortly afterwards which indicated that nearly 70 per cent of its expenditure related to a related party transaction involving Powercor. • Based on the reported information, the efficiency carryover amount to be carried over by CitiPower and Powercor at the end of the period was zero, due to the net negative carryover amount that would exist. This outcome would effectively insulate those distributors from any penalties arising from inefficiencies incurred in 2004, or expenditure brought forward from 2005 to 2004. Accordingly, in its Draft Decision, the Commission considered that there were good reasons for assuming that the reported information for CitiPower and Powercor for 2004 was not representative of efficient recurrent levels of expenditure, and so ought not to be relied upon for the purpose of estimating operating and maintenance expenditure for the 2006-10 regulatory period. As a result, the Commission adopted a ‘placeholder’ assumption on 2004 recurrent operating and maintenance expenditure for these distributors and engaged Wilson Cook and Co. to provide it with an opinion on a reasonable estimate of the recurrent operating and maintenance expenditure that would be incurred by CitiPower and Powercor for the year ended 31 December 2006. This estimate was to be based on a distribution business of average efficiency and having the same functions and obligations encompassing the prescribed distribution services applicable to CitiPower and Powercor at the end of 2004. The process that Wilson Cook and Co. followed in undertaking this review was to: • discuss the terms of reference with the Commission and agree on a programme for the work; • clarify with CitiPower and Powercor the cost categories for which they required more detailed data; • examine each cost category and review the explanations given by CitiPower and Powercor for movements and variations in them; October 06 186 Essential Services Commission, Victoria Final Decision • where appropriate, make comparisons with other electricity distributors in Victoria and, in respect of total operating and maintenance expenditure, in other jurisdictions; • determine what would have been a reasonable range of movement in the costs over the period 2001-2004; and • determine what would have been an efficient and sustainable level of operating and maintenance expenditure for CitiPower and Powercor in 2004, excluding non-recurrent items. In examining CitiPower and Powercor’s expenditure, Wilson Cook and Co.: • based its analysis on CitiPower and Powercor’s regulatory accounting information as provided to it by the Commission, inclusive of the adjustments that the Commission included in its Draft Decision; • noted that CitiPower and Powercor had provided the Commission with information on actual costs incurred in providing services under their related party contracts and that the Commission had made adjustments reflecting those costs; • made adjustments to the information itself to incorporate changes of allocations between cost categories that were advised by CitiPower and Powercor; • took into account the responses and submissions made by CitiPower and Powercor; • considered whether any expenditure items were likely to be non-recurrent; and • considered whether there had been any changes in capitalisation or cost allocation policies and whether there had been a consequential impact on reported operating and maintenance expenditure. When considering the costs and the movements in costs reported by CitiPower and Powercor, Wilson Cook and Co. had regard to: • the impact of changes in activities and functions of the businesses; • differences in cost allocation policies (such as in the allocation of costs between regulatory account categories or, to the limited extent possible, between the regulated, unregulated and excluded business components) amongst the Victorian businesses; • differences in capitalisation policies, especially in respect of overheads, amongst the Victorian businesses; and • any other factors that might explain differences between the businesses. All information provided to Wilson Cook and Co. by CitiPower and Powercor was also provided to the Commission. A draft of Wilson Cook and Co.’s report was provided to the Commission, CitiPower and Powercor for comment and a final report was provided to these parties on 23 September 2005. CitiPower and Powercor have expressed various concerns regarding the approach adopted by Wilson Cook and Co., particularly the reliance placed on its approach of benchmarking costs per customer. To support these concerns, CitiPower and Powercor engaged three consultants October 06 187 Essential Services Commission, Victoria Final Decision (Benchmark Economics, Meyrick and Associates and SKM) to review the draft Wilson Cook and Co. report, provide a high level critique and commentary on the adoption of a single performance indicator as a basis for benchmarking, and comment on appropriate models for estimating efficiency. These consultants expressed the view that Wilson Cook and Co. had relied too heavily on the other Victorian distributors rather than on comparisons with other jurisdictions. Wilson Cook and Co. reviewed the submissions by CitiPower and Powercor, which included the reports from their consultants on benchmarking, and made adjustments to its report in response. In its final report Wilson Cook and Co. concluded that: • CitiPower’s reported operating and maintenance expenditure for 2004 should be adjusted down by $1.1m to reflect additional maintenance costs that might be considered to represent ‘catch up’ expenditure from 2002, and by $2.1m in overhead costs related to business restructuring that were considered to be of a non-recurrent nature; and • Powercor’s reported operating and maintenance expenditure for 2004 should be adjusted down by $13.8m in light of Wilson Cook and Co.’s assessment that its overhead costs were significantly higher than the other Victorian distribution businesses. Adjusting for these findings, the Wilson Cook and Co. report set out the levels of operating and maintenance expenditure that it considered represented efficient recurrent expenditure levels for CitiPower and Powercor in 2006 in 2004 dollars. In Wilson Cook and Co.’s view, the efficient level of recurrent expenditure for CitiPower in 2006 was $32.8 million (in 2004 dollars), while for Powercor it was $93.4 million (in 2004 dollars), excluding capitalised indirect overheads. The Commission notes that the Wilson Cook and Co. estimates are based on the relevant costs of providing distribution services as contained in the Draft Decision. However, this Final Decision has resulted in changes to these costs, notably an increase for AGLE and a decrease for United Energy. In response to these changes, Wilson Cook and Co. has advised that it is doubtful that the adjustments made in respect of CitiPower would be retained if the work was reassessed but that the comparison may remain valid in respect of Powercor. Just prior to the Commission receiving Wilson Cook and Co.’s final report, it came to the Commission’s attention that Phillips Fox, acting for CitiPower and Powercor, wrote to Wilson Cook and Co. alleging that Wilson Cook and Co. had engaged in conduct that contravened the Trade Practices Act 1974, Fair Trading Act 1999 (Victoria) and Fair Trading Act 1986 (New Zealand). In that letter, Phillips Fox reserved the rights of CitiPower and Powercor to institute proceedings against Wilson Cook and Co. for breaches under these Acts and to seek appropriate remedies, including declarations, injunctions and damages. In response to receiving this letter, Wilson Cook and Co. sought its own legal advice regarding this letter and this resulted in some delays in finalising its report. The Commission deplores the use of such threats against experts and other consultants that it has engaged in order to assist it in performing its statutory functions. The Commission emphasises that the appropriate avenue for a distributor to adopt where it has concerns regarding the methodology or conclusions of such an expert or consultant is to make appropriate October 06 188 Essential Services Commission, Victoria Final Decision representations to the Commission. Distributors also have the right to appeal Commission’s decisions to the Appeal Panel. The Commission has considered the information provided to Wilson Cook and Co. by CitiPower and Powercor and the findings of Wilson Cook and Co., in addition to the information previously provided by CitiPower and Powercor to the Commission. On the basis of this information the Commission has formed a judgement as to the efficient recurrent operating and maintenance expenditure that it should adopt for CitiPower and Powercor for 2004, for the purpose of deriving both the efficiency carryover amounts for 2001-04 and to be used as the basis for estimating operating and maintenance expenditure for the 2006-10 regulatory period. The information provided to the Commission and/or Wilson Cook and Co. reveals that for CitiPower in 2004: • There is an amount of direct overheads ($1.8 million) included in the reported operating and maintenance expenditure for 2004 which would have been capitalised had the capital works program not been disrupted due to industrial action. • There is an amount of indirect overheads ($2.1 million) included in the reported operating and maintenance expenditure for 2004 which would have been capitalised had the capital works program not been disrupted due to industrial action. The Commission considers that, in exercising its judgement as to a reasonable level of recurrent operating and maintenance expenditure for CitiPower, it is appropriate for a consistent capitalisation policy to be applied from year to year. Accordingly, the Commission has made further adjustments to CitiPower’s operating and maintenance expenditure to remove the overheads (both direct and indirect) that would be expected to be capitalised. In doing so, the Commission notes that the capitalisation policy that underpins the capital expenditure forecasts needs to be consistent with the forecasts of operating and maintenance expenditure. Accordingly, the Commission has increased the indirect (corporate) overheads included in the capital expenditure forecasts (refer Chapter 7). The information provided to the Commission and/or Wilson Cook and Co. reveals that for Powercor in 2004: • The level of corporate costs63 incurred has increased significantly between 2001 and 2004. • The significant increase in corporate costs from 2003 to 2004 is explained by a change in allocation policy (resulting in a greater allocation of corporate costs to prescribed services) rather than increases in costs. • Other operating costs include redundancy costs in 2003 of $2.1m that would not be expected to be a recurrent expenditure.64 63 64 These costs are categorised as regulatory and other operating in the regulatory accounting statements. The Commission has been informed that $1.6 million has already been adjusted for with the reversal of movements in provisions. October 06 189 Essential Services Commission, Victoria Final Decision In response to further queries from the Commission, Powercor provided additional information to justify the increase in operating expenditure from 2003 to 2004, including more detailed information regarding the total corporate costs incurred, the allocation of these costs to Powercor, CitiPower and ETSA Utilities, and the allocation between prescribed services and excluded services. For the purpose of evaluating this information, the Commission notes that: • • 65 On a like for like basis, Powercor’s reported operating and maintenance expenditure increased by 15 per cent from 2000 to 2004, whilst the operating and maintenance expenditure for the other distributors did not increase materially over this same period. y Powercor has indicated that its costs have increased substantially because it has chosen to deliver improved customer service — it has the best call centre performance of all the distributors, and has received the largest increase in revenue through the S-factor scheme during the current regulatory period. y However, the Commission would also expect that entering into joint ownership with CitiPower would result in some synergies across the businesses. Although Powercor and CitiPower have indicated that they have never claimed a reduction in costs as a result of the joint ownership, the 2003 Chairman’s Report refers to benefits arising from structural reorganisation related to service delivery and profitability. The realisation of these benefits is not consistent with an increase in costs. The increase in Powercor’s reported operating and maintenance expenditure over the 2000-04 period is largely attributable to increases in corporate costs. y Corporate costs are expected to be relatively fixed over time. Similarly, Powercor’s submission to Wilson Cook and Co’s draft report indicated that the likely cost drivers for these costs are revenue and employee numbers. This is consistent with the benchmarking approach for these costs adopted by the Commission at the time of the last price review. The increase in the reported corporate costs does not appear to be consistent with relatively flat revenue and employee numbers. y Powercor has indicated that the corporate costs in 2001 and 2002 cannot be relied upon. It is of the view that there is an error arising from the allocation of costs during the transition from a stapled distributor/retailer to a stand alone distributor. The Commission requested information on the explanation of variations in corporate costs since 2001. This information was not provided. Instead, in response to a subsequent request Powercor provided information on the variation between 2003 and 2004 in the interests of providing the Commission with some information in a timely manner. This information revealed that the variation since 2001 was likely to have been of use to the Commission.65 It is noted that in the letter to Powercor from PB Associates dated 5 September (provided to the Commission 14 October), PB Associates suggest that previous years overheads costs could be reworked using the cost allocation policies applying the 2004 financial year in order to compare costs on a ‘like for like’ basis. October 06 190 Essential Services Commission, Victoria Final Decision • • Wilson Cook and Co. highlighted the increases in Powercor’s operating and maintenance costs since 2001. Although the analysis represented a simple comparison, the results showed that: y On a cost per customer basis, Powercor’s operating and maintenance costs have increased significantly over the period, and by significantly more than the other Victorian distributors. y Overhead costs per customer and overhead costs in total have increased significantly in each year since 2001. In 2004, the overhead costs per customer are more than six times greater than in 2001. Further, the total overhead costs are more than double those reported by other Victorian distributors. Meyrick and Associates (Meyrick)66 has undertaken partial factor productivity analysis of Powercor’s total operating and maintenance expenditure. This analysis indicates that Powercor is the most efficient of the distributors. y However, when Meyrick undertakes partial factor productivity analysis on the basis of the specification underpinning the rate of change calculation incorporated in the operating and maintenance benchmarks (see Chapter 6), Powercor is the least efficient of the distributors. This specification is based on work undertaken by Pacific Economics Group for SP AusNet. y Meyrick considers that in specifying the capacity measure for the purposes of undertaking their analysis, MVA-km is preferred to peak demand. The unavailability of MVA-km data for the Victoria distributors has led Meyrick to substitute line km. Further, the weights adopted by Meyrick are derived from econometric work in New Zealand rather than Victoria. It is the Victorian weightings that are incorporated in the PEG work. y Additionally the Commission notes that the use of line lengths would result in Powercor being presented favourably given the nature of its network. • The total corporate costs incurred by Powercor have increased by $5 million from 2003 to 2004 due to additional costs incurred in providing services to ETSA Utilities. However, the costs allocated to ETSA Utilities remained unchanged from 2003 to 2004. • When comparing the increase in corporate overheads from 2003 to 2004, Powercor adjusted for $5.3 million in overheads allocated to maintenance in 2004. However a corresponding reduction in maintenance costs is not apparent. • A significant proportion of the variation in corporate costs from 2003 to 2004 is due to the under or over recovery of network personnel. Taking into account all of these matters, the Commission considers that an adjustment to Powercor’s reported operating and maintenance expenditure is appropriate to account for inefficiencies, changes in allocations and non-recurrent expenses. 66 Meyrick and Associates 2005, Review of Wilson Cook & Co Final Report ‘Estimate of Efficient Opex for CitiPower and Powercor’, 5 October, provided in a confidential submission from CitiPower and Powercor 10 October 2005. October 06 191 Essential Services Commission, Victoria Final Decision The information before the Commission indicates that an adjustment to Powercor’s operating and maintenance expenditure of up to $13.8m may be appropriate based on the review undertaken by Wilson Cook and Co. However, the Commission considers that any adjustment should take into account that the increases may be due to a number of factors, including an increase in the efficient costs of providing services to Powercor’s customers. In the absence of being able to accurately identify the contributors to the increase, the Commission has made a judgement that at least $5.5m is not due to an increase in the efficient cost of providing services to Powercor’s customers. Therefore, for these reasons, an adjustment of $5.5 million has been made to Powercor’s operating and maintenance expenditure in 2004. In Table 5.6, the Commission sets out CitiPower and Powercor’s reported 2004 operating and maintenance expenditure that reflects the adjustments described above. This table also provides, for comparison purposes, the Wilson Cook and Co. estimate of efficient recurrent operating and maintenance expenditure for CitiPower and Powercor (although it should be noted that, in light of the changes to the relevant costs made since the Draft Decision, these estimates might no longer be appropriate) and the ‘placeholder’ approach adopted in the Draft Decision. Table 5.6: Adjustments to the 2004 reported operating and maintenance expenditure, CitiPower and Powercor, $million, real $2004 Reported operating and maintenance expenditure CitiPower Powercor 47.3 110.2 0.1 3.8 Adjustments Provisionsa b (0.1) c (2.8) d (2.4) e Contractual arrangements (6.5) Capitalisation of direct overheads (1.8) Capitalisation of indirect overheads (2.1) Excluded services Capitalisation Errors (5.0) Further adjustments Commission’s adjustment (5.5) Adjusted total 31.7 103.5 Wilson Cook and Co estimate for 2006 32.8 93.4 Placeholder from Draft Decision a b 27.4 c d 93.2 e refer Section 5.24 refer Section 5.2.2 Refer Section 5.2.5 Refer Section 5.2.6 Refer Section 5.2.5 5.2.8 Summary The adjustments made to the information provided in the distributors’ regulatory accounting statements for the purposes of enabling that information to be used appropriately in this price review are summarised in Table 5.7 for operating and maintenance expenditure and Table 5.8 for capital expenditure. October 06 192 Essential Services Commission, Victoria Final Decision Table 5.7: Adjustments to reported operating and maintenance expenditure, 2000-04, all distributors, $million, real $2004 2000 2001 2002 2003 2004 Provisions -0.7 -1.9 -3.0 2.0 0.8 Excluded services 0.0 0.0 0.0 -0.1 0.0 Retail -1.4 -0.6 -0.1 -0.3 0.0 Capitalisation -0.5 -1.2 -1.5 -1.6 0.0 Contractual arrangements 0.0 0.0 0.0 0.0 -0.2 Provisions 0.0 0.6 -11.8 -0.3 0.1 Excluded services 0.0 -4.4 0.0 0.2 -0.1 Retail -4.2 -1.8 -1.3 0.0 0.0 Capitalisation 0.0 0.0 0.0 0.0 -6.6 Errors 0.0 0.0 0.0 0.8 -2.4 Contractual arrangements 0.0 0.0 0.0 -5.3 -6.5 Provisions -2.4 -30.1 -6.0 1.1 3.8 Excluded services -0.1 -9.5 3.2 0.0 0.0 Retail -1.3 -0.6 0.0 0.0 0.0 Errors 0.0 0.9 0.0 0.0 0.0 Contractual arrangements 0.0 0.0 0.0 0.0 -5.0 Further adjustments 0.0 0.0 0.0 0.0 -5.5 Provisions -3.2 -0.3 1.4 -0.8 -0.6 Excluded services 0.0 -1.2 0.4 -6.8 0.0 Retail -3.6 -5.2 -6.2 -4.0 0.0 Errors 0.0 0.5 -3.8 -4.5 0.6 Contractual arrangements 0.0 0.0 0.0 0.0 -0.6 Provisions -4.7 4.7 -1.7 -1.1 1.6 Contractual arrangements 0.0 -6.6 -4.2 -8.9 -12.3 October 06 193 AGLE CitiPower Powercor SP AusNet United Energy Essential Services Commission, Victoria Final Decision Table 5.8: Adjustments to reported capital expenditure, 2000-04, all distributors, $million, real $2004 2000 2001 2002 2003 2004 Excluded services 0.0 -1.4 -1.2 -0.9 -1.4 Capitalisation 6.2 9.7 5.9 1.0 1.4 Contractual arrangements 0.0 0.0 0.0 0.0 -0.1 Provisions 0.1 0.1 0.0 -0.5 -0.4 Excluded services 0.0 -1.7 0.0 0.0 0.0 Retail 0.0 0.0 -31.9 0.0 0.0 Capitalisation 0.0 0.0 0.0 0.0 8.3 Contractual arrangements 0.0 0.0 0.0 -5.0 -6.4 Provisions -1.1 -0.3 -0.9 -0.3 -1.8 Excluded services 0.0 -3.8 -4.5 0.0 0.0 Errors 0.0 -9.2 0.0 -9.5 0.0 Excluded services 0.0 -0.9 -2.8 0.0 0.0 Errors -1.3 -0.7 1.8 -1.4 0.0 Excluded services 0.0 -3.5 -0.5 0.8 0.0 Errors 20.1 -22.2 -14.2 -8.5 -5.9 October 06 194 AGLE CitiPower Powercor TXU United Energy Essential Services Commission, Victoria Final Decision 6 OPERATING AND MAINTENANCE EXPENDITURE Operating and maintenance expenditure requirements are added into the forecast revenue requirements as a separate component — the other components of the revenue requirement being the cost of capital, regulatory depreciation and forecast tax liability (see Chapter 9) and the efficiency carryover amounts (see Chapter 10). As with capital expenditure, the distributors are not required to spend the operating and maintenance expenditure forecast. Under the Commission’s incentive-based framework, incorporating a CPI-X price control and an efficiency carryover mechanism, the distributors are encouraged to achieve efficiencies in their operating and maintenance expenditure over the period. The framework is designed so that the benefits of these efficiencies are shared with customers over time. This Chapter sets out the operating and maintenance expenditure forecasts used to determine the distributors’ revenue requirements for the 2006-10 regulatory period as well as the information considered and reasons for the decision. 6.1 Final Decision The operating and maintenance expenditure forecasts used to determine the distributors’ revenue requirements are set out by component in Table 6.1 and by year in Table 6.2. Table 6.1: Operating and maintenance expenditure, all distributors, 2006-10, $million, real $2004 Base opexb Step changes c d Rate of change Impact of growth e Total opex Increase above base opex AGLE CitiPower Powercor SP AusNeta United Energy 234.9 155.0 516.3 460.8 374.3 8.5 11.8 42.5 56.4 17.9 4.2 2.7 9.1 8.2 6.6 12.5 7.5 27.6 36.4 20.4 260.1 177.1 595.6 561.8 10.7% 14.2% 15.4% 21.9% 419.3 f 12.0% Note: Totals may not add due to rounding. The Commission’s decision cannot necessarily be compared on a line for line basis with the distributors’ proposals because in some cases costs associated with the rate of change have been included as a step change and in some cases costs associated with the impact of growth have been included as a step change. a Formerly TXU b Refer to Table 6.8 c Refer to Table 6.23 d Refer to Section 6.2.3 e Refer to Section 6.2.4. f An increase of 11.5 per cent when the step change for GSL payments is excluded. October 06 195 Essential Services Commission, Victoria Final Decision Table 6.2: Operating and maintenance expenditure by year, all distributors, 2006-10, $million, real $2004 2006 2007 2008 2009 2010 Total AGLE 50.1 50.9 51.9 53.0 54.3 260.1 CitiPower 34.0 35.117 35.3 36.0 36.7 177.1 Powercor 114.0 116.6 118.9 121.5 124.6 595.6 SP AusNet 106.7 109.4 112.3 115.1 118.3 561.8 United Energy 80.8 82.5 84.2 86.0 85.8 419.3 Note: Totals may not add due to rounding 6.2 Reasons for the Decision As foreshadowed in the 2001-05 Price Determination (ORG 2000a, pp. 87-88), the Commission in its Final Framework and Approach indicated that it would assume that the value of operating and maintenance expenditure in 2005 would equal the level of operating and maintenance expenditure incurred in 2004, adjusted by the annual efficiency gain implied by the forecasts established in the last price review for the years 2004 and 2005. Using these assumptions, the Commission indicated that the starting point, or base operating and maintenance expenditure, for the year 2006 would be the operating and maintenance expenditure incurred in 2005, reduced for standard metering67, Guaranteed Service Level (GSL) payments68, and licence fees.69 This value would then be further adjusted for any improvement in efficiency that the Commission considered appropriate between the years 2005 and 2006, having particular regard to experience to date in the 2001-05 regulatory period and any other relevant considerations. Once the starting point, or base operating and maintenance expenditure, had been determined using the methodology outlined above, the Commission then indicated that it would use the ‘rate of change’ approach to recognise anticipated productivity improvements, and the costs associated with the impact of growth, to determine the operating and maintenance expenditure forecasts for the 2006-10 regulatory period. To recognise the potential that the distributors may be required to perform new (or changed) functions or meet new (or changed) legislative obligations, the Commission provided for the distributors to propose step changes which would be added to the base operating and maintenance expenditure where sufficient supporting information is provided. 67 68 69 Prescribed service standard metering will be subject to a separate metering price control in the 2006-10 regulatory period. The Commission has made changes to the GSL payments scheme (refer Chapter 3). Accordingly the expenditure forecast for GSL payments is considered separately. Expenditure on licence fees is being allowed as a pass through under the price controls. October 06 196 Essential Services Commission, Victoria Final Decision 6.2.1 Distributors’ proposed operating and maintenance expenditure The distributors forecast $2,235 million of operating and maintenance expenditure over the 2006-10 regulatory period. This was 37 per cent greater (on an average annualised basis) than the level of expenditure undertaken over the 2001-04 period (see Figure 6.1). This forecast increase was due to claims by the distributors that: • their rate of productivity improvement would decline and labour rates would increase; • they would incur costs from servicing the forecast increase in customer numbers; and • they faced numerous changes in functions and obligations for which they would incur large increases in operating and maintenance expenditure. The distributors’ forecasts for each component of operating and maintenance expenditure are set out in Table 6.3. Figure 6.1: Operating and maintenance expenditure, industry aggregate, actual operating and maintenance expenditure 2001-04a and distributors’ proposals 2005-10, $million, real $2004 600 500 400 $M 300 200 100 0 2001 2002 2003 2004 2005 2006 Actual opex a 2007 2008 2009 2010 Distributor proposed Exclusive of operating and maintenance expenditure associated with prescribed metering services. October 06 197 Essential Services Commission, Victoria Final Decision Table 6.3: Operating and maintenance expenditure proposed by the distributors, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Base opex 236.3 237.0 572.6 458.1 422.7 Step changes 38.6 21.5 121.3 112.4 30.0 Rate of change 3.6 20.9 50.5 35.7 0.0 Impact of growth 4.4 0.9 0.7 28.6 7.5 280.4 745.1 634.8 460.1 Total opex 282.9 a Note: Totals may not add due to rounding. Based on AGLE’s current regulatory obligations with respect to the cost of safety compliance The ability of the distributors to retain the benefits of any spending that is less than forecast creates an incentive for them to ‘overstate’ their expenditure forecasts in order to obtain a more generous revenue requirement and price cap. This incentive, together with the asymmetry of information between the distributors and the regulator, makes it very difficult for the regulator to determine the efficient level of expenditure required to deliver reliable distribution services by simply having regard to the distributors’ submitted expenditure proposals. If the regulator accepts the distributors’ forecasts, and that level of expenditure is not required, then customers will pay more than they should for a given level of service. On the other hand, if the regulator reduces the distributors’ forecasts without good reason, there is a risk of not providing sufficient expenditure for the distributors to maintain the reliable provision of services over the longer term. In deciding upon the expenditure requirements for the distributors, the Commission must therefore make a judgement on the level of expenditure that will be reasonably required by the distributors to operate and maintain their networks and meet their obligations. The fact that the operating and maintenance expenditure reported by the distributors over the 2001-04 period is much lower than estimated at the last price review and the sizeable increase in operating and maintenance expenditure which is forecast to be required over the 2006-10 regulatory period (especially given that such expenditure is largely recurrent) raises questions over the reasonableness of the distributors’ forecasts. In this regard the Commission notes the EUCV’s (2005c, p. 11-12) comments: Further, the ESCoV has noted that when it assumed that the DBs did have a better understanding of the cash needs of the network (such as during the last EDPR in 2000) and granted the DBs the funds requested, the DBs demonstrated quite clearly that they had claimed much higher amounts than were really needed to manage the networks, and to improve on service standards. It is quite clear that in the last price review that the DBs sought funds which would permit them to adequately manage the networks — the issue is that they did not need all of these October 06 198 Essential Services Commission, Victoria Final Decision funds and so took the difference between needs and the allowed amounts to profit. This approach has had two outcomes: x consumers have had to pay an unnecessary premium for the DBs to manage the networks x the DBs had no regulatory cost constraint on them in the management of the networks and so the actual expenditure by the DBs reveals the funds really needed by the DBs for their opex and capex. The Commission notes that the benchmarks set at the last price review by the Office of the Regulator-General allowed for operating and maintenance expenditure of $2,100 million over the 2001-05 period. Over this same time period, the distributors only spent $1,638 million (assuming expenditure in 2005 is the same as the average over 2001-04), or $460 million less than allowed. With this in mind, the Commission’s approach to the 2006-10 price review was to give particular focus to assessing the distributors’ forecasts against historic expenditure, the information provided by the distributors as to reasons for incurring additional operating and maintenance expenditure over the 2006-10 regulatory period, and relevant information available from a range of other sources. The Commission has also had regard to the need to ensure that the operating and maintenance expenditure included in the revenue requirement is reasonable in aggregate. Whilst the Commission has assessed each component of the operating and maintenance expenditure this does not represent the amounts of money that the distributors are required to spend against each component. Under the Commission’s incentive-based framework, the distributors are given incentives to increase their returns by meeting their service and regulatory obligations at lower cost. Customers benefit from these efficiency gains over the longer term through lower real prices. 6.2.2 Base operating and maintenance expenditure The base level of operating and maintenance expenditure proposed by each distributor is provided in Table 6.4. October 06 199 Essential Services Commission, Victoria Final Decision Table 6.4: Annual base operating and maintenance expenditure as proposed by the distributors, all distributors, 2006, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy 2004 as reported in regulatory accounts 48.6 47.3 114.0 93.4 85.6 plus efficiency changes (2004-05) -0.2 0.6 1.4 -0.3 0.0 less GSL payments 0.0 0.0 0.0 0.5 0.0 less expenditure associated with standard metering 0.5 0.5 0.8 0.4 0.5 less licence fees 0.6 0.0 0.0 0.6 0.6 Base opex 47.3 47.4 114.5 91.6 84.5 Note: May not add due to rounding. The distributors’ proposals have been updated since the release of the Draft Decision The Final Framework and Approach for estimating operating and maintenance expenditure relied on two important assumptions: 1) that the revealed costs are efficient; and 2) that operating and maintenance expenditure is recurrent. This approach relied on the incentive properties of the regulatory framework established at the last price review, in particular the efficiency carryover mechanism. This mechanism aimed to provide additional incentives for the distributors to achieve efficiencies and then report the actual cost of service provision in order to claim the efficiency carryover amounts. The intent of the mechanism was to only reward sustainable efficiencies — where lower operating costs are followed by higher operating costs, then the mechanism assumes that there is an efficiency loss and a penalty applies. Thus, to continually earn rewards under the mechanism, a distributor would have to achieve efficiency gains year on year and report these increasingly efficient cost levels to the Commission. In formulating its framework and approach for the 2006-10 price review, the Commission assumed that it could rely on the incentive properties of the efficiency carryover mechanism such that the level of operating and maintenance expenditure incurred in 2001-04 was efficient. The framework and approach established also assumed that, due to the recurrent nature of operating and maintenance expenditure, the 2004 reported operating and maintenance expenditure would provide a reasonable representation of at least the efficient base operating and maintenance expenditure for the 2006-10 regulatory period. To ensure that this was the case, the Commission reviewed the information reported in the distributors’ regulatory accounting statements to assist it in understanding the costs reported, to ensure that its analysis is based on the relevant costs (that is the costs of providing distribution October 06 200 Essential Services Commission, Victoria Final Decision services), and to ensure that it was using appropriate information for the purposes of calculating the efficiency carryover amounts and establishing the basis for estimated operating and maintenance expenditure in the 2006-10 regulatory period (see Chapter 5). Table 6.5 presents the Commission’s decision on the operating and maintenance costs for 2000 to 2004 that it considers relevant for this purpose. Table 6.5: Historical operating and maintenance expenditure, 2000-04, all distributors, $million, real $2004 2000a 2000b 2001c 2002c 2003c 2004c AGLE 53.7 49.6 43.3 44.54 50.0 48.4 CitiPower 36.4 31.3 30.2 20.5 24.9 31.7 Powercor 99.2 89.7 81.74 87.6 101.1 103.5 SP AusNet 96.8 93.1 86.9 90.3 86.1 93.4 United Energy 79.4 73.4 76.8 72.6 74.6 74.9 a Includes metering data services and public lighting which were classified as prescribed services prior to 2001. Excludes metering data services and public lighting which were classified as excluded services from 2001. c Adjusted as discussed in Chapter 5. b The recurrent operating and maintenance expenditure of each distributor for 2004, set out in Table 6.5, is used as the basis for determining base operating and maintenance expenditure for 2006. In rolling forward the recurrent operating and maintenance expenditure to 2006, the Commission has deducted expenditure from the 2004 value as follows: • The amounts spent on Guaranteed Service Level (GSL) payments equal to the actual expenditure for GSL payments reported in 2004 — expenditure on GSL payments in the 2006-10 regulatory period is instead considered a step change by the Commission (see Section 6.2.6). • Maintenance expenditure on standard metering equal to that reported in 2004 — expenditure on standard metering services has been incorporated in the prescribed metering service price controls from 2006 (see Chapter 14). • The Commission’s licence fees as reported in 2004 — expenditure on licence fees is being allowed as a pass through under the price controls from 2006 (see Chapter 12). As set out in Chapter 5, for the purposes of calculating the relevant costs for CitiPower and Powercor, the Commission has made an adjustment to the information contained in their regulatory accounting statements of $0.7 million and $5.0 million respectively to remove a payment made by them in 2004 to a related party for in-fill insurance services. The in-fill insurance services are designed to reduce the insurance cover excess to zero on claims by third parties. A market does not exist for insurance of excess payments due to ‘moral risk’, that is, if the insured incurred no risk they have no incentive to minimise the risk covered. Thus any attempt to establish a market risk premium is based on a false premise, given that such a market premium does not actually exist (refer to Chapter 5). October 06 201 Essential Services Commission, Victoria Final Decision However, the payment of excess insurance costs is a normal business expense where the quantum of the expense may vary over time as do many other business expenses, and therefore the Commission recognises that uninsured losses need to be considered in determining the distributors’ forecast operating and maintenance expenditure. This is not a new (or changed) function or legislative obligation. Accordingly, the Commission has decided to include an amount to recognise uninsured losses in the base operating and maintenance expenditure. The Commission notes that SP AusNet70 has also proposed a step change for self insurance, however its claim is for losses incurred by SP AusNet itself, rather than by third parties. Since the Draft Decision, CitiPower and Powercor provided to the Commission: • a confidential report prepared by AON Risk Solutions that quantifies its exposure to claims by third parties; and • sections of a confidential internal document relating to Fire Liability Exposure, Fire Claims History, Outstanding General Liability Claims, and Claims Management Responsibility. This information indicated that the amount included by CitiPower and Powercor for in-fill insurance services is likely to be too high to be representative of the cost of uninsured losses for the following reasons: • The amount was calculated on the basis of the 75th percentile, rather than the expected value. Whilst this may be an appropriate basis for determining the amount of a provision, as confirmed by AON during a meeting with the Commission, it is not considered to be appropriate for the purpose of determining an annual expenditure allowance. • In the case of the bushfire liability risk for Powercor, quantification of the risk took into account events prior to the Ash Wednesday fires in 1983. There have been many changes in the industry since then to reduce the impact of the distribution system on bushfires. • The material provided indicates that Powercor has not experienced any significant bushfire claims or any claim against its fire liability insurance policy since privatisation (October 1994). The probability of such an event occurring is thus less than one in ten years. • The average value of claims for bushfires occurring after the Ash Wednesday fires has been $34,000 per annum compared to Powercor’s quantification of losses incorporated in the 2004 operating and maintenance expenditure of $3.5 million per annum. The amount proposed by SP AusNet ($1.2 million per annum) was determined by SAHA International based on the cost of replacing poles and wires. However the Commission notes that, under the ‘building blocks’ approach, the costs incurred by the distributor are not the total costs of the replacement asset, but just the financing charges for a period of approximately two and a half years, given that there will not be an efficiency carryover mechanism on capital expenditure during the 2006-10 regulatory period. Accordingly, SP AusNet’s quantification of the cost of such events would appear to significantly overstate the likely cost. 70 Formerly TXU October 06 202 Essential Services Commission, Victoria Final Decision The Commission has therefore decided to add into the base operating and maintenance expenditure an amount for uninsured losses (self insurance) for each of the distributors based on the difference in the movement in the relevant provision in 2004 and the average annual movement in the relevant provision between 2000 and 2004. This will ensure the distributors are provided with a reasonable level of funding for the frequent uninsured events that occur, where the expenditure incurred in 2004 is greater or less than that incurred on average over the period. Additionally for the rural distributors there is a risk of third party claims arising from bushfires. Based on the information provided by the distributors, the excess payable under the distributors’ insurance policies is in the order of $5,000,000 and the probability of such an event occurring would appear to be a around 1 in 20 years. Therefore, the Commission has included an additional amount of $250,000 in the 2004 base operating and maintenance expenditure for Powercor and SP AusNet. Having determined the starting point (that is, the base operating and maintenance expenditure), the Commission has rolled forward this operating and maintenance expenditure to 2005 based on the efficiency improvement that the Commission has determined to be appropriate between 2004 and 2005. The Commission’s Final Framework and Approach indicated that the 2004 operating and maintenance expenditure would be rolled forward to 2005 based on the efficiencies assumed in the 2001-05 benchmarks. However, the framework and approach assumed that it could rely on the operation of the efficiency carryover mechanism to assume that the 2004 base operating and maintenance expenditure was representative of the efficient recurrent expenditure. The Commission considers that it can rely on these assumptions for AGLE and SP AusNet and apply the foreshadowed approach. However, for CitiPower, Powercor and United Energy, the Commission has had to estimate the efficient recurrent operating and maintenance expenditure for 2004. For CitiPower this required an adjustment for items that were not recurrent, for Powercor this required an adjustment for an amount that could not be said to represent efficient increases in operating costs, and for United Energy the Commission based its estimate on rolling forward previous year information. For these distributors it would not be appropriate to roll forward the 2004 operating and maintenance expenditure to 2005 on the basis of the foreshadowed approach when the estimates are based on more recent information on their costs and better information is available on the likely efficiencies achieved over the 2001-04 period. For these distributors the Commission has therefore applied the ‘rate of change’ and growth adjustment for the 2006-10 regulatory period. The efficiency gains between 2004 and 2005 that have been used by the Commission for this purpose are set out in Table 6.6. Table 6.6: Efficiency gain Assumed efficiency gains, all distributors, 2004 to 2005, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy -0.22 0.37 1.37 -0.28 1.02 The 2005 operating and maintenance expenditure that results from this calculation has then been rolled forward to 2006 based on the efficiency improvement that the Commission has determined to be appropriate between 2005 and 2006. The Commission considers that the ‘rate of change’ and impact of growth determined for the 2006-10 regulatory period (as discussed in October 06 203 Essential Services Commission, Victoria Final Decision Sections 6.2.3 and 6.2.4 respectively) is a reasonable representation of the efficiency improvement for this purpose. Thus the base operating and maintenance expenditure is rolled forward from 2005 to 2006 on the same basis as it is rolled forward from 2006 to 2010. In Table 6.7, the Commission’s decision on the 2006 base level of operating and maintenance expenditure and its derivation for each distributor is set out. Table 6.7: Base operating and maintenance expenditure, all distributors, 2006, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy 2004 recurrent opex (see Table 6.5) 48.4 31.7 103.5 93.4 74.9 plus efficiency changes (2004-05) (see Table 6.6) -0.2 0.4 1.4 -0.3 1.0 less GSL paymentsa 0.0 0.0 0.3 0.5 0.0 less expenditure associated with standard metering 0.6 0.5 0.8 0.4 0.4 less licence fees 0.6 0.6 0.7 0.6 0.6 plus self insurance 0.1 0.0 0.2 0.5 0.0 2006 base operating and maintenance expenditure 47.0 31.0 103.3 92.2 74.9 Note: May not add due to rounding. a As reported by the distributors in their performance reports. Executive remuneration In assessing the distributors’ operating and maintenance expenditure requirements, the Tariff Order requires the Commission to consider executive remuneration. Distributors must forecast executive remuneration in terms of the total remuneration, average remuneration per executive and actual headcount as per section 5.9.2 of Electricity Industry Guideline No. 3. Executive remuneration represents less than 2 per cent of the distributors’ proposed base operating and maintenance expenditure. The Commission has compared the distributors’ proposals on executive remuneration for the 2006-10 regulatory period with the executive remuneration expenditure reported by the distributors over the 2001-04 period and with the benchmarks set at the last price review (see Table 6.8). This analysis indicates that the proposed average executive remuneration rate is in line with that reported over the current period and lower than the benchmarks set at the last price review. It is noted, however, that United Energy has 12 executives paid $2.4 million per annum, although their statutory accounts reveal they have no direct employees. Therefore, the Commission considers that the level of executive remuneration is appropriately reflected in the base operating and maintenance expenditure. October 06 204 Essential Services Commission, Victoria Final Decision Table 6.8: Executive remuneration, all distributors, 2006-10 AGLE CitiPower Powercor SP AusNet United Energy Executive remuneration ($ million per annum, real $2004) 2001-05 forecasts 1.4 2.9 3.2 1.9 3.6 2004 actual 1.1 1.9 3.8 3.3 0.5 2006-10 distributors’ proposals 1.0 0.9 2.8 1.1 2.4 2001-05 forecasts 6 12 13 14 14 2004 actual 10 9 14 15 2 2006-10 distributors’ proposals 9 5 11 5 12 Number of executives 6.2.3 Rate of change The Commission indicated that the distributors’ operating and maintenance expenditure might be expected to change over the 2006-10 regulatory period to reflect changes in input cost drivers and productivity. This has been referred to as the ‘rate of change’. It is applied to the 2005 base operating and maintenance expenditure figure to establish the forecast for 2006 and is used to roll forward the 2006 base operating and maintenance expenditure forecasts for 2007 to 2010. The ‘rate of change’ is defined as the year to year change in operating and maintenance expenditure for a number of factors such as expected productivity improvements and changes in the price of distributors’ inputs. The rates of change proposed by the distributors in their price-service proposals are set out in Table 6.9. October 06 205 Essential Services Commission, Victoria Final Decision Table 6.9: Proposed rate of change in operating and maintenance expenditure, all distributors Proposed rate of change per cent p.a. Basis for rate of change AGLE 0.00 Did not support a reduction of forecast costs for unidentified efficiency gains. In its submission to the Position Paper, AGLE proposed a rate of change of 1.8 per cent per annum plus a real increase in labour costs, but this is not reflected in its templates. CitiPowera -2.83 Productivity Commission (productivity growth in the Australian electricity, gas and water sectors 1998/99 – 2003/03) and KPMG’s Labour Rate report Powercora -2.83 Productivity Commission (productivity growth in the Australian electricity, gas and water sectors 1998/99 – 2003/03) and KPMG’s Labour Rate report SP AusNeta -2.51 SP AusNet originally proposed a rate of change of -0.89 per cent per annum based on a PEG report on the Partial Factor Productivity trend in the US and KPMG’s Labour Rate report. This has been increased based on its latest forecasts of labour cost increases. United Energy 0.00 Did not support a reduction of forecast costs for unidentified efficiency gains a A negative rate of change implies that there is an increase in costs net of any productivity improvements. The distributors commissioned KPMG and Pacific Economics Group (PEG) to support the rates of change that they submitted in their price-service proposals. In its original price-service proposal, SP AusNet indicated that its rate of change of -0.89 per cent per annum consisted of an underlying rate of annual productivity improvements of 0.82 per cent (based on studies of US distribution businesses by PEG, see Box 6.1), offset by allowances of 1.26 per cent for increasing labour costs (based on KPMG’s report indicating increasing labour costs of 4.5 per cent per annum) and 0.45 per cent per annum for increased training costs. SP AusNet subsequently increased its forecast of labour cost increases, resulting in a revised rate of change of -2.51 per cent per annum. CitiPower and Powercor indicated that they expected the industry operating and maintenance expenditure productivity trend to decline by 2.83 per cent a year over the 2006-10 regulatory period based upon: • projecting forward analysis conducted by the Productivity Commission on the productivity growth in the Australian electricity, gas and water sectors from 1998-99 to 2002-03, which indicated that productivity varied between -5.0 per cent in 1998-99 and 3.4 per cent in 1999-00; and • consideration of evidence arising from KPMG’s analysis of real increases in labour rates of between 4 and 5 per cent per annum over the 2004-10 period. October 06 206 Essential Services Commission, Victoria Final Decision Box 6.1: Calculation of changes in partial factor productivity As part of its price-service proposals, SP AusNet commissioned PEG to write a report on the projection of its future operating expenses. The report, “Predicting Growth in SPI’s O&M Expenses”, focused on the more mature North American utility industry and found that: … the total cost of power distribution depends chiefly on the number of customers served but also depends on delivery volumes (PEG 2004a, p. 5). The Commission used PEG’s econometric results as a means of calculating the changes in the partial factor productivity. The change in partial factor productivity (PFP) is calculated by the difference between the change in operating and maintenance expenditure and the change in operating and maintenance expenditure driven by changes in growth factors such as customer numbers, energy consumption and peak demand. The change in operating and maintenance expenditure driven by changes in growth factors was determined by multiplying the annual change in the key network drivers of customer numbers, energy consumption and peak demand, by the weights or estimated coefficients computed for these same network drivers by Pacific Economics Groups (PEG) on behalf of SP AusNet, based on Victorian data. The estimated coefficients were 0.431 for customer numbers, 0.296 for energy consumption and 0.272 for peak demand. Using average figures for the 2000-04 period, and establishing an industry-wide operating and maintenance expenditure figure (based on the total average operating and maintenance expenditure for the industry) allowed the Commission to establish an industry wide partial factor productivity growth rate for operating and maintenance expenditure. In its Issues Paper and Position Paper, the Commission raised a number of concerns with regard to the way in which the distributors had calculated the rate of change. The main issue for the Commission was why US data rather than Victorian data was used by PEG to calculate the rate of annual productivity improvements for SP AusNet when the analysis of Total Factor Productivity (TFP) that PEG undertook on behalf of the Commission suggested that the use of Victorian data is more appropriate. The Commission supported the approach proposed by SP AusNet but considered that Victorian data should be used. Additionally the Commission raised concerns regarding the assessment of expected external labour rates commissioned by the distributors and undertaken by KPMG.71 This study forecasts that real wage increases of 4 to 5 per cent per annum will occur over the period 2004-2010. The Commission engaged PEG to review the KPMG report. PEG identified issues with KPMG’s statistical methodology and results. According to PEG, “after properly controlling for the effects of inflation, KPMG’s preferred model projects that wages will decline rather than increase in real terms over the 2006-2010 period” (PEG 2004, p. 22). A copy of PEG’s report, a copy of KPMG’s response to the PEG report, and PEG’s subsequent response are available on the Commission’s website. The Draft Decision on the methodology for calculating the rate of change combined a backward looking approach to identify the trend in operating and maintenance expenditure (change in 71 This report is available on the Commission’s website http://www.esc.vic.gov.au/electricity832.html October 06 207 Essential Services Commission, Victoria Final Decision partial factor productivity) and a forward looking approach to include the expected increase in labour costs. The change in partial factor productivity72 was determined based on the difference between the change in operating and maintenance expenditure and the change in operating and maintenance expenditure driven by changes in growth factors such as customer numbers, energy consumption and peak demand (see Box 6.1). The reported information provided by distributors for 2000 to 2004 (including the adjustments discussed in Chapter 5) was used to determine the change in operating and maintenance expenditure over the period. The results of this analysis suggested that the average weighted rate of change in operating and maintenance expenditure was 1.22 per cent per annum, which represents a reduction in the operating and maintenance expenditure. With regard to expected changes in labour costs, the Commission acknowledges that labour costs are not falling. Labour costs have been increasing at a greater rate than CPI over a number of years. The issue is whether there will be a real increase in labour rates over the next regulatory period, particularly given the recognised shortage of skilled electricity workers in Victoria. The Commission held discussions with the Electrical Trades Union (ETU) and Energy Safe Victoria (ESV) to improve its understanding of the constraints that are currently impacting upon the labour market and the resulting effect on costs. The Commission understood that the approach being adopted within the Victorian electricity industry was to increase the intake of apprentices (which has already commenced) and to constrain wage rate increases. In its Draft Decision, the Commission stated that it expected that labour costs would increase by 4 per cent per annum in nominal terms (or 1.5 per cent per annum in real terms, assuming a CPI of 2.5 per cent per annum) over the 2006-10 regulatory period, based on information from the ETU regarding Enterprise Bargaining Agreements that had been negotiated in Victoria. Assuming that labour costs account for 40 to 60 per cent of costs,73 the Commission calculated that this would result in a 0.6 to 0.9 per cent per annum increase in operating and maintenance expenditure over the period. The annual rate of change calculated under this approach, incorporating the average weighted rate of change in operating and maintenance expenditure and the forecast real labour rate increases, was -0.32 to -0.62 per cent per annum. The Commission has also considered the decisions taken by regulators in the other Australian jurisdictions on this issue. This information is compared to the distributors’ proposals and the Draft Decision in Table 6.10. 72 73 Partial factor productivity growth is the change in productivity arising from a change in a given input, such as labour, assuming all other inputs are held constant. This assumption is reasonably consistent with SP AusNet’s assumption regarding the rate of change in operating and maintenance expenditure based on the labour rate increase (SP AusNet 2004f, p. 108) October 06 208 Essential Services Commission, Victoria Final Decision Table 6.10: Rates of change in operating and maintenance expenditure Source Commission’s approach in Draft Decision Distributors’ submissions South Australia Projected labour cost increases Productivity improvements Estimated net impacta 4.0% p.a. nominal 1.5% p.a. real -1.22% p.a. -0.32 to -0.62% p.a. 4 – 5% p.a. real -0.82% p.a. (SP AusNet) -2.83 to 0.0% p.a. -5.0% - 3.4% p.a. (Productivity Commission) 2.1% p.a. real -0.84 to -1.26% p.a. ACT 5.0% p.a. nominal -1.0% p.a. -0.5 to 0.0% p.a. Queensland 4.5% p.a. nominal -1.0% p.a. -0.2% to 0.2% p.a. Nil Nil 0% p.a. NSW a Assumes that labour comprises 40 to 60 per cent of operating and maintenance expenditure and a CPI of 2.5 per cent per annum. A negative number for productivity improvements and estimated net impact represents an increase in costs. Taking into consideration the expected labour rate increases, the productivity improvements over the 2000-04 period and the analysis undertaken by regulators in the other Australian jurisdictions, the Commission applied a rate of change of 0 per cent over the 2006-10 regulatory period in its Draft Decision. In response to the Draft Decision, the distributors have questioned the principle of incorporating efficiency gains into the operating and maintenance expenditure benchmarks and stated that labour rate increases would be higher than those assumed in the Draft Decision. SP AusNet (2005f, p.35) and United Energy (2005i, p. 13) stated that if the Commission anticipates future efficiency gains in setting operating expenditure benchmarks, customers will enjoy an immediate gain of 100 per cent of those efficiency gains. According to these distributors, this was neither ‘fair sharing’ nor was it an outcome from a gain actually ‘achieved’ (contrary to clause 2.1(c)(2) of the Victorian Tariff Order (2005)). In a workably competitive market, the market prices will tend to move based on industry-wide productivity improvements. Those firms that outperform the industry-wide productivity improvements will generally receive higher returns than the other firms, and those firms that underperform the industry-wide productivity improvements will generally receive lower returns than the other firms. Other stakeholders supported this view, indicating that productivity improvements were expected in all industries and therefore should continue to be expected within the electricity industry sector. The Commission’s forecasts of the level of operating and maintenance expenditure that will be required by the distributors to manage their networks are based on consideration of industrywide trends. This includes a consideration of changes in productivity and labour costs. Consistent with the operation of a workably competitive market, customers receive the benefit of October 06 209 Essential Services Commission, Victoria Final Decision industry-wide benefits immediately. Where a distributor outperforms these industry-wide trends, then those efficiencies are retained by the distributor for five years under the efficiency carryover mechanism. A distributor will therefore benefit when it achieves greater efficiencies than the industry-wide trend, but is penalised when it is less efficient. In this regard, CUAC (2005c, p. 4) supported the Commission's approach, indicating that productivity improvements should be considered as business as usual and not part of the efficiency carryover mechanism. However, it identified that improvements in productivity will be largely offset by increases in labour costs as the labour market continues to tighten in the short term. SP AusNet (2005f, p. 35) and United Energy (2005i, p. 13) also stated that it was not reasonable to expect the distributors to improve efficiency at the same rates as in the past. To set the future required efficiency improvement equal to history ignores the reality that, as distributors approach the productivity frontier, the potential rate of productivity growth declines. These distributors contend that the proposed rate of change formula is based on the recent historical productivity trend of a group of recently privatised distribution businesses. They commented that the high productivity growth that has recently been experienced has been facilitated by special circumstances that will not be repeated in the next five years. In response the Commission notes that the period over which the change in the partial factor productivity is calculated excludes the years immediately post privatisation during which the change in partial factor productivity may have reflected higher productivity gains. Therefore, the Commission is of the view that it is reasonable to assume that the industry-wide improvements in productivity over the 2000-04 period will be achieved, on average, over the 2006-10 period. Therefore, the Commission has decided to confirm the use of the methodology it put forward n the Draft Decision. However, it has updated the change in partial factor productivity since the Draft Decision based on the updated historic operating and maintenance expenditure (including capitalised indirect overheads) as set out in Chapter 5. The Final Decision on the change in partial factor productivity is 0.83 per cent per annum, that is, a reduction in operating and maintenance expenditure. The distributors also questioned the assumptions that the Commission had made in regard to changes in labour rates. In confidential submissions provided to the Commission, CitiPower and Powercor calculated an effective nominal labour cost increase of 5.7 per cent per annum based on its Enterprise Bargaining Agreements (copies of which were provided to the Commission). Similarly, SP AusNet calculated a nominal increase in labour costs of 5.76 per cent per annum based on its Enterprise Bargaining Agreement. Using the information provided by these distributors, the Commission has calculated the forecast increase in nominal labour costs over the next regulatory period to be approximately 5.0 per cent per annum. The difference between the distributors’ estimates and the Commission estimate is the period over which one-off changes (for example, changes in long service leave) are recovered. For October 06 210 Essential Services Commission, Victoria Final Decision example, the distributors prorated these costs over the life of the EBA (three years) whereas the Commission has prorated the costs over the period in which the rate will be applied (six years — 2005 to 2010). The distributors’ approach assumes that similar one off costs will be incurred when the next EBA is negotiated. The change in partial factor productivity reflects the increase in labour rates over the 2000-04 period. To calculate the rate of change for the 2006-10 regulatory period, it is necessary to also include the incremental change in the labour rate increase that is expected relative to the 2000-04 period. The nominal increase in labour rates over the 2001-04 period has been assumed to be 3.43 per cent per annum based on the average of the actual labour rate increases reported in the Victorian budget papers for the period 2000/01 to 2003/04. This results in an expected change in the increase in labour costs of 1.57 per cent per annum over the 2006-10 regulatory period. In the Draft Decision the Commission estimated labour costs to represent between 40 and 60 per cent of total operating and maintenance expenditure. However, according to PEG (2005b, p. 22), labour costs represent 62.3 per cent of total operating and maintenance expenditure across the Victorian electricity distributors. For the Final Decision, the Commission has therefore assumed that labour costs represent 62.3 per cent of total operating and maintenance expenditure. Given that the Commission has calculated the weighted change in partial factor productivity based on the updated adjusted historic operating and maintenance expenditure (including capitalised indirect overheads) as 0.83 per cent per annum (see above), the rate of change is calculated as follows: Rate of change = Change in PFP + Labour cost increase * Proportion of labour = 0.83 - 1.57 * 0.623 = -0.15 per cent per annum This represents an increase in operating and maintenance expenditure of 0.15 per cent per annum. 6.2.4 Impact of growth Another factor considered in determining the operating and maintenance expenditure forecasts for the 2006-10 regulatory period is the costs incurred from servicing the forecast increase in the number of customers expected over the period. The distributors set out the expected cost to service additional customers over the 2006-10 regulatory period in their price-service proposals (see Table 6.11). October 06 211 Essential Services Commission, Victoria Final Decision Table 6.11: Proposed cost impacts from the expected growth in customer numbers, all distributors Cost per customer per annum AGLE $12.76 CitiPower $14.07 Powercor $12.10 SP AusNet Included in rate of change of -2.51 per cent per annum $7.74 — $10.02 United Energy In an Open Letter issued on 27 July 2005, the Commission indicated that the rate of change proposed in the Draft Decision was incorrect in that it did not incorporate the impact of growth on the operating and maintenance expenditure forecasts for the 2006-10 regulatory period. It further indicated that, in order to address this issue, it intended to forecast the impact of growth on these operating and maintenance expenditure forecasts using the same methodology that was applied in calculating the change in partial factor productivity, with the same drivers of growth and the same coefficients, and using the Commission’s Final Decision on growth forecasts. Stakeholders were generally supportive of the Commission’s proposed approach as outlined in its Open Letter. Using the Final Decision on the growth forecasts (see Chapter 4), the impact of growth for each of the distributors has been calculated using the following formula: Change in growth = 0.431 * Ln Change in customer numbers + 0.272 * Ln Change in peak demand + 0.296 * Ln Change in energy consumption Table 6.12 sets out the impact of growth for each distributor for the 2006-10 regulatory period based on this methodology. This impact has been included in the forecast operating and maintenance expenditure for the 2006-10 regulatory period. Table 6.12: Impact of growth, all distributors, per cent per annum AGLE CitiPower Powercor SP AusNet United Energy 1.73 1.59 1.74 2.55 1.78 6.2.5 Step changes Having determined the 2006 base operating and maintenance expenditure starting point, the Commission’s approach is to recognise that the distributors may be subject to changes in functions or obligations in 2006 that would not necessarily be reflected in the 2004 recurrent expenditure. The 2006 base operating and maintenance expenditure should therefore be adjusted for costs arising from new (or changed) functions and legislative obligations (termed ‘step changes’). For these purposes, the reference to legislative obligations is intended to encompass all regulatory obligations whether imposed by legislation or another regulatory instrument, for example, a licence, code or price determination. October 06 212 Essential Services Commission, Victoria Final Decision Accordingly, the distributors were required to identify any step changes and provide information supporting the basis and quantum of these step changes. The step changes identified by each distributor are set out in Table 6.13. Since the Draft Decision, a number of the step changes initially proposed by the distributors have been withdrawn. Table 6.13: Distributor identified step changes to operating and maintenance expenditure for 2006-10, $million, real $2004 New functions and legislative obligations AGLE CitiPower Powercor SP AusNet United Energy Total Cost of safety compliancea 26.6 5.0 21.9 5.5 17.8 76.8 Electric Line Clearance Regulations 0.8 2.0 49.7 31.5 0.5 84.5 5.5 18.6 Ageing assets Apprentices 5.9 GSL payments scheme 1.1 Road Management Act 1.1 4.2 Voltage compensation claims 0.6 0.3 Growth related faults Audits and accreditation 0.2 Asset inspections 1.5 0.0 5.9 41.5 2.3 44.9 12.2 5.8 2.5 25.8 2.1 1.5 2.5 7.0 7.0 7.0 2.9 4.6 0.6 0.6 Occupational health and safety Critical infrastructure protection 24.1 7.8 0.3 Allowance for cost of self insurance 1.9 2.9 3.2 b b 6.0 Premature failure of XLPE underground cable 7.8 1.5 6.0 3.2 SCADA master station upgrade 3.2 0.5 Ring fencing 0.8 Electricity demand side response 0.6 Financial report for 2009 regulatory financial information 0.1 9.8 0.5 0.8 0.6 0.6 1.8 0.1 Automated B2B 6.5 6.5 Distribution Code – Quality of Supply 2.0 2.0 (continued next page) October 06 213 Essential Services Commission, Victoria Final Decision Table 6.13: Distributor identified step changes to operating and maintenance expenditure for 2006-10, $million, real $2004 New functions and legislative obligations AGLE CitiPower SPI Powernet augmentation Powercor SP AusNet 1.0 0.5 United Energy Total 1.5 System changes for changes to GSL payments scheme 0.0 0.0 GSL payments for reliability 0.7 0.7 Increased labour cost Total 38.6 21.5 121.3 112.4 2.5 2.5 30.0 323.8 a Note: Totals may not add due to rounding. With the exception of AGLE, the distributors’ proposals are based on a risk management approach, rather than literal compliance, with the safety regulations. b CitiPower and Powercor included an allowance for the cost of self-insurance in their reported 2004 expenditure. In reviewing the step changes proposed by the distributors, the Commission notes that, with the exception of the step change originally proposed by SP AusNet for a reduction in the Energy Safe Victoria (ESV) levy (and since withdrawn), the distributors have not proposed reductions in operating and maintenance expenditure as a result of functions or legislative obligations that require less expenditure in the 2006-10 regulatory period than in the current regulatory period. The Commission has taken this into consideration when assessing the step changes. To assist the Commission in assessing the distributors’ proposals and to estimate reasonable expenditure associated with the step changes, the Commission engaged Wilson Cook and Co, technical engineering consultants, to review the reasonableness of the distributors’ expenditure proposals. Wilson Cook and Co’s report is available on the Commission’s website. Further, the Commission has undertaken its own analysis of the proposals and considered the views of stakeholders to arrive at its Final Decision. In particular, the Commission has formed its own view on whether the identified changes are appropriately categorised as step changes based on information received from the distributors, stakeholders and relevant parties, and its own analysis. Each step change proposed by the distributors is discussed in the following sections, including the step changes that have subsequently been withdrawn by the distributors. Cost of safety compliance The distributors are required to comply with a variety of legislative and regulatory requirements including the Electricity Safety (Network Assets) Regulations 1999. A major audit was conducted by the former Office of the Chief Electrical Inspector during the 2001-05 regulatory period which identified that the distributors did not comply with a number of the regulations, specifically: • Regulation 13 – Minimum distances between aerial lines and the ground, particularly those over driveways • Regulation 17 – Minimum distances between aerial lines and parts of tramway systems October 06 214 Essential Services Commission, Victoria Final Decision • Regulation 20 – Construction of underground lines – location of underground lines • Regulation 22 – Substations – minimum distances for pole mounted substations • Regulation 23 – Earthing and electrical protection – a low voltage network asset must be earthed so that the resistance of the neutral conductor of the service line is not more than 1 ohm to earth • Regulation 27 – Inspection and testing – earth systems must be tested every ten years. The Electricity Safety Act 1998 provides the opportunity for distributors to apply for variations to the Regulations by means of exemptions from the Regulations to achieve equal or better safety outcomes applicable to networks through the establishment of electricity safety management schemes (ESMSs). The Act also provides the opportunity for persons authorised under an approved scheme to be exempt from certain sections of the Act or from the Regulations. The distributors have each developed and submitted ESMSs to Energy Safe Victoria (ESV).74 At the time their price-service proposals were received, none of the distributors’ ESMSs had been gazetted through an Order in Council. However, the Commission understands that all distributors have now had their ESMSs gazetted in the form submitted. Additionally, the distributors have submitted Electricity Safety Management Plans (ESMPs) to ESV identifying plans to achieve compliance with specific regulations. In developing their ESMPs, the distributors assumed that ESV would be able to grant exemptions to certain safety regulations. At the time their price-service proposals were received, ESV’s powers to grant exemptions were unclear, however the legislation has recently been amended in this regard. ESV is now able to recommend to the Governor in Council that a scheme be accepted where it: … is satisfied that the level of safety to be provided by the scheme minimises as far as practicable – (i) the hazards and risks to the safety of any person arising from the upstream network to which the scheme applies; and (ii) the hazards and risks of damage to the property of any person arising from the upstream network to which the scheme applies. ESV has now granted an exemption to CitiPower in relation to the height of aerial service lines and has been in discussions with Powercor regarding an exemption for it in relation to the height of aerial service lines. Whilst some distributors, principally SP AusNet and United Energy, have been undertaking works to improve their compliance with the Regulations, other distributors, principally CitiPower and Powercor, have focused on risk assessments and seeking exemptions to the Regulations. 74 ESV incorporates the former Office of the Chief Electrical Inspector (OCEI) October 06 215 Essential Services Commission, Victoria Final Decision Since the Draft Decision, the Commission has met with the distributors and ESV to obtain a better understanding of the regulations that the distributors do not currently comply with and the actions that will be required to move towards compliance over the 2006-10 regulatory period. Each distributor has provided more detail in regard to the expenditure that will be required for this purpose and has detailed the actions that will be undertaken. CitiPower and Powercor (2005f, p. 1) have proposed that, in the event the exemptions they have been seeking are not granted prior to the Final Determination, then a pass through should be considered so that if the exemptions are not granted they are able to recoup the costs of complying with the Regulations in the absence of those exemptions. The Commission has given consideration to this proposal. However, it is of the view that the only regulation for which the level of uncertainty is such that expenditure cannot be reasonably forecast is regulation 23(11) regarding earthing. Whilst there is not a sufficient level of certainty to forecast the capital expenditure associated with this regulation, the Commission is of the view that there is sufficient certainty to forecast the operating expenditure. With regard to the other regulations, the Commission is of the view that there is sufficient certainty for the expenditure for the 2006-10 regulatory period to be estimated. Hence, the Commission has included as a step change a level of expenditure that is consistent with ESV’s understanding of the actions that are required to meet the conditions of any exemptions granted or to be granted. The allowances for these step changes are based on the Commission’s assessment of the reasonable levels of expenditure required by an efficient distributor — they do not prescribe the expenditure that must be undertaken. Each distributor must make its own decision regarding the requirements and risks associated with compliance. The Commission also notes that some distributors have undertaken very little expenditure to date to address these risks. In this regard, AGLE (2005f, p. 46) continues to insist that it is appropriate that its forecast expenditure be based on compliance with the Regulations and should not consider the possibility of exemptions. The Commission considers that any amount included in the expenditure requirements should represent the requirements of an efficient distributor. It does not appear that the approach adopted by AGLE is consistent with the approach that would be expected to be taken by an efficient distributor. The Commission has sought further information from AGLE regarding the most likely costs it would incur in complying with the safety regulations on the assumption that it is granted exemptions from compliance, similar to those that have been, or are likely to be, granted to the other distributors. This information has now been provided. The Commission considered this information when assessing the reasonable expenditure for AGLE for each regulation. Whilst the Commission has assessed each of the regulations in turn, it has given consideration to a reasonable level of operating and maintenance expenditure for safety compliance in aggregate. In its considerations of a reasonable level of expenditure, the Commission notes that the distributors have had a legal obligation to comply with these Regulations since 1999. In some October 06 216 Essential Services Commission, Victoria Final Decision instances the distributors have pointed to a lack of expenditure allowance as a reason for not undertaking expenditure. However, the distributors have had more than sufficient financial capacity to respond to these obligations over the period. Further, the distributors were provided with expenditure of $138 million (in 2004 dollars) for compliance with these regulations over the 2001-05 regulatory period. Whilst some distributors appear to have undertaken works in the current period, other distributors have not. This illustrates the tenuous link between a legal obligation and the expenditure allowance. The expenditure allowance provided by the Commission neither guarantees nor prevents compliance with obligations. It is entirely up to the distributors to respond to their obligations accordingly. Regulation 13 — Minimum distances between aerial lines and the ground, particularly those over driveways The forecast expenditure proposed by the distributors as being required to improve compliance of aerial line clearance heights, together with the distributors’ assumptions, is set out in Table 6.14. The forecast operating expenditure and capital expenditure is also provided to appropriately compare where different capitalisation policies have been adopted. Table 6.14: Distributors’ proposed expenditure, aerial service lines, all distributors, 2006-10, $million, real $2004 Opex Capex Total AGLE 0.0 5.5 5.5 CitiPower 1.7 5.8 7.5 Powercor 8.4 16.9 25.3 SP AusNet 3.1 12.6 15.7 United Energy 0.4 24.8 25.1 Assumptions Based on precedent in CitiPower’s and Powercor’s exemption application Approx 792 aerial service lines to be rectified per annum and 259 aerial service lines to be repaired per annum Approx 3440 aerial service lines to be rectified per annum and 2590 aerial service lines to be repaired per annum Prorated based on Powercor’s risk analysis and the number of residential customers Additional 2000 service audits per annum, Priority 1 and 2 services to be replaced in years 1-4, priority 3 services in year 5 Discussions with ESV have indicated that CitiPower’s and Powercor’s assumptions are reasonable based on the information provided to ESV in support of their exemption applications. In the absence of an application for an exemption, SP AusNet forecast its expenditure by prorating Powercor’s costs based on the ratio of residential customers. The Commission considers this approach to be reasonable. However, the Commission also notes that Powercor’s forecast expenditure has increased since SP AusNet submitted its costs due to a late change to October 06 217 Essential Services Commission, Victoria Final Decision Powercor’s exemption application by ESV. The Commission has therefore prorated these additional costs for SP AusNet and increased its forecast expenditure accordingly. The forecast step change in operating expenditure proposed by United Energy appears reasonable. AGLE did not forecast any step change in operating and maintenance expenditure in relation to aerial service lines. The forecast capital expenditure is considered by the Commission in Chapter 7. Regulation 17 — Minimum distances between aerial lines and parts of tramway systems The forecast expenditure proposed by the distributors as being required to improve compliance of tramway assets, with the distributors’ assumptions, is set out in Table 6.15. The forecast operating expenditure and capital expenditure is also provided to appropriately compare where different capitalisation policies have been adopted. Table 6.15: Distributors’ proposed expenditure, tramway assets, all distributors, 200610, $million, real $2004 Opex Capex Total Assumptions AGLE 0.1 1.8 1.9 Opex - Inspection of all 1585 poles shared with tramways and a survey of unattached aerial crossings of about 37km of tram track. Capex - 174 low voltage lines to be modified over five years CitiPower 0.3 5.0 5.3 Opex – additional minor works procedures, replace 10 tramways owned poles per year. Capex – relocation of CitiPower overhead assets in vicinity of tramway assets Powercor 0.0 0.0 0.0 SP AusNet 0.0 0.0 0.0 United Energy 0.1 0.3 0.4 Opex – one off survey. Capex – rectify some level of non compliance Discussions with ESV have indicated that the distributors’ forecast step changes in operating expenditure associated with tramways assets appear reasonable. The forecast capital expenditure is considered by the Commission in Chapter 7. Regulation 20 — Construction of underground lines – location of underground lines The forecast expenditure proposed by the distributors as being required to improve compliance of underground lines, together with the distributors’ assumptions, is set out in Table 6.16. October 06 218 Essential Services Commission, Victoria Final Decision Table 6.16: Distributors’ proposed expenditure, location of underground assets, all distributors, 2006-10, $million, real $2004 Opex AGLE 0.0 CitiPower 0.0 Powercor 0.0 SP AusNet 0.0 United Energy 0.3 Assumptions Additional 200 surveys per annum During meetings with the distributors and ESV, ESV indicated that it expected that distributors would be able to develop a risk assessment to leave underground assets in their current locations if they could demonstrate that they knew where their assets were located. Accordingly, it is expected that some expenditure would be incurred to improve the information on the location of underground assets. Whilst United Energy proposed $300,000 over the five year period for additional surveys, SP AusNet forecast $1.5 million under audits and accreditation for the automation of records. SP AusNet’s proposed step change for the automation of records has not been included in the revenue requirement on the basis that process improvements such as this would only be undertaken where the benefit exceeds the costs, and therefore it would not be appropriate to include the costs without the benefits. The expenditure proposed by United Energy is considered to be reasonable to improve the information relating to underground assets. A similar step change will be provided for the other distributors so that they can also improve their records relating to underground assets. Regulation 22 — Substations — minimum distances for pole mounted substations The forecast expenditure proposed by the distributors as being required to improve compliance of pole mounted substations, together with the distributors’ assumptions, is set out in Table 6.17. The forecast operating expenditure and capital expenditure is also provided to appropriately compare where different capitalisation policies have been adopted. October 06 219 Essential Services Commission, Victoria Final Decision Table 6.17: Distributors’ proposed expenditure, pole mounted substations, all distributors, 2006-10, $million, real $2004 Opex Capex Total AGLE 0.3 1.1 1.3 CitiPower 0.4 7.0 7.4 Powercor 0.0 10.0 10.0 SP AusNet 0.0 0.0 0.0 United Energy 0.0 9.7 9.7 Assumptions Opex – 700 inspections per annum Opex – 800 inspections per annum and additional monitoring of 60 substations per annum. Capex – 200 aerial substations to be replaced per annum Capex – 400 aerial substations to be replaced per annum Opex – Program commenced in 2004 and is due to be completed by the end of 2008. AGLE and CitiPower proposed a step change in operating expenditure to increase the number of inspections and monitoring of pole mounted substations. The expenditure proposed by them appears to be reasonable. United Energy indicated that its surveying of pole mounted substations had already commenced and therefore the costs were included in its reported 2004 operating and maintenance expenditure. Although the program is scheduled for completion by the end of 2008, United Energy did not propose a negative step change reflecting that these costs will not be incurred from 2009. United Energy was of the view that this step change was not material. The Commission does not consider this to be a reasonable approach, and has therefore incorporated a negative step change of $0.1 million in total across 2009 and 2010. The forecast capital expenditure is considered by the Commission in Chapter 7. Regulation 23 — Earthing and electrical protection — a low voltage network asset must be earthed so that the resistance of the neutral conductor of the service line is not more than 1 ohm to earth The forecast expenditure proposed by the distributors as being required to improve compliance with the earthing requirements, together with the distributors’ assumptions, is set out in Table 6.18. The forecast operating expenditure and capital expenditure is also provided to appropriately compare where different capitalisation policies have been adopted. October 06 220 Essential Services Commission, Victoria Final Decision Table 6.18: Distributors’ proposed expenditure, earthing and electrical protection, all distributors, 2006-10, $million, real $2004 Opex Capex Total AGLE 10.4 15.8 26.2 CitiPower 2.0 0.0 2.0 Powercor 9.5 0.3 9.8 SP AusNet 0.0 0.1 0.1 United Energy 17.1 0.0 17.1 Assumptions Opex – a more sophisticated test of half its service lines @ $93 per test Opex – 15,000 tests per annum @ $35 per test, plus a controlled sample test of 1,500 services per annum @ $50 per test Opex – 52,000 tests per annum @ $35 per test, plus a controlled sample test of 1,500 services per annum @ $50 per test Opex and capex based on a risk management approach. Cost to comply with current regulations is $87.5m over the five year period. If all service cables tested every 10 years, then $16.4 million over 5 years based on 563,000 services. Opex – 132,500 tests per year until 2010 and 62,000 tests in 2010 @ $32 per test. The number and cost of tests proposed by CitiPower and Powercor appear reasonable. Whilst AGLE’s assumption regarding the number of tests to be undertaken appears reasonable, the cost of each test does not appear to be reasonable when compared to the cost proposed by the other distributors. Accordingly, the Commission has reduced AGLE’s expenditure based on a unit cost of $35 per test, consistent with that proposed by CitiPower and Powercor. SP AusNet did not forecast any expenditure based on a risk management approach, but indicated that the cost of testing each service cable every ten years would be $16.4 million over the five year period. The Commission is of the view that it is reasonable that SP AusNet test half of the services over the 2006-10 regulatory period. Given that SP AusNet has a similar number of service cables to Powercor, expenditure of $9.5 million over the 2006-10 regulatory period has been included in the revenue requirement for SP AusNet. United Energy’s forecast expenditure is based on testing approximately one fifth of its service cables in each year from 2006-09 and approximately one tenth of its service cables in 2010. Given that service cables are required to be tested once every ten years, the Commission considers that it is more likely that one tenth of the service cables will be tested in each year of the 2006-10 regulatory period. The Commission is therefore of the view that it is more likely that United Energy will undertake approximately 62,000 tests per annum. Accordingly, the forecast expenditure to be included in the revenue requirement for United Energy has been reduced based on undertaking 62,000 tests per annum. October 06 221 Essential Services Commission, Victoria Final Decision United Energy75 disagrees with this approach — it has advised that it has not been testing its service cables as required, and therefore there is a catch up of testing in the first four years of the period. The Commission notes that if an efficiency carryover amount has been obtained for not undertaking these works as required during the 2001-5 regulatory period, this efficiency gain is not sustainable, and customers should not pay twice (through a step change and through an efficiency carryover amount). The unit cost proposed by United Energy is considered to be reasonable. The forecast capital expenditure is considered by the Commission in Chapter 7. Regulation 27 — Inspection and testing — earth systems must be tested every ten years The forecast expenditure proposed by the distributors as being required to improve compliance with the requirement to inspect and test earth systems, together with the distributors’ assumptions, is set out in Table 6.19. The forecast operating expenditure and capital expenditure is also provided to appropriately compare where different capitalisation policies have been adopted. Table 6.19: Distributors’ proposed expenditure, inspection and testing, all distributors, 2006-10, $million, real $2004 Opex Capex Total AGLE 0.3 4.1 4.4 CitiPower 0.7 0.7 1.4 Powercor 4.0 3.1 7.1 SP AusNet 0.8 7.4 8.2 United Energy 0.0 0.9 0.9 Assumptions Opex - additional testing of earths in rural areas approximately 320 tests per annum @ $155 per test Opex – test regime of high risk assets (580 tests per annum @ $125 per test) and random sample across network (500 tests per annum @ $125 per test) Opex – targeted test regime ($125,000 per annum) and additional program for SWER distribution substations ($675,000 per annum) Opex – 10,700 tests of SWER isolators and substations ($0.9m, incremental cost = $0.8m) The step changes in operating expenditure proposed by the distributors to improve compliance with these inspection and testing requirements appear reasonable. The forecast capital expenditure is considered by the Commission in Chapter 7. The step changes in operating expenditure to improve safety compliance that will be included in the distributors’ revenue requirement are summarised in Table 6.20. 75 Email from Andrew Schille dated 7 October 2005 October 06 222 Essential Services Commission, Victoria Final Decision Table 6.20: Step changes in operating expenditure for safety compliance, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Aerial service lines 0.0 1.7 8.4 5.0 0.4 Tramway assets 0.1 0.3 0.0 0.0 0.1 Underground lines 0.3 0.3 0.3 0.3 0.3 Aerial substations 0.3 0.4 0.0 0.0 -0.1 Earthing and electrical protection 3.9 2.0 9.5 9.5 8.6 Inspection and testing of earthing 0.3 0.7 4.0 0.8 0.0 Total 4.9 5.4 22.2 15.6 9.3 Electric line clearance The Electricity Safety (Electric Line Clearance) Regulations 2005 were promulgated on 1 July 2005. These Regulations clarify various issues relating to the encroachment of vegetation towards electric lines. However, ESV has indicated in correspondence with the distributors that: With regard to the current industry practice of practical compliance rather than literal compliance at all times on the clearance space between electric lines and vegetation, the Regulations are unchanged. The Office advises that it will not change its present interpretation or enforcement actions, but will continue to ensure that literal compliance occurs during the Proclaimed Fire Declaration Period for the area. In a response to this correspondence dated 10 August 2005, CitiPower and Powercor have indicated that Powercor has received legal advice that: The [ESV’s] statement of intent in respect of non-enforcement of the Code (except during Proclaimed Fire Declaration Periods) does not change distributors’ legal obligations to comply with the Code. Distributors continue to have a legal obligation to comply with all requirements of the Code, in the absence of an exemption from the [ESV] under r10 of the Regulations. Accordingly CitiPower, Powercor and SP AusNet have proposed expenditure which they assert is necessary to ensure that at all times (that is, not just during a Proclaimed Fire Declaration Period) their vegetation clearance is such as to comply with the electric line clearance requirements set out in the Regulations. The forecast expenditure proposed by the distributors as required to comply with the new Regulations, together with the distributors’ assumptions, is set out in Table 6.21. October 06 223 Essential Services Commission, Victoria Final Decision Table 6.21: Forecast expenditure, electric line clearance, all distributors, 2006-10, $million, real $2004 Opex Assumptions AGLE 0.8 Anticipated expenditure at time of submitting proposal, however proclamation of new Electricity Safety (Electric Line Clearance) Regulations 2005 effectively removes AGLE’s exposure in this area CitiPower 2.0 $0.4m to comply with the new Regulations and $1.6m to maintain clearance at all times Powercor 49.7 $2.2m to comply with the new Regulations and $47.5m to maintain clearance at all times SP AusNet 31.5 Additional cutting cycle United Energy 0.5 Advice from a qualified arborist In determining the revenue requirement for each distributor, the Commission must determine the costs which it is reasonable to include in that requirement. If the Commission was to include an allowance for expenditure that is unlikely to be required, then the distributor would make a windfall gain to the extent that the expenditure is not actually incurred. Given that ESV has indicated that it only intends to enforce literal compliance with the requirements imposed by the Regulations as to the clearance between electric lines and vegetation during Proclaimed Fire Declaration Periods, the Commission considers that a reasonable allowance for the costs of complying with these Regulations is one that is based on literal compliance with the Regulations during Proclaimed Fire Declaration Periods (as opposed to during periods outside Proclaimed Fire Declaration Periods). However, the Commission does regard the $0.4 million proposed by CitiPower and the $2.2 million proposed by Powercor to meet the new Regulations as the consequence of a change in obligation which is appropriately regarded as a step change. Similarly the $0.5 million proposed by United Energy has been included in the revenue requirement as a step change. Consistent with the expenditure provided to CitiPower and Powercor, the Commission has also included a step change of $0.4 million for AGLE and $2.2 million for SP AusNet. Ageing assets CitiPower and Powercor forecast increased operating and maintenance expenditure resulting from the projected increase in the average age of their asset bases. CitiPower and Powercor were of the view that ageing assets would result in increased operating and maintenance expenditure because, to maintain service standards, the assets will become more resource intensive reflecting the decline in the condition of the assets. CitiPower and Powercor engaged SKM to assess the likely increase in inspections, maintenance costs and failures arising as a result of the projected increase in the average age of their asset October 06 224 Essential Services Commission, Victoria Final Decision bases. Their preliminary conclusions were used to quantify an operating and maintenance expenditure increase. During the course of the review, the Commission noted that SP AusNet did not consider that changes in operating and maintenance expenditure arising from the requirement to service ageing assets were a ‘step’ change. There are a number of areas where there is upward pressure on costs that are not assessed as meeting criteria for a step change and are therefore not claimed as incremental operating and maintenance cost [including]…increased maintenance costs due to the gradual ageing of certain network assets (SP AusNet 2004f, p. 112). SP AusNet’s modelling had indicated that maintenance costs would increase by $13 million over the five year period due to ageing assets. In its expenditure review prior to the Draft Decision, Wilson Cook and Co noted that ageing assets were not a new phenomenon but were a feature of electricity supply networks and thus the proposed expenditure was not a step change, but should be included in the rate of change. In its Draft Decision, the Commission did not consider ageing assets a new (or changed) function or legislative obligation and thus excluded this expenditure from the revenue requirements for these distributors. Given that there was not a sharp increase in the age of assets (but rather a steady increase in the age of assets) over time, increasing costs for maintaining ageing assets should be reflected in the reported costs and therefore incorporated into the rate of change. In response to the Draft Decision, CitiPower (2005g, p. 3) and Powercor (2005l, p. 4) stated that whether the proposed expenditure was a step change or not was of no relevance. Failing to provide for an efficient level of operating and maintenance expenditure in respect of ageing assets leads to outcomes and/or incentives that are inconsistent with the Commission's efficiency-related statutory objectives. These distributors also contend that, if the Draft Decision on reducing replacement capital expenditure was translated into the Final Decision, then further age-related maintenance costs would need to be incurred. United Energy (2005i, p. 16) commented that the Commission's approach to the rate of change did not explicitly allow for the ageing of network assets because there was no facility in the original guidance that allowed the distributors to input opening and closing average asset lives. As a result, United Energy requested an increase in operating and maintenance expenditure of $300,000 per annum based on internal modelling and engineering assessments. According to United Energy, if the Commission maintained its Final Decision, then the rate of ageing would greatly increase and the impact of this ageing on operating and maintenance expenditure would require a substantial and detailed review. The Commission has analysed the change in the weighted average remaining life of assets (weighted based on the written down value of assets) between 2001 (as forecast in the last price review) and 2005 (as forecast in the current price review) and the change in maintenance costs between 2000 and 2004. This analysis indicates that there is no correlation between the two parameters (R2=0.06). October 06 225 Essential Services Commission, Victoria Final Decision Given that there is no correlation between the ageing of assets (represented by the change in the weighted average remaining life of assets) and the change in maintenance costs, no additional expenditure has been included for ageing assets. This is because the Commission is not satisfied that ageing assets will lead to a change in maintenance costs. Cost of apprentices In their original price-service proposals, AGLE and United Energy proposed a separate step change for apprentices which the Commission considered in conjunction with the increased labour costs in its Draft Decision. AGLE indicated that it planned to increase the number of apprentices taken on each year from 3 in 2004 to 8 in 2005 and then to 15 in 2007. Similarly SP AusNet and United Energy indicated they would be increasing their intake of apprentices, although SP AusNet had originally included these costs in its rate of change. In its Draft Decision, the Commission included costs associated with increasing labour rates, including the costs of apprentices, in the rate of change. The Commission’s analysis prior to the Draft Decision indicated that there were various subsidies available from the federal and State governments for apprentices so that the incremental costs to the distributor were unlikely to be material. In its response to the Draft Decision, AGLE (2005, p. 46) stated that it currently has an arrangement with VICTEC Limited whereby apprentices are hired by VICTEC and provided with 'on the job training' by the distributor. VICTEC receives the government funding as the employer of apprentices whilst the distributor pays an hourly rate for apprentices while they are working for and obtaining their 'on the job' training. AGLE also indicated that it provides uniforms, safety equipment and other miscellaneous equipment as required for this ‘on-the-job’ training. Accordingly it considers that incremental costs are incurred by the distributors when employing additional apprentices, and that these costs are material. The Commission understands that the other distributors have a similar arrangement with VICTEC. In a submission to the Draft Decision, the Hon. Minister Theophanous (2005, p. 2) commented that: The capacity of Victoria's energy industry to provide a competitive, reliable and sustainable energy supply depends fundamentally on the continued maintenance and development of a skilled workforce. Industry faces important challenges in recruiting and training skilled employees, arising from the ageing of the workforce, the low level of interest in the industry of young people entering the workforce, the reduced level of recruitment that followed industry reform, and the substantial investment and technological change facing the energy sector in coming decades. As the primary responsibility for meeting these challenges rests with the Businesses, the Government urges the Commission to give regard to demonstrated programs of the Businesses that add long term skills capacity to the Victorian electricity distribution sector. The Commission sought further information from the distributors regarding their plans for recruiting apprentices. CitiPower and Powercor considered they currently had a reasonable October 06 226 Essential Services Commission, Victoria Final Decision number of apprentices and therefore did not consider this to be a step change. AGLE, SP AusNet and United Energy provided details regarding the number of apprentices to be employed and the costs of these apprentices. The Commission considers that the hiring and training of new workers to meet expanded obligations or to replace retiring workers should be part of a long term human resource strategy that a prudent distributor would already have in place to ensure that the distributors have the long term skills capacity required. As indicated in the response from the Hon. Minister Theophanous, the distributors clearly have the responsibility for maintaining this capacity. The distributors have spent $200 million less on operating and maintenance expenditure than was forecast as being required at the last price review. AGLE, SP AusNet and United Energy will each be receiving an efficiency carryover amount in their revenue requirement as a result of this underspending relative to the forecasts for the period. The claims by these distributors for increased expenditure to meet the costs of new apprentices appear at odds with their claims that the efficiencies they have achieved are sustainable over the longer term. Additionally, the Commission considers that any increased costs incurred employing apprentices within the industry will already be reflected in the rate of change. Therefore, the Commission has not included the costs of apprentices as a step change because it does not consider this a new (or changed) function or legislative obligation. GSL payments scheme In determining the base level of operating and maintenance expenditure, the distributors were required to deduct the GSL payments that they expected to pay in 2004. Whilst CitiPower, Powercor and United Energy did not deduct any expenditure for GSL payments in determining the base operating and maintenance expenditure forecast, AGLE deducted $0.05 million and SP AusNet deducted $1.82 million. The distributors were then expected to include forecast expenditure required for GSL payments, based on their proposals for the GSL payments scheme over the 2006-10 regulatory period, in the operating and maintenance expenditure step changes. The distributors’ proposals for the GSL payments scheme are discussed in the Chapter 3. AGLE, SP AusNet and United Energy most recently forecast expenditure of $1.1 million, $41.5 million and $3.5 million respectively, over the 2006-10 regulatory period for GSL payments. In its Draft Decision, the Commission considered increased expenditure arising from the changes to the GSL payments scheme was a step change because it was a changed regulatory obligation from 1 January 2006. Consequently, the expenditure on GSL payments in 2004 was excluded from the calculation of the base operating and maintenance expenditure but the forecast cost of meeting the revised GSL payment scheme was included in the revenue requirement. In response to the Draft Decision, the distributors indicated that additional expenditure was required for them to meet their GSL payment obligations. October 06 227 Essential Services Commission, Victoria Final Decision In light of this, the Commission has re-examined the thresholds of the revised GSL payments scheme (see Chapter 3). The expenditure required by the distributors to meet their GSL payment obligations has been revised in accordance with these thresholds and included as a step change. Road Management Act The Road Management Act 2004 (RMA) has legislated a number of specific requirements that utility infrastructure and service providers must adhere to when their operations affect the physical structure or operation of roads. According to United Energy, regulations are still being developed that are expected to exempt specific works from requirements to obtain consent or give notice. The additional costs associated with the implementation of the RMA are claimed to include the establishment of systems and processes for accreditation, consent and notification processes, and payment of prescribed fees (United Energy 2004e, p. 126). Consequently, each distributor has proposed an increase to their operating and maintenance expenditure requirements. AGLE, CitiPower and Powercor have also proposed an increase of $4.6 million, $3.0 million76 and $17.9 million respectively to their capital expenditure requirements. However, as AGLE noted, the details of the Act will not be known until the Codes of Practice underpinning the Act are developed over the next few years. In its Draft Decision, the Commission included expenditure associated with the RMA as a step change because it considered this a new legislative obligation from 2005 and so would not be reflected in the base level of operating and maintenance expenditure in 2004. The Commission indicated that an expenditure amount would be incorporated into the revenue requirement for the next regulatory period. Whilst AGLE, SP AusNet and United Energy accepted the Draft Decision, CitiPower and Powercor noted that the Draft Decision did not fully allow the amounts sought by them. In a late submission prior to the Draft Decision, CitiPower and Powercor increased their proposed expenditure by $1.5 million and $6.8 million respectively. Given the short notice of this increase, the Commission did not have the time to consider the increase and so incorporated only 50 per cent of the additional costs proposed by CitiPower and Powercor in the Draft Decision. CitiPower and Powercor have since provided a full break down of the costs associated with permits and road authority interfacing, and confirmed that there was no overlap between operating and maintenance expenditure and capital expenditure. In its submission to the Draft Decision, the Streetlighting Group of Councils (2005, p. 8) did not agree that the RMA imposed new obligations on the distributors that would require an increment of cost anywhere near the $27.2 million proposed by the distributors. It contended that the responsibilities imposed on distributors under the RMA were no more onerous than their current obligations under relevant OH&S and Planning and Environment legislation, and through individual responsibilities required by Local Government by virtue of the Local Government Act 76 Excluding overheads October 06 228 Essential Services Commission, Victoria Final Decision 1989. According to the Streetlighting Group of Councils, the spirit and intent of the RMA was only to standardise and consolidate disparate statutory obligations as they relate to road reservations under a single statutory instrument, rather than to extend those obligations. The Commission notes that the Regulatory Impact Statement that accompanied the RMA contemplated that additional costs in the form of consent fees would be incurred by the distributors. The RIS did not include the additional administrative costs that would be incurred by the distributors in applying for permits and in notifying VicRoads of works. Therefore, the Commission remains concerned about the increase in costs submitted by CitiPower and Powercor, particularly given the uncertainty as to how the obligations will be enforced, the amounts included by CitiPower and Powercor in their capital expenditure forecasts, and the operating and maintenance expenditure proposed relative to the other distributors. The Commission continues to be of the view that the Road Management Act is a new legislative obligation and should be considered as a step change. However, whilst it continues to be of the view that the expenditure proposed by AGLE, SP AusNet and United Energy is reasonable, and that the expenditure originally proposed by CitiPower and Powercor is reasonable, it is not convinced that the additional expenditure proposed by CitiPower and Powercor shortly before the Draft Decision is reasonable. The amounts included with the revenue requirement for this step change are set out in Table 6.22. Voltage compensation claims As discussed in Chapter 2, the distributors are required to compensate residential and small business customers for damage due to voltage variations (surges and brown outs). The Commission codified the circumstances in which customers are entitled to compensation in the Electricity Industry Guideline No. 11: Voltage Variation Compensation. Insurance companies have the right of subrogation under the law. The Commission recently clarified that its guideline on voltage variation compensation does not prevent the insurance companies’ right to subrogation under the law. Each distributor proposed additional expenditure to cover claims made by insurance companies, in anticipation that this clarification will increase the number of claims by insurance companies. The additional operating and maintenance expenditure originally proposed by the distributors varied from $0.3 million for CitiPower to $3.6 million for AGLE over the 2006-10 regulatory period. AGLE also proposed expenditure for the introduction of a ‘new-for-old’ policy, similar to that proposed by CitiPower and Powercor in their enhanced service offerings. The introduction of a ‘new-for-old’ policy has been discussed in Chapter 2. Wilson Cook and Co reviewed the expenditure proposed by the distributors and found that the proposed amounts were reasonable. October 06 229 Essential Services Commission, Victoria Final Decision Having given consideration to the views expressed by Wilson Cook and Co and the distributors, in the Draft Decision, the Commission included expenditure for voltage variation claims as a step change as it was considered a change in regulatory obligations following the Commission’s 2004 clarification of the Electricity Industry Guideline No. 11: Voltage Variation Compensation in regard to insurance companies’ rights to subrogation. For these purposes the amount the Commission included for this expenditure were as proposed by the distributors, with the exception of AGLE. The Commission considered that expected expenditure would be lower than that forecast by AGLE. AGLE has a smaller number of customers than Powercor, SP AusNet and United Energy, and the number of over voltage events reported by AGLE is significantly less than these three distributors. Therefore, AGLE’s expenditure would be expected to be lower than that incurred by Powercor, SP AusNet and United Energy. AGLE and United Energy were the only stakeholders to comment on this issue and both distributors accepted the Commission’s Draft Decision. Therefore, the Commission has included amounts for voltage compensation claims as a step change. The amounts included are the same as those included in the Draft Decision. Growth-related faults According to its submission, Powercor believes that unexpected, gradual load growth will result in load related faults on low voltage circuits and distribution substations, and increased voltage variation complaints. For the purposes of the Draft Decision, both Wilson Cook and Co and the Commission considered that this expenditure was not a step change because it was not a new (or changed) function or legislative obligation. In response to the Draft Decision, Powercor stated that this step change was justified for the following reasons: • Wilson Cook and Co acknowledged the legitimacy of load-related maintenance expenditure in its final report. • Further factual evidence was provided to demonstrate that expenditure on growth-related faults in 2004 was below average. • The impact of growth-related expenditure varies with system dynamics and the degree to which a distributor is ‘rural’ or low density. Consequently, Powercor considered the issue unique to rural distributors. Since the release of the Draft Decision, the Commission has included a growth-related component to operating and maintenance expenditure (see Section 6.2.4). The Commission is of the view that this growth-related component addresses changes in operating and maintenance expenditure that are related to growth. This includes the expenditure proposed for growth-related faults. Additionally the Commission notes that the expenditure allowed under this growth-related component is well in excess of the amount that Powercor has proposed for this step change. October 06 230 Essential Services Commission, Victoria Final Decision Therefore, the Commission has not included additional expenditure for this item as a step change. Audits and accreditation The distributors proposed step changes arising from their obligations in regard to various audits and accreditations. • AGLE, CitiPower and Powercor submitted additional operating and maintenance expenditure for audits required by ESV during the 2006-10 regulatory period. • AGLE and United Energy submitted additional operating and maintenance expenditure for regulatory audits required to be undertaken by the Commission. • AGLE submitted additional operating and maintenance expenditure for financial audits required to be undertaken by the Commission. • CitiPower and Powercor submitted additional operating and maintenance expenditure for internal audits. OCEI (ESV) audit and regulatory audit ESV undertook a major audit of the distributors in 2001, but has not undertaken an audit since. Accordingly, AGLE, CitiPower and Powercor were of the view that the costs associated with an ESV audit were not included in the actual operating and maintenance expenditure for 2004. Therefore, these distributors did not believe that this required expenditure has been included in the base operating and maintenance expenditure forecast and noted that ESV has foreshadowed more frequent audits in the 2006-10 regulatory period. The Commission conducted a desktop audit of the distributors’ regulatory obligations in 2004. AGLE and United Energy were of the view that minimal costs associated with the Commission’s regulatory audits were included in the actual operating and maintenance expenditure for 2004 and thereby in the base operating and maintenance expenditure forecast. These distributors have also noted that the Commission has foreshadowed annual audits in the 2006-10 regulatory period. Therefore, they proposed additional operating and maintenance expenditure. In the Draft Decision, the Commission did not include expenditure for this item as a step change because it did not consider it a new (or changed) function or legislative obligation. Additionally it noted that the 2004 base operating and maintenance expenditure (and benchmarks from the previous price review) includes higher regulatory costs associated with the conduct of this price review. This higher level of costs was not expected to be incurred during the first three years of the next regulatory period, and therefore would offset costs associated with other regulatory obligations not incurred in 2004, such as the ESV and regulatory audit costs, in addition to the transition from state-based to national regulation. While United Energy accepted the Draft Decision, CitiPower and Powercor did not on the basis that they believe regulatory costs will increase substantially due to the change from state-based to national regulation, and that a price review spans multiple years. October 06 231 Essential Services Commission, Victoria Final Decision The Commission notes that the distributors will spend in the order of $1 million each, if not more, on the price review in each of 2004 and 2005. This higher level of expenditure is included in the base operating and maintenance expenditure for each distributor. However, this expenditure is not expected to be incurred in 2006, 2007 or 2008, but is expected to be incurred in 2009 and 2010. As a result, the base operating and maintenance is in the order of $3 million higher for each of the distributors than if the phasing of expenditure had been considered in the expenditure forecasts. For this reason, the Commission continues to be of the view that the higher level of costs provided through the inclusion of the costs associated with the price review will offset costs associated with other regulatory obligations not incurred in 2004, such as these ESV and regulatory audit costs. Financial audit In the Draft Decision, the Commission included additional expenditure as a step change for the costs incurred from financial audits as this was a changed regulatory obligation for AGLE. While distributors are required to accompany the submission of their regulatory accounting statements with a Special Purpose Financial Report, AGLE has accompanied its regulatory accounting statements with a Review Report. Additional operating and maintenance expenditure was allowed for AGLE because the cost of a Special Purpose Financial Report is higher than a Review Report and thus, for AGLE, base level operating and maintenance expenditure may understate the costs of financial audits. However, the Commission noted that it had allowed AGLE to submit its regulatory accounting statements on the same financial year basis as its statutory accounts, rather than on the current calendar year basis. This will enable AGLE to have an audit on its regulatory accounts in conjunction with its statutory accounts, which will offset in part the additional costs associated with a Special Purpose Financial Report. AGLE agreed with the Commission’s approach to this issue and thus the Commission has maintained this approach in its Final Decision. Internal audits CitiPower and Powercor have an internal risk-based audit program where the level of auditing is driven by a fixed percentage of the total work conducted over the network. According to CitiPower and Powercor, the anticipated increase in total workloads over the 2006-10 regulatory period means that additional auditing will be required to maintain the current sample rate to support the risk-based approach. Additionally CitiPower in a confidential submission to the Commission proposed a step change in expenditure for audits and accreditation for the following reasons: • To fund the roll out of its Contractor Performance Management System (CPMS) to the majority of its external suppliers and audit all field projects undertaken by contractors. October 06 232 Essential Services Commission, Victoria Final Decision • Greater competition in the provision of customer contestable works driving the need for an increase in accreditation and quality auditing regimes around contractors hired by customers for these external works. Powercor, also in a confidential submission, proposed a step change in expenditure for audits and accreditation for the following additional reasons: • An increased number of customer works (where customers choose their own contractor, rather than having to use Powercor for the works) undertaken due to revised rules and processes expanding the range of work and simplifying this option for customers. • A requirement by ESV for increased self and independent auditing of new customer connection works. In the Draft Decision the Commission indicated that, with the exception of the customer connection inspections, the Commission did not consider internal audits a step change because it was not considered a new (or changed) function or legislative obligation. The Commission noted that a letter from ESV dated 10 September 2004 indicated that a higher level of inspection of connection works would be required. However, the Commission was of the view that the costs associated with these works are included in the excluded service charge for new connections. The Commission also noted that: • the capital expenditure for new connections included in the Draft Decision was less than that proposed by CitiPower and Powercor and that therefore the audit programme would not need to be expanded at the rate proposed; and • no new (or changed) function or legislative obligation for internal audits was envisaged for the 2006-10 regulatory period. In response to the Draft Decision, CitiPower and Powercor accepted the Commission's view on the costs of customer connection inspections provided that the associated cost was included in its excluded service charge. The Commission notes that these costs would only be included in the excluded service charge if CitiPower and Powercor submit a revised schedule of charges in accordance with Electricity Industry Guideline Number 14, and these revised charges were approved by the Commission. CitiPower and Powercor were of the view that other costs arising from internal audits should be included for the following reasons. • It was consistent with the primary objective of protecting the long term interests of consumers. • It was consistent with the facilitating objective of efficiency and facilitating effective competition. • The Commission’s statement that capital expenditure is lower than proposed was flawed. The physical volume of capital expenditure drives the expansion of audits and accreditation rather than the financial value of that capital expenditure. October 06 233 Essential Services Commission, Victoria Final Decision The Commission remains of the view that this is not a new (or changed) function or legislative obligation and is therefore not considered to be a step change. Additionally the Commission notes that, where there is no new or changed function or legislative obligation but an increase in the volume of work, these additional costs are recovered through the rate of change and the impact of growth. Asset inspections In a late submission prior to the Draft Decision, CitiPower proposed a step change in expenditure to increase the frequency of inspection of low voltage assets and Private Overhead Electric Lines (POELs). CitiPower indicated that ESV had requested that the frequency of inspections be increased following a Bushfire Mitigation Audit in 2004 to ensure that it complied with the Electricity Safety (Bushfire Mitigation) Regulations 2003. The Commission did not include the expenditure for asset inspections as a step change in its Draft Decision, but noted that prior to its Final Decision it would consult with ESV regarding the need for this proposed step change. ESV has confirmed that CitiPower was not compliant with its requirement to inspect POELs every 36 months. However, ESV also noted that there were not many POELs in CitiPower’s area. In these circumstances, the Commission concluded that this was a changed legislative obligation for CitiPower and sought further information from CitiPower (and other distributors) regarding the number of POELs in their respective areas. From the information provided by CitiPower the Commission noted that an additional 156 inspections were required per annum at a cost of $705 per inspection. Given the density of CitiPower’s area, the Commission does not consider this to be a reasonable cost for each inspection, and has reduced the forecast expenditure for this step change from $0.6 million to $0.2 million over five years. Occupational health and safety SP AusNet indicated that WorkSafe Victoria introduced two new requirements in 2004. • First, regulations came into operation, as of 31 March 2004, with the overall objective to prevent incidents at workplaces involving falls of more than 2 metres and to prevent or reduce injury resulting from those falls. SP AusNet estimated that incremental operating and maintenance expenditure of approximately $4.8 million over the 2006-10 regulatory period was required to meet this requirement. • Second, new guidelines were introduced in July 2004 in relation to work practices and procedures that must be followed when working in the vicinity of overhead lines and underground cables. SP AusNet estimated that incremental operating and maintenance expenditure of approximately $2 million would be required over the 2006-10 regulatory period to meet this requirement. In relation to the prevention of falls, SP AusNet has indicated that work is underway to meet the requirements but that further reduction of risk is required. The Commission noted that AGLE has also proposed additional capital expenditure to address this issue. In relation to the guidelines on undertaking work near overhead and underground assets, SP AusNet anticipated increased workloads responding to queries from the Melbourne One Call Centre. October 06 234 Essential Services Commission, Victoria Final Decision SP AusNet also indicated that s. 207 of the Occupational Health and Safety (Asbestos) Regulations 2003 limits the removal of asbestos without a licence. SP AusNet does not currently require a licence to work with asbestos. However, according to SP AusNet, its proposed program of work for zone substations over the 2006-10 regulatory period will require it to obtain an asbestos removal licence. SP AusNet has forecast the incremental cost to current practices of complying with the requirements to maintain an asbestos removal licence at $0.3 million over the 2006-10 regulatory period. In its Draft Decision, the Commission considered this a step change and an amount was included in SP AusNet’s revenue requirement for the related expenditure. The amounts included were adjusted by the Commission based on the advice it had received from Wilson Cook and Co.: • The proposed expenditure to prevent falls ($4.8 million) was reduced by 50 per cent as, based on its experience, it was regarded as being greater than necessary; • The proposed expenditure to automate records of underground lines ($1.5 million) was not included in the expenditure requirement on the basis that this is a process improvement. Process improvements will only be undertaken by a prudent business where the benefits exceed the costs. Given that there is no reduction to reflect the benefits, the costs should also not be included. In response to the Draft Decision, SP AusNet indicated that it did not understand the level of adjustment made and proposed an additional step change of $0.7 million to meet new training requirements which came into effect 1 July 2005. The Commission remains concerned that no other distributors have proposed this change in legislation as a step change for changes to the legislative requirements for occupational health and safety, although it is noted that AGLE has included additional expenditure in its proposed capital expenditure for this reason. There is a potential for double counting by SP AusNet whereby the proposed additional expenditure could be included as a step change and could also be reflected in the proposed capital expenditure. With regard to the proposed expenditure to automate records of underground lines, the Commission notes that a step change in expenditure for each of the distributors to improve the records of underground lines has been included under the cost of safety compliance (Regulation 20). Given the uncertainties associated with this particular proposed step change, the Commission has upheld its Draft Decision. Additionally it has included the amount proposed by SP AusNet for training as a step change. Critical infrastructure protection AGLE, CitiPower, Powercor and SP AusNet forecast additional operating and maintenance expenditure as a result of the apparent increasing threat of terrorism. AGLE, SP AusNet and United Energy also forecast additional capital expenditure to address this issue. CitiPower, Powercor and SP AusNet indicated that the additional expenditure was associated with meeting requirements under the Terrorism (Community Protection) Act 2003. According to October 06 235 Essential Services Commission, Victoria Final Decision these distributors, this Act requires them to establish and implement risk management plans, conduct reviews and audits, take part in exercises and make all improvements necessary to protect the State’s critical infrastructure including the distribution assets. While AGLE did not refer to the Terrorism (Community Protection) Act 2003 in its price-service proposal, it had undertaken reviews of the security of key infrastructure, which led to a number of initiatives to improve the security of key installations. Additional operating and maintenance expenditure was forecast for additional patrols of key infrastructure and remote monitoring of alarms by accredited security service providers. SP AusNet also forecast additional operating and maintenance expenditure to respond to heightened security measures that are foreshadowed following several fatalities in NSW. These measures included communication or public education programs, increased primary security measures (improved fencing, locks etc) and increased detection measures (monitoring alarms, closed circuit television (CCTV) etc). In the Draft Decision, incremental expenditure was included for critical infrastructure protection as the Commission considered that expenditure was required to meet recent legislative obligations that came into effect in 2004. Consequently, the expenditure levels proposed by the distributors were included in the revenue requirements. This followed advice from Wilson Cook and Co that the proposed amounts appeared reasonable. While AGLE accepted the Draft Decision, United Energy identified that the forecast in its initial submission was insufficient for securing critical infrastructure. It proposed $200,000 per annum for increased patrols when the alert level is high and permanent manning for when the alert level is extreme, and $100,000 per annum to prepare risk management plans, audit risk management plan, participate in training exercises, and if necessary, to certify risk management plans. The expenditure proposed by United Energy appears reasonable when compared to the expenditure proposed by the other distributors. The expenditure proposed by each of the distributors to meet its obligations under the Terrorism (Community Protection) Act 2003 has therefore been included in their respective expenditure requirements. Allowance for cost of self-insurance In its price-service proposal, SP AusNet proposed an allowance of $6 million over the 2006-10 regulatory period for the cost of self-insurance of low likelihood high impact risks. SP AusNet claimed that such an allowance would enable it to cover the cost of replacing items damaged as a result of a rare event which was not insured. An example of such an event was a significant bushfire in SP AusNet’s distribution area. In its price-service proposal, SP AusNet referred to recent decisions by the Australian Competition and Consumer Commission and the Independent Pricing and Regulatory Tribunal in NSW to allow self-insurance costs. In its Draft Decision, the Commission noted that there may have been a need to provide for self insurance, however self-insurance could not be considered a step change because it was not linked to a new (or changed) function or obligation. October 06 236 Essential Services Commission, Victoria Final Decision SP AusNet provided a report prepared for it by SAHA International that identified and quantified the self-insured risks. In Chapter 5, the Commission has noted that this report overstates the risks associated with the loss of poles and wires. The report assumed that the amount to be provided reflects the total replacement cost of the poles and wires. However, given that any assets installed will be rolled into the regulatory asset base at the time of the next price review, and given the absence of an efficiency carryover mechanism, the only costs incurred by SP AusNet are the financing costs for a period of approximately two and a half years. With the Commission’s approach to assessing capital expenditure at the aggregate level, the Commission considers that there should be some flexibility for the financing costs associated capital expenditure above the forecast, up to a cap, to also be rolled into the regulatory asset base, based on the circumstances (see Chapter 7). The Commission considers that substantial losses of poles and wires may be a factor that is taken into account by the relevant regulator at the time of the next price review when considering whether these additional financing costs should be rolled into the regulatory asset base. The Commission considers this to be the appropriate approach for dealing with these risks, rather than including additional operating and maintenance expenditure as a step change. SP AusNet was also proposing to self insure for the financial failure of a retailer. However, as noted in Chapter 12, the financial failure of a retailer will be a relevant pass through event in the 2006-10 regulatory period. The Commission does not consider self insurance to be a new (or changed) function or regulatory obligation and has therefore not regarded it as a step change. It should be noted that the base operating and maintenance expenditure has been adjusted upwards for all the distributors for uninsured losses and for Powercor and SP AusNet for the excess on third party claims for bushfire damage. Premature failure of XLPE underground cables In their original price-service proposals, AGLE and Powercor stated that operating and maintenance expenditure would increase over the regulatory period to reflect the projected premature failure of cross linked polyethylene (XLPE) underground cables. Both distributors indicated that the installed XLPE cables would not achieve a 40 or 50 plus year life as anticipated and were now, in many cases, reaching the end of their reliable life after only 20 to 25 years. AGLE and Powercor suggested that the cost impact arises through an increased need to monitor and test the cable condition, and that this cost is expected to increase by approximately $100,000 per annum and $650,000 per annum respectively. Wilson Cook and Co noted that an increase in cable monitoring and testing may have been valid in these circumstances but that it did not meet the definition of a step change. In its Draft Decision, the Commission also considered that this expenditure was not associated with a new (or changed) function or legislative obligation and thus no allowance was included in the revenue requirements for the 2006-10 regulatory period. October 06 237 Essential Services Commission, Victoria Final Decision In response to the Draft Decision, AGLE has withdrawn this as a proposed step change whilst Powercor continues to be of the view that the step change proposed was justified. Its reasons are as follows: • External technical advice confirmed that there was an emerging issue of premature failure of underground cables. • Wilson Cook and Co had acknowledged the legitimacy of the expenditure. • The expenditure was not reflected in the 2004 operating and maintenance expenditure — the program was published in December 2004 and implemented in 2005. • Failure to recognise this expenditure would necessitate inefficient premature replacement of a number of underground cables. The Commission notes that while the distributors identified assets for which additional maintenance was required, the distributors did not identify assets for which maintenance may have been deferred. Additionally the Commission continues to be of the view that this expenditure is not associated with a new (or changed) function or legislative obligation and thus no allowance has been included in the revenue requirements for the 2006-10 regulatory period. SCADA master station upgrade CitiPower purchases SCADA Master-Station services from SPI Powernet to support its control centre functions. It is claimed that SPI Powernet is proposing to upgrade the system in 2007 and is proposing to levy CitiPower $0.49 million for its share of the upgrade cost. Wilson Cook and Co considered this item should be capitalised. However, CitiPower indicated that it can not be capitalised because it is not an asset that it owns. In its Draft Decision, the Commission indicated that it did not consider this a step change because it was not linked to a new (or changed) function or legislative obligation. Further, it was noted that the distributors have identified increases to their operating and maintenance expenditure based on expenditure incurred in years other than 2004, but have not identified reductions to their operating and maintenance expenditure based on expenditure incurred in 2004 but not expected to be incurred in 2006-10. The Commission was of the view that it was reasonable to expect that expenditure increases and reductions would largely net out and thus a step change was not required. Stakeholders did not comment on this issue in their responses to the Draft Decision although in discussions with the Commission CitiPower has noted its concern with the Commission’s Draft Decision. The Commission’s review of CitiPower’s operating and maintenance expenditure incurred in 2004 has resulted in adjustments for any expenditure incurred in 2004 that was not considered to be recurrent (see Chapter 5). It is therefore not reasonable to assume that non-recurrent expenditure incurred in 2004 will offset this proposed expenditure. October 06 238 Essential Services Commission, Victoria Final Decision Additionally the Commission notes that CitiPower’s obligation to pay for the upgrade of the SCADA master station is an obligation placed on it by a third party. If the expenditure was not included in CitiPower’s expenditure requirement, then CitiPower may choose the inefficient option of replicating its own SCADA master station. For these reasons, the Commission now regards this as a changed obligation, and has included the proposed expenditure in the revenue requirement. SPI Powernet augmentation Powercor originally proposed $1.1 million associated with switching and non-capital relocation of existing assets arising from SPI Powernet’s asset replacement program during the 2006-10 regulatory period. At the time of the Draft Decision, the Commission did not have sufficient information available for it to consider this expenditure a step change, although the Commission noted that other distributors had not proposed similar step changes. Since then, the Commission has undertaken a further review of this issue. The expenditure outlined by Powercor was estimated based on the works program proposed by SPI PowerNet. Powercor considered this expenditure a step change because SPI PowerNet had undertaken a very low level of work in Powercor’s area in 2004. Powercor also noted that it was not in a position to know what work programs had been undertaken in other distributors’ areas in 2004 and so could not comment on the reason why other distributors had not proposed a similar step change. In Powercor’s view, the Commission's obligation is to consider expenditure based on actual works being undertaken by Powercor. Since the Draft Decision, SP AusNet has indicated that SPI PowerNet has planned a number of initiatives that will require it to undertake works on its assets at the connection interface. SP AusNet stated that they have agreed to coordinate their respective asset replacement activities to coincide with SPI PowerNet's program, and has proposed a step change of $0.5 million over the 2006-10 regulatory period accordingly. The Commission notes that with the vertical separation in the electricity industry, there is a need to coordinate the works between SPI PowerNet and the distributors. Works at the transmission level are more critical to a reliable and secure electricity supply than the works at the distribution level as more customers are supplied from a single point on the transmission system than the distribution system. SPI Powernet has written to both Powercor and SP AusNet to advise its current plans for works at terminal stations in their area. The letter to Powercor dated 2 August 2005 (as an example) states that: As per usual processes we will require Powercor to coordinate switching, relocation or alteration of its system as required to facilitate these works. … [SPI Powernet] also confirms that any DB relocation costs have not been provided for in their revenue cap. October 06 239 Essential Services Commission, Victoria Final Decision The works undertaken by SPI PowerNet place an obligation on the distributor. The Commission therefore considers that this is a changed obligation imposed on the distributors by a third party and that the expenditure proposed by the two distributors should be incorporated in the revenue requirement. Electricity demand side response In its original price-service proposal, AGLE proposed $0.6 million for negotiating with potential demand side suppliers, developing technical and operating standards, and legal costs associated with entering agreements with demand side suppliers. Wilson Cook and Co regarded the proposed expenditure as prospective and not necessarily related to a new function or obligation as demand management has always been an attribute of efficient utility operation. However, some stakeholders, particularly the Victorian Consumers’ Group, supported additional incentives for the distributors to introduce additional demand side management initiatives. The view was expressed that additional expenditure should be incorporated in the revenue requirement even if there was no guarantee that the distributors will deliver an outcome, given the potential long term benefits to customers if the peak demand is reduced and augmentation costs are reduced. In its Draft Decision, the Commission did not consider expenditure associated with electricity demand side response a step change because it was not linked to a new (or changed) function or legislative obligation. However given the strong views expressed by consumer representatives and the materiality of the expenditure proposed, the Commission incorporated the step change proposed by AGLE in the revenue requirement, and also included the same amount for the other distributors. The Commission indicated that it would require the distributors to report on an annual basis the demand side activities that have been undertaken and the outcomes that have been delivered. While AGLE and United Energy supported the inclusion of expenditure for demand side response, the Department of Sustainability and Environment stated that it was important to ensure that the distributors reported to stakeholders on the success or otherwise of their demand management programs. It suggested that the Commission could establish a demand management consultation group which could invite the distributors to present progress on their demand management programs. The Commission will consider this and notes that there are a variety of forums that could be utilised for presentations by the distributors. No stakeholders opposed the inclusion of this expenditure in the revenue requirement, even if there is no guarantee that the distributors will deliver an outcome. Accordingly, the Commission will include an amount in the revenue requirement for each distributor for negotiating with potential demand side suppliers, developing technical and operating standards, and legal costs associated with entering agreements with demand side suppliers. The Commission will require distributors to report on an annual basis the demand side activities that have been undertaken and the outcomes that have been delivered. October 06 240 Essential Services Commission, Victoria Final Decision Additional step changes proposed by AGLE In its original price-service proposal, AGLE proposed a number of other step changes. These were as follows: • Mobile computing implementation — forecast an additional $2 million to procure ongoing support from the vendor of a new mobile computing system that is planned to be implemented. • Outage management, market and billing systems — forecast an additional $1.9 million to procure ongoing support from the vendor of a new outage management system that is planned to be implemented. • Head Office relocation costs — forecast an additional $0.8 million to relocate its head office when its current lease expires. • Ring fencing — forecast an additional $0.8 million to comply with the Commission’s Draft Decision on ring-fencing. The additional expenditure proposed was for location changes ($0.1 million), training ($0.25 million), reviewing procedures ($0.1 million), compliance auditing ($0.2 million) and IT enhancements ($0.15 million). • Public consultation on various matters — forecast an additional $0.5 million to carry out more customer and stakeholder consultation, particularly in areas such as network pricing and network development. • Sponsorship and marketing — forecast an additional $0.03 million for marketing of multiple supply tariffs to retailers and $0.4 million to fund economic development groups within its area. • Additional EWOV cases — forecast an additional $0.2 million to manage an expected increase in the number of claims raised with EWOV in relation to voltage compensation claims. • Gather and provide data on all public lighting poles — forecast an additional $0.2 million to collect, record and disseminate information on public lighting in accordance with the Public Lighting Code. • Financial report for 2009 regulatory financial information — forecast an additional $0.1 million to provide audited regulatory accounts to the Commission on a calendar year basis in the penultimate year of the regulatory period, in addition to the regulatory accounts submitted on a financial year basis. The Commission requested this financial information as a condition to change the submission of regulatory accounts from a calendar year basis to a financial year basis. Shortly prior to the release of the Draft Decision, AGLE proposed further step changes to reflect the costs associated with changes that had been proposed to the service standards and service incentive arrangements. In its Draft Decision, the Commission considered that only the expenditure associated with ring fencing and the financial report for 2009 regulatory financial information could be considered step changes and linked to new (or changed) functions or legislative obligations. With regard to ring fencing, the Commission noted that it released a ring fencing guideline in October 2004. October 06 241 Essential Services Commission, Victoria Final Decision AGLE’s submissions during the consultation process for that guideline indicated that it did not comply with the proposed requirements. With regard to the financial report for 2009 regulatory financial information, the Commission noted that this was an additional requirement by the Commission to transition from calendar year end reporting to financial year end reporting (consistent with its statutory accounts) for AGLE. With regard to the other items, the Commission considered that many of the proposed expenditure items would already be included in the 2004 base level of operating and maintenance expenditure, and in the case of changes proposed to the service standards and service incentive arrangements, that the proposed changes that AGLE was responding to had not been included in the Draft Decision. Furthermore, any business process improvements which resulted in lower costs will be self financing because the net costs would be expected to be less than those reflected in the revenue requirement. AGLE subsequently withdrew the proposed step changes for each of these step changes except ring fencing, the financial report for 2009 regulatory financial information, and a change to the GSL payments scheme from supply restoration time to annual duration of interruptions. With regard to the change in the GSL payments scheme, it argued that its systems could not provide such information and that $0.1 million was required to amend its systems and $0.11 million per annum was required to administer the GSL payments scheme. The only other comments provided on the Draft Decision regarding AGLE’s various step changes were provided by the Streetlighting Group of Councils who supported the decision to not include the gathering and provision of data on public lighting poles as a step change. The Commission continues to be of the view that the expenditure proposed for ring fencing ($0.8 million) and the financial report for 2009 regulatory financial information ($0.1 million) are considered to be step changes and that the expenditure proposed is reasonable. With regard to the changes to its systems to accommodate the change in the GSL payments scheme, the Commission also considers this to be a change in obligation and thus a step change. Furthermore, the expenditure proposed is reasonable given the current state of AGLE’s systems. However, given the number of GSL payments administered by AGLE, the Commission is of the view that no incremental costs will be incurred by AGLE on an annual basis and the proposed expenditure has not been included as a step change. Additional step changes proposed by SP AusNet Like AGLE, SP AusNet also proposed a number of additional step changes. These were as follows: • Automated B2B — forecast incremental costs of $6.5 million to manage exceptions arising from higher levels of B2B transactions with the new automated systems and processes that are planned. • Distribution Code: Quality of Supply — forecast an additional $2 million for load balancing to address negative sequence compliance under the Electricity Distribution Code. October 06 242 Essential Services Commission, Victoria Final Decision • Utility Meters Act and Regulations — forecast an additional $1.7 million to comply with the requirements of the Utility Meters (Metrological Controls) Act 2002 and associated regulations. • Testing of CTs and VTs — forecast an additional $1.5 million to comply with the CT and VT test requirements in the Electricity Customer Metering Code. • NEMMCO standard for data communications — forecast an additional $0.7 million for costs associated with providing data, in accordance with NEMMCO’s standards, from large wind farms that may be connected during the regulatory period. • OCEI (ESV) levy savings — forecast an operating and maintenance expenditure reduction of $0.8 million to reflect an expected reduction in the OCEI (ESV) levy. In its Draft Decision, the Commission did not include amounts in the operating and maintenance expenditure forecasts for these proposed step changes, with the exception of automated B2B, because they were not linked to new (or changed) functions or legislative obligations. With respect to automated B2B, the Commission noted that it was a new obligation but that it was expected that automated B2B processes would reduce the manual workarounds that were currently being undertaken by the distributors. While SP AusNet may have been incurring capital expenditure in the current period to develop automated B2B processes, the operating and maintenance expenditure incurred in fulfilling these functions should decrease with the new automated processes. To the extent that SP AusNet’s step change related to an increase in exceptions, the Commission expected that these data-related issues would be addressed in the period of time leading up to the implementation of the automated B2B systems. The Commission also noted that no other distributor submitted proposed expenditure for automated B2B processes. In response to the Draft Decision, SP AusNet transferred the proposed step changes for the Utility Meters Act and Regulations and testing of CTs and VTs to the metering price control and withdrew the proposed step changes for the NEMMCO standard for data communications and OCEI (ESV) levy savings. With regard to the other two proposed step changes it made the following comments: • Automated B2B — SP AusNet believed that it was in a unique position compared to the other Victorian distributors. Throughout 2004, it was working with a stapled retailer for the vast majority of its B2B transactions through highly customised and efficient processes built specifically to the requirements of the two ring-fenced parties. From the date of national B2B, this will not be the case and those transactions will pass through national B2B, which by its very nature is a compromise across all market participants that does not suit any party perfectly. While national B2B will be more efficient for the whole market, and will reduce loss of efficiency as the proportion of TRUenergy customers on SP AusNet’s network gradually declines, national B2B will be less efficient than the situation in 2004. • Electricity Distribution Code: Quality of Supply — SP AusNet believed that the decision to exclude expenditure did not reflect the Commission's desire to change current industry practice and adopt a more proactive approach to managing quality of supply compliance. October 06 243 Essential Services Commission, Victoria Final Decision As a result of increased monitoring, it detected Negative Sequence Voltage issues. It proposed: y 36 x 22 kV feeders requiring load balancing y 10 x 22 kV feeders requiring transpositions y 10 x 66 kV lines requiring transpositions, would restore quality of supply within Electricity Distribution Code requirements for 8964 customers. The Commission’s Final Decision on each of these proposed step changes is as follows: • Automated B2B — the Commission notes the concerns raised by SP AusNet, however it also notes that clause 7.4A.4(k) of the National Electricity Rules allows market participants to enter into bilateral agreements between parties so that if the national B2B Procedures introduce inefficiencies, then the affected parties can agree to conduct B2B communications in another way. If the automated B2B arrangements introduce inefficiencies relative to the existing arrangements, to the extent identified by SP AusNet, then the Commission would expect that SP AusNet would explore alternative arrangements rather than adopting the automated B2B arrangements. Accordingly, the Commission is of the view that, whilst the distributors have the choice of accepting this as a new obligation, SP AusNet has the option to continue the status quo. • Electricity Distribution Code: Quality of Supply — the Commission continues to be of the view that this is not a step change as it is not a new (or changed) function or legislative obligation. An efficient distributor would have been undertaking the types of works proposed by SP AusNet such that a step change in expenditure was not required. If an efficiency carryover amount has been obtained for not undertaking these works during the 2001-5 regulatory period, this efficiency gain is not sustainable, and customers should not pay twice (through a step change and through an efficiency carryover amount). Enhanced customer service offerings In their price-service offerings, CitiPower and Powercor proposed “enhanced” offerings for consideration to “deliver additional value to customers”. These enhanced offerings entailed increased operating and maintenance expenditure associated with such areas as: • improved contact centre responses; • improved customer connection times; • ‘new-for-old’ replacement of customer equipment damaged by voltage surges; • increased local community representation; and • increased access to GSL payments for customers receiving worse than average performance. CitiPower proposed an additional $10.8 million in operating and maintenance expenditure to provide these enhanced customer offerings, while Powercor proposed an additional $32.1 million. October 06 244 Essential Services Commission, Victoria Final Decision The additional cost associated with providing ‘new-for-old’ replacement of customer equipment damaged by voltage surges has been considered in the Chapter 2. The additional costs associated with improving customer call centre response, improving customer connection times, and increasing access to GSL payments have been considered in Chapter 3. In relation to increasing local community representation, Powercor proposed an additional $1.1 million over the 2006-10 regulatory period to have a senior company representative visit major regional centres on a rotational basis. These proposed visits aimed to allow customers to meet with the company and hold face-to-face discussions, raise any issues of concern to them and obtain information or assistance on any network or customer service related issues. According to its submission, Powercor conducted customer research which indicated that its rural-based farming and business customers placed a high value on local representation and faceto-face contact. Powercor was of the view that the improved level of service would enhance the level of customer satisfaction for its rural based customers without imposing significant costs upon them. In its Draft Decision, the Commission did not include this expenditure because it did not consider increased local community representation as a step change. Increased local community representation was not a new (or changed) function or legislative obligation. No comments were received on this issue in response to the Draft Decision and CitiPower and Powercor have not included the expenditure in their most recent submissions. Hence, the Commission has not included this expenditure as a step change in the Final Decision. Increased labour costs In their original price-service proposals, the distributors identified that a shortage in the availability of skilled electricity workers would place significant upward pressure on their operating and maintenance costs. Each distributor maintained that there was strong evidence to indicate that a shortage of skilled labour in Victoria will have long lasting impacts on the cost of service delivery, and as a consequence impact the operating and maintenance expenditure trend. • SP AusNet maintained that there was evidence to demonstrate that, as a result of a skills shortage, labour costs would diverge from underlying CPI trends during the next period. The impact of this effect was incorporated in its forecast rate of change. • Powercor and CitiPower stated that the increased demand for skilled labour in the industry, combined with wage movement associated with an ageing workforce, would have a similar impact. This impact was incorporated in their forecast rate of change. • AGLE and United Energy made similar comments, however both treated the increase in real employment costs and additional costs for apprentices and training as a step change. October 06 245 Essential Services Commission, Victoria Final Decision In support of the forecast impacts of a constrained labour market, an assessment of expected external labour rates was commissioned by the distributors and undertaken by KPMG. This study forecast that real wages will increase by 4 to 5 per cent per annum over the period 2004-10.77 The Commission engaged Pacific Economics Group (PEG) to review the KPMG report. PEG had serious concerns with KPMG’s statistical methodology and results. According to PEG (2004, p. 22): … after properly controlling for the effects of inflation, KPMG’s preferred model projects that wages will decline rather than increase in real terms over the 2006-2010 period. A copy of PEG’s report is available on the Commission’s website. In the Draft Decision, the Commission did not include expenditure associated with increased labour costs as a step change because it did not consider this a new (or changed) function or legislative obligation. However, an increase in labour costs was incorporated into the rate of change, and an increase in labour costs associated with capital expenditure was also included in the capital expenditure requirement. Stakeholders did not comment on the Draft Decision treatment of increased labour costs. Consequently, the Commission has maintained this approach in the Final Decision. Impact of industrial action In its original price-service proposal, CitiPower and Powercor claimed that an adjustment to their 2006 base level of operating and maintenance expenditure was required to take account of work deferred from 2004 as a result of industrial action. Industrial action in 2004 reportedly resulted in the loss of 126,000 man-hours and 50,000 man-hours for Powercor and CitiPower respectively, requiring equivalent increases in the base expenditure level of $8.8 million (based on $68.25 per man-hour) and $4.9 million (based on $96.00 per man-hour) respectively. In its Draft Decision, the Commission indicated that it did not consider this a step change because it was not a new (or changed) function or legislative obligation. During Wilson Cook and Co’s review of CitiPower and Powercor’s operating and maintenance expenditure, CitiPower and Powercor indicated that, on resolution of the industrial action after the submission of the price-service proposal, they had deferred some non priority capital works which enabled them to complete the operating and maintenance works planned for 2004. Accordingly, CitiPower and Powercor have withdrawn this proposed step change. Land tax United Energy originally proposed an additional $0.4 million of operating and maintenance expenditure per annum due to increased liabilities for land tax. According to United Energy, additional expenditure was required because of real increases in land tax arising from real 77 This report is available on the Commission’s website http://www.esc.vic.gov.au/electricity832.html October 06 246 Essential Services Commission, Victoria Final Decision increases in land values. United Energy indicated that the increased liabilities were calculated net of any decrease in the rates of land tax applicable from 2005, and were levied on properties it owns and leases. The Commission did not include an allowance for land tax in its Draft Decision because it did not consider it a new (or changed) function or legislative obligation. Increases in expenditure due to land tax would be reflected in the rate of change. The Commission also noted that the State Budget provided some relief from land taxation. In response to the Draft Decision, United Energy accepted the Commission’s Draft Decision and accepted that an allowance for land tax would be included in the rate of change. The Commission has therefore not included an amount for land tax in the revenue requirements for the 2006-10 regulatory period. Reliability investigations Powercor originally forecast additional operating and maintenance expenditure of $0.3 million per annum to monitor and identify areas of poor reliability. Powercor indicated that this was in response to feedback from its customer information sessions. In the Draft Decision, the Commission indicated that it did not consider this a new (or changed) function or legislative obligation. The increased GSL payments and liabilities under the S-factor scheme would provide Powercor with an incentive to identify areas of poor reliability and to improve the reliability where it is efficient to do so. Powercor subsequently withdrew this proposed step change. Therefore the Commission has not included expenditure for this item in the revenue requirement for the next regulatory period. Embedded networks In its original price-service proposal, United Energy included an additional $1 million in operating and maintenance expenditure over the 2006-10 regulatory period associated with uncertain responsibilities in relation to embedded networks.78 According to United Energy, the proposed changes to the regulatory framework for embedded networks place additional responsibilities on the distributor including issuing National Metering Identifiers (NMIs) and metering. In the Draft Decision, the Commission indicated that it did not consider this expenditure was a step change because it was already an existing obligation. 78 Some electricity customers are not directly connected to the distributor's network. They may be connected to a separate network that takes supply from a distributor’s network. A separate network that takes supply from a distributor’s network and resupplies electricity through the separate network to customers is referred to as an embedded network because it is embedded within the distributor's network. Customers supplied in this way are referred to as embedded network customers (examples of embedded networks are caravan parks, retirement villages, shopping centres and high rise apartment buildings). October 06 247 Essential Services Commission, Victoria Final Decision In response, United Energy accepted the Commission’s decision and thus the proposed expenditure has not been included in the revenue requirement. Embedded generation Powercor forecast that an increased number of embedded generators would seek connection to its network during the 2006-10 regulatory period. This was as a result of initiatives by the Victorian Government to facilitate embedded generation, particularly wind farms. Powercor forecast that, as a result of this policy, Powercor would incur an additional expenditure of $0.8 million in negotiating the connection of embedded generators. In its Draft Decision, the Commission did not consider this a step change and noted that a separate cost recovery mechanism exists for costs associated with the connection of embedded generators. Powercor subsequently withdrew this step change. Therefore the Commission has not included expenditure for this item in the revenue requirement for the next regulatory period. Potential retailer liquidation costs In its original price-service proposal, United Energy identified that the success of retail competition in the Victorian electricity market exposed them to an increased risk of retailer liquidation. United Energy claimed that the uncertainty surrounding Retailer of Last Resort (RoLR) arrangements required an additional step increase in operating and maintenance expenditure to mitigate the risk of small retailer failure. Under its original price-service proposal, United Energy provided for $0.5 million in operating and maintenance expenditure associated with the failure of an electricity retailer, and indicated that these costs included the costs of bad debts and the resources required to transact the necessary market obligations. In its Draft Decision, the Commission indicated that it did not consider this a step change because it was not associated with a new (or changed) function or legislative obligation. The treatment of ROLR events is currently the subject of a separate review by the Commission and a pass through for the administration costs associated with a ROLR event was provided for. United Energy accepted the Draft Decision and thus the Commission has not included a step change for a ROLR event. The Commission has maintained the provisions for the pass through of the administrative costs arising from such an event (see Chapter 12). Decision on the step changes Table 6.22 sets out the Commission’s decision on the amounts that will be added to the base operating and maintenance expenditure for each distributor for costs associated with step changes. October 06 248 Essential Services Commission, Victoria Final Decision Table 6.22: Step changes to operating and maintenance expenditure for 2006-10, $million, 2006-10 New functions and legislative obligations AGLE CitiPower Powercor SP AusNet United Energy Total Cost of safety compliance 4.4 5.3 22.2 17.2 9.3 58.4 Electric Line Clearance Regulations 0.4 0.4 2.2 2.2 0.5 5.7 0.0 0.0 Ageing assets Apprentices 0.0 GSL payments scheme 0.1 Road Management Act 1.1 Voltage compensation claims 0.6 0.2 Asset inspections 0.0 0.0 6.4 21.6 1.3 29.4 2.7 5.3 5.8 2.5 17.4 0.3 2.1 1.5 2.5 7.0 Growth related faults Audits and accreditation 0.0 0.0 0.0 0.0 0.0 0.2 0.2 0.2 Occupational health and safety 3.9 Critical infrastructure protection 0.3 1.9 2.9 Allowance for cost of self insurance 3.2 3.9 1.5 0.0 Premature failure of XLPE underground cable 0.0 0.0 SCADA master station upgrade 0.0 0.5 Ring fencing 0.8 Electricity demand side response 0.6 Financial report for 2009 regulatory financial information 0.1 9.8 0.5 0.8 0.6 0.6 0.6 0.6 3.0 0.1 Automated B2B 0.0 0.0 Distribution Code – Quality of Supply 0.0 0.0 0.5 1.5 SPI Powernet augmentation 1.0 System changes for changes to GSL payments scheme 0.1 Total 8.5 0.1 11.8 42.5 56.4 17.9 137.2 Note: Totals may not add due to rounding. October 06 249 Essential Services Commission, Victoria Final Decision The step changes for each distributor are provided, by year, in Table 6.23. Table 6.23: Step changes in operating and maintenance expenditure by year, all distributors, 2006-10, $million, real $2004 2006 2007 2008 2009 2010 Total AGLE 2.0 1.7 1.6 1.6 1.7 8.5 CitiPower 2.3 2.8 2.2 2.2 2.2 11.8 Powercor 8.4 8.5 8.3 8.4 9.0 42.5 SP AusNet 11.6 11.4 11.3 11.0 11.0 56.4 United Energy 4.2 4.1 3.9 3.9 1.8 17.9 October 06 250 Note: Totals may not add due to rounding Essential Services Commission, Victoria Final Decision 7 CAPITAL EXPENDITURE The Commission uses forecasts of capital expenditure as an input into determining the revenue requirement. The capital expenditure forecasts are added to the rolled forward value of the regulatory asset base and from this value the capital financing component of the revenue requirement is calculated (see Chapters 8 and 9). Distributors undertake capital expenditure to, among other things: • augment the capacity of the network to meet demand growth; • replace aged or obsolete assets; • improve the quality and reliability of supply; • meet the requirements of other regulators such as Energy Safe Victoria (ESV) and the Environmental Protection Agency (EPA); and • purchase non-network assets (for example, buildings and vehicles) for normal business purposes. The capital expenditure forecasts that are established by this price review do not represent amounts of money that the distributors are required to spend. Under the Commission’s incentivebased framework, the distributors are given incentives to increase their returns by meeting their service and regulatory obligations at lower cost. Customers benefit from these efficiency gains over the longer term through lower real prices. The Commission’s Final Decision on the capital expenditure forecasts represents an increase of 30 per cent above historic capital expenditure levels.79 The Commission considers these forecasts provide sufficient financing capacity for the distributors to continue to meet their service obligations during the 2006-10 regulatory period and over the longer term. That is, the forecasts will provide sufficient financing capacity for the distributors to: • maintain and improve service levels in line with the targeted service levels set out in Chapters 2 and 3; • continue to meet their obligations to a growing customer base; and • meet a range of new service obligations and functions. The forecasts reflect the Commission’s view on the cost of meeting these service obligations at this time. 79 30 per cent above historic gross capital expenditure levels and 45 per cent above historic net capital expenditure levels. This comparison is based on the capital expenditure in 2001-05, with the expenditure in 2005 being assumed to be the average of the expenditure over the 2001-04 period. October 06 251 Essential Services Commission, Victoria Final Decision This Chapter sets out the Commission’s Final Decision on the capital expenditure forecasts that will be used in determining each distributor’s revenue requirement for the 2006-10 regulatory period and the reasons for the decisions it has made. 7.1 Final Decision The Commission’s Final Decision on the capital expenditure forecasts that have been used to determine each distributor’s revenue requirement is set out in Tables 7.1, 7.2 and 7.3. Table 7.1: Capital expenditure by asset category, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNeta United Energy Reinforcements 41.6 100.2 167.7 94.9 83.3 New customer connections 80.0 139.1 268.9 261.5 106.4 Load Movement 0.0 20.1 0.0 0.0 0.0 Reliability & quality maintained 41.1 133.6 268.8 162.7 190.6 Reliability & quality improved 0.0 0.0 19.1 24.2 4.8 Environmental, safety and legal 18.5 38.8 78.0 98.2 52.5 SCADA/Network control 9.4 6.2 15.4 25.4 0.0 Non-network assets – IT 29.4 43.1 55.8 25.9 52.9 Non-network assets – other 12.8 5.6 52.6 1.4 12.4 Total gross capex 232.8 486.5 926.4 694.2 503.0 Customer contributions 22.6 28.8 130.4 66.4 20.3 210.2 457.8 795.9 627.8 482.7 Total net capex a Note: May not add due to rounding. Formerly TXU Table 7.2: Capital expenditure (gross) by year, all distributors, 2006-10, $million, real $2004 2006 2007 2008 2009 2010 Total AGLE 50.7 44.3 46.6 41.9 49.3 232.8 CitiPower 101.3 96.7 95.3 104.6 88.7 486.5 Powercor 171.8 186.2 190.4 187.6 190.3 926.4 SP AusNet 139.3 132.8 133.9 140.1 148.2 694.2 United Energy 101.1 95.0 95.5 102.1 109.4 503.0 Note: May not add due to rounding. October 06 252 Essential Services Commission, Victoria Final Decision In addition, the extent a distributor incurs additional capital expenditure which is above that included in the revenue requirement (excluding expenditure associated with reliability improvements or Melbourne’s CBD security of supply project) but is at or below the applicable expenditure cap set out in Table 7.3, it may have the financing costs associated with that higher level of capital expenditure rolled into the regulatory asset base in 2011. However, the decision on whether to permit the roll-in of this expenditure is ultimately one that is at the discretion of the relevant regulator at that time based on the circumstances that give rise to the additional expenditure. Table 7.3: Capital expenditure (gross) compared to historic expenditure, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Total Historic expenditure (2001-04)a 179.1 374.2 712.5 533.9 386.9 2,186.6 Variance (2006-10) 53.7 112.3 213.9 160.3 116.1 656.4 Expenditure requirement (2006-10) 232.8 486.5 926.4 694.2 503.0 2,843.0 Expenditure cap (2006-10) 289.5 559.5 964.9 768.8 565.3 3,148.1 a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure is divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). The expenditure proposed by CitiPower to improve the security of supply in Melbourne’s CBD has been excluded from the expenditure requirement. The Commission will consult on the appropriate planning standard for the Melbourne CBD area, the appropriate project to meet this planning standard and the way in which the expenditure will be recovered from customers. If the outcome of the consultation process leads to a change in the Electricity Distribution Code, the expenditure determined through that process will a pass through (see Chapter 12 and clause 5 of Volume 2). This mechanism will allow CitiPower to recover the estimated expenditure for the CBD security of supply project finalised as a result of that process, should it proceed. Additionally, should it proceed, the Commission will require separate reporting of the expenditure associated with this project in CitiPower’s regulatory accounting statements and will exclude this expenditure from out-turn expenditure for the purposes of assessing historic expenditure in this category in future price reviews. The distributors have different capitalisation policies. As a result some distributors have a higher proportion of expenditure that is capitalised relative to others. The Commission’s Final Decision on the total expenditure forecasts that have been used to determine each distributor’s revenue requirement is set out in Table 7.4 to enable the total expenditure to be compared across distributors. October 06 253 Essential Services Commission, Victoria Final Decision Table 7.4: Total expenditure, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Operating expenditure 260.1 177.1 595.6 561.8 419.3 Gross capital expenditure 232.8 486.5 926.4 694.2 503.0 Total expenditure 493.0 663.6 1521.9 1256.0 922.3 Note: May not add due to rounding. 7.2 Reasons for the Decision At the time of the last price review, the distributors’ proposed levels of expenditure for the 200105 period were substantially higher than the average rate of expenditure for the 1996-99 period. The proposed increases ranged from 26 per cent (Powercor) to 54 per cent (SP AusNet80) and the final benchmarks established represented a substantial increase over historic expenditure levels, although they were lower than the distributors’ proposals. The forecast increase in capital expenditure was attributed to growth in demand and customer numbers, improved quality and reliability of supply, an increasing requirement to replace aged assets, the costs of full retail competition, compliance with safety regulations and reduced up-front contributions by customers to the costs of connection (ORG 2000a, p. 48-49). This projected increase in capital expenditure did not eventuate. Instead, the level of capital expenditure that has been undertaken over the 2001 to 2004 period has been closer to the levels of capital expenditure undertaken in the 1995 to 2000 period (see Figure 7.1). At the same time, most distributors have generally maintained or improved service levels despite higher growth in customer numbers than forecast. 80 Formerly TXU October 06 254 Essential Services Commission, Victoria Final Decision Figure 7.1: Total gross capital expenditure, industry aggregate, actual and benchmark capital expenditure 1996-04, $million, real $2004 600 500 $million 400 300 200 100 0 1996 1997 1998 1999 2000 2001 Benchmark 1996-2005 Gross CAPEX 2002 2003 2004 2005 Actual Gross CAPEX The fact that capital expenditure has been lower than forecast may be due to a combination of factors: • efficiency gains achieved over the period; • the deferral of capital expenditure projects between regulatory periods; • changes in external drivers of expenditure, for example lower than anticipated peak demand; and/or • the overstatement of capital expenditure requirements at the time the previous benchmarks were set. 7.2.1 Commission’s objectives In assessing a reasonable level of capital expenditure, the Commission must have regard to its objectives under the Essential Services Commission Act 2001, particularly its primary objective to protect the long term interests of Victorian consumers with regard to the price, quality and reliability of electricity distribution services. It must also have regard to its facilitating objectives including to facilitate efficiency in the electricity distribution industry and the incentive for efficient long-term investment, and to facilitate the financial viability of the electricity distribution industry. The challenge associated with this balance was recognised by the Productivity Commission. In its Review of the National Access Regime, the Productivity Commission (PC 2004, p. 102): October 06 255 Essential Services Commission, Victoria Final Decision considered the tradeoff between regulatory errors that overcompensate service providers and those that undercompensate. Regulatory error that undercompensates service providers could discourage investments of considerable benefit, with flow-on effects for investment in related markets. On the other hand, regulatory error that overcompensates service providers distorts decision making. The Commission considered that both types of regulatory error are likely to distort investment and have adverse efficiency implications. If the capital expenditure forecast overcompensates the distributor, then customers will pay more than they otherwise would and the distributor will earn higher returns. If the capital expenditure forecast undercompensates the distributor, then the distributor may not invest in the network and this will impact on the long term reliability of the network. The regulatory framework in place encourages the distributors to meet their obligations more efficiently and thus outperform the Commission’s forecasts. Distributors are able to retain the benefits of any out-performance against the forecasts for the length of the regulatory period. Conversely, if distributors undertake a level of capital expenditure that is higher than that forecast, the initial financing costs of this investment will not be recoverable although the actual capital expenditure is rolled into the regulatory asset base at the following regulatory reset. This is not expected to be a significant issue because any investment greater than the annual profile would be expected to occur towards the end of the regulatory period. This is particularly so where the profile of investment in the forecasts includes a ‘step change’ in expenditure rather than a gradual increase.81 In this case, any additional financing costs will only be incurred over a relatively short period. Distributors will not be able to carryover any efficiency gains associated with capital expenditure efficiencies achieved during the 2006-10 regulatory period into the 2011 regulatory period (see Chapter 10). However, the removal of the efficiency carryover mechanism on capital expenditure incurred in the 2006-10 regulatory period also means that distributors will receive no penalty through this mechanism from spending more than forecast. Further, they will most likely benefit in subsequent regulatory periods by earning a return on an increased asset base. The increased incentive rates in the service incentive scheme for the 2006-10 regulatory period will provide a greater incentive for the distributor to undertake economically efficient projects to improve reliability (see Chapter 3). Given the differential between the existing incentive rates and the new incentive rates, the Commission expects that the distributors will have a significantly enhanced incentive to identify projects that will be funded through the service incentive scheme at a much higher rate than the cost of the project. There will therefore be greater opportunities for the distributors to profit through the service incentive scheme. The Commission considers that the opposing incentives to underspend relative to the forecasts to increase returns, and to not underspend relative to the forecasts so as to avoid incurring the increased penalties for deteriorating performance under the service incentive mechanism, will provide the appropriate disciplines on the distributors to ensure that investment is efficient and effective in delivering service outcomes. 81 The increase in gross capital expenditure from 2004 to 2006 is 47 per cent from AGLE, 30 per cent for CitiPower, 11 per cent for Powercor, 10 per cent for SP AusNet and 32 per cent for United Energy. October 06 256 Essential Services Commission, Victoria Final Decision 7.2.2 Framework and approach Given that capital expenditure has remained at similar levels over the last 10 years, the Commission’s approach to assessing the distributors’ proposed capital expenditure levels in this price review has been to place emphasis on past levels of capital expenditure as a starting point for determining the efficient levels of future capital expenditure. To this end, the Commission began its analysis of the distributors’ proposals by comparing each distributor’s proposed capital expenditure with the level of average capital expenditure undertaken during the 2001-04 period. In arriving at its Final Decision, the Commission has also reflected on the experience and behaviour of the distributors in response to the incentives under the regulatory framework. This includes recognising the incentive the distributors have to over-estimate their expenditure at the time of a price review to maximise their revenue requirement. In doing so, the distributors are able to benefit under the regime without achieving efficiencies, as the estimates are greater than what is actually required from the outset of the next regulatory period. In this regard, the Commission notes that the distributors’ capital expenditure proposals for the 2006-10 regulatory period are considerably higher than the level of expenditure undertaken in the 2001-04 period (see Figure 7.2). Figure 7.2: Total gross capital expenditure, industry aggregate, actual capital expenditure 1996-04,a distributor forecast 2005 and distributor proposal 2006-10, $million, real $2004 900 800 700 600 500 $M 400 300 200 100 0 1996 1997 1998 1999 2000 Actual capex (inc meters) a 2001 2002 2003 2004 DB proposed CAPEX (ex meters) 2005 2006 2007 2008 2009 2010 DB proposed CAPEX (inc meters) Out-turn gross capital expenditure includes prescribed distribution use of system and metering costs. As set out in the Position Paper, the Commission was of the view that establishing a starting point for expenditure levels through the use of trend analysis (based on out-turn information) is the most effective means to assess the reasonableness of expenditure claims. Whilst trends cannot be completely determinative of future requirements, they do provide a reasonable basis October 06 257 Essential Services Commission, Victoria Final Decision for assessing variations in capital expenditure for the 2006-10 regulatory period compared to history. Given the incentives that distributors have to over-state their future capital expenditure requirements, the Commission also considered that it was appropriate to apply considerable discipline on the distributors to support their expenditure proposals. For this reason, the Commission believed that any assessment of future capital expenditure should take into account historic levels of capital expenditure, with variations from such historic levels being supported by cogent reasons. It was for this reason that the Commission identified the need for distributors to provide it with their asset management plans and strategies. This information was sought to assist the Commission to identify the need for, and the distributors’ ability to implement, the expenditure associated with capital works outlined in the distributors’ proposals for the 2006-10 regulatory period. In the course of this price review, some distributors have criticised the Commission’s use of historic information. United Energy (2005c, p. 22-23) stated that the Commission’s approach was ‘flawed’ and that: The Commission’s predecessor also encouraged the distributors to think that actual capital expenditure “revealed” in one period would not be used as a basis for setting future benchmarks. However, the Commission notes that, in the last price review, the Office of the RegulatorGeneral (ORG) decided that it would take the distributors’ historic and forecast costs of delivering an electricity distribution service as its starting point when setting the 2001-05 benchmarks (ORG 2000a, p. 47). 7.2.3 Distributors’ proposed capital expenditure The distributors have proposed gross capital expenditure of $3.4 billion over the 2006-10 regulatory period, compared to historic expenditure over the 2001-04 period (expressed on a five year basis) of $2.2 billion. The distributors’ submissions are summarised by asset category in Table 7.5 and by year in Table 7.6. October 06 258 Essential Services Commission, Victoria Final Decision Table 7.5: Capital expenditure forecasts by asset category, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Reinforcements 71.5 157.4 183.9 125.3 103.5 New customer connections 83.5 172.7 265.6 335.9 101.2 Load Movement 0.0 23.0 0.0 0.0 0.0 Reliability & quality maintained 74.5 153.3 282.4 185.7 233.6 Reliability & quality improved 1.3 0.0 41.9 27.2 5.4 Environmental, safety and legal 33.5 40.2 76.7 102.7 84.6 SCADA/Network control 14.0 6.9 16.2 28.9 0.0 Non-network assets – IT 43.7 41.1 77.9 11.7 60.9 Non-network assets – other 22.2 6.5 56.0 1.6 14.7 Total gross capex 344.1 601.0 1,000.6 819.0 603.9 Increase in gross capex relative to historic expenditure 92% 61% 40% 53% 56% Customer contributions 23.6 35.6 128.8 95.8 19.3 320.5 565.4 871.8 723.1 584.6 Total net capex a Note: May not add due to rounding. Most likely expenditure based on exemptions to the Electricity Safety Regulations. AGLE does not support this scenario and remains of the view that more expenditure is required for the distributors to comply with the Regulations within the 2006-10 regulatory period. Table 7.6: Capital expenditure (gross) forecasts by year, all distributors, 2006-10, $million, real $2004 2006 2007 2008 2009 2010 Total AGLE a 68.4 70.1 69.3 62.2 74.1 344.1 CitiPower 114.3 115.9 120.3 134.0 116.40 601.0 Powercor 187.3 202.7 205.7 202.1 202.8 1,000.6 SP AusNet 149.3 159.2 161.0 170.1 179.4 819.0 United Energy 121.9 118.7 114.4 121.0 128.0 603.9 a Note: May not add due to rounding. Most likely expenditure based on exemptions to the Electricity Safety Regulations. AGLE does not support this scenario and remains of the view that more expenditure is required for the distributors to comply with the Regulations within the 2006-10 regulatory period. According to the distributors’ price-service proposals, the forecast increase in capital expenditure is being driven by an increase in reinforcement and replacement expenditure, new customer connections and environmental, safety and legal requirements. CitiPower also proposed additional capital expenditure of $50.4 million (including capitalised indirect overheads) to upgrade the security of supply to the Melbourne CBD. In the Position Paper, the Commission expressed its concern regarding the increases in the proposed expenditure relative to the historic levels. The concern was that: October 06 259 Essential Services Commission, Victoria Final Decision On reviewing the historic trends in capex and the distributors’ capex forecasts, the Commission is not convinced that the distributors’ forecasts of expenditure are more appropriate than assessing variations to trend as outlined in its Framework and Approach. The Commission therefore maintains the view that its Final Framework and Approach will provide an appropriate balance between adequate investment in the networks (particularly in the light of improved and maintained reliability over the past period) and ensuring customers pay no more than is required for efficient investment. (ESC 2005a, p. 71) The challenge associated with the distributors overstating their requirements together with the asymmetry of information is recognised widely by regulatory bodies and approaches have been developed to address it. Ofgem faced similar issues to those faced by the Commission with substantial increases in proposed capital expenditure relative to historic trends, and similar incentives for the distributors to overstate their requirements. It therefore introduced a ‘sliding scale’ mechanism that sets the allowed expenditure and efficiency incentive based upon a ratio of the distributor’s proposed expenditure to a benchmark established for Ofgem by PB Power (Ofgem 2004b). Such a mechanism aims to address the situation where a distributor proposes more expenditure than required and benefits through the period when it spends less because of the overestimation rather than through the achievement of efficiency gains. The principles and objectives of the Ofgem scheme are to: • retain an incentive for efficiency throughout; • reduce the emphasis on Ofgem’s or its consultant’s view of the appropriate level of capital expenditure; • reduce the perceived risk that the price control causes under-investment; • allow but not encourage overspend (expenditure in excess of the ‘allowance’); • reduce the possibility of ‘high’ capital expenditure distributors making very high returns from underspend; • reward the ‘low’ capital expenditure distributors if they deliver what they propose; and • avoid strong incentives to underspend by cutting corners and not delivering outputs or by storing up problems for subsequent periods. The regulator in Queensland (the Queensland Competition Authority) was faced with similar concerns regarding substantial increases in capital expenditure proposed by Energex, in particular, and its ability to deliver the proposed capital works program given the state of its workforce planning. QCA allowed 80 per cent of the capital expenditure proposed by Energex and introduced a mechanism to pass through additional capital expenditure if it could be demonstrated that it was required to meet minimum service standards. Whilst the Commission’s preferred approach was to assess the distributors’ proposals using its stated framework and approach, the Commission indicated that it would consider the inclusion of a ‘sliding scale’ type mechanism in the price controls, similar to that developed by the UK October 06 260 Essential Services Commission, Victoria Final Decision regulator (Ofgem), if this was the means required to achieve outcomes consistent with its Final Framework and Approach. However, the Commission was satisfied that the Draft Decision was consistent with its Final Framework and Approach and it did not need to further consider the introduction of a ‘sliding scale’ type mechanism. 7.2.4 Review of the distributors’ proposals Wilson Cook and Co was engaged to assist the Commission in reviewing the variations in capital expenditure proposed by the distributors relative to historic expenditure, and their asset management processes. Wilson Cook and Co was required to: • assess whether the distributors’ proposed expenditure would provide appropriate service outcomes for Victorian electricity customers for the least cost; • assess the information provided by the distributors to support variations from the historic trend in capital expenditure; and • report on the links between capital expenditure, operating and maintenance expenditure and the distributors’ asset management plans (Wilson Cook and Co 2005, p. 123). In assessing the reasonableness of the distributors’ proposed capital expenditure, Wilson Cook and Co had regard to the Commission’s framework and approach. It therefore adopted a threepart approach to the review of the distributors’ capital expenditure proposals: (a) we compared the average annual levels of capex during the current period with those proposed for the next; (b) we examined the reasons given for the distributors’ capex proposals (including a review of trends in reinforcement and replacement capex and a high-level examination of the main factors or projects that made up their projections); and (c) as a final step, we reviewed the reasonableness of the overall level of capex proposed by each distributor. (Wilson Cook and Co 2005, p. 8) Wilson Cook and Co produced a report prior to the Draft Decision, which identified a number of specific instances where it considered the distributors’ proposals to be overstated and recommended corresponding downward adjustments. In arriving at its Draft Decision on the capital expenditure set out in the distributors’ priceservice proposals, the Commission had regard to: • the distributors’ proposed capital expenditure under each asset category; • the relationship between the proposed capital expenditure and historic expenditure; • the information that the distributors had provided in support of their proposals and the reasons they provided for the variation in expenditure; • the opinion of Wilson Cook and Co; and • the comments and information provided by other stakeholders. October 06 261 Essential Services Commission, Victoria Final Decision Having had regard to the facts before it at that time, the Commission was generally of the view that Wilson Cook and Co’s recommendations were reasonable, but considered that a number of further adjustments were required to appropriately reflect labour cost escalation, the level of capitalised indirect overheads, and the removal of capital expenditure to improve reliability as this was to be provided through the service incentive mechanism (refer Chapter 3). The Draft Decision on capital expenditure, with a comparison to historic expenditure, is set out in Table 7.7. Table 7.7: Draft Decision on gross capital expenditure, all distributors, $million, real $2004 Historic expenditurea Draft Decision Increase relative to historic expenditure AGLE 179.1 236.6 32% CitiPower 374.3 403.2 8% Powercor 712.5 765.7 7% SP AusNet 534.0 623.6 17% 386.9 465.2 20% United Energy a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period) In their submissions to the Draft Decision, the distributors criticised Wilson Cook and Co’s report and the way in which the Commission had relied upon this report. For example: AGLE believes that, because of: y The obviously inappropriate outcomes of the adjustments recommended; y The errors in the high level assessment of a reasonable level of CAPEX which is used to justify the overall adjustments recommended; and y The qualitative, confused and superficial nature of the analysis of the individual expenditure categories, the Commission would be making a significant error if it placed much weight on the recommendations of the Wilson Cook report. (AGLE 2005f, p. 53) Similarly CitiPower (2005i, pp 10-11) and Powercor (2005u, pp10-11) were of the view that: The Commission does not have unfettered discretion in relation to the methodology it uses to determine capital expenditure allowances. Indeed, the Commission’s methodology for capital expenditure must produce outcomes and/or incentives that are consistent, inter alia, with the Commission’s primary objective and efficiency-related objectives. … The Commission’s Draft Decision fails to provide for an efficient level of capital expenditure, because it has relied extensively on advice from Wilson Cook that is, itself, factually flawed. October 06 262 Essential Services Commission, Victoria Final Decision In response to the Draft Decision, further meetings were held between the Commission and Wilson Cook and Co, and the distributors, and some distributors provided additional information. Additionally, three of the five distributors revised their capital expenditure proposals downwards. Wilson Cook and Co and the Commission reviewed the additional supporting information provided by the distributors, including their submissions to the Draft Decision. Wilson Cook and Co reported to the Commission on the impact of the additional information on the opinions it expressed in its original report. It has quantified the consequential adjustments where possible, and relied on professional judgement otherwise. This report (which is contained in a letter to the Commission) is available on the Commission’s website. In particular, in response to the comments from the distributors regarding its assessment of a reasonable level of overall expenditure, Wilson Cook and Co has made a number of amendments to its analysis. On the basis of this revised analysis, the distributors’ proposed capital expenditure, with a limited number of adjustments recommended by Wilson Cook and Co, was considered by Wilson Cook and Co to be reasonable, and the level of historic capital expenditure was considered to be below a reasonable level. Wilson Cook and Co’s recommended that increases for the distributors of between 31 per cent and 66 per cent in gross capital expenditure (excluding indirect capitalised overheads and labour cost escalation) relative to historic gross capital expenditure could be supported. However, Wilson Cook and Co (2005b, p. 3) has indicated in its report that there are a number of matters which the Commission will need to review for the purpose of making the appropriate adjustments. These matters are: • capital expenditure for electrical safety compliance; • capitalised indirect overheads; • labour cost escalation incorporated in the capital expenditure; • capital expenditure to maintain reliability and quality; and • in CitiPower’s case, the proposed expenditure for the CBD security of supply project. After the Commission’s review and adjustment for these matters (see Section 7.2.9), the resulting increases in the capital expenditure for the distributors would be between 35 per cent and 62 per cent relative to historic gross capital expenditure. This compares to increases for the distributors of between 7 per cent and 32 per cent relative to historic gross capital expenditure in the Draft Decision. In short, if all Wilson Cook and Co’s recommendations are adopted, this would result in levels of capital expenditure for 2006-10 that are at a significantly higher level than has been experienced since privatisation. A reconciliation between the Draft Decision on gross capital expenditure and the forecast gross capital expenditure at the asset category level, following the review by Wilson Cook and Co and October 06 263 Essential Services Commission, Victoria Final Decision the Commission’s adjustments for labour cost escalation and other matters, is provided in Table 7.8. Table 7.8: Reconciliation of gross capital expenditure, all distributors, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Draft Decision 236.6 403.2 765.7 623.6 465.2 Increase relative to historica 32% 8% 7% 17% 20% Change in Wilson Cook and Co adjustment since Draft Decision 69.7 121.9 277.9 76.2 136.6 Change in distributor’s proposal since Draft Decision -1.7 -43.4 -179.8 -0.3 -43.1 Other changes since Draft Decision b -15.0 77.7 101.1 69.3 6.6 Forecast at asset category level (based on Wilson Cook’s further report) 289.6 559.5 964.9 768.8 565.3 Increase relative to historica 62% 49% 35% 44% 46% Note: May not add due to rounding. a Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). b Other changes includes, for example, changes in labour cost escalation, changes in capitalised indirect overheads, and removal of capital expenditure for reliability improvements. The movement in the other changes between the Draft Decision and the Final Decision is largely as a result of the distributors revising their requirements which offset adjustments made in the Draft Decision. Notwithstanding its review of the detailed information provided by the distributors, Wilson Cook and Co (2005b, p. 5) has indicated in its report that areas of subjectivity remain where judgement is required to be exercised, for example: • the weighing-up of costs and benefits; • the treatment of provisions for future expenditure that may not arise; and • the treatment of projected expenditures in circumstances where deferral to a later period is possible. The Commission also notes that the scope of work undertaken by Wilson Cook and Co did not require them to: • consider the Commission’s objectives, including forming a judgement as to the appropriate balance of interests between the distributors and customers; • consider the workings of the incentive-based regulatory framework, including the operation of the efficiency carryover mechanism and the service incentive mechanism; or • make a judgement as what the distributors will actually spend. October 06 264 Essential Services Commission, Victoria Final Decision It is ultimately the Commission’s responsibility (as the regulator) to make these judgements and determine the expenditure allowances that are to be included in the forward looking revenue requirements, having regard to these things, among others. In discharging this responsibility, the Commission will, of course, have regard to the advice of its technical consultants, as well as to all other relevant information (such as the submissions of the distributors and other stakeholders. However, it is not obliged to simply adopt the views or of any other stakeholder, in fulfilling its functions. On the contrary, it must form its own view on these matters, taking into account all relevant information. The Commission is concerned that the aggregate level of capital expenditure recommended in the further report by Wilson Cook and Co (2005b) is not reasonable given the task that would confront the distributors in delivering the capital works programs implied in the expenditure forecasts with the resource constraints identified in their price-service proposals. 7.2.5 Aggregate level of capital expenditure In its Position Paper, the Commission noted that the trend in historic expenditure was more evident at the aggregate level of capital expenditure rather than at an asset category level: The Commission maintains the view that the trend in capex continues to be an appropriate starting point for considering each distributor’s capex forecasts for the 2006-10 regulatory period. The Commission notes that capex at a disaggregated level may be lumpy, but exhibits a trend at an aggregated level (ESC 2005a, p. 58). Wilson Cook and Co (2005, p. 16) also considered that it was reasonable to assess capital expenditure at the aggregated level. In its earlier report it commented that: Some distributors proposed a ‘bottom-up’ estimate of capex requirements instead of the use of past trends. However, ‘bottom-up’ estimates – those prepared when project-byproject analyses are undertaken as part of conventional network planning and asset management planning exercises – tend to over-estimate capex requirements. Thus in our view it is still necessary to consider the reasonableness of the overall level of capex proposed. Furthermore Wilson Cook and Co (2005, p. 14) stated that: Although each individual capex project or programme may be justified when considered in isolation, it is still necessary that the aggregated expenditure projection of each distributor be reasonable. When the expenditure is considered in aggregate, overlaps in projects are identified, and projects are prioritised to reflect the resource (labour, machinery and financial) constraints. This is similar to the budgeting process within a large organisation where the individual budgets of business areas tend to be reduced when aggregated at the company level as the needs of the organisation are prioritised. October 06 265 Essential Services Commission, Victoria Final Decision As a result of this prioritisation process, projects may be delayed or deferred. The level of preparation of the projects and programmes we reviewed was appropriate for planning purposes, recognising that plans do not constitute, by themselves, a justification for proceeding with work until detailed studies have been prepared and the relevant criteria met. In this context it is normal for some work to be advanced later on, for other work to be deferred, for some to be amended and for other items to be dropped altogether. (Wilson Cook and Co 2005, p. 14) In its earlier report Wilson Cook and Co checked the adjustments recommended at the asset category level by assessing the reasonableness of the resultant expenditure proposals in aggregate. The approach adopted for this reasonableness check was to (1) estimate the replacement cost of the asset base, and (2) compare the capital expenditure as a proportion of the replacement cost of the asset base to the rate of replacement of the asset base (2 per cent based on an average life of 50 years) and the rate of growth in energy consumption. Wilson Cook and Co made further adjustments to the capital expenditure proposals where the capital expenditure did not appear to be reasonable at the aggregate level. These adjustments at the aggregate level were not incorporated by the Commission into its Draft Decision, principally because they were not material relative to the other adjustments recommended by Wilson Cook and Co. Wilson Cook and Co’s approach to checking the reasonableness of the capital expenditure at the aggregate level was criticised by the distributors on the basis that: • the replacement cost of the asset base had been underestimated; • in rolling forward the asset base, an inappropriate index was used; and • the appropriate measure of growth is peak demand rather than energy consumption. Wilson Cook and Co therefore amended its analysis in its further report (2005b, p. A30) which increased the reasonable range of capital expenditure indicated by this approach. It concluded that (Wilson Cook and Co 2005b, p. 4): The [reasonableness] test leads to the conclusion that the companies’ revised expenditure proposals, after our revised adjustments, cannot be considered unreasonable when tested by this measure. The reasonable range, as determined using Wilson Cook and Co’s analysis, expressed relative to historic expenditure is provided in Table 7.9. October 06 266 Essential Services Commission, Victoria Final Decision Table 7.9: Comparison of average annual historic gross capital expenditure with Wilson Cook and Co’s reasonable range (based on peak demand growth), all distributors, $million, real $2004 Historic expenditurea Reasonable range Increase in historic expenditure – low end of range Increase in historic expenditure – mid point of range Increase in historic expenditure high end of range AGLE 35.8 37 - 55 3.4% 28.5% 53.6% CitiPower 74.9 64 – 95 -14.3% 6.4% 27.2% Powercor 142.5 152 - 228 6.3% 32.9% 59.4% SP AusNet 106.8 119 - 178 11.4% 39.0% 66.6% United Energy 77.4 98 - 148 26.6% 58.9% 91.2% Note: May not add due to rounding. a Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). Table 7.9 indicates that the range considered by Wilson Cook to be reasonable is extremely broad. It also indicates that an increase in gross capital expenditure of at least 27 per cent relative to historic expenditure is required to ensure that all of the distributors are within Wilson Cook and Co’s reasonable range when the range is calculated based on peak demand growth. The Commission also notes that, when the reasonable range is calculated based on peak demand growth, Wilson Cook and Co’s recommendations place the forecast capital expenditure for AGLE and CitiPower at the high end of the reasonable range, and for Powercor, SP AusNet and United Energy towards the mid point of the reasonable range. If the reasonable range is calculated based on energy consumption growth, consistent with Wilson Cook and Co’s earlier report, then the forecast capital expenditure with Wilson Cook and Co’s recommended adjustments is towards the high end of the reasonable range for SP AusNet, and above the high end of the range for the other distributors. 7.2.6 Implementation of capital works programs An issue for consideration by the Commission is whether the distributors will actually spend the forecast capital expenditure, particularly where it is a significantly greater level of expenditure than the historic expenditure. Distributors have no obligation to undertake the capital works programs that underpin their proposals for capital expenditure. Instead, subject to meeting required service standards, the incentive-based regulatory framework encourages distributors to defer the capital works and benefit from the avoided financing costs. Additionally, the distributors may not have the labour resources to undertake an increased capital works program. In their price-service proposals, the distributors identified concerns regarding the October 06 267 Essential Services Commission, Victoria Final Decision shortage of skilled labour in the electricity industry. For example, CitiPower (2004e, pp 77-79) noted that: • Skill imbalances take some time to resolve, as entry into electricity distribution field work requires a four year apprenticeship to be undertaken, and a further two years of on-job training and experience. • The shortage of new skilled labour is exacerbated by the fact that 40 per cent of tradespeople currently in the electricity sector are aged 45 years or more. An ageing workforce impacts on labour productivity through increases in time taken to complete tasks and/or inability to undertake more strenuous activities. • The demand for labour resources in Victoria will increase with the mandatory roll out of interval meters commencing in 2006 (refer Chapter 13). • The demand for labour resources has increased across South East Australia, with significant increases in capital expenditure forecast in South Australia, New South Wales and Queensland. In this regard, Wilson Cook and Co (2005b, p. 5) noted that the ability of the distributors to implement their plans: … can only be conjectured, we see no reason why the companies, along with others in the country and worldwide, cannot gear up for the additional workload foreseen, providing they take concerted action for that purpose. … We expect that expenditure will ramp up over the period due to the need to increase the resource base … The Commission notes that the pattern of expenditure over the 2001-05 regulatory period is consistent with a ramp up there has already been a ramp up in capital expenditure, during the current regulatory period, which may reflect labour and/or financial constraints. 7.2.7 Information asymmetry The balance between overcompensating and undercompensating the distributors for their expenditure requirements is made more complex for the regulator given the information asymmetry that exists between the regulator and the distributors. Investment in the distribution network involves a large number of relatively small projects. This contrasts with investment in the transmission network which involves a small number of relatively large projects, which may more readily be assessed on a project-by-project basis. As demonstrated in this price review, when requested to provide supporting information, the distributors are able to produce a large amount of material to support individual projects. However, this material does not constitute a commitment to execute those projects nor an assessment of their capacity to execute them within the regulatory period. This requires that the distributors’ proposals for future expenditure must be subject to careful scrutiny. However, the Commission does not have the information necessary to develop the counterfactual at this project by project level. The Commission must therefore largely rely on the facts before it which are at an aggregate level, and include the levels of historic expenditure. October 06 268 Essential Services Commission, Victoria Final Decision 7.2.8 Commission’s determination of capital expenditure requirements Having regard to the matters discussed above, the Commission considers that its approach should be to make a determination as to the reasonable capital expenditure requirements of the distributors for the 2006-10 regulatory period at an aggregate level rather than at an asset category level. Nevertheless, in section 7.2.9 the Commission reviews each of the distributors’ proposed capital expenditures at an asset category level. The reason for this is that it is the total of the allowed capital expenditure at the asset category level that is the basis for the expenditure cap for each distributor (discussed below). As stated above, the historic out-turn capital expenditure for the 2000-04 period appears to much more closely reflect the historic out-turn capital expenditure in the 1995 to 2000 period than the distributors’ forecasts for the 2001-05 regulatory period or the Commission’s benchmarks (see also ESC 2005a, p. 18). The Commission is therefore of the view that the historic expenditure over the 2001-04 period should continue to be an important consideration in determining the forecast capital expenditure at the aggregate level for the 2006-10 regulatory period. The Commission recognises that there are reasons as to why a reasonable forecast of capital expenditure for 2006-10 may be different from historic expenditure, including: • growth in peak demand; • the ageing of the asset base – which may lead to an increase in expenditure; • the removal of expenditure for reliability improvements from the forecasts; and • expenditure to comply with new regulatory obligations such as amendments to the Electricity Safety Regulations. In this regard, the Commission notes that: • The distributors’ most recent proposals represent increases in gross capital expenditure that vary between 40 per cent and 92 per cent above historic expenditure. • Wilson Cook and Co’s further report, excluding any adjustments for labour cost escalation, capitalised indirect overheads or electrical safety compliance, recommends increases in gross capital expenditure of between 31 per cent and 66 per cent relative to historic expenditure. • After adjustments for labour cost escalation, capitalised indirect overheads and electrical safety compliance have been considered, the increases in gross capital expenditure recommended by Wilson Cook and Co.’s further report are between 35 per cent and 60 per cent relative to historic expenditure; • Wilson Cook and Co’s reasonableness check indicates that an increase in gross capital expenditure of at least 27 per cent relative to historic expenditure is required to ensure that all distributors are within its reasonable range. • At the last review, the distributors’ proposed gross capital expenditure was 34 per cent higher than historic expenditure, on average, and the Final Decision provided for gross capital expenditure of 23 per cent more than historic expenditure. However, in the current October 06 269 Essential Services Commission, Victoria Final Decision regulatory period, the distributors have only spent 8 per cent more than historic expenditure on average. • If capital expenditure was assumed to increase at the same rate as peak demand growth, then the capital expenditure would be expected to increase by approximately 22 per cent.82 • The gross capital expenditure proposed by the distributors is between 1.4 and 2 times greater than the proposed regulatory depreciation, which is incongruous in the longer term. Furthermore, the proposed rates of regulatory depreciation has increased from levels of around 4.6 per cent prior to 2001 to 6.1 per cent from 2006, with the rate of depreciation increasing significantly for CitiPower from 2006 and for the other distributors from 2001 (see Chapter 8). • The risk to the distributors of requiring more expenditure than the forecast expenditure allowance is to a degree mitigated by the removal of capital expenditure from the efficiency carryover mechanism. This means that the cost to the distributor of investing more than the forecast allowance is limited to the financing costs for capital expenditure in excess of the forecast allowance. • Where expenditure is required above the forecast, distributors will have access to additional revenue where the investment leads to improved service outcomes. Taking into account all of the information before it, it is for the Commission to exercise its judgement regarding a reasonable level of gross capital expenditure at the aggregate level for each distributor. There is no formulaic approach to adopt in exercising such judgement rather there is a range of factors for the Commission to consider. The information before the Commission suggests that a lower bound for an increase in forecast gross capital expenditure relative to historic expenditure may be 8 per cent, based on the experience during the current period, and that a higher bound may be between 35 per cent and 60 per cent, based on the review of the expenditure at the asset category level. After taking all the matters referred to earlier in this Chapter into account, and erring on the side of caution, the Commission has decided that a reasonable forecast of gross capital expenditure at the aggregate level for each distributor over the 2006-10 regulatory period is an amount that is 30 per cent greater than the historic expenditure incurred by that distributor over the 2001-04 period. The Commission recognises that this increase may include projects that can be deferred or are not required at all. However, it considers that the cost of providing more capital expenditure than required is likely to be less than the cost of providing less than required. The adoption of a forecast on this basis ensures that customers only pay for a level of capital expenditure that the Commission reasonably expects will be incurred by the distributors over the next regulatory period, given the level of historic expenditure. The Commission notes that it could have made a range of adjustments to take into consideration differences in the historic expenditure by distributor due to, for example, different growth rates, different profiles of asset age, different strategies for deferral of expenditure and different 82 Assumes peak demand growth of 4 per cent per annum compounded over five years. October 06 270 Essential Services Commission, Victoria Final Decision maintenance regimes. However, this would have drawn the Commission into attempting to interpret detailed information, not all of which is available to the Commission. Additionally the Commission considers that the magnitude of the 30 per cent increase relative to historic expenditure is sufficiently high to render it unlikely that the forecast capital expenditure that has been determined by the Commission for each distributor will be below that which is reasonably required for the 2006-10 period. Moreover, the Commission considers that the 30 per cent increase in forecast capital expenditure relative to historic expenditure is reasonably generous given the concerns raised by the distributors regarding the availability of skilled resources to undertake capital works programs. Nonetheless, the Commission recognises that this approach is subject to some risk in that it is conceivable that a distributor’s capital expenditure requirements during the 2006-10 period might exceed the forecast capital expenditure. It therefore considers that there should be further flexibility where the distributor requires additional investment. Accordingly, the Commission has decided that, when the capital expenditure incurred by a distributor exceeds the forecast capital expenditure included in its revenue requirement (excluding expenditure associated with reliability improvements or CitiPower’s Melbourne CBD security of supply project)83 the distributor should be able to apply to have the financing costs associated with this higher level of capital expenditure, up to a cap, rolled into the regulatory asset base in 2011. However, the decision on whether to permit such a roll-in of financing costs is ultimately one that is at the discretion of the relevant regulator at that time based on the circumstances that give rise to the additional expenditure. Together with the removal of capital expenditure from the efficiency carryover mechanism, such an approach retains an incentive for efficiency throughout the regulatory period, provides for (but does not encourage) spending more than the forecast expenditure and reduces the incentives to underspend. The Commission is of the view that the appropriate cap to apply under this approach is the total of the expenditure that has been determined based on the review by Wilson Cook and Co with additional adjustments by the Commission for labour rate escalation, capitalised indirect overheads and safety compliance. In short, the actual gross capital expenditure in 2006-09 and the forecast gross capital expenditure for 2010 will be rolled into the regulatory asset base at the next price review. However, to the extent the actual gross capital expenditure in 2006-09 and the forecast gross capital expenditure for 2010 (excluding capital expenditure associated reliability improvements or CitiPower’s Melbourne CBD security of supply project) is greater than the forecast expenditure for 2006-10 but equal to a less than the expenditure cap, the financing costs associated with that additional capital expenditure may also be rolled into the regulatory asset base at the next price review. For this price review, the capital expenditure that has been rolled into the regulatory asset base for 2005 is the forecast determined as part of the last price review. Under the approach adopted 83 Thse are dealt with through separate mechanisms in the price controls. October 06 271 Essential Services Commission, Victoria Final Decision to forecasting capital expenditure at the aggregate level for this price review, the Commission considers there is merit in the potential for reforecasting the capital expenditure for 2010 as part of the next price review, prior to rolling it into the regulatory asset base. Table 7.10 sets out a comparison of the gross capital expenditure as proposed by the distributors, their historic expenditure, the applicable expenditure cap for each of them and the Commission’s decision on the distributors’ gross capital expenditure for the 2006-10 regulatory period. Table 7.10: Comparison of Final Decision on gross capital expenditure to historic expenditure, the distributors’ revised proposals and the aggregate by asset category, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Historic expenditurea 179.1 374.3 712.6 534.0 386.9 Distributor’s revised proposals 344.1 601.0 1000.6 819.0 603.9 Increase relative to historic 92.1% 60.6% 40.4% 53.4% 56.1% Expenditure cap 289.5 559.5 964.9 768.8 565.3 Increase relative to historic 61.7% 49.5% 35.4% 44.0% 46.1% Commission’s Final Decision 232.8 486.5 926.4 694.2 503.0 30.0% 30.0% 30.0% 30.0% 30.0% Increase relative to historic a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period) The Commission’s decision on capital expenditure by asset category has been determined by prorating the difference between the Final Decision at the aggregate level and the expenditure cap across asset categories with the following exceptions: • Environmental, safety and legal expenditure has not been adjusted; and • The new customer connections and customer contributions have not been adjusted where the forecasts are consistent with the historic levels of expenditure. 7.2.9 Assessment of the distributors’ capital expenditure proposals by asset category In this section, the Commission reviews the distributors’ proposed capital expenditures at an asset category level. For the reasons given previously, the Commission has determined the distributors’ capital expenditure requirements for 2006-10 at an aggregate level rather than an asset category level. However, subject to the constraints previously identified, this review at the asset category level confirms that the Commission’s determination as to the aggregate capital expenditure requirements for each distributor for the 2006-10 regulatory period is reasonable. While the incentive framework provides an allowance for capital expenditure at the aggregate level, it does not prescribe the amounts that must be spent on particular projects or by asset October 06 272 Essential Services Commission, Victoria Final Decision category. It is a matter for the distributor to prioritise and undertake expenditure consistent with its own requirements. However, the outcome of the review of the capital expenditure at the asset category level provides an expenditure cap. As discussed previously, the purpose of the expenditure cap is to provide a limit on the additional capital expenditure above that included in the revenue requirement for which the financing costs may be rolled into the regulatory asset base in 2011. In some of the detailed tables that follow, the amount included in the expenditure cap is higher than the expenditure proposed by the distributor. Where this occurs, this is due to the incorporation of upward adjustments for labour cost escalation and capitalised indirect overheads, which have been reviewed by the Commission rather than by Wilson Cook and Co. For example, United Energy included labour cost escalation as a step change in operating and maintenance expenditure and did not include labour cost escalation in its capital expenditure forecasts. To ensure that the capital expenditure proposed by each of the distributors has been assessed on a consistent basis, the Commission has added an amount for labour cost escalation to United Energy’s proposed capital expenditure for each asset category. As a result, and in the absence of offsetting adjustments, the amount included in the expenditure cap for an asset category may sometimes be higher than the amount proposed by United Energy. Labour costs Labour cost escalation was included in the proposed capital expenditure by all distributors, except United Energy. Instead, United Energy forecast labour cost escalation as a step change in operating and maintenance expenditure. The approach that the Commission has taken to assess the labour costs included in the distributors’ capital expenditure forecasts is the same as that used to assess the labour costs included in the distributors’ operating and maintenance expenditure forecasts. The reasons for escalating labour costs and the approach to determining an appropriate rate to escalate these costs are discussed in detail in Chapter 6. In the Draft Decision, a real labour cost escalation of 1.5 per cent annum was included in the capital expenditure forecasts, based on a nominal labour cost escalation of 4.0 per cent per annum, determined by reference to the Enterprise Bargaining Agreements negotiated in Victoria, and a CPI of 2.5 per cent per annum. In response to the Draft Decision, further information was provided by the distributors regarding the nominal labour cost escalation. As discussed in Chapter 6, the Commission has forecast the nominal labour cost increase for the 2006-10 regulatory period to be 5.0 per cent per annum. Based on a forecast CPI of 2.77 per cent (see Chapter 9), this equates to a real labour cost increase of 2.23 per cent per annum. The Final Decision on the labour cost escalation is summarised in Table 7.11 together with the distributors’ proposals and the Draft Decision. The adjustment for labour cost escalation has October 06 273 Essential Services Commission, Victoria Final Decision been prorated across the asset categories based on the labour costs84 for each asset category as advised by the relevant distributor. Table 7.11: Adjustments to capital expenditure for labour cost escalation, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ original proposal 17.8 32.4 50.1 37.8 0.0 Draft Decision 9.2 11.6 18.0 13.6 22.2 Distributors’ revised proposal 17.8 12.1 16.7 32.6 0.0 Commission’s adjustment -4.0 6.1 8.4 -10.3 30.8 Amount included in expenditure cap 13.8 18.2 25.1 22.3 30.8 Capitalised indirect overheads AGLE, CitiPower and Powercor have included costs arising from the capitalisation of indirect (corporate) overheads in their capital expenditure forecasts. This is consistent with their treatment of indirect (corporate) overheads in the current regulatory period — each of these distributors currently capitalise some of its indirect (corporate) overheads. SP AusNet and United Energy have expensed all of their indirect (corporate) overheads. Accordingly, all the indirect (corporate) overheads incurred by SP AusNet and United Energy, and that part of the indirect (corporate) overheads that is not capitalised by AGLE, CitiPower and Powercor, have been included in their proposed operating expenditure requirements for the 2006-10 regulatory period. To ensure that these costs are treated in a consistent manner across distributors, and unless there is a change in the capitalisation policies of AGLE, CitiPower and Powercor between 2004 and 2006, the Commission is of the view that the indirect (corporate) overheads should be assessed in the same way as it has assessed the distributors’ operating and maintenance expenditure forecasts (see Chapter 6). That is, the capitalised indirect overheads should be rolled forward from 2004 to 2005 and from 2005 to 2006-10 using the same assumptions for the rate of change (including the impact of growth) as for the operating and maintenance expenditure for that distributor. The Commission has not been able to identify any change to the capitalisation policies of AGLE, CitiPower and Powercor. Consequently, the Commission has adjusted the amount of indirect (corporate) overhead costs included in the capital expenditure forecasts by an amount equal to the difference between the indirect (corporate) overhead costs forecast by the distributors over the 2006-10 regulatory period and those calculated in accordance with the Commission’s operating and maintenance expenditure framework and approach based on 2004 reported indirect (corporate) overheads. 84 For each asset category, the distributors have provided a breakdown of the capital expenditure into materials, labour, direct overhead and indirect overhead. October 06 274 Essential Services Commission, Victoria Final Decision Additionally, consistent with the decision on operating expenditure, the capitalised indirect overheads for CitiPower in 2004 are assumed to be $2.0 million higher than that reported by CitiPower (see Chapter 5). In the Draft Decision, the Commission made adjustments to CitiPower’s and Powercor’s indirect (corporate) overheads of $21.2 million and $41.3 million, respectively. In subsequent submissions, CitiPower and Powercor substantially reduced their capitalised indirect (corporate) overheads to be in line with the Commission’s Draft Decision. Their revised proposals are based on the capitalised indirect overheads in their 2004 regulatory accounting statements, and do not incorporate any change over time with the rate of change and the impact of growth, or the increase in capitalised indirect overheads assumed by the Commission for CitiPower. The Final Decision on the capitalised indirect overheads is summarised in Table 7.12 together with the distributors’ proposal and the Draft Decision. The adjustment between the distributors’ proposed capitalised indirect (corporate) overheads and the Commission’s view of an appropriate level of capitalised indirect (corporate) overheads for the 2006-10 regulatory period has been prorated across the asset categories, based on the level of indirect (corporate) overheads allocated to each capital expenditure asset category by the relevant distributor. Table 7.12: Adjustments to capital expenditure for indirect (corporate) overheads, all distributors, 2006-10 regulatory period, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ original proposal 16.6 74.0 98.2 0.0 0.0 Draft Decision 9.1 52.8 56.9 0.0 0.0 Distributors’ revised proposal 16.6 52.2 56.2 0.0 0.0 Commission’s adjustment -7.1 13.8 3.4 0.0 0.0 Amount included in expenditure cap 9.5 66.0 59.6 0.0 0.0 Note: May not add due to rounding. The Commission recognises that the distributors have different capitalisation policies. In this price review, the Commission has been able to assess the level of indirect overheads capitalised based on the information available from the last price review. The distributors have provided more detail regarding their proposed capitalisation of direct overheads and indirect overheads for the 2006-10 regulatory period during the course of this price review. The Commission will use this information for the next price review to ensure that any reported information is compared on a like-fore-like basis with the forecasts in the revenue requirement, particularly given the removal of capital expenditure from the efficiency carryover mechanism. Reinforcement capital expenditure Distributors undertake reinforcement capital expenditure in order to meet growing demand upon the network. Reinforcement capital expenditure involves augmentation of network components to ensure they have sufficient capacity to meet high peak demand days. October 06 275 Essential Services Commission, Victoria Final Decision The distributors proposed a level of reinforcement capital expenditure over the 2006-10 regulatory period that was greater than was spent in the 2001-04 period to accommodate forecast increases in peak demand. The increases in expenditure proposed ranged between 48 per cent (United Energy) and 199 per cent (SP AusNet). The distributors’ proposed capital expenditure on reinforcement is set out in Table 7.13, along with the actual level of reinforcement capital expenditure undertaken over the 2001 to 2004 period. Table 7.13: Proposed capital expenditure — reinforcements, all distributors, $million, real $2004 Historic expenditurea Distributors’ original proposals relative to historic expenditure Draft Decision relative to historic expenditure Distributors’ revised proposals relative to historic expenditure 23.9 199% 57% 199% CitiPower 80.1 b 142% 30% 97%b Powercor 70.7 212% 115% 160% SP AusNet 41.9 197% 134% 199% United Energy 69.9 66% 22% 48% AGLE a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period) b Includes $44.1 million (excluding indirect overheads) to improve the security of supply in the Melbourne CBD area. This project is discussed separately in the next section. Excluding this project, the proposed increase in CitiPower’s reinforcement expenditure from 2001-04 to 2006-10 is 39 per cent. The reasons the distributors gave for their proposed increases in reinforcement expenditure include forecast increases in peak demand, increased utilisation levels and a need to maintain utilisation within prudent levels, and the increased penetration of air conditioning. The distributors’ reasons cited for the increase in reinforcement expenditure required are set out in Table 7.14. October 06 276 Essential Services Commission, Victoria Final Decision Table 7.14: Reasons cited for proposed increase in reinforcement capital expenditure Reasons AGLE AGLE commissioned PB Associates to develop a generic model for estimating demand-related capital expenditure and load demand growth, to compare to its own estimates. AGLE’s estimates, which were $2.6 million higher than PB Associates’ estimates, were included in its price-service proposal. Additionally AGLE included expenditure for projects not recognised in the PB Associates modelling: • conversion of 6.6kV network assets in the Preston area to 22kV ($14 million); • sub-transmission line augmentation resulting from the augmentation of terminal stations; and • augmentation where prescribed voltage levels are breached before plant/line ratings are exceeded. CitiPower Reinforcement capital expenditure in 2006-10 regulatory period is expected to exceed that in previous periods due to: • increasing focus on the value of the security of electricity supply by the community and state and local governments; and • the need to reinforce and augment the network to meet demand growth while maintaining utilisation within prudent operating levels as scope to efficiently utilise existing capacity reduces compared with previous periods. CitiPower included $44.1 million, excluding indirect overheads, to improve the security of supply in the Melbourne CBD. For the purposes of the Commission’s analysis, this has been excluded from reinforcement expenditure and is considered separately in the next section. Powercor The main factors said to be driving reinforcement capex are the high level of utilisation of the network, growth in localised pockets and the increasing penetration of air conditioning. SP AusNet SP AusNet’s proposed increased spending in the 2006-10 regulatory period is said to be driven by increased peak demand levels caused by increased penetration of air-conditioning, the associated load at risk, increased utilisation levels above that generally considered to be prudent, and service outcomes. United Energy The significant increase in reinforcement expenditure compared with the current period is said to be a result of lower demand than expected in the period 2001-05; the effects of projected demand growth for the period 2006-10; and the need to maintain prudent levels of utilisation and reliability performance. Source: AGLE 2004, pp. 43-44; CitiPower 2004, p. 50; Powercor 2004, pp. 60-62; SP AusNet 2004, pp. 71-72; United Energy 2004, p. 89. Each of the distributors has spent less than their estimated requirements for reinforcement capital expenditure set at the last price review. Some of the savings may be due to efficient deferral since actual peak demand growth over the current period has been lower than that forecast at the last price review. However some may also reflect an overstating of the forecasts at the last price review. Wilson Cook and Co assessed whether the reinforcement projects proposed by the distributors were achievable and whether the associated expenditure was reasonable. In assessing the achievability of the proposed expenditure, Wilson Cook and Co reviewed the consistency of distributors’ forecasts with other processes and plans (including workforce management plans and asset management plans), the weighted average remaining life of assets, load at risk, expected utilisation levels and supporting information provided by the distributors. October 06 277 Essential Services Commission, Victoria Final Decision Wilson Cook and Co considered that the network development proposals reasonably reflected the growth rates projected and were satisfied that individual projects were reasonable for inclusion in the distributors’ network development plans. However, in terms of the reasonableness of the distributors’ proposed expenditure, Wilson Cook and Co believed that the expenditure proposals were overstated. The extent to which it considered the distributors’ proposals to be overstated was reduced relative to its view at the time of the Draft Decision. AGLE AGLE engaged PB Associates to verify its forecasts of reinforcement capital expenditure. Wilson Cook and Co observed that AGLE had not required 50 per cent of the expenditure estimated for the 2001-05 regulatory period and that service levels did not appear to be affected, although AGLE’s current expenditure appeared low. Wilson Cook and Co also observed that AGLE’s capital expenditure estimate was higher than PB Associates’ estimate, and that this was not consistent with the expectation that estimates derived from a detailed planning approach should generally lead to lower projections than a deterministic model (due to synergies). This suggested that AGLE’s projections may be overstated. Wilson Cook and Co also noted that there may be double-counting due to the way estimates have been categorised and prepared, and thus some provisions need not be accepted in full. Wilson Cook and Co endorsed AGLE’s program for converting the 6.6kV network in the Preston area to 22kV, noting that it will allow greater network flexibility and the rationalisation of equipment as well as additional capacity. In response to additional information provided by AGLE, Wilson Cook and Co accepted that the expenditure under this category is low in the current period and ought to be increased. However, it remained unconvinced that the proposed increased is required in full. In conclusion, it expressed the view that AGLE’s reinforcement capital expenditure proposal was overstated by $10.0 million, excluding the impact of indirect (corporate) overheads and labour cost escalation. This compares to an adjustment of $31.4 million recommended by Wilson Cook and Co at the time of the Draft Decision. CitiPower CitiPower engaged PB Associates to verify its forecasts for reinforcement capital expenditure. However, in making the comparison between PB Associates’ estimates and its own estimates, CitiPower identified an amount of $51 million for items that were not included in the PB Associates’ estimates. In response to the Draft Decision, CitiPower provided further information to support the items removed by Wilson Cook and Co. These items related to labour cost escalation, the Roads Management Act, indirect overheads, and Docklands connection expenditure (the expenditure for which has subsequently been transferred to new customer connections). Additionally, October 06 278 Essential Services Commission, Victoria Final Decision CitiPower reduced its proposed expenditure for reinforcements, excluding labour cost escalation and indirect overheads, from $193.8 million to $157.4 million (a reduction of $36.4 million). With the exception of the expenditure to comply with the Road Management Act, and the capital expenditure to improve the security of supply in the Melbourne CBD which is discussed in the next section, Wilson Cook and Co was satisfied that, on the information made available to it, the individual projects were reasonable for inclusion in CitiPower’s network development plans, and the nature of the reinforcement expenditure proposed by CitiPower was justified. With regard to the proposed expenditure on the Road Management Act, Wilson Cook and Co made an adjustment of 50 per cent ($1.5 million) on the basis that the expenditure proposed was provisional in nature. This compares to a total adjustment to the reinforcement capital expenditure of $34.6 million, excluding the reduction for the CBD security of supply project, at the time of the Draft Decision. Powercor Similar to CitiPower, Powercor had PB Associates verify its forecasts of reinforcement capital expenditure. As with CitiPower, Wilson Cook and Co questioned the identification by Powercor of $81 million of expenditure that was not included in the comparison between Powercor’s own estimates and PB Associates’ estimates. Powercor provided further information to support the items removed by Wilson Cook and Co. These items related to labour cost escalation, the Roads Management Act, indirect overheads, service pits and non reinforcement activities. Additionally, Powercor reduced its proposed expenditure for reinforcements, excluding labour cost escalation and indirect overheads, from $220.3 million to $183.9 million (a reduction of $36.4 million). With the exception of the expenditure to comply with the Road Management Act, Wilson Cook and Co was satisfied that, on the information made available to it, the individual projects were reasonable for inclusion in Powercor’s network development plans, and the nature of the reinforcement expenditure proposed by Powercor was justified. With regard to the proposed expenditure on the Road Management Act, Wilson Cook and Co made an adjustment of 50 per cent ($7.3 million) on the basis that the expenditure proposed was provisional in nature. This compares with a total adjustment to the reinforcement capital expenditure of $63.6 million at the time of the Draft Decision. SP AusNet Wilson Cook and Co noted that the unit costs used to estimate some items of SP AusNet’s reinforcement expenditure might be too high. In most cases, Wilson Cook and Co was of the view that the costs were substantially higher than the standard unit costs used in other jurisdictions. Additional information provided by SP AusNet since the Draft Decision did not convince Wilson Cook and Co that the unit rates were reasonable. October 06 279 Essential Services Commission, Victoria Final Decision Wilson Cook and Co expressed the view that the adjustment for unit costs in SP AusNet’s reinforcement capital expenditure of $17.0 million, excluding the impact of labour cost escalation, recommended at the time of the Draft Decision should be retained. United Energy In the Draft Decision, concern was expressed regarding the use by United Energy of a 10 per cent POE and high economic growth assumption in modelling the reinforcements expenditure. Since the Draft Decision, United Energy has remodelled its reinforcement expenditure based on a medium growth scenario which has resulted in a reduction in its proposal from $115.7 million to $93.2 million (a reduction of $22.5 million). The Commission remains concerned with the use of a 10 per cent POE growth forecast, but is satisfied that on this occasion United Energy has adapted the PB Associates’ models to reflect a risk based planning approach. Additionally the Commission notes that the growth rate in the 10 per cent POE forecast is approximately the same as the growth rate in the 50 per cent POE forecast. Wilson Cook and Co noted that the company’s zone substation utilisation is at a high level and accepted the need for increased expenditure. However, Wilson Cook and Co remained of the view that some projects will be delayed or deferred, as in the past. Considering both of these issues, it reduced the recommended adjustment from $34.7 million to $10.3 million. Including adjustments for indirect (corporate) overheads and labour cost escalation, Table 7.15 summarises the capital expenditure for reinforcements for each of the distributors for the 2006-10 regulatory period. Table 7.15: Capital expenditure — reinforcements, all distributors, 2006-10 regulatory period, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ revised proposals 71.5 157.4 183.9 125.3 103.5 Wilson Cook and Co adjustment -10.0 -1.5 -7.3 -17.0 -10.3 b -44.1 CBD security of supply c -2.3 4.7 2.3 -1.5 5.3 Amount included in expenditure cap (2006-10) 59.2 116.5 178.9 106.8 98.5 Historic expenditure (2001-04)a 23.9 80.1 70.7 41.9 69.9 Variance 35.3 36.4 108.2 64.9 28.6 148% 45% 153% 155% 41% Commission’s adjustment a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). b The expenditure to improve the security of supply in the Melbourne CBD is not incorporated in the expenditure requirement for reinforcement. It is considered separately in the next section. c Includes adjustments for labour cost escalation (refer Table 7.11) and indirect (corporate) overheads (refer Table 7.12) October 06 280 Essential Services Commission, Victoria Final Decision CBD security of supply CitiPower proposed $50.2 million to strengthen the security of supply to the Melbourne CBD (see Table 7.16) based on a proposal to move from the existing planning criterion for the CBD of “N-1” to “N-1 Secure”. The proposed cost of this project includes $6 million of indirect (corporate) overheads and labour cost escalation. Table 7.16: Proposed capital expenditure — CBD security of supply, CitiPower, 2006-10 regulatory period, $million, real $2004 Distributors’ revised proposal 2008 2009 2010 Total 12.7 17.1 20.4 50.2 Under the existing “N-1” planning criterion, the CBD network can withstand any credible single contingency fault at subtransmission or zone substation level without sustained interruption to customers, but not a second contingency event. Under the proposed “N-1 secure” planning criterion, the network would be able to withstand a second contingency event without sustained interruptions to customers, within 30 minutes of the first event occurring. CitiPower engaged SKM to analyse a range of future CBD supply options. SKM (2004b) were of the view that: • Melbourne CBD’s security of supply is the second lowest of comparable CBDs reviewed by SKM in terms of maximum demand, energy at risk and planning criteria. • The number of people potentially affected by a supply failure is over 8 times higher than the number of CitiPower’s CBD customers. • A supply failure to the CBD would be comparable in effect to a major transmission failure elsewhere on the power system. • Loss of supply to the CBD would impact on people in many ways including traffic chaos, loss of supply to many hospitals, health and safety issues, loss of economic activity and an adverse effect on consumer activities. The Commission is of the view that ensuring ongoing security of supply to the Melbourne CBD area is of primary importance to the Victorian economy. As demonstrated when power failed to the CBD area in 2002 and in the power failures that occurred in Auckland and New York, the disruption of supply to the CBD has a significant impact on the economy. Hence, the Commission fully supports CitiPower’s proposed project and considers it a positive step, especially given the low comparative rating that SKM has given to the level of security of supply that currently exists in Melbourne’s CBD. However, the cost of the work proposed is significant. Given the incentive properties of the regulatory framework, the Commission is concerned that to include the project in the revenue requirement may result in customers paying for the project even if it did not proceed. Additionally, the Commission is of the view that a project of this type should be subject to sufficient review and consultation on the need for the change in the planning standard, what planning standard is appropriate, the cost of meeting the planning standard and how it should be paid for. October 06 281 Essential Services Commission, Victoria Final Decision The Commission proposed in its Draft Decision that the capital expenditure associated with this project should be excluded from CitiPower’s revenue requirement but that, where the project proceeds, the expenditure associated with the project (including compensation for financing costs incurred) should be rolled into the regulatory asset base at the end of the regulatory period, subject to the regulator’s satisfaction that the regulatory test under the National Electricity Rules85 has been appropriately applied, and that the project has been executed in a prudent and efficient manner. Under the Commission’s proposed approach, customers would only fund the project if the planning standard is changed and the project is identified as cost effective through an appropriate public consultation process. CitiPower also has an incentive to ensure that the expenditure associated with the project is efficient because the expenditure associated with the project would only be rolled into CitiPower’s regulatory asset base where it could be demonstrated that it was executed in a prudent and efficient manner. In response, CitiPower provided a detailed submission concluding that it would not proceed with the Melbourne CBD security of supply project within the 2006-10 regulatory period on the basis set out in the Commission’s Draft Decision. CitiPower indicated that in its view: • The Commission had not assessed the proposal against its statutory objectives, in particular the implications of its proposed decision for the incentives for efficient investment. • The regulatory test under the National Electricity Rules was not applicable as the project has been proposed for economic reasons, rather than reliability reasons. The CitiPower distribution system will not exceed its technical limits in normal conditions, or following a single credible contingency event, in the absence of the CBD security of supply project. • It had already undertaken extensive consultation which had been positive. • The Commission is unable to bind any future regulator as is proposed under the approach. • The proposed treatment of the CBD security of supply project is somewhat novel in Australian regulatory terms. CitiPower also noted that recent Design, Reliability and Performance Licence Conditions imposed on NSW distributors by the Minister of Energy and Utilities require that the planning standard for the Sydney CBD has a security of supply standard not dissimilar to the ‘N-1 secure’ standard proposed by it. The Commission issued an Open Letter on 11 August 2005 to further consult on this project. Given the in principle support for this project from City of Melbourne and Victoria Police, the Commission specifically sought comments from those parties, as well as other interested stakeholders, as to the detail of CitiPower’s proposal, and particularly the impact on prices to customers. With regard to the most appropriate cost recovery mechanism, the Commission consulted on the following options for recovering the costs of the project: 85 Formerly the National Electricity Code October 06 282 Essential Services Commission, Victoria Final Decision • Include the costs in the revenue requirement and recover them from customers as proposed by CitiPower. • Exclude the costs from the revenue requirement and recover them from customers from 2011 if the project proceeds, as proposed in the Draft Decision. • Recover the costs from customers through a pass through mechanism if an obligation is placed on CitiPower (through the Electricity Distribution Code) to proceed with the project. • Recover the costs from customers but pass them back if an obligation is not placed on CitiPower (through the Electricity Distribution Code or any other regulatory instrument) to proceed with the project. Whilst Victoria Police did not respond to the open letter, the City of Melbourne (2005, p. 1) indicated that it was not in a position to speak on behalf of the business and residential community with respect to their willingness to pay for the extra security of supply through an increase in electricity pricing, nor was it able to comment on whether CBD customers should pay extra compared to non-CBD customers for the additional benefit of a secure supply. Furthermore it was unable to comment on whether the consultation process undertaken by CitiPower to date was appropriate for a project of this magnitude. In its response to the open letter, CitiPower (2005y, pp. 2-3) reaffirmed its view that: The CBD security of supply project should be accorded the same regulatory treatment as all other distribution capital expenditure. Such a treatment would accord with the approach to ex-ante capital expenditure in the ACCC/AER Principles and therefore be consistent with the Commission’s facilitating objectives under the Essential Services Commission Act 2001, the Electricity Industry Act 2000 and the Victorian Electricity Industry Tariff Order (sic), in view of the Commission’s findings of fact with respect to the importance of the CBD security of supply project to the Victorian economy. … The project produces broad economic benefits to Melbourne’s CBD and surrounds and as such the costs for the project should be recovered from all customers … Although the beneficiary pays pricing is a desirable goal, CitiPower is of the view that the efficiency benefits created from such pricing will be minor given the current average pricing and the additional administrative costs of a separate tariff. The broad nature of the beneficiaries of the project will further reduce efficiency signals as it would be very difficult to clearly partition and bill all the customers that should contribute to the project. The Hon. Minister Theophanous (2005, p. 2) indicated that: The importance of CBD supply reliability for the smooth running of the economy, and the broader Victorian community is widely acknowledged. However, it takes on even greater importance when the efficient and effective management of major community emergencies (that may or may not be directly caused by an electricity supply problem) is required. Many emergency services rely on the reliability of CBD electricity supply, as do many of the emergency management coordination functions that are the crucial October 06 283 Essential Services Commission, Victoria Final Decision responsibilities of Government, its agencies and key infrastructure. I therefore urge that the issue of providing an appropriately secure supply to the CBD is investigated. Additionally, Powercor’s Customer Consultative Group (2005, p. 1) suggested that the costs should be recovered from all Victorians. The Commission notes that there is currently no mechanism for recovering costs for this project in this way and that such an approach may raise issues regarding equity. The Commission remains concerned that there is currently no obligation on CitiPower to strengthen the security of supply in the CBD area. Accordingly, if the expenditure for this project is included in the revenue requirement there is no guarantee that the project would proceed. Given the magnitude of this project relative to those normally associated with the distribution network, there is a potential for large windfall gains (or losses) for customers or CitiPower should the project be funded and not proceed, or not be funded and then proceed during the regulatory period. In each case there would be no sharing of risk — either CitiPower or its customers would bear the entire risk of the project until the next Price Determination takes effect in 2011. CitiPower has clearly articulated that the project will not proceed if the expenditure is excluded from the revenue requirement and recovered in the 2011 regulatory period if the project proceeds. It prefers an option in which the expenditure is recovered from customers but returned if an obligation is not placed on CitiPower to proceed with the project. The Commission recognises CitiPower’s concerns about the risk of the project not being undertaken if it is not able to recover the financing costs until the next regulatory period. However, it does not consider that customers should pay for the project if it does not proceed. Therefore, the Commission considers a within period pass through mechanism would be appropriate once the planning standard has been altered. The pass through mechanism has precedents in other jurisdictions, with similar mechanisms introduced in South Australia for expenditure associated with connection point and subtransmission line projects, and in Queensland for identified capital projects with a value greater than $5 million and a probability of less than 80 per cent. The Commission will undertake a consultation process to consider an amendment to the Electricity Distribution Code. The Commission will consult on: • the most appropriate planning standard for the Melbourne CBD; • the most appropriate project to deliver that outcome; and • who should pay for the project, for example, electricity distribution customers in the Melbourne CBD area, CitiPower’s electricity distribution customers, all electricity distribution customers or all Victorians. The Commission anticipates working with CitiPower to identify the planning standard options and project options to consult on, with an Issues Paper to be released in June 2006. If this consultation process leads to a change in the Electricity Distribution Code, the pass through mechanism (referred to in Chapter 12 and implemented in clause 5 of the Volume 2) to October 06 284 Essential Services Commission, Victoria Final Decision allow CitiPower to recover the forecast expenditure for the CBD security of supply project should it proceed. Additionally should the project proceed, the Commission will require separate reporting of the expenditure associated with this project in CitiPower’s regulatory accounting statements and will exclude this expenditure from out-turn expenditure for the purposes of assessing historic expenditure in this category. Furthermore, the Commission has aligned the incentive rates under the S-factor scheme for the CBD area with the $60 000 per MWh value identified by CitiPower and SKM to be the value of lost load in the Melbourne CBD (refer Chapter 3). New customer connections Distributors incur new customer connection capital expenditure to establish new customer connections to the network. Part of this cost may be recovered from customers through customer contributions. The level of customer contributions for the 2006-10 regulatory period is discussed in the next section. Whilst some distributors have proposed increases in new customer connections capital expenditure over the 2006-10 regulatory period (see Table 7.17), others have proposed decreases. Table 7.18 sets out the reasons for the forecast changes. Table 7.17: a Proposed gross capital expenditure — new customer connections, all distributors, $million, real $2004 Historic expenditurea Distributors’ original proposals relative to historic expenditure Draft Decision relative to historic expenditure Distributors’ revised proposals relative to historic expenditure AGLE 72.0 16% -10% 16% CitiPower 107.4 55% -20% 61% Powercor 276.5 1% -33% -4% SP AusNet 246.2 42% 3% 36% United Energy 130.4 -7% -17% -22% Assumes all customer contributions are for customer connections. October 06 285 Essential Services Commission, Victoria Final Decision Table 7.18: Reasons for proposed changes in new customer connections capital expenditure Reasons AGLE Forecast of new customer connections prepared by NIEIR CitiPower Number of new connections expected to remain relatively consistent over the period until 2010 Powercor Growth in new customer connections is reasonably consistent throughout the period, however there is an upturn in growth due to an anticipated economic upturn in 2010 SP AusNet Growth rates, as forecast by NIEIR, are similar to those experienced during 2001-05. Increase in gross connection expenditure reflects an increase in cogeneration costs for several windfarm projects in the Gippsland area ($17 million) and an increase in underground estate costs relating to the application of the Commission’s Electricity Industry Guideline No. 14. United Energy Reduction in forecast for the 2006-10 regulatory period primarily driven by the exclusion of meters and the anticipated reduction in fully funded capital works Source: AGLE 2004, p. 44; CitiPower 2004, p. 56; Powercor 2004, p. 63; SP AusNet 2004, p. 68; United Energy 2004, p. 92. Prior to the Draft Decision, Wilson Cook and Co suggested a number of adjustments to the capital expenditure for new customer connections proposed by the distributors based on an apparent discrepancy in the proposed ratio of new connections to new customers compared to historic data, and the unit cost of new connections. On further review following the Draft Decision, Wilson Cook and Co had doubts about the veracity of the historic data for new customer numbers which may have led to distorted ratios between historic new customer numbers and new connection numbers. As a result, in its further report it has removed the reductions for AGLE, Powercor and United Energy of $13.7 million, $74.3 million and $18.4 million respectively that were recommended in its earlier report. CitiPower In its price-service proposal, CitiPower proposed capital expenditure of $23.0 million for load movement. Given the uncertainty on whether capital expenditure would be categorised as a load movement or a new customer connection, Wilson Cook and Co considered the capital expenditure for load movement in conjunction with its assessment of capital expenditure for new customer connections. Wilson Cook and Co noted that the capital expenditure proposed by CitiPower for new customer connections, having regard to the additional expenditure associated with the Docklands development, was high relative to historic expenditure. The number of new connections was forecast to be on average 12 per cent higher than historic levels, when the other distributors were forecasting similar or lower levels of new connections. Wilson Cook and Co therefore proposed a reduction in its adjustment for capital expenditure for new customer connections from $65.4 million to 10 per cent ($17.5 million). October 06 286 Essential Services Commission, Victoria Final Decision SP AusNet In its earlier report, Wilson Cook and Co recommended a reduction to SP AusNet’s proposed capital expenditure for new customer connections of $56.2 million. SP AusNet has since indicated that the increase in the proposed capital expenditure for new customer connections was due to the adoption of an “underground only” policy (endorsed by ESV) for new LV services. In response to further questions from Wilson Cook and Co, SP AusNet advised that the cost of these underground connections was $5 million less than originally proposed. Wilson Cook and Co therefore recommended in its further report that SP AusNet’s proposed expenditure be reduced by $5 million. Wilson Cook and Co queried the increase in the proposed capital expenditure for new customer connections compared to historic expenditure. Whilst the undergrounding of LV services and increases in unit costs explain some of the increase relative to historic expenditure, they did not justify all of this proposed increase. In its further report, Wilson Cook and Co therefore recommended that SP AusNet’s proposed expenditure be reduced by a further 5 per cent ($15.7 million). The Commission notes that SP AusNet has proposed expenditure of $17 million and customer contributions of $15.3 million over the period to connect new wind farms to its network. Recovery of connection costs associated with windfarms is defined by the Electricity Industry (Wind Energy Development) Act 2004, and should therefore be excluded from the expenditure forecast. Therefore the Commission has removed $17 million from new customer connections and $15.3 million from customer contributions. Including adjustments for indirect (corporate) overheads and labour cost escalation, the capital expenditure for new customer connections for each of the distributors for the 2006-10 regulatory period is summarised in Table 7.19. Table 7.19: Capital expenditure (gross) — new customer connections, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ revised proposals 83.5 172.7 265.6 335.9 101.2 Wilson Cook and Co adjustment 0.0 -17.5 0.0 -20.7 0.0 Commission’s adjustment b -3.5 6.5 3.3 -20.9 5.2 Amount included in expenditure cap (2006-10) (a) 80.0 161.7 268.9 294.3 106.4 Historic expenditure (2001-04)a (b) 72.0 107.4 276.5 246.2 130.4 Variance (a-b) 8.0 54.3 -7.6 48.1 -24.0 11% 50% -3% 20% -18% a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate) overheads (refer Table 7.12) and other adjustments by the Commission October 06 287 Essential Services Commission, Victoria Final Decision Customer contributions Customers are required to contribute towards the capital cost of new customer connections where the incremental cost of the connection is greater than the incremental revenue. All distributors have proposed reductions in customer contributions over the 2006-10 regulatory period (see Table 7.20). Table 7.20: Proposed customer contributions, all distributors, $million, real $2004 Historic expenditurea Distributors’ original proposals relative to historic expenditure Draft Decision relative to historic expenditure Distributors’ revised proposals relative to historic expenditure AGLE 28.1 -16% -32% -16% CitiPower 44.8 -28% -58% -21% Powercor 166.8 -23% -42% -23% SP AusNet 124.7 -10% -31% -23% United Energy 49.4 -51% -58% -61% a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). In the last Price Determination, the ORG proposed new guidelines for calculating customer contributions to the cost of network connection and augmentation by customers, developers, embedded generators and other parties. The proposed new guidelines were significantly different from those employed by four of the five distributors, whose policies were inherited from the former State Electricity Commission of Victoria. The impact of the proposed new guidelines was that the level of capital contributions by customers would generally fall, thereby lowering the barriers to connection faced by customers. This policy change was not fully promulgated by the Commission until April 2004 with the release of an updated Electricity Industry Guideline 14. The delayed implementation of the new Guidelines means that the level of customer contributions during the 2001-04 period does not necessarily reflect the likely level of customer contributions for the 2006-10 regulatory period. Customer contributions as a proportion of gross new customer connections expenditure, as reported for 2004 and as proposed by the distributors for 2006, are set out in Table 7.21. October 06 288 Essential Services Commission, Victoria Final Decision Table 7.21: Customer contributions as a proportion of gross new customer connections capital expenditure, all distributors, per cent 2004 2006 As reported Distributors’ revised proposals AGLE 32.4 28.0 CitiPower 40.4 19.0 56.2 48.7 47.6 25.9 22.5 19.1 Powercor SP AusNet a United Energy a Excludes $17 million for windfarms in the new customer connection capital expenditure and $15.3 million as a customer contribution Customer contributions as a proportion of gross new customer connections capital expenditure decreased for all distributors from 2004 to 2006. However it is difficult for the Commission to assess a reasonable proportion given the different mix of projects undertaken by the distributors (and therefore the different levels of contribution by customers), the absence of historic information (given the change in approach over the current regulatory period), and the different levels of compliance by the distributors to the requirements of the Guideline. Whilst the Commission has concerns regarding the level of customer contributions proposed by some of the distributors, given the level of uncertainty, the Commission has not made any adjustments based on the proportion. However it expects that more consistent information will be available at the next review to make a more thorough assessment. In public information sessions convened by the Commission during this price review (see Appendix A), customers, particularly in the Bendigo area, raised a number of concerns over the costs they were being quoted by Powercor for connection to the network. However, these quotes were provided by Powercor prior to the updated Guideline. Powercor has indicated that quotes for customer contributions have reduced since the implementation of its new connection policies and principles consistent with the Guideline. Wilson Cook and Co has recommended that the level of customer contributions be reduced proportionally to the reduction in capital expenditure for new customer connections. If the capital expenditure on new customer connections is reduced, then the customers’ contribution to those costs would also be expected to reduce. With the reduction in the adjustments to new customer connections, there is also a reduction in the adjustments to customer contributions. In its further report, Wilson Cook and Co’s adjustments to the customer contributions of AGLE, Powercor and United Energy of $4.4 million, $39.2 million and $3.7 million have been removed. Wilson Cook and Co has also reduced the adjustments to CitiPower’s and SP AusNet’s customer contributions from $12.0 million to $3.5 million, and from $9.5 million to $4.8 million respectively. The Commission has adjusted the customer contributions proportionally to any adjustments to the capital expenditure for new customer connections. It is also of the view that customer October 06 289 Essential Services Commission, Victoria Final Decision contributions attributable to the connection of windfarms ($15.3 million) should be removed from SP AusNet’s proposed customer contributions, consistent with the treatment of new customer connections capital expenditure. The level of customer contribution for each distributor is set out in Table 7.22. In determining these amounts, the Commission has accepted Wilson Cook and Co’s recommendations regarding customer contributions and has removed SP AusNet’s contributions for windfarms. Table 7.22: Customer contributions, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ revised proposals 23.6 35.6 128.8 95.9 19.3 Wilson Cook and Co adjustment 0.0 -3.5 0.0 -4.8 0.0 -1.0 1.4 1.6 -16.3 1.0 Amount included in expenditure cap (2006-10) (a) 22.6 33.5 130.4 74.8 20.3 Historic expenditure (2001-04)a (b) 28.1 44.8 166.8 124.7 49.4 Variance (a-b) -5.5 -11.3 -36.4 -49.9 -29.1 -20% -25% -22% -40% -59% Commission’s adjustment b a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate) overheads (refer Table 7.12) and other adjustments by the Commission Load movement Distributors undertake capital expenditure on load movement to accommodate customers who relocate within a network. The movement of customers within a network (for example, due to changes of residences or business locations) does not generally change the total load on the network. However, a distributor may need to augment the capacity of the part of the network to which the customer relocates to accommodate the higher level of demand within that area. CitiPower was the only distributor to forecast capital expenditure relating to load movement over the 2006-10 regulatory period. CitiPower originally forecast load movement capital expenditure of $24.1 million over the period, which was reduced to $23.1 million since the Draft Decision. The reasons CitiPower cited for this expenditure included changes in network configuration required by inner city and CBD residential development and asset relocations to allow adjacent construction activities to maintain the prescribed clearance from its network. Wilson Cook and Co originally recommended that this proposed expenditure not be accepted because it considered that it had already been considered elsewhere. In response, CitiPower provided further supporting information. As a result, in its further report, Wilson Cook and Co re-assessed this expenditure in conjunction with CitiPower’s proposed capital expenditure for new connections, and recommended that no adjustment be made. Accordingly, the only October 06 290 Essential Services Commission, Victoria Final Decision adjustments that the Commission has made relate to changes in labour cost escalation and capitalised indirect overheads. The load movement capital expenditure for each distributor for the 2006-10 regulatory period is set out in Table 7.23. Table 7.23: Capital expenditure — load movements, all distributors, 2006-10 regulatory period, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ revised proposals 0.0 23.0 0.0 0.0 0.0 Wilson Cook and Co adjustment 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.0 0.0 0.0 Amount included in expenditure cap (2006-10) (a) 0.0 23.3 0.0 0.0 0.0 Historic expenditure (2001-04)a (b) 0.0 34.8 0.0 0.0 0.0 Variance (a-b) 0.0 -11.5 0.0 0.0 0.0 0% -33% 0% 0% 0% Commission’s adjustment b a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), and indirect (corporate) overheads (refer Table 7.12) Reliability and quality maintained Capital expenditure to maintain reliability and quality relates to expenditure undertaken to replace and renew existing network assets. With time, network assets age and deteriorate and, if not replaced, may fail, resulting in a deteriorating level of service reliability and quality. The distributors have proposed capital expenditure to maintain reliability and quality over the 2006-10 regulatory period that exceeds the historic expenditure (see Table 7.24). Table 7.25 sets out the reasons cited by the distributors for this increased level of expenditure. Table 7.24: Annual average capital expenditure — reliability and quality maintained, all distributors, $million, real $2004 Historic expenditurea Distributors’ original proposals relative to historic expenditure Draft Decision relative to historic expenditure Distributors’ revised proposals relative to historic expenditure AGLE 33.7 121% 69% 121% CitiPower 71.9 122% 75% 113% Powercor 168.5 76% 24% 68% SP AusNet 125.2 33% 11% 48% United Energy 73.1 227% 143% 220% a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). October 06 291 Essential Services Commission, Victoria Final Decision Table 7.25: Reasons for proposed increase capital expenditure to maintain reliability and quality Reasons AGLE PB Associates modelled replacement expenditure for AGLE. Estimates from this modelling were consistent with AGLE’s own estimates and were based on an increasing number of poles, overhead service conductors, and cross arms that will need replacement during the 200610 regulatory period. Communications and protection schemes associated with the sub transmission system are to be replaced due to age. There are also increasing failure rates of porcelain surge diverters, and premature failure of early manufactured XLPE cable, and overhead high voltage single blade isolators. There is an ongoing project to refurbish some of the zone substation buildings. CitiPower The main driver of the proposed expenditure is said to be the ageing nature of the assets – over 12 per cent of them will reach the end of their lives by the end of the regulatory period, of which the majority will require replacing. A key project proposed is to replace ageing 22kV subtransmission cables and two 22/11kV zone substations on the southern fringe of the CBD. Powercor PB Associates undertook an independent verification of Powercor’s expenditure forecasts and SKM was engaged to verify the unit rates used in the PB Associates’ model. Powercor’s estimates (excluding indirect overheads) were below PB Associates’ estimates. The proposed expenditure is largely condition-driven. The main features of this proposal are the replacement of wooden cross-arms, wooden and concrete poles, older zone substation equipment, and overhead and underground cable replacement. The latter is driven, in part, by some premature failures of XLPE cables. SP AusNet The main drivers of the proposed expenditure are: • additional expenditure on pole replacement, reflecting the trend of increasing condemnation rates, ageing profile and higher failure rates; • additional expenditure on overhead conductor replacement (due to increasing failure rates of copper and steel conductors) and pole top structures (reflecting the expected increase in condemnation rates of cross-arms and insulators); and • the rebuilding of ten zone substations with packaged solutions. United Energy United Energy “is entering a period in which the requirement for assets replacement expenditure will substantially increase. This increase in replacement expenditure reflects the age profile of the asset population, the large proportion of assets installed beginning in the early 1960s, and the fact [that] many of the assets installed at that time are approaching the end of their expected lives” (United Energy 2004, p. 95). United Energy states that its replacement expenditure is driven by life extension programmes cost-effectively deferring expenditure from the current period to the next; increasing condemnation rates for poles; replacement of underground cable and low voltage pillars; and increases in the replacement of supervisory cables together with aged relays in a 10-year programme that commenced in 2003. Source: AGLE 2004, pp. 46-53; CitiPower 2004, pp. 60-65; Powercor 2004, pp. 66&68-69; SP AusNet 2004, pp. 78-80; United Energy 2004, p. 96. Wilson Cook and Co reviewed and analysed the consistency of the proposed replacement expenditure with the forecasts of weighted average remaining lives and other age profile information as well as asset management plans and processes. Its view was that the approach used by distributors to estimate replacement expenditure was consistent with normal planning procedures, and that the capital expenditure was targeted appropriately and could be considered reasonable. However, Wilson Cook and Co recommended that the expenditure provision be reduced in some areas. October 06 292 Essential Services Commission, Victoria Final Decision AGLE In its earlier report, Wilson Cook and Co recommended an adjustment to AGLE’s proposed expenditure to maintain reliability and quality of $13.1 million on the basis that it was overstated — the proposed expenditure was twice that of the 2001-03 period and programs such as the Preston network conversion project (categorised as reinforcement capital expenditure) had the potential for duplication with replacement capital expenditure. In its submission to the Draft Decision, AGLE (2005f, p. 56) was of the view that Wilson Cook and Co had not adequately taken into account two factors in reaching its conclusion to reduce the expenditure proposed. Firstly, the expenditure trend for this category of expenditure, and secondly, the age profile of the AGLE network. On further review of the supporting information provided by AGLE, Wilson Cook and Co noted that the increase in expenditure, including an adjustment of $13.1 million, was 70 per cent above historic expenditure. It considered this to be appropriate to allow for the ageing of assets and therefore retained the adjustment of $13.1 million. CitiPower CitiPower engaged PB Associates to verify its proposed capital expenditure to maintain reliability and quality. However, in making the comparison between PB Associates’ estimates and its own estimates, CitiPower identified an amount of $42 million for items that were not included in PB Associates’ estimates. In its earlier report, Wilson Cook and Co made an adjustment for this amount. In response to the Draft Decision, CitiPower provided further information to support the items removed by Wilson Cook and Co. These items related to labour cost escalation, direct overheads, indirect overheads, and the replacement of aluminium neutral screen service lines. Additionally, CitiPower increased its proposed expenditure to maintain reliability and quality, excluding labour cost escalation and indirect overheads, from $109.4 million to $130.5 million (an increase of $21.1 million). In light of the further information, Wilson Cook and Co considered that the expenditure proposed by CitiPower was reasonable, with the exception of the rate at which CitiPower proposed to replace aluminium neutral screen service lines. In its further report Wilson Cook and Co. therefore recommended an adjustment to this expenditure of 50 per cent ($4.1 million). Powercor When comparing PB Associates’ estimate to its own estimate, Powercor, like CitiPower, identified $39.9 million from its own forecasts for indirect (corporate) overheads and labour cost escalation and another $47.0 million for the Road Management Act, fault capital expenditure, chemical treatment of poles and bird covers, and safety compliance (service replacement and CMEN-related capital expenditure) that were not included in PB Associates’ estimates. In its earlier report, Wilson Cook and Co recommended that an adjustment of $63.8 million be made for these items. October 06 293 Essential Services Commission, Victoria Final Decision Powercor subsequently provided further supporting information. Additionally, Powercor increased its proposed expenditure to maintain reliability and quality, excluding labour cost escalation and indirect overheads, from $191.4 million to $257.5 million (an increase of $66.1 million). Following review of the additional information provided by Powercor, Wilson Cook and Co came to the view in its further report that the expenditure proposed by Powercor to maintain reliability and quality was reasonable. SP AusNet In its earlier report, Wilson Cook and Co suggested that SP AusNet’s proposed expenditure in this category was overstated by $15.2 million on the basis that it could not say with certainty that the forecast expenditure would be undertaken during the 2006-10 regulatory period. Following the Draft Decision, SP AusNet proposed two increases to its proposed capital expenditure to maintain reliability and quality — $10.9 million to replace ‘white stringy-bark’ poles and $5.05 million for terminal station works in conjunction with SPI Powernet’s asset replacement program. On review of further information provided by SP AusNet, Wilson Cook and Co noted in its further report that the expenditure proposed by SP AusNet to maintain reliability and quality was 48 per cent higher than historic expenditure, and that the expenditure in this category had increased considerably over the past two years. Nevertheless, based on this increase in expenditure, Wilson Cook and Co was of the view that the expenditure proposed by SP AusNet was reasonable and removed the adjustment of $15.2 million. United Energy In its earlier report, Wilson Cook and Co observed that the level of capital expenditure to maintain reliability and quality proposed by United Energy was 220 per cent higher than the historic expenditure and proposed a reduction of $71.8 million. In response to the Draft Decision, United Energy stated that the Commission was failing to meet its primary objective under the Essential Services Commission Act unless United Energy was provided with sufficient capital expenditure to maintain existing levels of reliability and quality. Furthermore, it stated that if the age profile of its asset base is permitted to become progressively older, reliability and quality will diminish unless countervailing measures are taken by it to deliver improvements. Additionally, further supporting information was provided by United Energy, including a reconciliation between the historic expenditure and proposed expenditure. Wilson Cook and Co accepted United Energy’s arguments in principle, but given the increase in proposed expenditure above historic levels, remained concerned that some projects may be deferred or delayed as in the past. In its further report, Wilson Cook and Co therefore reduced its recommended adjustment to this expenditure from $71.8 million to $23.4 million (10 per cent). October 06 294 Essential Services Commission, Victoria Final Decision The levels of projected capital expenditure to maintain reliability and quality for each of the distributors for the 2006-10 regulatory period are set out in Table 7.26. The adjustment includes adjustments for indirect (corporate) overheads and labour cost escalation, as discussed in Sections 7.2.5 and 7.2.6. Table 7.26: Capital expenditure — reliability and quality maintained, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ revised proposals 74.5 153.3 282.4 185.7 233.6 Wilson Cook and Co adjustment -13.1 -4.1 0.0 0.0 -23.4 -2.7 6.0 4.3 -2.6 14.7 Amount included in expenditure cap (2006-10) (a) 58.7 155.4 286.7 183.1 224.9 Historic expenditure (2001-04)a (b) 33.7 71.9 168.5 125.2 73.1 Variance (a-b) 25.0 83.6 118.2 57.9 151.8 74% 116% 70% 46% 208% Commission’s adjustment b a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate) overheads (refer Table 7.12) and other adjustments by the Commission Reliability and quality improved While the distributors undertake asset renewal and replacement to ensure the maintenance of current service reliability and quality levels, they also undertake investment in the network to improve service reliability and quality levels. The levels of capital expenditure proposed by the distributors to improve reliability and quality during the 2006-10 regulatory period are set out in Table 7.27. Table 7.27: Proposed capital expenditure — reliability and quality improved, all distributors, $million, real $2004 Historic expenditurea Distributors’ original proposals relative to historic expenditure Draft Decision relative to historic expenditure Distributors’ revised proposals relative to historic expenditure AGLE 3.6 -64% -100% -65% CitiPower 5.9 -100% -100% -100% Powercor 46.5 -5% -63% -10% SP AusNet 56.4 -13% -56% -52% United Energy 26.9 -57% -80% -80% a Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). October 06 295 Essential Services Commission, Victoria Final Decision With the exception of CitiPower, each of the distributors proposed expenditure in their original price-service proposals to improve the reliability of supply: • AGLE proposed $1.3 million to improve areas of poor reliability. • Powercor proposed approximately $11 million to improve the overall reliability performance to customers/areas currently receiving the lowest level of service and improve the ability to automatically detect outages through automated fault indicators. Powercor also proposed approximately $6.6 million to continue with existing reliability programs which will maintain the 2005 average reliability over the 2006-10 regulatory period. • SP AusNet proposed around $23 million to address reliability in its worst served areas — Murrindindi, Kinglake, Newmerella, Cann River, Mount Dandenong, Sassafras and Upwey. • United Energy proposed $12 million to, among other things, reduce the frequency of momentary interruptions and improve its performance in its worst served areas. In their enhanced offerings,86 CitiPower and Powercor proposed additional capital expenditure to achieve certain outcomes: • CitiPower proposed $28 million to, among other things, increase the number of customers who remain served during planned or unplanned transmission network contingencies and to underground network assets on the CBD fringe. • Powercor proposed $54 million to, among other things, improve reliability performance by targeting key feeders and reducing the impact and incidence of pole fires, and $38 million to improve the security of supply. Some distributors also made proposals to improve quality of supply: • Powercor proposed expenditure of $26.4 million to improve the quality of supply to customers/areas where the quality of supply is not compliant with the requirements of the Electricity Distribution Code, and to improve the proactive identification and rectification of supply quality issues. • SP AusNet proposed expenditure of $24 million to resolve quality of supply issues to ensure it complies with the Electricity Distribution Code and to install equipment to measure harmonics and flicker. • United Energy proposed $1.05 million per annum to improve the quality of supply delivered to customers so that it improves its compliance with the Electricity Distribution Code. In their enhanced offerings, CitiPower and Powercor also proposed additional expenditure to improve quality of supply: • 86 CitiPower proposed expenditure of $28 million to, among other things, reduce the number of voltage sags of duration less than 1 second in commercial/retail areas.87 Under CitiPower and Powercor’s enhanced offerings, customers would receive less of a real average price reduction in the next regulatory period in return for the delivery of these offerings. October 06 296 Essential Services Commission, Victoria Final Decision • Powercor proposed expenditure of $54 million over the 2006-10 regulatory period to, among other things, reduce the extent and impact of voltage fluctuations. While in the current regulatory period, expenditure was incorporated in the revenue requirement for distributors to improve service reliability, in the next regulatory period the focus is on retention of current average reliability levels and the cost of any improvements in average reliability is to be recovered through the service incentive mechanism (see Chapters 2 and 3). This decision is based on the limited information available to suggest that, notwithstanding pockets of poor reliability, customers do not value further improvements in the average level of reliability. Further, any additional funding for improvements in reliability should be linked to measurable outcomes. Consequently, the Commission considers that the revenue requirement should not include expenditure associated with further improvements in average reliability. Where improvements do occur distributors will receive additional revenue for these improvements through the S-factor scheme and the avoided GSL payments. Therefore, the Commission has excluded the distributors’ proposed capital expenditure on reliability improvements. Prior to the Draft Decision SP AusNet and United Energy had included expenditure to improve reliability. This has subsequently been removed from their proposed expenditure. Conversely, AGLE and Powercor indicated that the new incentive arrangements would not provide sufficient funding to improve the reliability for their worst served customers. The Commission notes that, even if the expenditure was provided to these distributors, there is no guarantee that the outcome would be delivered. The distributors have an incentive to defer these works and thereby improve their profitability. The incentive rates in the new service incentive arrangements have increased substantially relative to the existing rates. This will provide an incentive to the distributors to be innovative in delivering improved outcomes to these customers, and will provide a mechanism to increase revenue to fund these works. In contrast to the approach to expenditure for reliability improvements, the Commission has decided to incorporate amounts in the revenue requirement for improvements in the quality of supply where it is determined that a distributor is not currently in compliance with the quality standards set out in the Electricity Distribution Code, and recognising that there is currently no financial incentive under which additional revenue will be provided to the distributors where quality of supply improves. Wilson Cook and Co reviewed the expenditure proposed by the distributors to improve quality of supply to meet the standards set out in the Electricity Distribution Code. In its earlier report, Wilson Cook and Co expressed the view that the expenditure proposed by SP AusNet and United Energy was reasonable, but that the expenditure proposed by Powercor was not. Wilson Cook and Co considered that the amount proposed by Powercor constituted a provision. 87 Proposed commercial/retail areas to be targeted by CitiPower include Armadale, Camberwell Junction, Prahran/Richmond, Collingwood, South Melbourne, Albert Park and Port Melbourne. October 06 297 Essential Services Commission, Victoria Final Decision Based on additional supporting information provided by Powercor, Wilson Cook and Co in its further report reduced its earlier recommended adjustment from $11.5 million for the Draft Decision to $7 million. The Commission has received a large amount of feedback at public information sessions and in submissions that indicates that stakeholders, particularly in rural and regional areas, are concerned with the quality of supply that they currently receive (see Chapter 2). Given these concerns, the Commission considers that additional monitoring of supply quality in rural areas is required and that the cost of increasing the number of voltage monitoring devices installed by 20 per cent should be incorporated into the revenue requirement (see Chapter 2). The data obtained from this additional monitoring will assist the Commission, the distributors and customers in understanding the distributors’ level of compliance with the Electricity Distribution Code’s requirements, the level of quality received by customers and where improvements should be made. To this end, the Commission has decided to include in the revenue requirement: • an additional 27 sophisticated voltage monitoring devices to be installed by Powercor during 2006, at a cost of $648 000; and • an additional 17 sophisticated voltage monitoring devices to be installed by SP AusNet during 2006, at a cost of $408 000. The levels of capital expenditure for each of the distributors for the 2006-10 regulatory period to improve reliability and quality, including adjustments for indirect (corporate) overheads and labour cost escalation, is set out in Table 7.28. Table 7.28: Capital expenditure — reliability and quality improved, all distributors, 2006-10 regulatory period, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ revised proposals 1.3 0.0 41.9 27.1 5.4 Wilson Cook and Co adjustment -1.3 0.0 -22.4 0.0 0.0 Commission’s adjustmentb 0.0 0.0 0.9 0.1 0.3 Amount included in expenditure cap (2006-10) (a) 0.0 0.0 20.4 27.2 5.7 Historic expenditure (2001-04)a (b) 3.6 5.9 46.5 56.4 26.9 Variance (a-b) -3.6 -5.9 -26.1 -29.2 -21.2 -100% -100% -56% -52% -79% a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure is divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate) overheads (refer Table 7.12) and other adjustments by the Commission October 06 298 Essential Services Commission, Victoria Final Decision Environmental, safety and legal Capital expenditure for environmental, safety and legal matters refers to expenditure that distributors may need to undertake to ensure that they are compliant with the requirements of Energy Safe Victoria (ESV), the Environmental Protection Agency (EPA) and other legal and regulatory requirements. The distributors proposed very large increases in environmental, safety and legal capital expenditure over the next regulatory period (see Table 7.29). This expenditure has been proposed to comply with: • electricity safety regulations; • environmental obligations; • infrastructure security obligations; • the Road Management Act 2004; and • safety obligations. Additionally, some distributors proposed capital expenditure for: • undergrounding; and • a Technology Development Fund. Table 7.29: Proposed capital expenditure — environmental, safety and legal, all distributors, $million, real $2004 Historic expenditurea Distributors’ original proposals relative to historic expenditure Draft Decision relative to historic expenditure Distributors’ revised proposals relative to historic expenditure AGLE 7.2 364% 241% 364% CitiPower 1.2 3637% 2590% 3378% Powercor 22.6 488% 196% 239% SP AusNet 0.0 0% 0% 0% United Energy 13.2 613% 155% 540% a Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). The Commission has been in discussions with ESV and the distributors regarding the expected costs to comply with the electrical safety regulations over the 2006-10 regulatory period. On the basis of these discussions the Commission has made adjustments to the capital expenditure proposed by AGLE and CitiPower, which are discussed in more detail in the following sections. Wilson Cook and Co reviewed the balance of the expenditure proposed by the distributors. In summary, Wilson Cook and Co’s recommendations, which are discussed in more detail in the following sections, are: • Environmental — reduction in expenditure proposed by AGLE; October 06 299 Essential Services Commission, Victoria Final Decision • Infrastructure security — no reductions in expenditure; • Road Management Act — reduction in expenditure proposed by AGLE; • Safety — reduction in expenditure proposed by SP AusNet; • Undergrounding — expenditure proposed by United Energy should not be included in revenue requirements; and • Technology Development Fund — expenditure proposed by United Energy should not be included in revenue requirements. The levels of capital expenditure for environmental, safety and legal (including adjustments for indirect overheads and labour rate escalation) for each of the distributors for the 2006-10 regulatory period are set out in Table 7.30. Table 7.30: Capital expenditure — environmental, safety and legal, all distributors, 2006-10, $million, real $2004 Distributors’ revised proposals AGLE CitiPower Powercor SP AusNet United Energy 33.5 40.2 76.7 102.7 84.6 Wilson Cook and Co adjustment c d -1.1 0.0 0.0 -5.2 -35.0e Commission’s adjustmentb -13.9 -1.4 1.3 0.7 2.9 Amount included in expenditure cap (2006-10) (a) 18.5 38.8 78.0 98.2 52.5 Historic expenditure (2001-04)a (b) 7.2 1.2 22.6 0.0 13.2 Variance 11.3 37.6 55.3 98.2 39.3 157% 3253% 244% 0% 297% a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period. b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate) overheads (refer Table 7.12) and adjustments by the Commission associated with the electrical safety regulations. c Includes an adjustment of $0.7 million for environmental and $0.4 million for the Road Management Act. d Adjustment to the proposed expenditure associated with safety. e Includes an adjustment of $10 million for undergrounding and $25 million for the Technology Development Fund Electrical safety regulations The distributors are required to comply with a variety of legislative and regulatory requirements including the Electricity Safety (Network Assets) Regulations 1999. A major audit was conducted by the former Office of the Chief Electrical Inspector during the 2001-05 regulatory period which identified that the distributors did not comply with a number of the regulations, specifically: • Regulation 13 — Minimum distances between aerial lines and the ground, particularly those over driveways • Regulation 17 — Minimum distances between aerial lines and parts of tramway systems October 06 300 Essential Services Commission, Victoria Final Decision • Regulation 22 — Substations – minimum distances for pole mounted substations • Regulation 23 — Earthing and electrical protection – a low voltage network asset must be earthed so that the resistance of the neutral conductor of the service line is not more than 1 ohm to earth • Regulation 27 — Inspection and testing – earth systems must be tested every ten years. The Electricity Safety Act 1998 provides the opportunity for distributors to apply for variations to the Regulations by means of exemptions from the Regulations to achieve equal or better safety outcomes applicable to networks through the establishment of electricity safety management schemes (ESMSs). The Act also provides the opportunity for persons authorised under an approved scheme to be exempt from certain sections of the Act or from the Regulations. The distributors have each developed and submitted Electricity Safety Management Schemes (ESMSs) to Energy Safe Victoria (ESV).88 At the time the price-service proposals were received, none of the distributors’ ESMSs had been gazetted through an Order in Council. However, the Commission understands that all distributors have now had their ESMSs gazetted in the form submitted. Additionally, the distributors have submitted Electricity Safety Management Plans (ESMPs) to ESV identifying plans to achieve compliance with specific regulations. In developing their ESMPs, the distributors have assumed that ESV will be able to grant exemptions to certain safety regulations. At the time the price-service proposals were received, ESV’s powers to grant exemptions were unclear, however the legislation was recently amended to clarify ESV’s powers. ESV is now able to recommend to the Governor in Council that a scheme be accepted where it: is satisfied that the level of safety to be provided by the scheme minimises as far as practicable – (i) the hazards and risks to the safety of any person arising from the upstream network to which the scheme applies; and (ii) the hazards and risks of damage to the property of any person arising from the upstream network to which the scheme applies. Whilst some distributors, principally SP AusNet and United Energy, have been undertaking works to improve their compliance with the Regulations, other distributors, principally CitiPower and Powercor, have focused on risk assessments and seeking exemptions to the Regulations. Since the Draft Decision, the Commission has met with the distributors and ESV to obtain a better understanding of the regulations that the distributors do not currently comply with and the actions that will be required to move towards compliance over the 2006-10 regulatory period. 88 ESV includes the functions of the former Office of the Chief Electrical Inspector (OCEI) October 06 301 Essential Services Commission, Victoria Final Decision Each distributor has provided more detail in regard to the expenditure that will be required for this purpose and has detailed the actions that will be undertaken. Furthermore, ESV has now granted an exemption to CitiPower in relation to the height of aerial service lines and has been in discussions with Powercor regarding its exemption in relation to the height of aerial service lines. In their original price-service proposals, each distributor identified large expenditures associated with achieving compliance with the ESV regulations. The distributors submitted forecast costs on the basis of two scenarios: • a risk management approach — which assumes certain exemptions to the safety regulations are granted by ESV; and • literal compliance — which assumes the distributors must literally comply with the safety regulations. The Commission considered the expenditure proposed by the distributors under a risk management approach in assessing a reasonable level of expenditure for the Draft Decision. In response, AGLE (2005f, p. 2) reaffirmed that its ‘Current Regulatory Obligations’ scenario is applicable because no exemptions have been granted to it. The Commission considers that any amount included in the expenditure requirements should represent the requirements of an efficient distributor. It does not appear that the approach adopted by AGLE is consistent with the approach that would be expected to be taken by an efficient distributor. The Commission has sought further information from AGLE regarding the most likely costs it would incur in complying with the safety regulations on the assumption that it is granted exemptions from compliance, similar to those that have been, or are likely to be, granted to the other distributors. This information has now been provided. The Commission considered this information when assessing the reasonable expenditure for AGLE for each regulation. CitiPower (2005e, p. 1) and Powercor indicated that their proposals were based on a risk management approach in anticipation that ESV would grant exemptions from literal compliance. To date, an exemption has only been provided to CitiPower for aerial service lines. In the event that exemptions were not granted for any items prior to the Final Determination, CitiPower and Powercor suggested that a pass through should be considered. The Commission has given consideration to this proposal. However, it considers that there is sufficient certainty regarding the actions to be undertaken by the distributors to improve compliance with each of the regulations, except regulation 23(11),89 for a reasonable level of expenditure to be forecast. The Commission was initially of the view that a pass through mechanism should be included in the price controls to allow the pass through of costs to comply with regulation 23(11) and any 89 Regulation 23(11) relates to the resistance of the neutral service conductor to earth, particularly in rural areas. October 06 302 Essential Services Commission, Victoria Final Decision associated exemptions when there is greater certainty over what these costs will be. However, with the Commission’s approach to assessing a reasonable level of capital expenditure in aggregate, the Commission no longer considers it necessary to include such a mechanism. Where a distributor spends more than forecast, the capital expenditure will be rolled into the regulatory asset base. Additionally, the Commission has foreshadowed that, at the time of the next price review, the regulator has the discretion to roll the financing costs associated with the additional capital expenditure incurred up to a cap, into the regulatory asset base. Hence, the Commission has included a level of capital expenditure that is consistent with ESV’s current understanding of the actions that are required to meet the conditions of any exemptions granted or to be granted. In assessing the capital expenditure proposals, the Commission notes that $168.3 million (in 1999 dollars) was included in aggregate in the distributors’ capital expenditure forecasts for the 2001-05 regulatory period for compliance with environmental, safety and legal obligations. The distributors have significantly underspent relative to this forecast. Of this aggregate amount, $34.2 million (in 1999 dollars) was included for compliance with the electricity safety regulations. Regulation 13 — Minimum distances between aerial lines and the ground, particularly those over driveways The forecast expenditure proposed by the distributors as being required to improve compliance of aerial line clearance heights, together with the distributors’ assumptions, is set out in Table 7.31. The forecast operating expenditure and capital expenditure is also provided to appropriately compare where different capitalisation policies has been adopted. Table 7.31: Distributors’ proposed expenditure, aerial service lines, all distributors, 2006-10, $million, real $2004 Opex Capex Total AGLE 0.0 5.5 5.5 CitiPower 1.7 5.8 7.5 Powercor 8.4 16.9 25.3 SP AusNet 3.1 12.6 15.7 United Energy 0.4 24.8 25.1 Assumptions Based on precedent in CitiPower’s and Powercor’s exemption application Approx 792 aerial service lines to be rectified per annum Approx 3,450 aerial service lines to be rectified per annum Prorated based on Powercor’s risk analysis and the number of residential customers Additional 2000 service audits per annum, Priority 1 and 2 services to be replaced in years 1-4, priority 3 services in year 5 Discussions with ESV have indicated that CitiPower’s and Powercor’s assumptions are reasonable based on the information provided to ESV in support of their exemption applications. In the absence of an application for an exemption, SP AusNet forecast its expenditure by prorating Powercor’s costs based on the ratio of residential customers. The Commission October 06 303 Essential Services Commission, Victoria Final Decision considers this approach to be reasonable. However, the Commission also notes that Powercor’s forecast expenditure has increased since SP AusNet submitted its costs due to a late change to Powercor’s exemption application by ESV. The Commission has therefore prorated these additional costs for SP AusNet and increased its forecast expenditure from $12.6 million to $14.6 million accordingly. AGLE’s and United Energy’s forecast expenditure were determined by prorating the expenditure proposed by CitiPower and Powercor respectively, based on the number of residential customers. Whilst United Energy’s expenditure appears reasonable using this approach, AGLE’s appears low. Accordingly AGLE’s proposed expenditure has been adjusted upwards from $5.5 million to $8.2 million. The forecast step change in operating and maintenance expenditure was considered by the Commission in Chapter 6. Regulation 17 — Minimum distances between a.c. aerial lines and parts of tramway systems The forecast expenditure proposed by the distributors as being required to improve compliance of tramway assets, together with the distributors’ assumptions, is set out in Table 7.32. The forecast operating expenditure and capital expenditure is also provided to appropriately compare where different capitalisation policies have been adopted. Table 7.32: Distributors’ proposed expenditure, tramway assets, all distributors, 200610, $million, real $2004 Opex AGLE 0.1 Capex 1.8 Total Assumptions 1.9 Opex - Inspection of all 1585 poles shared with tramways and a survey of unattached aerial crossings of about 37km of tram track. Capex - 174 low voltage lines to be modified over five years Opex – additional minor works procedures, replace 10 tramways owned poles per year. Capex – relocation of CitiPower overhead assets in vicinity of tramway assets CitiPower 0.3 5.0 5.3 Powercor 0.0 0.0 0.0 SP AusNet 0.0 0.0 0.0 United Energy 0.1 0.3 0.4 Opex – one off survey. Capex – rectify some level of non compliance Discussions with ESV have indicated that the level of non-compliance with this particular regulation is very high. ESV therefore expects the distributors to submit an application for an exemption and that minimal rectification work will be required. Given that minimal rectification work is expected to be required, the capital expenditure proposed by AGLE and United Energy appears reasonable. However the capital expenditure October 06 304 Essential Services Commission, Victoria Final Decision proposed by CitiPower appears high relative to that proposed by AGLE. The Commission has exercised its judgement to adjust downwards CitiPower’s capital expenditure relative to its proposal, from $5.0 million to $2.0 million. The forecast step change in operating and maintenance expenditure was considered by the Commission in Chapter 6. Regulation 22 — Substations – minimum distances for pole mounted substations The forecast expenditure proposed by the distributors as being required to improve compliance of pole mounted substations, together with the distributors’ assumptions, is set out in Table 7.33. The forecast operating expenditure and capital expenditure is also provided to appropriately compare where different capitalisation policies have been adopted. Table 7.33: Distributors’ proposed expenditure, pole mounted substations, all distributors, 2006-10, $million, real $2004 Opex Capex Total Assumptions AGLE 0.3 1.1 1.3 CitiPower 0.4 7.0 7.4 Powercor 0.0 10.0 10.0 Opex – 700 inspections per annum Opex – 800 inspections per annum and additional monitoring of 60 substations per annum. Capex – 200 aerial substations to be replaced per annum Capex – 400 aerial substations to be replaced per annum SP AusNet 0.0 0.0 0.0 United Energy 0.0 9.7 9.7 Opex – Program commenced in 2005 and is due to be completed by the end of 2008. Discussions with ESV indicate that the activity proposed by the distributors appears reasonable. The Commission is therefore of the view that the capital expenditure proposed by the distributors to improve compliance with this particular regulation is reasonable. The forecast step change in operating and maintenance expenditure was considered by the Commission in Chapter 6. Regulation 23 – Earthing and electrical protection – a low voltage network asset must be earthed so that the resistance of the neutral conductor of the service line is not more than 1 ohm to earth The forecast expenditure proposed by the distributors as being required to improve compliance with the earthing requirements, together with the distributors’ assumptions, is set out in Table 7.34. The forecast operating expenditure and capital expenditure is provided to appropriately compare where different capitalisation policies have been adopted. October 06 305 Essential Services Commission, Victoria Final Decision Table 7.34: Distributors’ proposed expenditure, earthing and electrical protection, all distributors, 2006-10, $million, real $2004 Opex Capex Total AGLE 10.4 15.8 26.2 CitiPower 2.0 0.0 2.0 Powercor 9.5 0.3 9.8 SP AusNet 0.0 0.1 0.1 United Energy 17.1 0.0 17.1 Assumptions Opex – a more sophisticated test of half services @ $93 per test Opex – 15,000 tests per annum @ $35 per test, plus a controlled sample test of 1,500 services per annum @ $50 per test Opex – 52,000 tests per annum @ $35 per test, plus a controlled sample test of 1,500 services per annum @ $50 per test Opex and capex based on a risk management approach. Cost to comply with current regulations is $87.5m over the five year period. If all service cables tested every 10 years, then $16.4 million over 5 years based on 563,000 services. Opex – 132,500 tests per year until 2010 and 62,000 tests in 2010 @ $32 per test. Discussions with the ESV and the distributors indicate there is currently no certainty regarding what actions are to be taken by the distributors to ensure that the resistance of the neutral conductor of the service line is not more than 1 ohm to earth, particularly in rural areas, although information is available regarding the tests to be undertaken to determine the resistance. With the exception of AGLE, the distributors have forecast an immaterial level of capital expenditure to meet the requirement that the resistance of the neutral conductor of the service line is not more than 1 ohm to earth. Given the uncertainties associated with this regulation, the capital expenditure forecast by AGLE has been removed. The forecast step change in operating and maintenance expenditure was considered by the Commission in Chapter 6. Regulation 27 — Inspection and testing – earth systems must be tested every ten years The forecast expenditure proposed by the distributors as being required to improve compliance of inspection and testing, together with the distributors’ assumptions, is set out in Table 7.35. The forecast operating expenditure and capital expenditure is provided to appropriately compare where different capitalisation policies have been adopted. October 06 306 Essential Services Commission, Victoria Final Decision Table 7.35: Distributors’ proposed expenditure, inspection and testing, all distributors, 2006-10, $million, real $2004 Opex Capex Total AGLE 0.3 4.1 4.3 CitiPower 0.7 0.7 1.3 Powercor 4.0 3.1 7.1 SP AusNet 0.8 7.4 8.2 United Energy 0.0 0.9 0.9 Assumptions Opex - additional testing of earths in rural areas approximately 320 test per annum @ $155 per test Opex – test regime of high risk assets (580 tests per annum @ $125 per test) and random sample across network (500 tests per annum @ $125 per test) Opex – targeted test regime ($125,000 per annum) and additional program for SWER distribution substations ($675,000 per annum) Opex – 10,700 tests of SWER isolators and substations ($0.9m, incremental cost = $0.8m) The capital expenditure proposed by the distributors to improve compliance with inspection and testing requirements appears reasonable. The forecast step change in operating and maintenance expenditure was considered by the Commission in Chapter 6. The forecast capital expenditure to improve safety compliance that will be included in the distributors’ revenue requirement is set out in Table 7.36. Table 7.36: Forecast capital expenditure for safety compliance, all distributors, 2006-10, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Aerial service lines 8.2 5.8 16.9 14.6 24.8 Tramway assets 1.8 2.0 0.0 0.0 0.3 Substation heights 1.1 7.0 10.0 0.0 9.7 Earthing and electrical protection 0.0 0.0 0.3 0.1 0.0 Inspection and testing 4.1 0.7 3.1 7.4 0.9 Total 15.2 15.5 30.3 22.1 35.7 Electric line clearance The Electricity Safety (Electric Line Clearance) Regulations 2005 were promulgated on 1 July 2005. These Regulations clarify various issues relating to the encroachment of vegetation towards electric lines. October 06 307 Essential Services Commission, Victoria Final Decision Only United Energy proposed capital expenditure to comply with these Regulations. It submitted a plan to ESV to remove overhangs by replacing bare overhead conductor with aerial bundled conductor. The amount proposed ($5.9 million) enables them to continue with this program. The Commission considers that the amount proposed is reasonable. Environmental Each of the distributors proposed additional capital expenditure to bring them into compliance with legislative changes impacting on their environmental obligations. These proposals include: • Oil containment — the bunding of some large transformers and other items of oil filled plant that are claimed to not conform to ‘literal’ compliance with current EPA regulatory requirements and Australian Standard (AS 1940 – 1993) requirements. • Noise abatement — distributors are required to maintain noise at the nearest residence to within levels complying with the State Environment Protection Policy (Control of Noise from Commerce, Industry and Trade) No N-1. With increased urbanisation, the distributors anticipate that, prior to 2010, at least some zone substations will become the subject of complaint from the occupants of nearby residences. • Asbestos regulations — during 2003 the State Government imposed more rigorous restrictions on the use and control of asbestos products and materials containing asbestos. The new regulations, the Occupational Health and Safety (Asbestos) Regulations 2003, combined with recent prohibitions made under the auspices of the Dangerous Goods Act 1985, require distributors to reduce potential exposure to asbestos. • Compliance with EPA guidelines — an increasing industry focus on compliance with EPA Guidelines (led by NSW distribution businesses) has highlighted potential areas that are claimed to need addressing in the 2006-10 regulatory period. Environmental-related expenditure proposed by the distributors was as follows: • AGLE — asbestos regulations ($1.2 million), oil containment ($0.6 million), noise abatement ($1.8 million). • CitiPower — noise abatement and management of oil spills ($13.1 million in total). • Powercor — relocation of overhead lines for vegetation clearance and bushfire mitigation ($52 million). • SP AusNet — asbestos regulation, compliance with EPA guidelines, management of oil spills and noise abatement ($10.5 million in total). • United Energy — noise abatement ($2.5 million), EMF tolerances ($1.5 million), and bushfire mitigation ($1.7 million). Wilson Cook and Co reviewed this proposed expenditure and was of the view that, with the exception of AGLE, it was reasonable, although it regards the expenditure proposed by CitiPower for oil containment works as provisional. An adjustment of $0.7 million to AGLE’s expenditure was recommended on the basis that the amount was considered to constitute a October 06 308 Essential Services Commission, Victoria Final Decision provision that may not be needed in full, the timing of projects of this nature can change, and the work might be deferred. The environmental-related capital expenditure is included in Table 7.30. Infrastructure security AGLE, SP AusNet and United Energy proposed capital expenditure of between $1.2 million and $16.6 million to improve the security of infrastructure (see Table 7.37). With this expenditure, these distributors aimed to prevent or minimise the impacts of acts of terrorism. Table 7.37: Distributors’ proposed total expenditure associated with infrastructure security, all distributors, $million, real $2004 Expenditure item AGLE CitiPower Powercor SP AusNet United Energy Capital expenditure 1.2 0.0 0.0 16.6 4.8 Operating expenditure 0.3 1.9 2.9 3.2 1.5 Total 1.5 1.9 2.9 19.8 6.3 Note: May not add due to rounding. AGLE’s proposed expenditure in this area is aimed at increasing the security of zone substations, while United Energy’s proposed expenditure is to: • assist in providing a consistent approach to identify and prioritise critical infrastructure; • consistently assess and treat security risks; • identify specific assets that, if immobilised, would result in widespread community impact; • identify specific actions and liaise with state emergency response agencies; and • provide assurance to the Government and community groups of pro-active preventative measures in respect to critical infrastructure assets. SP AusNet linked its proposal to obligations established under the Terrorism (Community Protection) Act 2003. SP AusNet stated that the expenditure is required to increase security measures at critical infrastructure sites and to develop contingency capabilities to manage loss of key infrastructure. Wilson Cook and Co reviewed this expenditure and in its opinion the majority of the expenditure proposed by distributors in this category was reasonable. The capital expenditure to secure the distributors’ infrastructure is included in the amounts set out in Table 7.30. Road Management Act 2004 The Road Management Act 2004 (RMA) aims to establish a coordinated management system for public roads that is intended to promote safe and efficient State and local public road networks October 06 309 Essential Services Commission, Victoria Final Decision and the responsible use of road reserves for other legitimate purposes, such as the provision of utility services. The RMA came into effect for utilities on 1 January 2005. Whilst all distributors have identified the RMA as impacting upon their operating and maintenance expenditure (see Chapter 6), AGLE is the only distributor to identify an impact on capital expenditure ($4.6 million) in this asset category for the 2006-10 regulatory period. However, CitiPower and Powercor have proposed additional capital expenditure for reinforcements and replacements for compliance with the RMA. AGLE has indicated that its proposed expenditure is required to: • reflect the increase in the cost of all capital works due to the resultant increase in complexity of work planning and reporting processes; and • install protective barriers or bury assets where lines are proposed. While the Commission considers the RMA is a new obligation and so additional expenditure relative to historic expenditure is justified, it notes that Wilson Cook and Co did not accept AGLE’s notification and permit component ($348 000 over the period) and considered the balance to be high. Wilson Cook and Co recommended an adjustment of $0.4 million in total to the capital expenditure proposed by AGLE to comply with the RMA. The capital expenditure for complying with the Road Management Act is included in Table 7.30. Safety AGLE and SP AusNet proposed capital expenditure relating to safety. Specifically, this expenditure was for: • compliance with regulations regarding “working at heights” ($1.0 million) (AGLE); and • accelerated replacement of selected assets (above that indicated by age and condition assessments) which may reduce fire ignitions and safety incidents ($37.3 million) (SP AusNet). The Commission notes the advice of Wilson Cook and Co, who commented that: • AGLE’s expenditure on working at heights was reasonable, and could be accepted in lieu of an operating expenditure step change for this expense; and • in SP AusNet’s case, this work, if carried out, would result in savings in asset replacements. Wilson Cook and Co therefore considered that it was likely that offsetting savings could be made in other capital expenditure categories as a result of the work proposed, and so recommended that consideration should be given to a reduction in the overall level of capital expenditure to account for duplication with other works. An adjustment of $5.2 million was recommended. The safety-related capital expenditure is included in Table 7.30. October 06 310 Essential Services Commission, Victoria Final Decision Undergrounding United Energy forecast capital expenditure of $10 million to underground parts of its network which, according to its submission, is driven by three key factors relating to its 22kV distribution assets: • improvements in public safety; • enhancement of the visual amenity; and • improvements in system reliability and performance. United Energy suggested that arrangements could be put in place to provide assurance to all stakeholders that its revenue requirement would be adjusted to permit it to recover only the cost of works actually completed under this program. At the time of the last price review, the ORG did not allow expenditure of this type to be reflected in the price controls for this regulatory period because the ORG believed that there was no sound basis for requiring all customers to contribute to the cost of a project that benefits particular customers only. However, it was noted that there were sound arguments for requiring distributors to contribute their avoided costs to such projects (ORG 2000a, p. 75). The ORG (2000a, p. 77) also noted that its decision did not prevent United Energy’s proposal from being further developed in consultation with municipalities and customers. VicRoads (2005, p. 1) indicated its support for United Energy’s proposed expenditure on undergrounding. An annual program of $2 million would be a relatively modest commitment given the scope of the problem of collisions with utility poles. However, it is considered that the returns to the community through a carefully targeted program developed in conjunction with VicRoads would be significant, both in economic terms and the broader impacts of road trauma. United Energy (2005c) also commented that: In regard to the general undergrounding program UED would be looking to support local council and community projects where undergrounding of network assets would provide environmental, safety, aesthetic and network operational benefits. Again however, the direct benefit to UED as the distributor is likely to be marginal in comparison to the community benefit derived. The Commission notes that United Energy and VicRoads were strong proponents of undergrounding during the last Price Review (ORG 2000a, p. 75-77). Conversely, the EUCV (2005b, p. 38) supported the Commission’s view that no additional funding for undergrounding should be considered as part of this review. October 06 311 Essential Services Commission, Victoria Final Decision The Commission has decided that where undergrounding is required it should be paid for by those who require it. Where it is considered that a public benefit would result, the Commission encourages the distributor and other proponents to seek support from policy makers. This decision does not prevent undergrounding projects from being undertaken. It does however prevent these projects from being paid for by customers who do not value them. The Commission also notes that, following the last Price Review, the State Government established a Powerline Relocation Scheme. Under this scheme, the Government funds up to 50 per cent of the cost of placing powerlines underground, or otherwise relocating them, where a community benefit will result. This is considered to be a more appropriate mechanism for obtaining the funds required to underground network assets where there is a community benefit. Additionally, the Commission is of the view that the incentive-based nature of its framework and approach will provide suitable stimulus to ensure that distributors assess such projects on their merits, and undertake undergrounding where the benefit to the distributor outweighs the cost. The Commission does not consider an allowance should be made for capital expenditure for undergrounding. Technology Development Fund United Energy proposed to contribute $5 million per annum to a Technology Development Fund, to provide practical and financial support to groups and institutions to undertake research and development activities to facilitate improvements in reliability, power quality and service performance. United Energy proposed that the Commission adjust its revenue requirement so that it only recovers the costs of work actually completed under the program. Wilson Cook and Co noted that the object of the fund was desirable, although other bodies carry out this work nationally and internationally. In addition, most if not all electricity distributors develop new techniques and improve their understanding of such issues in the normal course of their work. United Energy (2005c, p. 36) noted that the proposed technology fund was similar to the Innovation Funding Incentive allowed by Ofgem. UED has proposed an independent governance structure for the Community Program (which would oversee funding of the Technology Development Fund). Under the proposed arrangements, funding would only be available for works actually carried out, thus effectively addressing the Commission’s concern that funds may be allocated to R&D but not expended. EUCV (2005b, p. 40) supported the Commission’s view that inadequate support or justification had been provided by United Energy. The Commission is of the view that, where a distributor can identify benefits in pursuit of efficiencies, the power of the incentive-based framework would promote the distributors’ development of such programs without any additional funding. In relation to reliability benefits, October 06 312 Essential Services Commission, Victoria Final Decision where projects can provide a measurable impact on reliability, the distributor benefits through the S-factor scheme and the avoided payment of GSL payments. The Commission does not consider that an allowance should be made for capital expenditure for a Technology Development Fund. SCADA/Network control SCADA/Network control assets are used in the monitoring and control of network systems, including their associated main stations, remote terminal units and communication links. The level of expenditure proposed by the distributors under this category varied, with some distributors proposing large increases and others proposing declines over the 2006-10 regulatory period (see Table 7.38). Table 7.39 sets out the reasons for the distributors’ proposed level of expenditure. Table 7.38: Proposed capital expenditure — SCADA/Network control, all distributors, $million, real $2004 Historic expenditurea Distributors’ original proposals relative to historic expenditure Draft Decision relative to historic expenditure Distributors’ revised proposals relative to historic expenditure AGLE 1.1 1167% 1076% 1169% CitiPower 8.0 -8% -16% -14% Powercor 46.5 -63% -73% -65% SP AusNet 3.0 832% 792% 861% United Energy 0.0 - - - a Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). Table 7.39: Reasons cited for the proposed SCADA/Network control capital expenditure Reasons AGLE New SCADA system required over 2008 and 2009. Work to replace the ageing copper communications network with a modern fibre optic network will continue during the 2006-10 period. CitiPower Does not own a SCADA system as it contracts this service from SPI Powernet. Works proposed include replacement of aged communications equipment, upgrading zone substation monitoring and control systems, additional SCADA data security and security monitoring, and replacement of aged remote fault monitoring units. Powercor Works proposed include rationalisation and integration of control centre operational systems, migration to a fibre optic network, continuing investment in network monitoring and control, establishment of back-up SCADA communications links, alternate communications medium to trunk radio network, and improving communications capacity and SCADA polling time. SP AusNet Replace existing SCADA systems, increase the scale and scope of network monitoring and control, provide real-time monitoring and control of the total electricity network. United Energy No expenditure proposed. Source: AGLE 2004, pp. 57-58; CitiPower 2004, p. 71; Powercor 2004, p. 76; SP AusNet 2004, p. 93. October 06 313 Essential Services Commission, Victoria Final Decision Expenditure on SCADA/Network control assets is highly variable because of the need to upgrade these assets only periodically. Expenditure in excess of that incurred in previous regulatory periods will be necessary if the systems in place require upgrading and this did not occur in the previous regulatory period. Wilson Cook and Co’s view was that the estimates of expenditure under this category were reasonable based on the information that it had available. The level of SCADA/Network control capital expenditure for each distributor for the 2006-10 regulatory period (including adjustment for indirect (corporate) overheads and labour cost escalation) is set out in Table 7.40. Table 7.40: Capital expenditure — SCADA/Network 2006-10 regulatory period, $million, real $2004 control, all distributors, AGLE CitiPower Powercor SP AusNet United Energy Distributors’ revised proposals 14.0 6.9 16.2 28.9 0.0 Wilson Cook and Co adjustment 0.0 0.0 0.0 0.0 0.0 -0.6 0.3 0.2 -0.3 0.0 Amount included in expenditure cap (2006-10) (a) 13.4 7.2 16.4 28.6 0.0 Historic expenditure (2001-04)a (b) 1.1 8.0 46.5 3.0 0.0 Variance 12.3 -0.8 -30.0 25.6 0.0 1115% -10% -65% 852% 0% Commission’s adjustment b a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate) overheads (refer Table 7.12) and other adjustments by the Commission Non-network general assets — IT The distributors undertake expenditure on non-network general assets — IT to install or upgrade computer systems such as customer service systems, billing and collection systems, project management systems, fault recording systems, GIS systems, asset management databases, fleet management systems and security systems. There are also the usual corporate systems such as accounting and financial reporting systems, management reporting systems, payroll and HR systems and administrative systems. Relative to the actual level of IT expenditure undertaken between 2001 and 2004, the distributors are proposing either increases or decreases in the level of IT expenditure in the 2006-10 regulatory period (see Table 7.41). The reasons the distributors have given for the level of expenditure that they are proposing are set out in Table 7.42. October 06 314 Essential Services Commission, Victoria Final Decision Table 7.41: Proposed capital expenditure — non-network general assets — IT, all distributors, $million, real $2004 Historic expenditurea Distributors’ original proposals relative to historic expenditure Draft Decision relative to historic expenditure Distributors’ revised proposals relative to historic expenditure AGLE 24.4 87% -7% 80% CitiPower 52.0 -20% -21% -21% Powercor 41.7 90% 50% 87% SP AusNet 45.8 -85% -86% -75% United Energy 42.9 17% -6% 42% a Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). Table 7.42: Reasons cited for the proposed non-network general assets — IT capital expenditure Reasons AGLE Works proposed include a major system replacement program to deliver full ring fencing and interval meter roll out compliance, the replacement of hardware that has reached the end of its useful life, and costs for licence and system updates. CitiPower Works proposed include distribution systems, customer service systems, corporate IT requirements, IT infrastructure and security. Powercor Works proposed include distribution systems, customer service systems, corporate IT requirements, IT infrastructure and security. SP AusNet Works proposed include works associated with the Enterprise Asset Management System, Revenue Management System, Enterprise Application Integration, Knowledge Management System, Reporting and Data Interrogation, and Accessibility and Mobility Automation. United Energy Works proposed include works associated with technology infrastructure such as PC/LAN network and printers, billing systems, asset management systems, financial systems and storage and hardware. Source: AGLE 2004, pp. 59-64; AGLE (2005 ref); CitiPower 2004, pp. 68-70; Powercor 2004, pp. 72-74; SP AusNet 2004, p. 91; United Energy 2004, p. 99. As with SCADA/Network control assets, IT-related assets only require upgrading periodically. Consequently, it is expected that the level of expenditure undertaken under this category of capital expenditure will fluctuate from one regulatory period to another. Above-average expenditure relative to actual expenditure will be necessary if systems that were not upgraded in the last regulatory period now require replacement or upgrading. Wilson Cook and Co reviewed the proposed IT-system plans and associated expenditure of each of the distributors and generally considered the expenditure reasonable on the basis of the information that was before it. In its earlier report, Wilson Cook and Co recommended an adjustment to the expenditure proposed by AGLE and United Energy of $22.7 million and $10.0 million respectively. October 06 315 Essential Services Commission, Victoria Final Decision However, following the provision of additional supporting information to justify their proposed expenditure, Wilson Cook and Co has concluded in its further report that the expenditure proposed by these distributors is reasonable and so has removed these adjustments. Wilson Cook and Co noted that the plans for IT expenditure proposed by Powercor appeared only preliminary, that detailed designs for the work had not yet been undertaken in all cases, and that there may be room for expenditure reductions or deferrals as the work proceeds. It was of the view that Powercor’s proposed expenditure was overstated by $18.5 million, excluding indirect overheads and labour cost escalation. No additional supporting information was provided by Powercor for Wilson Cook and Co to change its view in this regard. To prepare for the roll out of interval meters (refer Chapter 13), the distributors are proposing significant investment in IT systems. In assessing a reasonable level of capital expenditure allocated to the DUoS price control and to the metering price control, the Commission has adopted the principle that the costs of those IT systems that are required for all customers should be recovered under the DUoS price control. The costs of those IT systems that are required only for customers that have the distributor’s meter installed should be recovered through the metering price control. The proportion of expenditure in IT systems allocated to the DUoS price control and to the metering price control varies by distributor. United Energy expressed concern that, because different consultants were reviewing the IT expenditure for DUoS and for metering, some expenditure could “slip through the net”. In this regard, the Commission notes that AGLE for example has proposed relatively low IT expenditure for the metering price control and relatively high IT expenditure for the DUoS price control, whilst SP AusNet has proposed relatively high IT expenditure for the metering price control and relatively low IT expenditure for the DUoS price control. To ensure IT expenditure does not “slip through the net”, in assessing the IT expenditure in this asset category the Commission has also included the difference between the distributor’s proposed IT expenditure for prescribed metering services and the Commission’s forecast for the metering revenue requirement. This has resulted in an increase in the IT expenditure for CitiPower and SP AusNet, with little change to the IT expenditure for AGLE and United Energy. With regard to Powercor, Wilson Cook and Co has already made an adjustment to the proposed expenditure on the basis that it did not appear to be reasonable. The Commission has therefore not transferred any IT expenditure from the metering price control to the DUoS price control. The levels of capital expenditure required for non-network assets — IT (including adjustments for indirect (corporate) overheads and labour cost escalation) for the 2006-10 regulatory period are set out in Table 7.43. October 06 316 Essential Services Commission, Victoria Final Decision Table 7.43: Capital expenditure — non-network general assets — IT, all distributors, 2006-10 regulatory period, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ revised proposals 43.7 41.1 77.9 11.7 60.9 Wilson Cook and Co adjustment 0.0 0.0 -18.5 0.0 0.0 Commission’s adjustmentb -2.3 9.0 0.1 17.4 1.7 Amount included in expenditure cap (2006-10) (a) 41.4 50.1 59.5 29.1 62.6 Historic expenditure (2001-04)a (b) 24.4 52.0 41.7 45.8 42.9 Variance 17.0 -1.9 17.8 -16.7 19.7 70% -4% 42% -36% 46% a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate) overheads (refer Table 7.12) and other adjustments by the Commission. Non-network general assets — other Distributors undertake expenditure on non-network general assets — other for the purchase or replacement of vehicles, tools and equipment, buildings and other property. Two of the five distributors have proposed expenditure above the levels incurred in 2001-04 on non-network general assets — other capital expenditure over the 2006-10 regulatory period (see Table 7.44). The reasons cited are set out in Table 7.45. Table 7.44: Proposed capital expenditure — non-network general assets — other, all distributors, $million, real $2004 Historic expenditurea Distributors’ original proposals relative to historic expenditure Draft Decision relative to historic expenditure Distributors’ revised proposals relative to historic expenditure AGLE 13.2 68% 29% 68% CitiPower 12.9 -4% -29% -49% Powercor 39.6 103% 50% 41% SP AusNet 15.6 -90% -90% -90% United Energy 30.5 -54% -52% -52% a Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). October 06 317 Essential Services Commission, Victoria Final Decision Table 7.45: Reasons cited for the proposed non-network general assets — other capital expenditure Reasons AGLE Replacement of heavy vehicles, light vehicles, and rebuilding of the Broadmeadows depot. CitiPower Replacement of all Personal Data Entry devices by 2010, refurbishment of the Rooney Street site. Powercor Replacement of all Personal Data Entry devices by 2010, significant motor vehicle and plant investment due to the proposed capital expenditure program, upgrade of zone substation fencing, development of a site in Western Melbourne, refurbishment of the Market Street site, and refurbishment of an aged and obsolete supervisory cable system. SP AusNet General equipment, motor vehicles and mobile plant, office furniture, property and telecommunications. United Energy Fleet, miscellaneous tools and equipment, furniture and equipment and property alterations. Source: AGLE 2004, p. 64; CitiPower 2004, p. 71; Powercor 2004, p. 77; SP AusNet 2004; United Energy 2004, p. 100. Wilson Cook and Co reviewed the expenditure proposals of the distributors, noting that CitiPower and Powercor had reduced their proposed expenditure from $12.4 million to $6.5 million and from $80.4 million to $56.0 million respectively since the Draft Decision. Wilson Cook and Co. commented that the distributors’ estimates were reasonable based on the information available. However it recommended that the proposals be reduced in some areas, for the following reasons: • Wilson Cook and Co observed that AGLE’s projected expenditure on other non-network capital expenditure was higher than for other distributors. It had reservations about the level of expenditure planned for other non-network capital expenditure, and was of the view that the level of expenditure proposed was overstated by $4.0 million, excluding indirect overheads and labour cost escalation. No additional information was provided to justify the increase relative to historic expenditure and therefore the adjustment has been retained. • Wilson Cook and Co noted that, prior to reducing its proposed expenditure, Powercor’s projected expenditure was higher than that for the other four distributors, and considered that it may be overstated by $12.8 million, excluding indirect overheads and labour cost escalation. This adjustment was not considered necessary after Powercor reduced its proposed expenditure and therefore the adjustment was removed in Wilson Cook and Co’s further report. The capital expenditure for non-network general assets — other (including adjustments for indirect (corporate) overheads and labour cost escalation) for each distributor for the 2006-10 regulatory period is set out in Table 7.46. October 06 318 Essential Services Commission, Victoria Final Decision Table 7.46: Capital expenditure — non-network general assets — other, all distributors, 2006-10 regulatory period, $million, real $2004 AGLE CitiPower Powercor SP AusNet United Energy Distributors’ revised proposals 22.2 6.5 56.0 1.6 14.7 Wilson Cook and Co adjustment -4.0 0.0 0.0 0.0 0.0 Commission’s adjustmentb 0.0 0.0 0.1 0.0 0.0 Amount included in expenditure cap (2006-10) (a) 18.2 6.5 56.1 1.6 14.7 Historic expenditure (2001-04)a (b) 13.2 12.9 39.6 15.6 30.5 Variance 5.0 -6.4 16.5 -14.0 -15.8 37% -50% 42% -91% -52% a Note: May not add due to rounding. Historic expenditure is based on the expenditure for 2001-04. To compare on a like-for-like basis, the expenditure has been divided by four (to derive an annual amount) and multiplied by five (to represent a five year period). b Includes adjustments for labour cost escalation (refer Table 7.11), indirect (corporate) overheads (refer Table 7.12) and other adjustments by the Commission Enhanced offerings In their original price-service proposals under ‘enhanced offerings’, CitiPower and Powercor proposed expenditure of $37.1 million and $26.2 million respectively over the 200610 regulatory period for undergrounding. CitiPower proposed funding of $5 million per annum through the Powerline Relocation Committee to assist funding for projects within the CitiPower area which, according to its submission, have been assessed for significant community benefit. An additional $10.5 million was proposed for undergrounding all new high voltage (11 kV and above) extensions. Powercor proposed to commence undergrounding in the areas of highest fire danger. Whilst CitiPower and Powercor have stated that significant community benefit will be achieved as a result of their forecast capital expenditure on undergrounding, they have not quantified the benefit or shown how that benefit was determined. The results of a customer survey provided by the distributors indicate that their electricity customers are willing to pay more than the estimated cost of undergrounding, although the survey was based on a small number of customers. In its submission to the Position Paper, CitiPower (2005cc, p. 3)) stated that the Commission has an obligation to investigate the benefits associated with undergrounding both from the standpoint of ensuring it meets its own objectives, but also from a societal perspective given the benefits from undergrounding largely accrue to the community as a whole. Powercor provided a similar response. As indicated earlier, the Commission notes that, following the last Price Review, the State Government established a Powerline Relocation Scheme. Under this scheme, the Government October 06 319 Essential Services Commission, Victoria Final Decision funds up to 50 per cent of the cost of placing powerlines underground, or otherwise relocating them, where a community benefit will result. This is considered to be a more appropriate mechanism for obtaining the funds required to underground network assets, where there is a community benefit. Additionally, the Commission is of the view that the incentive-based nature of its framework and approach will provide suitable stimulus to ensure that distributors assess such projects on their merits, and undertake undergrounding where the benefit to the distributor outweighs the cost. Furthermore, customers may contribute to the cost of undergrounding cables where they are willing to pay. The Commission has therefore not included expenditure for CitiPower and Powercor for undergrounding. Additionally, Powercor proposed: • the trialling of energy efficient technologies in a 600 site new estate in Melbourne’s north west using solar and photovoltaic technologies at a cost of $11 million; and • a $5 million distribution loss factor reduction strategy targeting high loss feeders. In its Position Paper, the Commission noted that trials of efficient technologies are already occurring, despite the lack of an explicit expenditure allowance. The Commission recognises that developers can charge a premium for land on the basis that energy efficient technology has been installed. As compensation can be acquired through direct means, the Commission is of the view that Powercor cannot expect all customers to contribute to such costs. With regard to the distribution loss factor reduction strategy, the Commission queried the efficiency of this strategy. Assuming losses are valued at $30 per MWh, the $5 million of capital expenditure may only result in a reduction in energy costs of $214 500 per annum. EUCV (2005b, p. 40) supported the Commission’s view. The Commission has therefore not included expenditure for Powercor for the trialling of energy efficient technologies or the proposed distribution loss factor reduction strategy. Nevertheless, if Powercor continues to believe that such expenditure is justified and proceeds to invest, then the capital expenditure will be presumed to be efficient and rolled into the regulatory asset base at the discretion of the relevant regulator. October 06 320 Essential Services Commission, Victoria Final Decision 8 REGULATORY ASSET BASE The distributors’ regulatory asset bases represent the value, as assessed by the Commission, of past or sunk network investments. This is the value on which the owner of the business can expect to earn a return (return on capital), and the value that is returned to the asset owner over the economic life of the assets (as regulatory depreciation). The Victorian Tariff Order sets out requirements that the Commission must comply with when determining the distributors’ regulatory asset bases. The Tariff Order sets out regulatory asset bases for each distributor as at 1 July 1994 and requires that at each regulatory period these values be adjusted for inflation, capital expenditure, depreciation, customer contributions and disposals over regulatory periods. This is referred to as the roll forward method. This Chapter sets out the Final Decision on the distributors’ regulatory asset bases for the 2006-10 regulatory period. The Chapter also sets out the information the Commission has considered in making its decision and the reasons for its decision. 8.1 Final Decision The regulatory asset bases that have been used to determine the return on capital and return of capital components of the distributors’ revenue requirements for each year of the 2006-10 regulatory period are set out in Table 8.1. These values have been determined in accordance with the Victorian Tariff Order requirements, adjusting for inflation, gross capital expenditure, customer contributions, disposals and regulatory depreciation. An adjustment has also been made for any difference between the assumed and actual net capital expenditure (and disposals) in the year 2000. Any under- or over-spend in actual capital expenditure (and disposals) in 2000 relative to the assumed capital expenditure and disposals has been subtracted from/added to the regulatory asset base as actual data for 2000 was not available to the Commission at the time the 2001 price determination was made. October 06 321 Essential Services Commission, Victoria Final Decision Table 8.1: Regulatory asset base, by distributor, 2006-10, $million, real $2004 2006 2007 2008 2009 2010 578.4 588.6 591.1 595.5 593.9 50.7 44.3 46.6 41.9 49.3 Customer Contributions 4.4 4.5 4.2 4.4 5.1 Disposals 0.0 0.0 0.0 0.0 0.0 36.0 37.4 38.0 39.1 39.5 Closing RAB 588.6 591.1 595.5 593.9 598.7 Average RAB 583.5 589.9 593.3 594.7 596.3 Opening RAB 990.9 1,022.1 1,049.5 1,075.5 1,114.7 Gross Capital Expenditure 101.3 96.7 95.3 104.6 88.7 Customer Contributions 5.7 5.6 5.5 6.0 6.0 Disposals 0.0 0.0 0.0 0.0 0.0 64.3 63.8 63.8 59.4 60.6 Closing RAB 1,022.1 1,049.5 1,075.5 1,114.7 1,136.9 Average RAB 1,006.5 1,035.8 1,062.5 1,095.1 1,125.8 1,626.5 1,671.3 1,729.5 1,790.7 1,847.1 171.8 186.2 190.4 187.6 190.3 25.9 26.1 26.0 26.0 26.5 0.0 0.0 0.0 0.0 0.0 101.2 101.9 103.2 105.3 106.3 Closing RAB 1,671.3 1,729.5 1,790.7 1,847.1 1,904.6 Average RAB 1,648.9 1,700.4 1,760.1 1,818.9 1,875.9 1,307.2 1,362.9 1,404.2 1,441.2 1,481.8 139.3 132.8 133.9 140.1 148.2 12.9 13.5 13.9 12.0 14.1 0.0 0.0 0.0 0.0 0.0 70.8 78.0 83.0 87.4 92.0 Closing RAB 1,362.9 1,404.2 1,441.2 1,481.8 1,523.8 Average RAB 1,335.1 1,383.5 1,422.7 1,461.5 1,502.8 AGLE Opening RAB Gross Capital Expenditure Regulatory Depreciation CitiPower Regulatory Depreciation Powercor Opening RAB Gross Capital Expenditure Customer Contributions Disposals Regulatory Depreciation SPAusNet Opening RAB Gross Capital Expenditure Customer Contributions Disposals Regulatory Depreciation (Continued next page) October 06 322 Essential Services Commission, Victoria Final Decision Table 8.1: Regulatory asset base, by distributor, 2006-10, $million, real $2004 2006 2007 2008 2009 2010 1,220.3 1,228.8 1,229.9 1,228.7 1,248.2 101.1 95.0 95.5 102.1 109.4 Customer Contributions 4.2 4.2 3.9 3.8 4.1 Disposals 0.0 0.0 0.0 0.0 0.0 88.4 89.7 92.8 78.7 69.6 Closing RAB 1,228.8 1,229.9 1,228.7 1,248.2 1,283.8 Average RAB 1,224.5 1,229.4 1,229.3 1,238.4 1,266.0 United Energy Opening RAB Gross Capital Expenditure Regulatory Depreciation The measure of inflation that the Commission has used to roll forward the regulatory asset bases for the 2001-05 period is the All Groups Consumer Price Index — Average of the Eight State Capitals, as published by the Australian Bureau of Statistics. The depreciation used to establish the opening regulatory asset bases in 2006 is the regulatory, rather than actual, depreciation determined in the 2001 price review. The values of regulatory depreciation that the Commission has used to establish the regulatory asset bases for the 2006-10 period are calculated using the depreciation profiles (straight-line on an inflation indexed asset base) and effective lives proposed by the distributors. The depreciation that will be used to establish the opening regulatory asset bases in 2011 will also be the regulatory, rather than actual, depreciation. The opening regulatory asset bases used to set the revenue requirements for the 2006-10 regulatory period have been based on the assumed capital expenditure (and disposals) for 2005. For the purposes of the next regulatory period, an adjustment will be required for any difference between assumed and actual year 2005 capital expenditure (and disposals). 8.2 Reasons for the Final Decision To calculate the opening regulatory asset base for each distributor at 1 January 2006, the following formula is used. Opening Regulatory Asset Base2006 = Opening Regulatory Asset Base2001 + Capital Expenditure2001-2005 – Customer Contributions2001-2005 – Regulatory Depreciation2001-2005 – Disposals2001-2005 Once the opening value has been established, the same approach is then used to determine the opening value for each year of the regulatory period. Forecasts of capital expenditure, customer contributions, regulatory depreciation and disposals are used in this calculation. October 06 323 Essential Services Commission, Victoria Final Decision 8.2.1 Opening value of the asset base (1 January 2006) To determine the regulatory asset base at 1 January 2006, the Commission has used the capital expenditure amounts set out in Chapter 5. These capital expenditure amounts and each distributor’s reported customer contributions and disposals have been used to roll forward the 1 January 2000 value of the regulatory asset base to 1 January 2005. An adjustment has also been made for the difference between the forecasts for year 2000 used in the last price review and the actuals reported, except for depreciation which is the regulatory depreciation estimate made for 2000. The Commission does not have all the information it requires to update the value of the distributors’ regulatory asset bases to 1 January 2006 because information on capital expenditure, customer contributions and disposals for the year 2005 is not available. As a result the Commission has used the estimates of capital expenditure, customer contributions, disposals and regulatory depreciation used in the 2001 price review to determine the 2005 revenue requirements. An adjustment will be made in 2010 for any difference between assumed and actual net capital expenditure for 2005, when the opening regulatory asset bases are calculated for the next regulatory period (which begins in January 2011). Regulatory depreciation will remain the same as that estimated for this price review. Table 8.2 sets out the resulting values of the regulatory asset base at 1 January 2006. Table 8.2: Regulatory asset base, by distributor, 2000-05, $million, real $2004 2000 2001 2002 2003 2004 2005 569.2 572.4 577.9 567.6 558.1 550.4 42.3 42.6 34.6 38.9 38.1 72.2 Customer Contributions 8.3 4.3 6.6 7.0 4.6 1.8 Disposals 0.4 0.1 1.7 2.5 0.1 0.0 30.4 32.7 36.7 39.0 41.0 42.5 Closing RAB 572.4 577.9 567.6 558.1 550.4 578.4 Average RAB 570.8 575.2 572.8 562.8 554.3 564.4 848.2 887.7 913.9 935.9 947.2 968.4 86.7 83.8 73.7 65.7 78.6 77.8 Customer Contributions 7.8 8.8 8.1 8.9 10.1 7.7 Disposals 2.6 7.0 0.2 0.3 0.3 0.0 36.8 41.8 43.3 45.2 47.0 47.6 Closing RAB 887.7 913.9 935.9 947.2 968.4 990.9 Average RAB 867.9 900.8 924.9 941.5 957.8 979.6 AGLE Opening RAB Gross Capital Expenditure Regulatory Depreciation CitiPower Opening RAB Gross Capital Expenditure Regulatory Depreciation (Continued next page) October 06 324 Essential Services Commission, Victoria Final Decision Table 8.2: Regulatory asset base, by distributor, 2000-05, $million, real $2004 2000 2001 2002 2003 2004 2005 1,540.9 1,587.6 1,605.3 1,593.6 1,585.3 1,592.2 175.3 158.3 139.21 149.6 161.9 163.6 42.4 25.5 32.0 38.8 37.1 17.6 3.5 0.9 2.2 1.4 1.5 0.0 82.7 114.1 116.7 117.7 116.5 111.7 Closing RAB 1,587.6 1,605.3 1,593.6 1,585.3 1,592.2 1,626.5 Average RAB 1,564.2 1,596.4 1,599.4 1,589.5 1,588.8 1,609.4 1,201.3 1,211.7 1,237.2 1,214.3 1,216.0 1,244.3 Gross Capital Expenditure 94.0 119.3 79.2 108.1 128.4 145.5 Customer Contributions 18.6 19.3 23.0 29.9 27.6 9.8 Disposals 13.2 1.0 1.6 0.2 0.0 0.0 Regulatory Depreciation 51.7 73.6 77.5 76.3 72.4 72.7 Closing RAB 1,211.7 1,237.2 1,214.3 1,216.0 1,244.3 1,307.2 Average RAB 1,206.5 1,224.5 1,225.7 1,215.1 1,230.1 1,275.7 1,180.5 1,206.7 1,195.5 1,198.8 1,199.0 1,189.5 109.3 79.2 89.5 87.1 83.2 121.5 Customer Contributions 18.5 14.2 11.7 7.7 5.9 1.1 Disposals 11.0 0.0 1.2 0.7 1.1 0.0 Regulatory Depreciation 53.6 76.1 73.3 78.4 85.7 89.6 Closing RAB 1,206.7 1,195.5 1,198.8 1,199.0 1,189.5 1,220.3 Average RAB 1,193.6 1,201.1 1,197.2 1,198.9 1,194.2 1,204.9 Powercor Opening RAB Gross Capital Expenditure Customer Contributions Disposals Regulatory Depreciation SPAusNet Opening RAB United Energy Opening RAB Gross Capital Expenditure Adjustment for the allocation of CitiPower’s IT assets The approach to rolling forward the distributors’ asset bases has been established to be consistent with the treatment of ‘pre-vesting’ assets as set out in the Tariff Order90 and to value investments since privatisation at cost (net of customer contributions). It does not provide for the re-valuation of assets already included in the regulatory asset base. In 2002, CitiPower made a $30 million adjustment to its regulatory accounts to transfer the proportion of the value of certain IT-related assets previously allocated to CitiPower’s retail arm into the distributor’s asset base. This transfer was made following the sale of CitiPower’s retail 90 Clause 2.1(b) of the Tariff Order. ‘Pre-vesting’ assets are the assets in place as at 1 July 1994. October 06 325 Essential Services Commission, Victoria Final Decision arm to Origin Energy and justified by CitiPower on the basis that these IT-related assets were now solely used by the distribution business. In subsequent discussions with the Commission, CitiPower reduced the value of the adjustment to these IT-related assets to $18 million so that it reflected the depreciated value of these assets. In its Draft Decision the Commission considered that CitiPower’s distribution customers had not benefited from the sale of the retail arm but, under CitiPower’s proposed approach, they were being expected to finance the IT assets previously allocated to the retail business. The Commission’s Regulatory Accounting Guideline No. 3 (Issue 4) is not prescriptive in terms of cost allocation. However, it does require costs that are directly attributable to the distributor be assigned accordingly and costs that are not directly attributable to the distributor be allocated to the distributor on a causation basis where a causation relationship exists. Where costs are allocated, the distributor is required to provide supporting information including the amounts that have been allocated, the basis of allocation, and the numeric quantity of each allocator. Capital expenditure is directly attributed or allocated to the appropriate business segments in the year in which it is incurred. The effect of CitiPower’s adjustment is to increase its regulatory asset base through a change in allocation policy rather than through the methodology outlined in the 2001-05 price review and reconfirmed for the 2006-10 price review. A change in allocation policy between the distribution and retail business does not constitute additional capital expenditure and thus should not result in an addition to the regulatory asset base of the distribution business. Allowing CitiPower to adjust its 2002 regulatory accounts for these IT-related assets is not consistent with the roll forward approach to establishing the asset base — CitiPower has not demonstrated that it has outlaid capital to acquire the balance of these assets. To now require distribution customers to pay more despite no additional costs being incurred would provide CitiPower with additional revenue for no corresponding increase in service capacity. Since the release of the Commission’s Draft Decision CitiPower has not responded to this issue. However Origin Energy (2005, p. 1) (the purchaser of the retail arm) supported this conclusion in response to the Position Paper, suggesting that: There is little justification for transferring IT expenditure allocated to CitiPower’s retail business to its distribution business simply as a result of the retail business having been sold off to a different owner. The decision to separate the businesses was taken by the former owner to maximise the aggregate sale price, and it seems unreasonable to ask distribution customers to pay more as a consequence. Consistent with the Draft Decision the Commission has excluded the addition of the value of IT assets claimed by CitiPower when rolling forward the asset base. October 06 326 Essential Services Commission, Victoria Final Decision Measure of inflation To establish a value for the opening regulatory asset base for the 2006-10 regulatory period, adjustments have been made to the actual outcomes of the 2001-05 regulatory period using an appropriate measure of inflation. The purpose of indexing asset values with inflation is to preserve the real value of the asset owners’ investment, thereby minimising inflation risk to the asset owner. It follows that the measure of inflation adopted should be that which provides the best measure of changes in the purchasing power of money in Australia. To establish each distributor’s regulatory asset base as at 1 January 2006, the Commission has applied the same methodology to adjust for inflation that was utilised in the 2001-05 price review. Specifically, this involves: • adopting the All Groups Consumer Price Index — Average of the Eight State Capital Cities (published by the Australian Bureau of Statistics) as the measure of actual inflation which is relevant for changes to the purchasing power of money in the Australian market; • using the CPI from nine months prior to a point in time as a proxy for the price level at that point in time, mirroring the treatment in the 2001-05 price controls; and • assuming all past and future revenue and expenditure is received or incurred at the midpoint of each calendar year. 8.2.2 Rolled forward values of the regulatory asset base (2006-10) Having determined the opening value of regulatory asset bases at 1 January 2006, estimates of the regulatory asset bases for each year of the 2006-10 regulatory period have been determined using the roll forward approach. Capital expenditure The estimates of gross capital expenditure rolled into the asset base are those determined in accordance with the Commission’s building block approach (see Chapter 7). Regulatory depreciation The purpose of allowing a ‘return of’ capital through depreciation when setting regulated charges is to return to investors the value of the capital that has been invested. This form of depreciation is consistent with the accounting concept of financial capital maintenance. The Commission has adjusted the components of the regulatory asset base for inflation over time, which implies that financial maintenance is preserved in real terms (that is, inflation adjusted) and depreciation reflects the return of the real cost of the asset. Ideally the rate of depreciation should be consistent with the economic potential of the asset over its physical life. In the consultation process, the Commission provided stakeholders with the opportunity to propose alternative methods for the calculation of regulatory depreciation. When considering alternatives, the Commission was concerned to ensure increased transparency for all stakeholders October 06 327 Essential Services Commission, Victoria Final Decision to understand the derivation of regulated charges and the extent to which costs have been allocated between current and future users of the regulated services. However, there was general support for the continued use of straight-line depreciation applied to an asset base that is indexed for inflation. In their October 2004 price-service proposals all of the distributors proposed straight-line depreciation. Such an approach is consistent with that implemented by regulators in other Australian jurisdictions. The Commission has applied the straight-line method for the calculation of regulatory depreciation for the 2006-10 period. In application, this methodology is transparent and easily replicated, and is also consistent with a stable growth in demand. This approach returns invested capital to the investor at a constant rate (in real terms) over the life of the asset. In applying the straight-line method for the calculation of regulatory depreciation, the Commission has not required the adoption of a standardised set of asset lives or classes. That is, it has adopted the asset lives proposed by the distributors. This ‘hands-off’ approach to determining regulatory depreciation reflects the fact that the rate of depreciation affects only the timing (rather than value) of cash flows. Additionally, consistent with the approach outlined in the 2001 Electricity Distribution Price Review, the Commission simply deducts the regulatory depreciation reflected in the price controls to determine the regulatory asset values in future regulatory periods — it does not recalculate the depreciation allowance for actual expenditure over the period. The Commission notes that it has received late proposals from AGLE and CitiPower that represent a significant change in the amount of regulatory depreciation recovered over the 2006-10 regulatory period. Similarly, the ORG received late proposals at the time of the last price review. The proposal provided by AGLE entails a change in estimate regarding the depreciable life of SCADA from 20 years to 5 years. AGLE stated that the change in estimate was considered appropriate as the technical life of SCADA equipment was considered to be much shorter than 20 years, because the hardware upon which it is built rarely has an available life longer than 4 years, thereby resulting in shorter manufacturer support periods (AGLE 2005, p. 93). This proposal will result in an increase in AGLE’s total amount of regulatory depreciation for the 2006-10 regulatory period by approximately $5 million (real $2004). The proposal provided by CitiPower entails a change in the calculation of regulatory depreciation for assets acquired before 1 January 2006 due to an error that CitiPower has identified in the model that calculated depreciation for its original October 2004 price-service proposals. CitiPower had incorrectly calculated depreciation rates by using new, rather than assumed remaining asset lives, thus resulting in depreciation rates lower than they ought to have been. The correction of this apparent has a significant impact upon CitiPower’s total amount of regulatory depreciation for the 2006-10 regulatory period, increasing that total by approximately $70 million (real $2004). This represents a change in the rate of total depreciation from 4.2 per cent to 5.9 per cent of the regulatory asset base. The Commission has to date adopted a ‘hands off’ approach to regulatory depreciation on the basis that different rates of depreciation will affect the timing, rather than the level, of the return October 06 328 Essential Services Commission, Victoria Final Decision of capital. Consistent with this approach, the Commission has made the adjustments submitted by AGLE and CitiPower. The regulatory depreciation amounts used by the Commission for the 2006-10 regulatory period are as set out in Table 8.3. Table 8.3: Regulatory depreciation schedule, 2006-10, by distributor, $million, real $2004 2006 2007 2008 2009 2010 Total AGLE 36.0 37.4 38.0 39.1 39.5 189.9 CitiPower 64.3 63.8 63.8 59.4 60.6 311.8 Powercor 101.2 101.9 103.2 105.3 106.3 517.8 SPAusNet 70.8 78.0 83.0 87.4 92.0 411.2 United Energy 88.4 89.7 92.8 78.7 69.6 419.2 Note: Totals may vary slightly due to rounding. As stated above, the depreciation rates applied by the Commission are the same as those submitted by the distributors. The Commission has been concerned, however, that its ‘hands off’ approach has limited the scope to consult on proposed changes to depreciation, particularly where changes to depreciation are proposed late in the price review process. While in principle depreciation rates affect only the timing (rather than value) of cash flows, the choice of depreciation rates will affect the stability of prices over time. Therefore, recognising the desirability of stability in the application and calculation of depreciation, the Commission foreshadows that it is unlikely to allow changes to depreciation profiles in future reviews where such changes do not provide adequate time for consultation and/or are not sufficiently supported by credible reasons. To ensure consistency and stability, the Commission anticipates that any future review will more closely evaluate regulatory depreciation proposals and asset lives for consistency with history, consistency of economic and technical lives of assets, and will also have regard to the implications for prices over the long term.91 The Commission also anticipates that, as depreciation rates impact on the timing of cash flows to the distributors but may have substantial implications for the intergenerational burden on customers, material changes to depreciation profiles would only be accepted where there is sufficient opportunity for consultation with customers (and they are not otherwise inappropriate). Table 8.4 illustrates how depreciation, as a percentage of the regulatory asset base, has changed over regulatory periods. 91 In their recent Electricity Distribution Price Control Review, Ofgem (2004a) expressed a similar view: “In the longer term, it would be reasonable to expect the price control treatment of long-lived assets to more closely approximate to their useful technical or economic lives, for example so that the customers that pay for an asset are those that derive benefit from it. Were it not for the peculiarities of pre-vesting asset lives and the need to maintain broadly stable financial profiles, it seems unlikely that 20 year lives would be optimal. Ofgem will want to review this issue at the next review in the light of these considerations” (Ofgem 2004, p.95). October 06 329 Essential Services Commission, Victoria Final Decision Table 8.4: Regulatory depreciation as a percentage of regulatory asset base, historic and forecast, by distributor 1994-2000 2001-05 2006-10 AGLE 5.2% 6.3% 6.4% CitiPower 4.2% 4.8% 5.9% Powercor 5.1% 7.1% 5.9% SPAusNet 4.2% 5.6% 5.8% United Energy 4.5% 6.3% 6.8% Public lighting In its submissions to the Draft Decision and Position Paper, the Street Light Group of Councils (SLG) expressed concern with regard to the valuation and subsequent depreciation associated with public lighting assets that form part of the regulatory asset base of each distributor. This issue had also been raised by the SLG in response to the Commission’s Issues Paper and in its submissions relating to the Review of Public Lighting Excluded Service Charges – Final Determination (ESC 2004c). The Commission considers that it has effectively addressed the concerns of the SLG through the review of public lighting excluded service charges. The Commission clearly outlined that the value of the regulatory asset base for each of the distributors (as at 1 July 1994) is directed by Clause 2.1 of the Tariff Order. The requirements of the Tariff Order are a matter for the State Government of Victoria and not the Commission. The Commission notes that the distributors do not have a specific tariff for public lighting customers. The depreciation on public lights in the regulatory asset base is therefore recovered across all customers. The proportion of public lighting assets to total sunk assets (for all distributors) is approximately 2 per cent. Consequently, the impact on prices will be immaterial. Also, the Public Lighting Code requires distributors to depreciate public lighting assets over the economic life of the asset. However it does not prescribe the number of years to which such an economic life corresponds.92 Customer contributions and disposals The estimates of customer contributions are as determined in accordance with the Commission’s building block approach (see Chapter 7), and the estimates of disposals are those submitted by the distributors in their October 2004 price-service proposals. 92 Public Lighting Code, September 2001. October 06 330 Essential Services Commission, Victoria Final Decision 9 COST OF CAPITAL FINANCING The cost of capital financing represents the largest proportion of the total revenue requirement for each distributor. It comprises both a return of capital and a return on capital. The return on capital (or weighted average cost of capital) is the financial return that investors seek when considering and assessing an investment decision. To provide an incentive for investors to invest, the rate of return should reflect the opportunity cost of their capital — that is, the return should be commensurate with the returns that an investor could expect to earn from other investment opportunities in the market, after adjusting for the different levels of risk that different investments entail. While low prices may be in the interests of customers in the short term, the Commission considers that the long term interests of customers (particularly with respect to reliability) require prices to generate sufficient returns to attract the investment required over the long term. The cost of capital for a particular investment is determined by the market. It is based on the aggregate demand and supply of investment funds and the riskiness of the potential cash flows generated by the investment in question relative to the riskiness of the cash flows generated by other investments. However, the cost (price) of capital cannot be observed in the same manner in which prices for other goods and services may be observed.93 Neither the regulated entity nor the regulator can observe or determine the cost of capital. Instead, the risk adjusted price for investment capital must be estimated from available capital market data, and can be interpreted using models drawn from finance theory and practice. In its previous reviews, the Commission emphasised the need to have primary regard to objective market evidence when estimating the cost of capital associated with the distributors’ assets, as well as the consistent application of models drawn from finance theory and practice. These principles are equally applicable to the current review. The Commission is mindful that the distributors will not recover the costs associated with the investments being made now for up to 40 or more years. This makes it important that the Commission also seeks to create, to the extent possible, a stable and predictable regime with decisions that can be replicated. However, having regard to the latest market evidence in isolation is unlikely to create a sufficiently stable and predictable regime. The imprecision with estimates of the cost of capital could result in the ‘best’ estimate of the cost of capital varying substantially from one review to the next. Given the substantial imprecision in estimates of the cost of capital and the need to foster a stable, predictable and replicable regime, the Commission considers it important to adopt a cautious approach when interpreting new but uncertain evidence relevant to the cost of capital, and to adopt a cautious approach when considering changes to key inputs or assumptions relative to those adopted in previous reviews. The application of these considerations to the estimation of 93 Aggregate economy wide measures of the cost of capital can be determined using data from the National Accounts October 06 331 Essential Services Commission, Victoria Final Decision the cost of capital associated with the distributors’ regulated activities is discussed in more detail in this chapter. This Chapter sets out the Commission’s Final Decision on the return on capital component of the cost of capital financing. The Final Decision is set out in Section 9.1 and the reasons for the Final Decision are set out in Section 9.2. 9.1 Final Decision The Commission has estimated the after-tax real cost of capital associated with the distributors’ regulated activities for the 2006-10 regulatory period (as at 31 August 2005) at 5.90 per cent. The estimate has been used to determine the revenue requirements for each distributor. The input parameters that it has used to derive this estimate are set out in Table 9.1. In estimating the after-tax weighted average cost of capital (WACC), the Commission has used the ‘vanilla WACC’, and utilised the Capital Asset Pricing Model (CAPM) to estimate the after tax return on equity. Table 9.1: Weighted average cost of capital and input parameters Final Decision 2.64% Risk free rate (real) (Rf) 0 Rural risk adjustment Debt premium (Rd) 1.425% Equity (market risk) premium (Rm – Rf) 6.00% Equity beta (βe) 1.00 Franking credit value (γ) 0.50 Gearing (debt/assets) 60% Inflation 2.56% Real after-tax ‘vanilla’ WACC 5.90% 9.2 Reasons for the Decision In the 2001 electricity distribution price review, the Commission adopted a real after-tax WACC to determine an appropriate rate of return on the distributors’ asset values over the regulatory period. At the time the Commission noted that dealing with the implications of taxation (and franking credits) in the WACC created a number of complexities and introduced scope for error. It also concluded that dealing with taxation implications in the WACC lacked transparency. October 06 332 Essential Services Commission, Victoria Final Decision As a result, the Commission chose a version of the WACC known as the ‘vanilla WACC’ to estimate the real after-tax cost of capital. WACC = Re E D + Rd V V where Re is the (real) required after-tax return on equity, Rd is the (real) cost of debt, and E, D and V are the market values of equity, debt and assets respectively. The real after-tax return on (cost of) equity was estimated using the Capital Asset Pricing Model (CAPM): Re = Rf + βe (Rm – Rf) where Rf is the risk-free rate of return, βe is the estimated equity beta and (Rm — Rf) is the return over the risk free rate that investors would expect in order to invest in a well-diversified portfolio of equities (otherwise referred to as the equity (market risk) premium). In making its Final Decision, the Commission considered the methodology used for estimating the after-tax WACC and the values of each of the input parameters that are used to estimate the WACC. 9.2.1 Methodology for estimating the after-tax WACC In previous price reviews, the Commission has used the CAPM to estimate the cost of capital associated with the distributors’ regulated activities.94 The CAPM is widely used and understood by both the finance community and industry, is consistent with the methodology used by virtually every other economic regulator in Australia and the UK and was not objected to in any submission to this review. Accordingly, the Commission has used the CAPM. While in theory the CAPM provides a direct estimate of the cost of capital associated with a project, in practice it can feasibly be used only to estimate the required returns to the equity-financed portion of the project. Accordingly, the version of the CAPM that has been used in this review specifies the estimate of the required real return to the equity providers as follows: Re = Rf + βe (Rm – Rf) where Rf is the risk-free rate of return, βe is the estimated equity beta and (Rm — Rf) is the return over the risk free rate that investors would expect in order to invest in a well-diversified portfolio of equities (otherwise referred to as the equity (market risk) premium). 94 The term ‘vanilla WACC’ has become a relatively common term used in Australia to refer to the simplified weighted average cost of capital formula that does not incorporate any treatment of tax. This approach assumes the treatment of tax is incorporated in the cash flows as a separate item in the revenue requirement. October 06 333 Essential Services Commission, Victoria Final Decision The cost of capital associated with an investment can then be estimated as the weighted average of the cost of equity and cost of debt (hence, weighted average cost of capital, or WACC), with the cost of debt financing normally estimated from the observed or estimated yields for debt financing. As a result, the cost of capital can be estimated as (abstracting from issues related to company tax): WACC = Re E D + Rd V V where Re is the (real) required after-tax return on equity, Rd is the (real) cost of debt, and E, D and V are the market values of equity, debt and assets respectively. In the 2001-05 price review, the Commission determined an after-tax version of the WACC and derived a benchmark allowance for taxation. This contrasted with the position advanced by the distributors at that time that an allowance for taxation should be provided by adopting a pre-tax WACC — that is, a higher WACC that includes compensation for tax. The benchmark for taxation calculated by the Commission reflected its view of the tax treatment of an efficient distributor, subject to the need for consistency with the other features of the Commission’s decision. The Commission adopted an after-tax WACC because it concluded that dealing with the implications of taxation (and franking credits) in the WACC creates a number of complexities, introduces scope for error and lacks transparency. The Commission considers that the approach implemented in the 2001 Electricity Distribution Price Review remains current and has adopted the same version of the after-tax WACC, again compensating for taxation by deriving a benchmark allowance for taxation. Accordingly, the assumptions required to estimate the after-tax WACC for the distributors’ regulated activities are: • real risk-free rate of return (Rf); • equity (market risk) premium (Rm — Rf); • proxy beta (βe); and • benchmark cost of debt (Rd) and financing arrangements ( E D and V V ). In submissions to this price review, AGLE proposed that the statistical technique known as the ‘Monte Carlo’ method be used to assist in estimating of the cost of capital associated with the distributors’ regulated activities. In later submissions, AGLE’s views have been supported by United Energy and the Energy Networks Association (ENA). Under the Monte Carlo method, a (joint) probability distribution is derived or assumed for all of the input parameters into the WACC. Many random sample observations are then simulated for each of the inputs and a probability distribution for the WACC derived. AGLE stated that using the Monte Carlo method would provide a more robust and transparent method for regulators to address the uncertainty in each WACC parameter. October 06 334 Essential Services Commission, Victoria Final Decision In its Position Paper, the Commission noted that, while the Monte Carlo method is used commonly in some fields to deal with uncertainty, it did not consider that the extensive information requirements for applying the method in a robust and transparent manner could be met. In response to the Position Paper, AGLE (2005b, p. 20) reiterated its view that the use of the Monte Carlo method would assist regulatory decision making. It stated that, among other things, the Monte Carlo method would provide further information on the real level of measurement error in the final value of WACC, provide further transparency and a more robust framework for deriving a conservative estimate for the WACC. According to AGLE, the Monte Carlo method would enable a degree of conservatism to be specified as a probability limit. United Energy (2005c) supported the use of Monte Carlo methods in principle, and the Energy Networks Association (ENA) (2005a, p. 8) supported the exploration of alternative methodologies for the estimation of WACC and expressed the view that the Commission’s: … dismissal of probabilistic approaches to cost of capital estimation is not soundly based. In response to the Draft Decision, United Energy (2005n) again supported the use of Monte Carlo simulation as a method to address uncertainty in the calculation of the WACC. United Energy (2005n) was of the opinion that Monte Carlo simulation provides the most objective and rigorous approach to dealing with uncertainty in the estimation process, and that it warrants the Commission’s full and objective consideration. Similarly, AGLE (2005f) in its response to the Draft Decision stated that The statistical approach is better than judgement applied to individual point estimates and can be undertaken without additional information requirements and without significant additional analysis...it also provides more certainty and transparency and assists in decision making (AGLE 2005, p. 75). Specifically in relation to the proposals made by AGLE (2005f, p. 5) for the measurement of the values of the input parameters, it has “assigned a statistical distribution where uncertainty was considered material”, and undertaken a Monte Carlo simulation to derive a probability distribution for the WACC. On this basis AGLE derived an equity beta of value of 1 with a uniform distribution 0.9 to 1.1, and an equity (market risk) premium (normally distributed) with a mean of 6 per cent and a standard deviation of 1.8 per cent. AGLE proposed that the 75-80th percentile from the calculated distribution be adopted as the value for WACC, and provided a point estimate of 6.70 per cent. The Commission has not been persuaded to use the Monte Carlo method on the basis of the comments made by AGLE, United Energy or the ENA regarding the ability of the methodology to increase transparency and certainty. The Commission acknowledges the concerns expressed by, amongst others, the Productivity Commission in its review of the National Access Regime and Gas Access Regime that there is sound reason for setting regulated charges at a level at which the Commission is confident the returns provided to investors are sufficient to continue to attract capital into the industry. Indeed, the Commission’s primary objective — referring as it does to the long term interests of consumers — directs the Commission to this end in any event. October 06 335 Essential Services Commission, Victoria Final Decision However, the Commission remains of the view that the methodology that is has used in previous reviews remains appropriate for this exercise. The Commission also rejects the contention made by AGLE (2005f) that the Commission is required to explicitly quantify the uncertainty in the estimation of the WACC and each of its input parameters. As the Commission has explained previously, it does not consider it possible to derive probability distributions — with which it can have the necessary level of confidence — for most of the WACC inputs. The fact that the Commission has relied on a number of sources of evidence when forming its views about the appropriate estimate for each WACC parameter makes it impossible to derive standard errors for the estimates using conventional means, and makes such estimates speculative. In addition, the Commission’s own experience in deriving its chosen values for the relevant inputs as evidenced in the remainder of this Chapter, has highlighted the speculative nature of going a step further in order to form a considered view on the shape of the probability distribution and measures of dispersion for each of the inputs. Thus, the Commission remains of the view that AGLE and United Energy have downplayed the significance of the information requirements necessary to apply the Monte Carlo method in a robust manner. As the Commission has also noted in its earlier discussions, it would not be correct to simply adopt the Commission’s selected parameter inputs as the central estimates (expected values) for these inputs, given the Commission’s view that its estimates embody a degree of conservatism. A similar view has been expressed by the ACCC (2005), which has acknowledged the many issues associated with the use of Monte Carlo simulation for the estimation of the WACC in the context of the telecommunications industry, finding that it is “important that the MC analysis is done using unbiased estimates of the WACC input parameters” (ACCC 2005, p. 62). Further, the value of Monte Carlo analysis is proven in the fields of computational physics and in the field of finance in (for instance) finding the arbitrage-free value of a particular derivative. However, no evidence has been provided that market practitioners consider it appropriate or that other regulators use the method when estimating the WACC. Lastly, the Commission remains of the view that transparency is important in the method that is used to estimate the WACC, and does not consider that the method proposed will improve the level of transparency. Merely because the Monte Carlo model itself is a mechanical process does not make the use of the model transparent as discussed above. The Commission considers that the key inputs to the calculation would be speculative, implying that transparency in the derivation of such inputs would be correspondingly low. In a similar vein, even if a probability distribution could be derived robustly for the WACC, the Commission notes that its primary objective requires it to exercise judgement on important trade offs on the basis of all of the information available, and does not consider that it is either necessary or appropriate to reduce this decision to an arbitrary cut off point on a probability distribution as proposed. October 06 336 Essential Services Commission, Victoria Final Decision The Commission’s views on this matter are indirectly supported in the Gray and Officer (2005c, p. 7) paper on estimating the equity (market risk) premium submitted in response to the Draft Decision by the Energy Networks Association. There is no natural law that says returns have to be characterised or represented by any mathematical function. This does not mean that one should not use distributions but simply they, like many models in finance, should be used with a degree of discretion because the distributions of stock market returns are rarely so well behaved that parameters can be estimated from histroric returns and then used with any confidence to forecast future returns. In their submissions to the Draft Decision CitiPower, Powercor and United Energy also identified approaches used in other jurisdictions to estimation the WACC. CitiPower and Powercor highlighted the probabilistic approaches employed in Western Australia, New South Wales and New Zealand. United Energy also considered the approach used by the Western Australian Economic Regulation Authority (ERA) (2005) in its recent decision under the Gas Code with regard to the Goldfields Gas Pipeline. United Energy indicated that the approach used — where the ERA adopts a range of feasible values for the underlying cost of capital variables, having regard to broad commercial practice and selecting a point estimate within the 90th percentile of the range to ensure that the regulator errs on the side of investors — is favourable approach to dealing with uncertainty. Turning first to the decisions of IPART (2005) and the ERA (2005), the Commission notes that those decisions have been made under the Gas Code, which differs in material respects to the regime applicable to the current price review. In particular, those regulators interpreted the requirements of the Gas Code as requiring the regulator to assess whether the WACC estimate as proposed was outside of a reasonable range, rather than for the regulator to determine an appropriate value for the WACC. The regulators, therefore, considered themselves legally obliged to refer to a range for the WACC and its constituent inputs. Moreover, neither regulator has used the Monte Carlo method to derive a WACC. The ERA (2005) noted that the Gas Code requires it to form a view about the range that a reasonable person would consider the WACC to lie within, which need not necessarily conform to the outcomes of a Monte Carlo study. The conclusion that IPART (2005) reached with regard to the application of the Monte Carlo method was as follows: The Tribunal notes that Monte Carlo simulation: • is not widely used in financial markets to set rates of return; • does not remove the uncertainty arising from individual parameter estimation; and • while it assists in generating a range of returns, does not necessarily result in a rate of return that meets the requirements of the Code. Nevertheless, the Tribunal’s view is that use of a Monte Carlo simulation framework does allow for uncertainty through the use of probability distribution for individual parameters, October 06 337 Essential Services Commission, Victoria Final Decision and thus meets the requirements of the Code in producing a range of returns that may reflect prevailing market conditions for funds. In practice, the aim of Monte Carlo simulation is to produce a wide range of possible outcomes for the rate of return. The Tribunal’s view is that, in deciding where to determine the rate of return within this range, it must be guided by the factors in sections 2.24 and 8.1 of the Code. This assessment must be made on a case by case basis. It is therefore inconsistent in this process of assessment to determine the rate of return at the 80th percentile or any other point in the probability distribution (IPART 2005, p. 95) Turning next to the decision of the New Zealand Commerce Commission (NZCC) (2004, p. 7.57.6), the Commission notes that the NZCC concluded that while “the Monte Carlo approach could potentially provide useful insights into the volatility of key outputs” it considered that “the appropriate approach was to refine the existing cost benefit model” (NZCC 2005). In its assessment of the Monte Carlo approach the NZCC was concerned with data quality and reliability, transparency of the modelling process and the extent to which additional information would be required to assess its application. One of the biggest criticisms made by the NZCC was the lack of time available to fully consider the merits and problems associated with a Monte Carlo approach. However, it should be noted that explicit price regulation of utilities in New Zealand is a relatively new phenomenon. When considering the applicability of a Monte Carlo approach to a regulatory environment, the Commission would consider it more informative to consider the approaches taken in jurisdictions that have substantial experience in regulating utilities, such as the US and UK, rather than those for whom explicit price regulation is new. The Commission is unaware that Monte Carlo analysis like that proposed by AGLE has become a standard and accepted tool in setting regulatory returns in mature regulatory environments. The Commission does not accept that a probabilistic approach to establishing a range for each parameter when estimating the WACC, similar to that implemented in the Gas Code, can provide greater certainty than the current approach offers. As with the application of a Monte Carlo approach, estimates of the WACC inputs remain reliant on the application of judgement to a number of different sources of information and estimation methodologies. On the basis of the concerns articulated above, the Commission has continued to apply the approach it has adopted in previous price reviews regarding the estimation of inputs when determining the WACC, which is to exercise judgement while taking into account all relevant information. 9.2.2 Estimating the after-tax WACC In this section, the Commission sets out its reasons and analysis of each of the input parameters used to determine the WACC. These parameters include: • real risk-free rate of return (Rf) • equity beta (βe) October 06 338 Essential Services Commission, Victoria Final Decision • equity (market risk) premium (Rm – Rf) • debt premium (Rd) and debt raising fees • equity raising costs • relative risk of the rural distributors The change in the WACC from that used in the last price review is due principally to the decline in long term real interest rates which, for ten year CPI-linked Commonwealth government bonds have declined from 3.50 per cent to 2.64 per cent.95 A further minor adjustment has been made to the allowance for the cost of debt (a reduction in the debt margin following market movements, but mostly offset by recognition of debt transaction costs that were not included in the last review). The distributors’ October 2004 proposals on the WACC and the various parameters that input into its determination are set out in Table 9.2, along with the WACC and parameters used in the Final Determination for the 2001 Electricity Distribution Price Review. During the course of the price review, the distributors resubmitted some of the parameters. These latest submitted numbers are discussed below where relevant. Table 9.2: Weighted average cost of capital and input parameters, distributor proposals and 2001-05 price review a 2001-05 review AGLE CitiPower Powercor SP AusNet United Risk free rate (real) Rf 3.50% 2.79% 2.80% 2.80% 2.80% 2.80% Rural risk adjustment — — — 0.50 — — 1.51–1.71% 1.65–1.85% 1.65–1.85% 1.51–1.71% 1.51–1.71% 1.67% 1.72% 1.72% 1.71% 1.60% 6.00-7.80 6.00-8.00% 6.00-8.00% 6.00-8.00% 6.00-8.00% 7.30% 6.94% 6.94% 7.00% 7.30% Debt premium (Rd) — Range — Point estimate 1.50% Equity (market risk) premium (Rm-Rf) — Range — Point estimate 6.00% (continued next page) 95 For the purposes of this Final Decision, the period that interest rates were measured was over the 20 trading days to 31 July 2005. For a discussion on why this period has changed refer to the section on the risk-free rate. October 06 339 Essential Services Commission, Victoria Final Decision Table 9.2: Weighted average cost of capital and input parameters, distributor proposals and 2001-05 price review 2001-05 review a AGLE CitiPower Powercor SP AusNet United 0.90-1.00 1.00-1.10 1.00-1.10 1.00-1.10 1.00 1.00 1.07 1.075 1.04 1.00 0.00-0.50 0.00-0.50 0-0.50 Equity beta — Range — Point estimate 1.00 Franking credit value — Range 0.50 0.30 0.50 0.50 0.30 0.30 Gearing (debt/assets) 60.00% 60.00% 60.00% 60.00% 60.00% 60.00% Inflation 2.60% 2.56% 2.50% 2.50% 2.56% 2.56% ‘Vanilla’ after-tax WACC (real) 6.80% 6.70% 6.80% 7.30%b 6.70%c 6.70% — Point estimate a Formerly TXU b Powercor proposed that a rural risk adjustment (represented separately here) be added to the risk free rate that, when removed, provides a real vanilla WACC of 6.80 per cent. c Excludes a proposed adjustment for rural risk. A point estimate of a proposed adjustment for rural risk was not provided. Real risk-free rate of return (Rf) Where the real cost of capital is used to determine regulated charges, an estimate of the real riskfree rate of return is required for the risk free element of the WACC. In principle, the risk-free benchmark in the CAPM should reflect the yield on a risk-free instrument. The yield on government securities is typically used as a proxy. In its previous reviews, the Commission has used a recent average (20 days) of the yield on Commonwealth Government inflation-indexed bonds with a term to maturity of 10 years to obtain a direct estimate of the real risk free rate of return. The indicative closing rates published by the Reserve Bank of Australia have been used as the data source. The Commission has noted previously that the use of inflation-indexed bonds appropriately utilises the latest market evidence and avoids the need for an independent assumption about future inflation. The use of market evidence is also objective and capable of being replicated across decisions and industries, and so reduces uncertainty associated with the regulatory process. Since the Commission first considered this matter in 1998, the use of a recent average of yields on inflation-indexed bonds with a remaining term of 10 years has become reasonably standard practice across all of Australian energy regulators and was adopted by all of the distributors to derive their risk free rate estimates in their price-service proposals. October 06 340 Essential Services Commission, Victoria Final Decision Subsequent to the submission of their price-service proposals, AGLE and United Energy have noted concern with this approach. For example, AGLE (2005b, p. 24) stated that: … there are likely to be inadequacies in the use of the index-linked Commonwealth bonds as the basis for estimating the true risk-free rate. AGLE and United Energy highlighted that, as evidence of this, regulators in the UK have not relied solely on current market rates or observed debt margins to estimate the risk-free rate, but instead have adjusted the risk-free rate where market rates are not expected to prevail. In their submissions to the Draft Decision, CitiPower, Powercor and United Energy all restated their concern that current yields on 10-year Treasury Indexed Bonds are at an histroric low and called on the Commission to consider that it would be prudent and reasonable to factor the risk that the risk-free rate may return to histroric levels in the future. By way of example, Powercor commented that: …there is likely to be more room for the real risk free rate to move up rather than down and therefore the distributors are likely to face a skewed real risk-free rate (Powercor 2005o, p. 4). In the 2001 Electricity Distribution Price Review, the issue of whether prevailing interest rates (averaged over a recent period) or some form of longer term average should be used to estimate the cost of capital was a central issue.96 The Commission notes that real interest rates (measured in the manner described above) have fallen since the 2001 Electricity Distribution Price Review, and that fall in the real interest rates accounts for virtually the entire decline in the Commission’s estimate of the cost of capital since that review. However, notwithstanding the observed decline in the real interest rates, the Commission does not consider it appropriate to modify its approach to deriving the real risk-free rate. The position that the Commission adopted in that review, after considering the advice of a number of finance experts and practitioners, was that the rates that are currently prevailing in the market provide the best forecast of interest rates over the forthcoming period. The yields currently observed reflect the rates at which parties are willing to buy and sell bonds and hence already reflect the weight of market opinion about future interest rate movements (including the histroric pattern of interest rates to the extent that history is considered relevant). Current yields also reflected the rates at which the distributors could lock in their debt financing if so desired and, in the Commission’s view the use of current interest rates was consistent with both theory and the weight of market practice. 96 Office of the Regulator-General 1998, pp. 195–201. The Commission considered more specifically whether recent yields on inflation-indexed bonds would provide the best proxy for the real risk-free rate in its subsequent review (ORG 2000a, pp.255-260). October 06 341 Essential Services Commission, Victoria Final Decision The Commission also noted at the time that using objective market evidence to derive the riskfree rate would increase the predictability of this element to the derivation of costs of capital for regulatory purposes. This was the approach applied in the Commission’s Draft Decision. Subsequent to the release of the Commission’s Draft Decision AGLE, CitiPower, Powercor and United Energy supplied a letter that outlined their concern regarding the measurement period used by the Commission when determining the value of the risk-free rate.97 In this submission the distributors proposed that the 20 day period used by the Commission to measure 10-year inflation-linked bonds (the last 20 trading days in August 2005) was a period where the yields on inflation-indexed bonds were artificially depressed (biased downwards). The distributors proposed that the downward bias was caused by a substantial one-off increase in demand for inflation-indexed bonds resulting from the maturity of Treasury Indexed Bond (TIB) 402 on August 20, 2005. This reduced the number of TIB issues in the market from four to three. The assumed underlying cause for the increase in demand for (and thus exerting downward pressure on yields) inflation-indexed bonds during the Commission’s measurement period is that the small number of investors that value such instruments would, on maturity of the bond, reinvest in similar inflation-linked bonds. In support of their view, AGLE, CitiPower, Powercor and United Energy provided additional evidence: • A letter from Westpac Institutional Bank dated 29 August 2005 that supports the view that the downward movement in yields on TIBs over the period from the 12th to the 19th August (from 2.50 per cent to 2.305 per cent) was “nearly entirely related to investors reinvesting the proceeds of the maturing 20/08/05 Commonwealth Indexed Bonds”. • A research paper from the Commonwealth Bank of Australia (CBA) that identifies the theoretical causes of a downward bias in TIBs, undertakes a statistical analysis that claims there has been a structural break in the yields on TIBs from 12 August 2005, and presents an econometric model that should be used to predict the unbiased risk-free rate on 31 August 2005. On review of this new information the Commission accepts the view, supported by empirical evidence, that the measurement period of inflation-indexed bonds cannot be considered to provide an unbiased estimate when determining the value of the risk-free rate of return for the 2006-10 regulatory period. The Commission accepts that the small market for inflation-linked bonds and the theoretical and empirical evidence for a downward bias in yields represented by a structural break could be seen to artificially depress the yields on TIBs. Additionally, the Commission notes that real yields have declined while nominal yields have remained relatively static implying a step increase in the forecast of inflation. In a normal environment, where inflationary expectations rise it would be expected that real yields would 97 Powercor 2005z, Letter to S. McMahon, 30 September. October 06 342 Essential Services Commission, Victoria Final Decision remain static (or even rise) while nominal yields would rise. The current observed pattern would suggest that the decline in real yields is artificial. In order to address the downward bias the Commission considers that it is appropriate to make an adjustment to the real risk-free rate. Subsequently, the issue to be addressed is to determine the most appropriate approach to adjust for the bias. In their research paper, CBA proposed the use of an econometric model to estimate the unbiased yield as at 31 August 2005. The Commission does not consider that this is an appropriate means to remedy for the bias. The implicit assumption underlying the CBA analysis is that past behaviour (with respect to interest rates) is a suitable means to forecast future outcomes. This approach is inconsistent with the view the Commission previously has expressed that the latest market information and data provides the best forecast of future inflation (provided of course that factors that may create a bias in the observed yields are not present). Based on this in principle approach, the Commission’s preferred response is to identify a measurement period that is not influenced by the downward bias, and to sample interest rates from that period. Data after August cannot be relied upon at this time as it is unclear for how long the downward bias may persist. On this basis, the Commission considers that it is appropriate to use the latest market evidence available prior to the biasing event. The Commission has therefore applied a measurement period for the calculation of the risk-free rate as the last 20 trading days of July 2005. This amended measurement period excludes any potential downward bias in the month of August, as identified by Westpac and CBA. On review of the evidence, the Commission considers it appropriate that the measurement period for the risk-free rate occur over the last 20 trading days of July 2005. This results in a risk-free rate of 2.64 per cent. The differing approach of the UK regulators to deriving the real risk-free rate was known at the time the Commission first considered this matter in 1998 (for example in the Monopolies and Mergers Commission (MMC) (1997) decision on Transco, which was referred to and drawn upon by the Commission in its 1998 review of gas access arrangements). Such an approach was not followed at the time (nor since by any other Australian regulators) for the reasons set out above. In its submission to the Draft Decision United Energy also called for the Commission to publicly commit to using whatever rates the market determines are appropriate at the next review and to any upward price implications this might have. While the Commission does not have the ability to bind any future regulator, it would expect that the most recent market data will be utilised in the assessment of an appropriate risk-free rate. United Energy (2005n, p. 9) also claimed that: “low” real risk free rates imply similarly “low” real growth rates (i.e. Solow’s Golden Rule holds). Consistency would appear to demand that, if the Commission is going to take the view that current market prices in respect of real interest rates are “right”, then it should also apply the implications of that view to all relevant aspects of the Final October 06 343 Essential Services Commission, Victoria Final Decision Determination. This issue is likely to be of particular relevance when estimating economic growth to develop electricity demand forecasts and, to some extent, growth capex programs. In other words, the economic growth assumptions underpinning electricity demand forecasts should reflect the economic growth assumptions underpinning the expected cost of capital. It is not obvious that the Commission’s assumptions on economic growth for the purposes of estimating electricity demand growth meet this criterion. If this is the case, the Commission is in error. The Commission does not accept that it is either necessary or appropriate to link the real risk-free rate that is used for a regulatory period with the assumption that it may make about economy wide growth. While the Commission is aware of the expected theoretical relationship between real risk free rates and economic growth (known as Solow’s Golden Rule), it notes that this relationship can only be expected to hold over the long term. For short periods — like a five year regulatory period — other methodologies for forecasting growth would be expected to yield superior forecasts and the Commission considers it appropriate to avail itself of such forecasts.98 In their submissions prior to the Draft Decision, the distributors also raised a number of issues associated with the implications of the averaging period for the risk-free rate for the estimation of debt financing costs, as well as issues associated with the inflation-linking of their revenue streams for the adequacy of the Commission’s allowance for the cost of debt financing. Both of these issues are addressed below in the Commission’s discussion of the cost of debt financing. In the Draft Decision the Commission indicated that, consistent with other regulators, it would adjust the risk-free rate to convert the semi-annual yields that are reported by the Reserve Bank of Australia into effective annual rates as required to estimate the cost of capital. It was recognised that while this adjustment is almost immaterial, it has been made for completeness. CitiPower and Powercor have highlighted to the Commission that the yields on Treasury Indexed Bonds reported by the Reserve Bank of Australia are calculated on a quarterly, rather than semiannual, basis. The Commission acknowledges this, and has adjusted for this accordingly. For its Final Decision the Commission has used the average of the observed yields on Commonwealth Government inflation-linked bonds over the 20 day period ending on 31 July 2005 as the real risk-free rate, which implied a rate (after adjusting to an effective annual rate) of 2.64 per cent. Following previous practice, a linear interpolation has been used to derive a proxy for the yield for an instrument with a remaining term of exactly 10 years. The Commission has also followed previous practice and derived its forecast of inflation by using the difference between the yield on nominal bonds calculated in the same manner (compounded on a semi-annual basis) and the real yield (using the Fisher transformation), which implied a long term inflation forecast of 2.56 per cent. It is important to note that the inflation forecast is only used to derive the benchmark taxation liabilities for the distributors. 98 No evidence was adduced that forecasters of short term economic growth use the real risk free rate as their forecast. October 06 344 Essential Services Commission, Victoria Final Decision Equity beta (βe) The equity beta reflects the level of non-diversifiable risk associated with a particular asset, relative to the (non-diversifiable) risk associated with a well-diversified portfolio of assets. The normal techniques for estimating equity betas require information on the economic returns of individual assets (the sum of dividends and changes in the market value of the asset) as well as the economic return on the well-diversified portfolio of assets, which is only available for entities listed on a stock exchange. As the distribution activities of regulated businesses are not separately listed on the Australian stock exchange, their equity betas cannot be estimated directly and it is necessary to use a proxy to determine the distributors’ after-tax WACC. Even where equity betas can be estimated for a particular entity, it is common practice to combine the equity beta estimate with information provided by the equity beta estimates for other firms to reduce the error associated with this variable. The Commission has noted in previous decisions that the estimation of the equity beta for regulated activities poses a number of challenges. There are few firms listed on the Australian Stock Exchange (ASX) that undertake similar activities to the distributors’ regulated activities, and so the set of empirical information (at least for Australia) is limited. Estimating equity betas also requires a number of methodological decisions to be made, for which there often is little theoretical guidance, which can have a substantial effect on the resulting estimates. As discussed in detail in the following section, the emergence and then ending of the ‘technology bubble’ in the world stock markets in recent years has been accepted elsewhere as potentially creating a bias in equity beta estimates, reducing the usefulness of some of the information that is available. Inevitably, equity beta estimation requires judgement and, given the Commission’s concern for stability and predictability in decision making, particularly judgement as to whether and to what extent any new information would justify a change from previous decisions. It is important to distinguish between the classes of risk that are reflected in the cost of capital and those that are not. Much of the risk associated with returns to a particular asset can be eliminated by capital market investors through diversification. Diversifiable risk generally arises from events that are unique to an entity or to a small group of entities. This implies that only the portion of risk that is associated with economy-wide events will be borne by investors and hence reflected in the cost of capital. Non-diversifiable risk can be influenced by changes to such factors as inflation, economic growth, tax rates, interest rates and international financial trading shocks. The level of gearing also affects the estimation and interpretation of equity betas. For a given level of risk for the particular activity or project, a rise in the proportion of debt in the entity’s financing structure will increase the level of risk borne by the equity providers. The Commission has adopted a benchmark financing structure for the distributors of 60 per cent debt-to-assets, and so an equity beta consistent with this level of gearing is required. The process of adjusting asset and debt betas for gearing levels is known as de-levering and re-levering, and the formula the Commission previously has used for this purpose is as follows: October 06 345 Essential Services Commission, Victoria Final Decision βa = βe E D + βd V V Where βa is the asset beta (the beta for an un-geared asset), βe is the equity beta, βd is the debt E D beta, is the proportion of equity funding and is the proportion of debt funding (gearing). V V In the 2001 Electricity Distribution Price Review, a proxy equity beta of 1.0 was adopted with reference to a deemed gearing ratio of 60 per cent debt to assets. A dominant theme in the distributors’ price-service proposals acknowledged that there are difficulties associated with the estimation of the equity beta. All distributors suggested that the value of the equity beta should not be less than 1. In support of their views, each of the distributors referred to additional material. AGLE provided a report prepared by the Strategic Finance Group (SFG 2004a), to which CitiPower, Powercor and SP AusNet99 also referred.100 AGLE also supplied a report prepared by KPMG (2004a) that discussed issues associated with, and means to develop, point estimates (with reference to the SFG report) for the WACC. SP AusNet and United Energy provided similar, but separately prepared KPMG reports. CitiPower (2004g) and Powercor (2004g) provided their own, but similar, analysis of cost of capital issues. Several common themes were presented in the submissions provided by the distributors with their original October 2004 submissions and to the Commission’s later Issues and Position Papers: • Recent statistical estimates of the equity beta are “low relative to historical averages”, but such estimates are “very imprecise” (SFG 2004a, p. 11). • There are commonly acknowledged issues associated with the estimation of the equity beta, including the frequency of observations and length of the sample period, poor statistical reliability, time variation in estimates, thin trading problems, the influence of outliers and the potential for the recent technology ‘boom and bust’ to have created a downward bias in equity beta. • Market evidence should be reviewed with caution and weight should be given to recent regulatory decisions to provide regulatory certainty. • Powercor and SP AusNet also concluded that the systematic risk of the predominantly rural distributors is higher than that of the urban distributors and, as such, the Commission should adopt a higher equity beta. This matter is addressed separately below. Based on the reports submitted in association with their price-service proposals, the distributors proposed a range of 0.9 to 1.1 for the equity beta, which was argued to be consistent with previous Australian regulatory decisions and market evidence. 99 100 Formerly TXU United Energy refer to an earlier (2003) but similar SFG report. October 06 346 Essential Services Commission, Victoria Final Decision In contrast to the distributors’ views, the Energy Users Coalition of Victoria (EUCV) has throughout the consultation process proposed that an equity beta in the range of 0.6 to 0.8 was more appropriate for electricity distribution businesses in light of the empirical information that both the Commission and other regulators have considered on betas for Australian and overseas firms (EUCV 2005a, p. 23). This is a view that was supported by the Victorian Consumers’ Groups (VCG) (2005a). For the purposes of setting regulated charges for the 2006-10 regulatory period, the Commission in its Draft Decision had regard to: • market evidence on equity betas, including current market evidence as well as market evidence that it considered at previous reviews; • the value that it adopted in its previous review of the price controls for the distributors; • the values adopted by other regulators in comparable decisions; and • overseas information on equity beta estimates (both current evidence and evidence from previous periods). On this basis, the Commission adopted an equity beta of 1 for an assumed gearing level of 60 per cent debt to assets. In its submission to the Commission’s Draft Decision, while AGLE did not consider the Draft Decision conservative on this matter, it agreed that the equity beta value of 1 as proposed by the Commission was consistent with the equity beta it had proposed in its previous submission, based on a uniform probability distribution of 0.9 to 1.1, with a mean of 1. AGLE considered that the value was consistent with that proposed by the SFG (2004a) paper provided with its October price-service proposal. AGLE noted that it accepted the Commission’s view that it was important for the beta estimate to be based upon market evidence, but highlighted that the difficulties with interpreting such evidence means that “there will be a need for careful analysis to derive appropriate conclusions about beta for the distribution businesses” in future reviews (AGLE 2005, p. 82). In their response to the Draft Decision, CitiPower and Powercor also maintained that the equity beta benchmark should be 1 consistent with their price-service proposals of October 2004. In further support of their view that 1 is the appropriate estimate for the equity beta, CitiPower and Powercor provided a number of papers that had been provided by ETSA Utilities in its Application for Review of the ESCOSA’s Electricity Distribution Price Determination (April 2005):101 • A Gray and Officer (2005a) report on the equity beta of an electricity distribution business: Report prepared for ETSA Utilities. • A NERA (2005a) report reviewing ESCOSA's decision on ETSA Utilities equity beta. • A Gray and Officer (2005b) report in response to the submission of the South Australian Treasurer to ESCOSA's Electricity Price Determination. 101 ETSA Utilities, like CitiPower and Powercor, is a member of the Cheung Kong Group of companies. October 06 347 Essential Services Commission, Victoria Final Decision • A NERA (2005b) report reviewing Associate Professor Lally's Critique of NERA's April Report. For the most part, these submissions highlighted themes or matters that the Commission itself has noted, such as the importance of stability in the regulatory regime and the implications of this for the relevance of ‘regulatory precedent’ when deriving WACC inputs and the potential errors associated with the estimation of equity betas, including the potential implications of the recent ‘boom and bust’ in technology stocks. However, that evidence along with the evidence adduced by the Treasury provided some additional empirical information, including information on betas for comparable US entities and estimates of betas for the Australian comparable entities that adopt more sophisticated estimation techniques (such as eliminating outliers). These other sources of information are discussed further below. In its submission to the Draft Decision, United Energy supported the Commission’s use of 1 as an appropriate estimation for the equity beta in light of “evidence of past decisions and the position of other regulators and economic advisers” (United Energy 2005n, p. 11). In support of its views, United Energy provides and cites a paper prepared for the Energy Networks Association (ENA) by Gray, Hall et. al (2005). This paper, provided to the Commission in response to the Position Paper, compared the performance of the ‘mechanical’ equity beta estimates that are prepared by the AGSM Risk Management Service to a number of alternative estimates for individual equity betas. These included lengthening the returns window, the use of the ‘Blume’ adjustment, a technique for eliminating outliers, using industry estimates rather than individual beta estimates and merely using a beta of 1 for all firms (that is, dispensing with the CAPM). The results of this analysis, as summarised by the authors, was to: … suggest that a longer data period should be used, and that the estimate should be adjusted toward unity using the Blume adjustment. In the absence of any such data, the best estimate of the equity beta for any company is unity (Gray, Hall et al 2005, p. 41). The joint Victorian Consumers’ Group (VCG 2005b) submission in response to the Draft Decision expressed concern that the ESC, in adopting an equity beta of 1, “continues to set the WACC above a level recently established by Australian regulators for electricity distribution in other jurisdictions” (VCG 2005b, p. 26). In particular, the VCG (2005b) submission contrasts the equity beta value applied in the Draft Decision to that used in the Commission’s Water Price Review Final Decision and the analysis in that document that referred to an equity beta of 0.70 for the energy sector. The VCG (2005b) submission implicitly raises two separate issues, which are, first, what the market evidence suggests about the equity beta for regulated activities in the energy sector and, secondly, to what extent the beta for regulated energy sector activities is likely to differ from the beta for regulated water sector activities (and, implicitly, whether the Commission’s conclusions in the Draft Decision are consistent with the conclusions it reached for the water businesses). The first of these matters is the central topic of this chapter, and will not be expanded upon here. Turning to the second of the matters, the Commission formed the view when setting regulated October 06 348 Essential Services Commission, Victoria Final Decision charges for the water sector that the systematic risk for regulated water sector activities is likely to be lower than that for the energy sector. These conclusions, in turn, were based upon: • the Commission’s a priori belief about the likely differences in betas between the water and energy sector; • estimates of the betas for water businesses in the US and UK and the observed relativities between the betas for water businesses and energy businesses; • the beta values that have been adopted by Australian regulators when setting water charges; and • the water businesses’ proposals, which were within the range of 0.75 and 1.00. The Commission remains of the view that the systematic risk of the regulated activities in the water sector is likely to be lower than that in the energy sector, and that the relativity of equity betas adopted is appropriate. The EUCV (2005d) also expressed concern that Australian regulators did not appear to appropriately benchmark the returns of electricity distributors with that of the market, nor appear to be consistent in determining “what is the correct value for equity beta” (EUCV 2005d, p. 52). The EUCV calls on the Commission to follow the decisions of ESCOSA, IPART and the QCA to apply a lower equity beta. Additionally, the EUCV (2005d, p. 46) state that: The ESCOV is required by its Act to set an equity beta which replicates the local market of like industries, international benchmarks for like industries and the recent decisions of other Australian regulators when setting equity beta. By setting an equity beta of 1.0, the ESCOV is failing to comply with the ESC Act and the National Electricity Rules. As noted earlier, the Commission has considered at length the issues and difficulties associated with deriving a proxy equity beta for the distributors’ regulated activities in its previous reviews. Many of the views expressed in submissions — in particular, that substantial weight should be placed upon previous regulatory decisions in light of the imprecision associated with equity beta estimates — reflect the Commission’s own previous conclusions. The Commission has emphasised, however, that as the cost of capital is a market-determined parameter, it is essential that an assessment of the available market evidence is made, even if that evidence is subsequently found wanting and therefore not accorded substantial weight. The Commission notes that the only means through which to resolve the issue of whether the Commission’s previous assumption of an equity beta of 1 is excessively conservative as commented by the customer representatives is with reference to the available market evidence but interpreted in light of the difficulties already discussed with estimating the equity beta. In its previous reviews, the Commission has referred to the equity betas produced by the AGSM Risk Management Service for the firms the Commission considered to be sufficiently comparable entities. Figure 9.1 updates the beta estimates provided in the Commission’s most recent decision regarding the pricing of Victorian water, and also shows how the equity beta estimate derived in October 06 349 Essential Services Commission, Victoria Final Decision this manner would have changed over time. All of the equity beta estimates are adjusted to reflect the target gearing level of 60 per cent debt-to-assets (all calculated using a zero debt beta). Figure 9.1: Average equity beta for comparable Australian entities 1.2 Equity beta (Relevered to 60 % D/A) 1 0.8 0.6 0.4 0.2 Jun-05 Mar-05 Dec-04 Jun-04 Sep-04 Mar-04 Dec-03 Sep-03 Jun-03 Mar-03 Dec-02 Jun-02 Sep-02 Mar-02 Dec-01 Sep-01 Jun-01 Mar-01 Dec-00 Sep-00 Jun-00 Mar-00 Dec-99 Sep-99 0 Note: Betas were obtained from the Risk Management Service of the Australian Graduate School of Management. The estimates include four years of observations, or the firm’s trading history. Firms are only included where there are more than twenty observations. Thin trading betas were used where the test for thin trading was failed at the 10 per cent level of significance. Gearing is calculated as the average of the annual gearing levels observed over the period over which the relevant beta was estimated. The value of equity is the firm’s market capitalisation using share price data obtained from Bloomberg. The value of debt is taken as the book value of debt, also obtained from Bloomberg. Loan notes are treated as equity (including where the note is interest bearing). The proxy group between September 1999 and December 1999 included AGLE and Envestra only, between March 2000 and December 2001, it comprised AGLE, Envestra and United Energy, in March 2002 it included AGLE, Envestra, United Energy and the Australian Pipeline Trust, between June 2002 and June 2003 it included AGL, Envestra, United Energy, the Australian Pipeline Trust and AlintaGas, and since September 2003 it has included AGLE, Envestra, the Australian Pipeline Trust, AlintaGas and GasNet. There have been at least two concerns explicitly or implicitly raised in submissions (and acknowledged by the Commission in its Draft Decision) with the conclusions that can be drawn from the equity beta estimates presented above. First, a number of submissions raised the concern that equity beta estimates for utility stocks measured over the period of the technology ‘boom and bust’ are likely to be downward biased. The rationale for this bias is that, while technology stocks rose during the stock market ‘bubble’ and then slumped during the subsequent correction, safe stocks like utilities moved in the opposite direction (and, as such, opposite to the market as a whole). To the extent that the technology bubble is not expected to repeat periodically, the measured covariance between utility stocks and the market would understate the expected covariance (and hence, expected equity beta). Both ESCOSA (2005a) and the QCA (2005) have accepted that the technology ‘boom and bust’ is likely to have led to a downward bias in measured equity betas over that period. The behaviour of the equity betas for the Australian firms, as set out above, appears consistent with the anticipated effect of the technology ‘boom and bust’. In addition, ESCOSA (2005a) also October 06 350 Essential Services Commission, Victoria Final Decision investigated the behaviour of the betas for US electricity distribution businesses over this period. Analysis of equity betas of firms in the US has the advantage of being able to make use of a much larger set of listed entities, as well as information over a longer period (of the Australian comparable firms used to derive the average equity beta above, only AGLE existed prior to August 1997). The information presented by ESCOSA (2005) is extended in Figure 9.2. Figure 9.2: Average equity beta for US electricity distribution businesses 0.9 0.8 0.7 Average re-levered beta 0.6 0.5 0.4 0.3 0.2 0.1 Jul-05 Jul-04 Jan-05 Jul-03 Jan-04 Jul-02 Jan-03 Jul-01 Jan-02 Jul-00 Jan-01 Jul-99 Jan-00 Jul-98 Jan-99 Jul-97 Jan-98 Jul-96 Jan-97 Jul-95 Jan-96 Jul-94 Jan-95 Jul-93 Jan-94 Jul-92 Jan-93 -0.1 Jan-92 0.0 -0.2 Month ending Note: The chart reflects the average equity beta (re-levered for gearing of 60 per cent debt-to-assets) across a group of 12 US electricity distributors, measured using monthly return observations. Figure 9.2 shows that, while the re-levered equity beta averaged across the sample of firms fluctuated within a band of about 0.6 to 0.8 over the period prior to the technology ‘boom and bust’, the equity beta estimates dropped substantially after about mid 1998, which is consistent with the proposition that the ‘boom and bust’ depressed measured equity betas. The Commission accepts that the recent technology ‘boom and bust’ is likely to have had a depressing impact on measured equity betas over the relevant period, and which is likely to lead to an understatement of the expected (forward-looking) equity beta where observations over the ‘boom and bust’ period are included in the sample. Second, the papers by Gray and Officer (2004) and the Energy Networks Association (Gray, Hall et al, 2005) also raise a number of additional empirical issues associated with the estimation of equity betas, as described above. The implication of both the Gray and Officer (2004) and Electricity Networks Association (Gray, Hall et al 2005) papers is that more sophisticated techniques may produce better estimates of equity betas from the available empirical data than produced by the public beta services (such as the AGSM Risk Management Service), in particular, to address particular statistical issues associated with the estimation of betas. Gray and Officer (2004) illustrate the potential differences in the equity beta estimates from the use of the more sophisticated methods, and the Electricity Networks Association (Gray, Hall et al 2005) report presents an analysis of the difference in the accuracy of the different equity beta estimation methods. October 06 351 Essential Services Commission, Victoria Final Decision As noted above, Gray and Officer (2005a) then derived equity beta estimates for the set of Australian comparable entities listed above that attempted to remove some of the potential problems, including to: • eliminate data for the technology stock ‘boom and bust’ period; and • eliminate observations considered to be outliers. The Commission notes, however, that ESCOSA had specific concerns with the Gray and Officer (2005a) equity beta estimates, which were that: • the results were based on consideration of only a limited number of comparable firms; • the Blume adjustment was applied to the raw beta estimates, which it considered to be inappropriate; and • on the advice of Professor Lally, only the first column of Gray and Officer’s results should be considered (the more narrow definition of outliers to data points with residual of greater than 2 standard deviations) (ESCOSA 2005b). After making these adjustments, ESCOSA accepted that the more sophisticated methods employed by Gray and Officer (2005a) provided support for an equity beta (for a gearing level of 60 per cent debt to assets) of approximately 0.82. The Commission shares ESCOSA’s concerns, most notably on the appropriateness of the Blume adjustment, which the Commission previously has considered at length (for instance, see ESC 2002) and that a more cautious definition of outliers should be employed (in light of Professor Lally’s comments). As noted in the Draft Decision the Commission welcomes the additional research being undertaken into the estimation of equity betas present in both reports, and encourages further research on improvements to the estimation of equity betas. To a large extent, the analysis presented in these reports underscores the caution the Commission has exercised in all of its previous price reviews when interpreting empirical information on equity betas. The Commission made several remarks in the Draft Decision that it considers remain relevant. First, when considering the applicability of the results in the report for the Energy Networks Association (Gray, Hall et al 2005), it needs to be understood that the Commission’s approach in previous decisions has not been merely to take an equity beta estimate for a single firm, or even the average of the equity beta estimates for a group of firms, and to apply that estimate uncritically. Rather, the Commission has also had regard to estimates of equity betas for relevant entities in other countries, the equity beta estimates used by regulators in other countries (to the extent that the CAPM is used), previous decisions by Australian regulators and the qualitative arguments presented, thus augmenting the information available from Australian empirical evidence. The Commission would expect to continue to place weight on all of the available information when deriving the equity beta for regulated entities. Second, an implication of each report is that regulators should have regard to estimates of equity betas that have been estimated using more sophisticated techniques than adopted by the public beta services (such as the AGSM Risk Management Service), with the latter referred to in a October 06 352 Essential Services Commission, Victoria Final Decision number of places as ‘mechanical’. Gray and Officer’s further work for ETSA Utilities provides an application of such a more sophisticated approach. While the Commission accepts that more sophisticated estimation techniques may produce better equity beta estimates, it notes that one of the main justifications for using public beta estimates is because the use of such sources promotes transparency and objectivity in decision making. Accordingly, an important prerequisite for placing substantial weight upon more sophisticated techniques is that the Commission and other interested parties are provided with sufficient opportunity to understand, replicate and examine the robustness of the results presented. The Commission notes that the results presented by Gray and Officer (2005a) have not been subject to substantial debate as yet (and were not even produced for review of the Victorian distributors), and that the use of such sophisticated techniques may not be consistent with the evidence on standard market practice that the distributors themselves have presented (for example, see Truong et al 2005). That said, the Commission considers that the techniques adopted are likely to represent an advance on previous techniques (notwithstanding that it may not be consistent with standard market practice), and that it is appropriate to place weight on the equity beta estimates presented (subject to the adjustments considered appropriate by ESCOSA). The results of the Gray and Officer (2005a, pp.36, 39) analysis are presented with the ECOSA (2005b, p.49) adjusted figures (based on the advice of Professor Lally) in Table 9.3. Table 9.3: Re-levered Beta estimates after removal of technology bubble and outliers: Officer and Gray (2005) and ESCOSA adjusted (2005a) Outlier Removal Criteria (standard errors) 2.0 2.0 Gray and Officer Blume beta 60%a ESCOSA recalculation of raw beta 60% 0.80 1.46 0.95 0.77 1.00 0.39 1.35 0.74 0.81 0.83 1.06 0.83 0.95 0.78 0.90 0.84 1.23 1.23 1.04 1.04 3.5 Years: 7/2001 – 12/2004 AGL Alinta APT Envestra Mean 4 Years: 1/1998 – 6/1990, 7/2001 – 12/2004 AGL Envestra Mean 5 Years: 1/1997 – 6/1998, 7/2001 – 12/2004 AGL Mean a AGSM monthly data file, SFG regression analysis, gearing estimates from ESCOSA’s Draft Determination Table 10.2, debt beta of 0.2 for Envestra and zero for other firms, consistent with the procedure used in ESCOSA’s Draft Determination p.168, equity betas are re-levered to 60 per cent gearing, outliers and the technology bubble are eliminated. Raw beta estimates are Blume-adjusted before being re-levered. October 06 353 Essential Services Commission, Victoria Final Decision As discussed above, the material presented to ESCOSA also provided further evidence of betas for US firms (see Table 9.4). Table 9.4: Gray and Officer (2004) Beta Estimates from Comparable US Firms Industry Name Electric Utilities (Central) Electric Utilities (East) Electric Utilities (West) Natural Gas Distribution Natural Gas Mean Number of Firms Mean Equity Beta Mean Leverage Equity Beta Relevered with Bd = 0 25 0.82 52% 0.98 30 0.76 49% 0.96 15 0.82 48% 1.06 31 0.65 46% 0.88 38 0.87 0.78 42% 1.25 1.03 Source: Gray and Officer (2004, p. 18). The table contains beta estimates for comparable U.S. firms computed by Value Line, http://pages.stern.nyu.edu/~adamodar/pc/datasets/betas.xls. The table also presents equity beta estimates after relevering to the benchmark assumption of 60 per cent debt financing. Mean leverage values have been rounded. In its assessment of the Officer and Gray (2004) data ESCOSA (2005a, p.137) noted that: Different sources can provide different outcomes since the outcomes are dependent on a number of factors such as the period covered by the data, the companies that are included in the sample, the index used as the independent variable, and whether any adjustments (such as the ‘Blume’ adjustment) have been made. In particular the use of the Value Line data was called into question as this data “is known to adopt the ‘Blume’ adjustment”, which is considered inappropriate for the regulatory context. In addition, ESCOSA (2005a, p. 137) observed that: Another reason why the ValueLine Betas are inappropriate is that a number of companies that make up the “Electric Utilities” are very diverse and may influence betas materially. For example, a number of companies that predominantly generate electricity (rather then distribute) are included in the list. Lally (2005) also developed estimates of the asset beta of US firms to expand the set of comparators for the purposes of the ESCOSA (2005a) decision (see Table 9.5). October 06 354 Essential Services Commission, Victoria Final Decision Table 9.5: Lally (2005) asset beta estimates, with equity beta estimates Source Data Period Value Line 1999 – 2003 1994 – 1998 2002 – 2003 1990 – 1994 1999 – 2003 1993 – 1997 1999 – 2003 1994 – 1998 1989 – 1993 Value Line Bloomberg Alexander Ibbotson Ibbotson S&P S&P S&P Median Number of firms in sample Electricity Utilities Asset Beta Electricity Utilities Equity Beta Gas Asset Beta Gas Equity Beta Overall Asset Beta Overall Equity Beta 83 0.35 0.88 0.17 0.43 0.29 0.73 147 0.26 0.65 0.26 0.65 0.26 0.65 93 0.27 0.68 0.20 0.50 0.25 0.63 35 0.33 0.83 0.22 0.55 0.27 0.68 50 0.12 0.30 0.06 0.15 0.11 0.28 108 0.32 0.80 0.33 0.83 0.32 0.80 80 0.18 0.45 0.19 0.48 0.19 0.48 73 0.19 0.48 0.32 0.80 0.26 0.65 65 0.34 0.85 0.29 0.73 0.32 0.80 0.27 0.68 0.22 0.55 0.26 0.65 Source: Lally (2005, p. 14). The Commission has generated equity betas consistent with 60 per cent gearing. The Lally (2005) analysis estimated asset beta of 0.30 resulted in an equity beta of 0.75, consistent with a gearing level of 60 per cent. The Commission has obtained its own estimates of beta for a group of specific firms, which it considers preferable to the Gray and Officer or Lally figures. However, the Commission notes that the Lally (2005) numbers are close to the Commission’s own estimates of beta for US firms. As discussed already, in addition to the empirical evidence on equity betas, the Commission considers it important to have regard to the decisions of other Australian regulators in relevant matters. Table 9.6 sets out the decisions that the Commission has had regard to. October 06 355 Essential Services Commission, Victoria Final Decision Table 9.6: Regulatory decisions on the equity beta Regulatory decision Adjusted equity beta (60 per cent debt to regulatory assets)a 2001 ACCC Powerlink Transmission Decision 2001 ESC Electricity Distribution Price Review 2002 ACCC ElectraNet Transmission Decision 2002 ACCC SPI PowerNet Transmission Decision 2002 ACCC Victoria Gas Transmission Final Decision 2003 ACCC Moomba to Adelaide Pipeline Gas Transmission Final Decision 2003 ESC Gas Access Arrangements 2004 ACCC Transend Transmission Decision 2004 ICRC ActewAGL Electricity Distribution Final Decision 2004 IPART Electricity Distribution Final Decision 2005 ESCOSA Electricity Distribution Redetermination 2005 QCA Electricity Distribution Final Decision 2005 IPART Revised Access Arrangement for AGL Gas Networks Final Decision a 1.0 1.0 1.0 1.0 0.98 1.16 1.0 1.0 0.9 0.78 – 1.11 0.90 0.90 0.80 – 1.00 Adjusted for consistency with the Commission’s assumptions about gearing. It is clear from Table 9.6 that there has been substantial convergence in Australian regulatory decisions on the equity beta of regulated gas and electricity infrastructure at around 1, which the Commission has adopted in its two most recent energy price reviews. Previously, the Commission has undertaken extensive analysis into the appropriate equity beta for a regulated electricity distribution business, and concluded that 1 is appropriate, having regard to the available market evidence, as well as other important matters, like the importance of creating a stable, predictable and replicable regulatory regime. The equity beta estimates have fallen substantially compared to the time of the last review. However, the Commission considers that the effects of the recent ‘boom and bust’ in technologyrelated stocks (as illustrated by the observed substantial reduction in equity betas for electricity distributors in the US) provides a plausible reason for placing little weight on the recent movements. The Commission also notes that the more sophisticated estimation techniques for equity betas that were provided to the current review also reinforce that the current movements in observed equity betas is likely to be misleading and that the market evidence may support an equity beta of 1. In view of the problems with interpreting recent market evidence and the Commission’s view of the importance of creating a stable, predictable and replicable regulatory regime, and having regard to the results of more sophisticated estimation methods, the Commission has again adopted an equity beta of 1 to estimate the cost of capital associated with the distributors’ regulated activities. That said the Commission remains of the view it has expressed in previous decisions that it would envisage placing more weight on market evidence on equity betas as the problems with the quality of data are remedied, the extent of information available improves and techniques for interpreting that evidence are refined. October 06 356 Essential Services Commission, Victoria Final Decision The Commission has adopted an equity beta of 1 for an assumed gearing level of 60 per cent debt to assets. Equity (market risk) premium (Rm – Rf) As measured and applied in practice, the equity (or market risk) premium that is used in the CAPM is the premium over and above the risk-free rate of return that investors expect to earn on a well diversified portfolio of assets. In its previous decisions, the Commission has noted that there are a number of methods available to estimate the (expected) equity premium. In its previous reviews, the Commission has formed the view that it is appropriate to consider a number of different sources of evidence when deriving a value for the equity (market risk) premium. In particular, it has had regard to at least three different techniques for estimating the equity premium. The first is to use averages of the historically observed premium, the second is to attempt to estimate the equity (market risk) premium from current share prices, assumptions about investors’ expected growth in dividends and a model for linking the variables (ex ante methods). A third method is to survey market practitioners or other experts directly. There are also variants to the methods. The Commission has also had regard to the extensive debate amongst practitioners and academics about whether there may be a priori reasons for the premium to have changed over time. In previous decisions, the Commission has discussed in some detail the potential shortcomings of each of the different equity (market risk) premium estimation methods. It has noted that both the choice of method and the detailed approach to applying any particular method are subject to extensive debate amongst finance theorists and practitioners, and poor statistical precision is a characteristic of all of the methods. The estimates of the equity (market risk) premium that were provided by the distributors in their price-service proposals lie within the range from 6 per cent to 8 per cent (see Table 9.2). A main source of evidence presented by AGLE, SP AusNet and United Energy for the range was a report from KPMG (and similar evidence in the case of CitiPower and Powercor) that summarised a number of estimates of the historical Australian equity (market risk) premium. KPMG (2004a) also commented that other methodologies, such as surveys or the ex-ante approach could not be relied on with confidence. In their price-service proposals distributors also commented that the equity (market risk) premium applied may have been significantly understated for the last 14 years as the measurements have, in their opinion, not taken the effect of dividend imputation (franking credits) into account. Consequently, the distributors maintained that their proposed range of between 6 per cent and 8 per cent for the equity (market risk) premium was conservative. CitiPower and Powercor stated that if the value of franking credits was not reduced, the equity (market risk) premium should be increased. Capital Research (2005) and the South Australian Centre for Economic Studies (SACES) (2005) provided reports that questioned the distributors’ views about the equity (market risk) premium. Both of the papers contained sophisticated methods for analysing past returns in order to derive October 06 357 Essential Services Commission, Victoria Final Decision the best estimate of the expected future equity premium from these returns. Capital Research (2005) and the SACES (2005) indicated that measuring the equity (market risk) premium over the longest period using an arithmetic average would overstate the expected equity premium because: • more weight should be placed upon more recent observations as the market has changed substantially (both Capital Research and SACES); • returns are more appropriately measured as 10–year holding period returns (Capital Research); • geometric means should be used to interpret past data and then adjusted to an equivalent arithmetic mean in order to avoid bias (both Capital Research and SACES); and • unexpected asset price inflation over the averaging period has led to an upward bias in the estimate of the equity premium (both Capital Research and SACES). Capital Research (2005) suggested that the use of a 10-year holding period, geometric mean (then adjusted to an arithmetic mean) and removing the bias caused by unexpected asset price inflation (as preferred) delivers an estimate of the expected equity (market risk) premium of approximately 6 per cent. Placing more weight upon the more recent market evidence (as recommended) results in an estimate of the equity (market risk) premium of 4.5 per cent. The SACES (2005) report found that placing sole weight on the last 30 years would imply an equity (market risk) premium of 5 per cent after the removal of biases (or about 5.6 per cent once the non-cash value of franking credits are included). Its other analysis suggested that the true range probably extends below this, between 5.1 per cent and 5.6 per cent (after adding on 0.6 percentage points for franking credits). In the Draft Decision, the Commission noted that (with specific reference to the distributors’ proposals) inferences from historical returns inevitably rely upon the same set of data. Consequently the differences in the estimated equity (market risk) premium must reflect differences in the time period of observations, the averaging technique and any adjustments that have been made to the raw estimate. The upper limit of the distributors’ range would appear to reflect an adjusted average over the period between 1974 and 1995, or the average between 1882 and 1987 (SFG 2004a, p. 26). It was noted that, as it is now 2005, neither of these time periods have any obvious justification. Rather than simply quoting a ‘range’ for the advice provided by history, the Commission considered it more appropriate to evaluate the different issues or choices available when estimating the equity (market risk) premium, and then to consider the different estimates of the equity (market risk) premium that result from each of the feasible choices. Turning to the Capital Research (2005) and SACES (2005) papers, the Commission noted that the new material presented suggested that the Commission’s previous view about the equity (market risk) premium of 6 per cent may be consistent with a more sophisticated interpretation of the long term historical evidence. In particular, that the material suggested that there are reasons to believe that the long term average may overstate the expected equity (market risk) premium (even on the assumption that the expected equity (market risk) premium has remained the same throughout history). October 06 358 Essential Services Commission, Victoria Final Decision The Commission adopted an equity (market risk) premium of 6 per cent in the Draft Decision, having regard to a range of information (much of which is summarised again below), including the new material presented by Capital Research (2005) and SACES (2005), information on the historical premium, other sources of information (including survey information and evidence the Commission previously has examined on the ex ante premium) and the Commission’s and other regulators’ previous findings. In their response to the Draft Decision, the distributors maintained that the equity (market risk) premium should be at least 6 per cent, consistent with the views expressed in their price-service proposals. AGLE and United Energy again commented that an equity (market risk) premium of 6 per cent to 8 per cent be applied for the 2006-10 period as they maintain the view that this is a value consistent with reference to the long term historical average. AGLE and United Energy were also concerned that the equity (market risk) premium estimate should be represented as a range, established with reference to a formalised estimation methodology based on a Monte Carlo approach. The Commission has addressed this in the discussion above. United Energy also questioned the merit of relying upon methodologies other than long term averages to establish an estimate of the equity (market risk) premium, such as surveys of market experts, economic models, inter-country comparisons and historical averages. United Energy was also concerned that the evidence that the Commission had relied upon to establish its value for the equity (market risk) premium was dated. The distributors jointly presented or commissioned several pieces of research relevant to determining the value that is to be adopted for the market risk premium. These pieces of research were: • a report by Strategic Finance Group Consulting (SFG, 2005b) exploring the relationship between franking credits and the market risk premium; • a report Gray and Officer (2005) which was commissioned to review and critique the material provided by Capital Research (2005); • a report by SACES (2005) which was commissioned by the ENA; and • a report by KPMG (2005c) summarising the assumptions that independent expert valuations have adopted regarding the market risk premium and ‘gamma’ in recent years (that is, in the situations where the discounted cash flow methodology is employed). In addition, the material provided by the distributors also referred to a recent survey of Australian firms regarding the assumptions those firms adopted when assessing the commercial viability of new projects. Turning to the report by SFG (2005b), the key conclusion of this report is that the Commission’s assumptions of an equity (market risk) premium of 6 per cent and a ‘gamma’ value of 0.50 are internally inconsistent. It also commented in the report that the Commission has ignored the value of franking credits when deriving an equity (market risk) premium in its previous review. October 06 359 Essential Services Commission, Victoria Final Decision The Commission’s analysis of this report is set out in more detail in the discussion on franking credits (see the Franking Credits section), but the main conclusions were as follows. • The Commission rejects the comment that it has ignored the value of franking credits in previous review. Rather the Commission has been careful to add back the non cash value of franking credits where appropriate. By way of example, in the Commission’s last major energy review, the formula employed was set out,102 an explicit adjustment was made to the long term average equity return that was reported,103 an explicit adjustment was made to the equity premium that Mercer identified as its preferred assumption,104 and an explicit adjustment was made for the credits when interpreting the survey evidence.105 • The mathematical formulae adopted by SFG (2005b) are identical to those adopted by the Commission, which should be expected as all reconcile to formulae published by Officer (1994) and Lally (2000). • However, inputs adopted by SFG (2005b) in its calculations are flawed, being assumed rather than measured, and generate materially misleading results. • In any event, the required adjustment to the equity (market risk) premium will depend upon how it is derived. For estimates based upon historical returns, an adjustment need only be made for the period since the introduction of dividend imputation, which implies that the adjustment to the long term average is small. The non cash value of franking credits has been added to the estimates of the equity (market risk) premium in the values reported below. Turning to the report by Gray and Officer (2005), the key conclusions of the report are as follows: • The average premium to equities measured over the last 30 years, 50 years, 75 years, 100 years and 120 years all exceed 6 per cent (these figures are set out in Table 9.7). • Some of the statistical techniques that are proposed in the Capital Research (2005) and SACES (2005) papers for the measurement of the equity (market risk) premium are considered inferior to the simple mean estimate. However, they find that the different techniques adopted (namely, the use of 10 year holding period returns by Capital Research (2005) and a filtering approach and more frequent data used by SACES (2005)) both generate estimates of the equity (market risk) premium approximately equal to (or in excess of) 6 per cent. • The main differences between the results presented by Capital Research (2005) and SACES (2005) arise from adjustments that were made to the raw estimates, namely to remove what was considered an upward bias in the estimate of the expected premium that would result from the use of actual returns (rise in the price earnings ratio in the case of Capital Research (2005), and the effect of the fall in interest rates and dividend imputation 102 103 104 105 ESC 2002, p.398. ESC 2002, p.328. ESC 2002, p.334. ESC 2002, p.340. October 06 360 Essential Services Commission, Victoria Final Decision in the case of SACES (2005)). Gray and Officer (2005) questioned all of these adjustments on the basis that they were not supported by strong theoretical or empirical justification. The estimates of the equity (market risk) premium that Gray and Officer (2005) produced, the results of Capital Research (2005) and SACES (2005) as updated by Gray and Officer (2005) but with the adjustments excluded and the averages the Commission previously reported (but updated) are set out in Table 9.7. Table 9.7: Average observed excess market returns Length of period Years Mean excess return Gamma increment (historic average) Gamma adjusted mean excess return 30 1975 – 2004 7.70% 0.65 8.34% a 1970 – 2004 4.04% 0.55 4.59% a 45 1960 – 2004 5.27% 0.43 5.71% 50 1955 – 2004 6.43% 0.39 6.82% a 55 1950 – 2004 6.77% 0.35 7.12% 75 1930 – 2004 6.58% 0.26 6.84% 100 1905 – 2004 7.15% 0.19 7.34% a 105 1900 – 2004 7.26 0.18 7.44% 120 1885 – 2004 7.17% 0.16 7.33% 35 a Commission calculated. These numbers update the mean excess returns for historical periods with different starting points than were previously published by the Commission (ESC 2002a) Turning to the adjustments proposed by Capital Research (2005) and SACES (2005), the Commission does not accept the argument of Gray and Officer (2005) that such adjustments should be ruled out, but rather accepts that this is an area where experts in the area may disagree. The Commission has substantial sympathy with the view of Gray and Officer (2005) that the interpretation of empirical evidence (including any adjustments to raw data or estimates) should have strong theoretical and empirical justification. However, the Commission also notes that the proposition at the heart of the Capital Research (2005) and SACES (2005) material has been common to other independent, credible pieces of research. The proposition is that the actual historical returns to equity may include substantial unexpected capital gains, which means that actual historical returns may have exceeded the expected returns over the period, which in turn implies that actual historical returns may exceed expected future returns, even if expected returns have not changed. By way of example, this proposition sits at the centre of the series of estimates of the US equity (market risk) premium that the Commission previously has considered and labelled as ‘alternative estimates of the historically expected returns’, which includes work by very eminent experts in the field of finance.106 Therefore, the Commission considers that the adjustments 106 ESC 2002, pp. 331-333. See McGrattan, E., Prescott, E., Taxes, Regulations and Asset Prices, NBER working paper no. 8623, 2001; Fama, E. and K. French, The Equity Premium, The Journal of Finance, Vol LVII, no. 2, 2002, p.638; October 06 361 Essential Services Commission, Victoria Final Decision proposed by Capital Research (2005) and SACES (2005) should be taken into account, and note that these adjustments would reduce the market risk premium measured over a 30 year period by approximately 150 basis points, but proportionately less over longer periods. The information that the Commission has taken into account in this regard is set out in Table 9.8. Table 9.8: Australian and US estimates of the equity (market risk) premium Study Period Actual excess returns Adjusted excess returns 1875 – 2005 7.0% 5.5% 1960 – 2005 5.6% 4.5% 1872 – 2000 5.6% 4.4% (div. growth) 1951 – 2000 7.4% 3.8% (div. growth) 1951 - 2000 7.4% 4.8% (div. growth) Australian estimates Capital Research (2005) US estimates Fama and French (2002) Source: Fama, E. and K. French, 2002, ‘The Equity Premium’, The Journal of Finance, Vol LVII, no. 2, p. 641, Table 1 and pp 654-655. The estimates are arithmetic averages of historical expected stock yields. The Fama and French results report the premium against (6 month) bills. The Capital Research estimates adjust the actual excess return for both the change in expected future volatility compared to the past and to remove the effect of the rise in the price earnings ratio. Turning to the other evidence that was provided on the assumptions of market practitioners, the reports by KPMG (2005c) and Truong et al (2005) indicate that in the application of the CAPM the majority of practitioners use 6 per cent as the equity ‘market risk’ premium. The majority of such decisions were made on the basis of precedent or established standards. In interpreting the survey information the Commission notes that the estimates provided by KPMG (2005c) and Truong et al (2005) need to be adjusted for the value of franking credits. The Commission has considered at length the issues associated with estimating the equity (market risk) premium at its previous reviews, the different estimation methodologies and the advantages and disadvantages of each. In particular the Commission has reviewed other evidence on market practitioners such as equity analysts and asset allocation consultants. For instance, in its 2002 Gas Decision, the Commission took into account work undertaken by Mercer Investment Consulting, a number of US surveys, and a Jardine Fleming Capital Markets Survey that covered 61 respondents in Australia (of which 35 were non-academics). The Commission also took account of survey evidence from the US, where more extensive surveys of market practitioners have been taken. The Commission considers it appropriate to continue to take account of this information. The evidence from practitioner surveys the Commission has taken into account in the current review is set out in Table 9.9. Jagannathan, R, E. McGrattan and A. Scherbina, ‘The Declining U.S Equity Premium’, Federal Reserve Bank of Minneapolis Quarterly Review, vol 24, no 4. October 06 362 Essential Services Commission, Victoria Final Decision Table 9.9: Study Practitioner survey estimates of the equity (market risk) premium Period Market Practitioner Expected mean excess return (average) Increment for imputation credits Gamma adjusted expected mean excess return 5.94% 0.82% 6.76% 6.00% - 8.00% 0.82% 6.82% - 8.82% Australian surveys Truong et al 2004 KPMG 2000 – 2004 Jardine Fleming 2001 Total 0.82% Academics 4.73% 0.82% 5.55% Brokers 4.92% 0.82% 5.74% Asset consultants/trustees 4.50% 0.82% 5.32% Corporate managers 3.13% 0.82% 3.95% 5.27% 0.82% 6.09% US surveys Welch (2000)a 1997 and 1998 Finance Academics Welch (2001)a 2001 Finance Academics Graham and Harvey (2001)b 2000 to 2001 7.1% (mean) 7.0% (median) 5.5% (mean) 5.0% (median) Chief Financial Officers 4.2% n/a n/a n/a 7.1% (mean) 7.0% (median) 5.5% (mean) 5.0% (median) 4.2%c a The equity premium reported is the 30 year arithmetic average equity premium measured against bonds. b The equity premium reported is the 10 year arithmetic average equity premium measured against bonds. c The range for the equity premium of 3.6-4.7 per cent reported in the Draft Decision referred to the range for the average of responses across six separate surveys conducted between 6 June 2000 and 10 September 2001, and the number reported in the table above is the weighted average results from these surveys. The median of the expected equity premium was below the mean for all except one of the surveys. Source: Jardine Fleming Capital Partners Limited, 2001, Welch, I, 2000, ‘Views of Financial Economists on the Equity Premium and on Professional Controversies’, Journal of Business, vol 73, no 4, pp. 501-537; Welch, I, 2001, The Equity Premium Consensus Forecasts Revisited, Cowles Foundation Discussion Paper No. 1325, Yale University; Graham, J., C. Harvey, 2001, Expectations of Equity Risk Premia, Volatility and Asymmetry from a Corporate Finance Perspective, working paper, Duke University. In contrast to the distributors’ submissions, the Energy Users Coalition of Victoria (EUCV) suggests that the equity (market risk) premium used by all regulators, including the Commission, is excessive. The EUCV proposes benchmarking of the distributors using financial indicators (EBIT/assets) observed in the marketplace as one solution for establishing a “correct value for the ERP” (EUCV 2005d, p. 52). October 06 363 Essential Services Commission, Victoria Final Decision The EUCV also provided their March 2005 submission to the South Australian regulator’s (ESCOSA) review of ETSA Utilities’ price controls. This submission advocates that the equity (market risk) premium “should rise and fall as the market conditions actually vary, rather than using a long term average, which currently disadvantages consumers, but will lead to disadvantaging regulated businesses in the future” (EUCV 2005d attachment, p. 100). The Commission notes that while its estimate of the equity (market risk) premium does reflect financial indicators observed in the market place, the contrast with the EUCV proposition is that the Commission has relied upon capital market data rather than accounting information. While accounting information may assist in interpreting capital market information, such an exercise would need to be undertaken carefully and acknowledge the difficulties with interpreting accounting information. No such study has been submitted to the review. The second proposition made by the EUCV (2005) was that a time varying equity (market risk) premium should be used. However, such an approach is not feasible or desirable. The Commission notes Gray and Officer’s (ENA 2005, p. 10-11) comments in this regard. We recognise that it is likely that the MRP is not stationary and likely to vary under different economic conditions. However, the fact that there is no adequate theory underlying the variability of MRPs makes it dangerous to adjust an MRP estimate simply because another year or two of data alter the estimated mean… We do not advocate increasing the MRP now for the same reason we did not advocate reducing the MRP estimate last year. The problems of the theory and measurement of MRPs suggest a conservative approach — a regulator should be very careful about making any changes without compelling evidence. Finally, the Commission has also taken account of other Australian regulators’ decisions, including its own past decisions, the most recent of which are set out in Table 9.10. Table 9.10 indicates that the Commission has adopted an equity premium of 6 per cent (for an assumed franking credit value of 0.50) in all of its past decisions, which is also the most common approach of other Australian regulators. While the Commission has noted previously that this value sits below the average of observed excess returns over the longest period, it has noted that it is within the range of plausible estimates, noting the imprecision of the estimate provided by the long term average and is appropriate when the totality of evidence is presented. The Commission remains of the view that the best estimate of the equity (market risk) premium will come from having regard to the results of each of the different methodologies (tempered by an understanding of the strengths and weaknesses of each methodology) rather than placing sole weight on any single methodology. Such a view has found support in submissions made to the Commission. October 06 364 Essential Services Commission, Victoria Final Decision Table 9.10: Equity premium estimates applied in Australian regulatory decisions Regulatory decision Equity premium (per cent) 2000 ESC Electricity Distribution Price Review 2000 IPART AGL Gas Distribution Final Decision 2000 OFFGAR Alinta Gas Distribution Final Decision 2001 ACCC Moomba to Adelaide Gas Transmission Final Decision 2001 ACCC Powerlink Electricity Transmission Final Decision 2001 QCA Envestra and Allgas Gas Distribution Final Decision 2002 ACCC ElectraNet Electricity Transmission Final Decision 2002 ACCC GasNet Gas Transmission Final Decision 2002 ACCC SPI PowerNet Electricity Transmission Final Decision 2002 ESC Gas Distribution Final Decision 2003 ACCC Moomba to Sydney Pipeline Gas Transmission Final Decision 2003 ACCC Murraylink Electricity Transmission Final Decision 2003 ACCC Transend Electricity Transmission Final Decision 2003 OTTER Aurora Electricity Distribution Final Decision 2004 ICRC ActewAGL Electricity Distribution Final Decision 2004 IPART Electricity Distribution Final Decision 2005 ESCOSA Electricity Price Review Final Decision 2005 QCA Electricity Distribution Final Decision 2005 IPART Revised Access Arrangement for AGL Gas Networks Final Decision 2005 ERA Final Decision on the Proposed Access Arrangement for the Goldfields Gas Pipeline 6.00 5.00 — 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 5.00 — 6.00 6.00 6.00 5.50 — 6.50 5.00 – 6.00 The Commission has adopted an estimate of 6 per cent as the market risk premium in all of its previous reviews. The additional information provided to this review has been mixed. Evidence has been presented that the historical average over more recent periods has been somewhat higher than previously considered, and additional survey evidence has suggested that some classes of practitioners adopt a value higher than 6 per cent (at least after the non cash value of franking credits is added back). However, evidence has also been provided that suggests that unexpected capital gains may have led to observed returns to shares in Australia overstating the historically expected returns, which is a phenomenon the Commission has considered previously in relation to the US market. The Commission has also continued to have regard to the information and views considered at previous reviews, as reported above. On balance, the Commission again adopted a market risk premium of 6 per cent for the current review. While it notes that while this value sits below the estimate provided by simple long term averages of excess returns, after having considered the totality of the evidence, the Commission is confident that this value will not understate the expected equity (market risk) premium, and is consistent it its assumption about the value of franking credits (discussed in the Franking Credit section below). October 06 365 Essential Services Commission, Victoria Final Decision Debt premium (Rd) and debt raising fees The standard practice among Australian regulators (including the Commission) is to adopt a benchmark for the cost of debt rather than the businesses’ actual costs. A regulated business’s actual debt costs cannot be applied in estimating the current cost of debt, as it may be determined by historical debt costs, and be influenced by actual gearing and credit rating levels, rather than the benchmark levels. The benchmark cost of debt should reflect the latest market evidence available on the borrowing costs of an efficiently financed electricity distribution business. The debt margins proposed by the distributors in their initial submissions are summarised in Table 9.11. The total proposed debt margin ranges from 151 basis points to 171 basis points above the 10 year Government Bond rate. All of the margins proposed by the distributors were based upon yield estimates from the CBA Spectrum service. Table 9.11: Distributor AGLE CitiPower Debt margins proposed by the distributors, basis points Debt margin Debt raising transaction costa Early debt re