Submission on the Senate Inquiry into the performance and management of electricity network companies

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1 Submission on the Senate Inquiry into the performance and management of electricity network companies 18 December 2014

2 Submission on the Senate Inquiry into The performance and management of electricity network companies Parliament of Australia 18 December 2014 This submission, which is available for publication, is made by: Ergon Energy Corporation Limited PO Box 264 FORTITUDE VALLEY QLD 4006 page 1

3 Introduction Ergon Energy Corporation Limited (Ergon Energy), in its capacity as a Distribution Network Service Provider (DNSP) in Queensland, welcomes the opportunity to provide comment to the Parliament of Australia on its Senate Inquiry into The performance and management of electricity network companies (Senate Inquiry). Ergon Energy notes that the current Senate Inquiry into the electricity industry follows on from a series of extensive policy and regulatory reviews over recent years. There have been over 17 separate enquiries conducted into aspects of the industry since 2010, including a Productivity Commission review, a Senate Select Committee inquiry into electricity pricing and two energy white papers. Ergon Energy is a member of the Energy Networks Association (ENA), the peak national body for Australia s energy networks. The ENA has prepared a comprehensive submission addressing the Senate Enquiry s Terms of Reference. Ergon Energy is fully supportive of the arguments contained in their submission. In response to the Parliament s invitation to provide comments on the Senate Inquiry, Ergon Energy has focused on the Terms of Reference, and has included comments against each of these in the Table of detailed comments below. Ergon Energy is available to discuss this submission or provide further detail regarding the issues raised, should the Parliament require. page 2

4 Table of detailed comments Question(s) Terms of Reference (a) The manner in which electricity network companies have presented information to the Australian Energy Regulator (AER), and whether they have misled the AER in relation to: (i) their weighted average costs of capital, (ii) the necessity for the infrastructure proposed, (iii) their regulated asset valuations, and (iv) actual interest rates claimed against actual borrowing costs. Ergon Energy Response The National Electricity Law (NEL) together with the National Electricity Rules (NER), form the regulatory framework through which the Australian Energy Regulator (AER) collects and receives information to prepare a network pricing determination. Section 28 of the NEL provides civil penalty provisions for noncompliance with a Regulatory Information Notice (RIN) or Regulatory Information Order (RIO) as well as for providing false and misleading information, including penalties of $2,000 for a person and $10,000 for a body corporate. Ergon Energy notes that it has populated and submitted all RINs that have been issued by the AER in the manner required. Further, the information provided has been subject to audit and Chief Executive Officer and Board sign-off as required by the AER. Ergon Energy also notes that is has incurred significant costs in collecting the information and undertaking the associated auditing required by the AER in this regard. Ergon Energy s information in its Regulatory Proposal is presented to the AER in accordance with Chapter 6 of the NER, as well as all applicable guidelines and models developed by the AER under the NER. Our Regulatory Proposal for 2015 to 2020 (including all supporting documents), which was submitted to the AER on 31 October 2014, clearly outlines this required information and our compliance with such. The AER accepted and published the Regulatory Proposal on the basis that it sufficiently complied with the relevant requirements. For its part, Ergon Energy is not aware of any concern or evidence that it has presented misleading information to the AER in relation to the matters set out in paragraph (a)(i)-(iv) of the Terms of Reference. Ergon Energy notes that the costs included in its Regulatory Proposal for the regulatory control period are forecasts and based on available information, derived from various internal and external sources. Forecasts can be incorrect or vary from actual results after the fact for a range of reasons, particular as economic, operational, technological or other circumstances and drivers can differ from the assumptions used to determine the original forecasts. page 3

5 For example actual peak demand in the regulatory control period was significantly different to the forecasts included in our Regulatory Proposal in 2009, and significantly different to the forecasts determined by the AER in their Final Distribution Determination. This was due to a combination of factors, including the impact of the Global Financial Crisis (GFC) on the Queensland economy where the rate of growth in electricity demand slowed significantly over the course of 2010 and Peak demand at this time was also impacted by cyclone events, milder summer temperatures, and changes to energy consumption. These impacts were not, nor could they be foreseen by the AER or Ergon Energy at the time the forecasts were prepared. The fact that actual demand has been lower than forecast is not evidence that the AER has been misled. Advice previously supplied by the AEMC to SCER indicates that historical actual demand data does not suggest that in practice NSPs continuously over-forecast demand (See Consideration of Differences in Actual Compared to Forecast Demand in Network Regulation, Advice to SCER, 26 April 2013). The AEMC s advice to SCER indicated that: More than anything, there is a pattern of variability in actual demand that is either less than, or greater than, forecast demand. There is no evidence of a bias in the network determination processes towards approving an inflated level of demand forecasts and hence higher than required capex allowance. (b) How electricity companies, including state government owned electricity companies such as Energex, have calculated the weighted average cost of capital (WACC) and how this measure has changed over time. In accordance with the NER, the AER must decide on the rate of return DNSPs are allowed to earn on the capital invested in the regulated distribution network. The NER now requires the allowed rate of return to achieve the following objective (the allowed rate of return objective ): 1 the rate of return for a Distribution Network Service Provider is to be commensurate with the efficient financing costs of a benchmark efficient entity with a similar degree of risk as that which applies to the Distribution Network Service Provider in respect of the provision of standard control services. Importantly, consistent with the principles of incentive regulation, the NER requires that the allowed rate of return is based on the efficient benchmark costs 1 NER, clause 6.5.2(c) page 4

6 of raising debt and equity from the capital markets to fund these investments. It is not based on Ergon Energy s actual financing costs. This approach of using a benchmark rate provides an incentive for NSPs, like Ergon Energy to achieve efficiency gains and ensures that we cannot be rewarded for inefficient funding practices and costs. 2 The calculation and application of the allowed rate of return (WACC) to our Standard Control Services (SCS) has undergone significant change in recent times as a consequence of new NER requirements and the introduction of the AER s Rate of Return Guideline (arising out of the AEMC s final rule determination on the National Electricity Amendment (Economic Regulation of Network Service Providers) Rule ). In particular, the AER s Rate of Return Guideline provides that the return on debt be updated annually during the regulatory control period in accordance with a trailing average approach. This differs from the previous regulatory approach which set the overall rate of return at the start of the regulatory control period, and held this rate constant over the whole period (usually five years). These intra-period adjustments allow the rate of return applied to our SCS to be more responsive to prevailing market conditions during the regulatory control period. Ergon Energy has set out detailed commentary on our proposed approach to determining the WACC for the next regulatory control period in Appendix C of our Regulatory Proposal 2015 to Importantly, as required by the NER, the WACC proposed by Ergon Energy is based on a benchmark efficient entity - that is, not on Ergon Energy proposing its own WACC. This estimate was based on extensive analysis by various independent experts of the methods used to estimate the return on equity within the context of the NER requirements. Based on the advice received from these experts and in order to best meet the rate of return objectives, Ergon Energy has departed from the AER s Rate of Return Guideline in favour of an estimate that gives appropriate regard to relevant estimation methods, financial models, market data and other evidence, as required by the NER and contemplated by the AEMC as an outcome of its 2012 Rule change process. 2 AEMC (2012), Final Rule Determination, National Electricity Amendment (Economic Regulation of Network Service Providers) Rule 2012, p https://www.ergon.com.au/ data/assets/pdf_file/0018/228402/appendix-c-rate-of-return.pdf page 5

7 Also, while Ergon Energy is required to propose a WACC in our Regulatory Proposal, it will be the AER that independently determines the actual WACC to be applied based on the NER. (c) Where anomalies are identified in relation to price structuring or allegations of price rorting by electricity companies, such as Energex, are raised, the possibility of these matters being investigated by a national independent body created by the Federal Government with the required powers and reach to investigate and prosecute, where necessary. Ergon Energy considers there is sufficient oversight through the distribution determination process and annual Pricing Proposal process to ensure there are no anomalies in relation to price structuring or to dispel claims of price rorting. This is because: In the next regulatory control period, the AER intends to place controls on the amount of revenue DNSPs can collect for SCS (a revenue cap ) consistent with the arrangements in the NER. This will determine the cap on revenue each year. Ergon Energy has proposed prices consistent with the revenue cap, taking into account adjustments allowed for matters such as inflation, incentive schemes, any under or over recoveries from previous years or any cost pass through amounts (i.e. Total Allowed Revenue). Ergon Energy is unable to retain amounts recovered greater than the Total Allowed Revenue from our customers. If we do,(for example, through an increase in actual consumption in a period against our forecast) the over-recovered amount is returned to customers in later pricing years through the Distribution Use of System (DUOS) unders and over account mechanism. The AER monitors our compliance with this through the annual Pricing Proposal process. The actual allocation of the Total Allowed Revenue to individual network tariffs should be up to the DSNP to determine, consistent with the arrangements in the NER. That is because Ergon Energy is the best placed to ensure cost reflective tariffs and tariff structures are developed for our customers. The structure of network tariffs are proposed in our annual Pricing Proposal and remain in place for the entire pricing year once the Pricing Proposal is approved by the AER. Ergon Energy has been transparent about our network tariff structural changes and has widely consulted with our stakeholders and continues to do so. 5 Importantly, under clause of the NER, the AER is only able to approve a pricing proposal where all forecasts associated with 5 Refer to https://www.ergon.com.au/network/network-management/network-pricing/network-tariff-strategy-consultation page 6

8 (d) To ascertain whether state-owned network companies have prioritised their focus on future privatisation proceeds above the interests of energy users. the proposal are reasonable. The AER will place caps on the prices of individual services for our Alternative Control Services (ACS). This generally involves the AER setting an initial price for each service in the first year of the next regulatory control period, and applying price caps using a specific formula for the remaining years. The price cap formula only allows prices to be annually adjusted for inflation, a real cost escalation and other adjustments. The resulting prices are subject to AER approval through the annual Pricing Proposal process. Ergon Energy is unable to charge above the prices approved by the AER. Finally, Ergon Energy does not consider that it is necessary to set up a national, independent body to perform the functions outlined in part (c) of the Terms of Reference, as the AER already has these functions/powers under Part 3 of the NEL. This includes monitoring compliance by regulated network service providers with network revenue or pricing determinations, 6 investigating breaches or possible breaches of provisions of the NEL, the regulations or the NER, 7 and instituting and conducting proceedings in certain circumstances (including in relation to offences against the NEL). 8 Ergon Energy s engagement program for the Regulatory Proposal over the past eighteen months has included direct customer engagement as well as a significant customer research program. Through our engagement programs, we have a clear understanding of the level of concern in the community about rising electricity prices. We also understand that our customers still want the peace of mind that comes from having a safe, dependable electricity service and they are increasingly seeking greater choice and control around their energy supply solutions. Our Regulatory Proposal has been designed to keep any increases to what we charge (in aggregate) for the use of the network the part of the bill we are responsible for as a distributor below inflation over the next five years. We are forecasting our distribution revenue to be $1,717 million in This is lower than our anticipated revenue of $1,753 million. In the period, Ergon Energy has done a lot already to achieve this 6 Section 15(1)(a)(ii) 7 Section 15(1)(b) 8 Section 15(1)(c) page 7

9 outcome. With consumption falling for the first time in , in parallel with peak demand flattening, we took prudent steps to reduce our capital investment program and focus on our efficiency and effectiveness as an organisation. This along with our growing demand management capability has supported a reduction of 20% (or $1.7Billion (Real $14/15) in our capital expenditure when compared to our regulator s approved allowances for As a result we were able to reduce our revenue requirement by $99 million and absorb the cost of Cyclone Yasi and Oswald. The reduced expenditure in means that our Regulated Asset Base will be lower than forecasted at the start of the next regulatory control period, should the changes proposed in the Queensland Government s Strong Choices plan applicable to Ergon Energy be implemented over the course of the period. The starting point for our network charges and revenue in will also therefore be lower than would otherwise have been the case had Ergon Energy kept spending to the level allowed for by the AER. Looking forward into , we expect to reduce our overall expenditure by a further 11% on top of the reductions we have already achieved in the current period. Ergon Energy notes that it has been taking action consistently for many years to reduce costs, improve efficiency, seek changes to network security criteria that have driven up capital costs and that it has prudently sought to defer major investment programs during the current regulatory control period in order to reduce the charges for the use of its network, and revenue that it can recover in the period. This outcome has been driven by: our responsiveness to changing market and economic conditions to prudently avoid or defer unnecessary and costly capital investment in the network; and successful deferment of considerable network investment due to our demand management initiatives; and ensuring that we do not compromise on meeting applicable safety, security, reliability and regulatory compliance requirements Ergon Energy s aim has been to ensure that our investment program remains prudent and does not further exacerbate affordability issues and to avoid incurring costs for work that was not required due to the lack of associated load or demand drivers. page 8

10 (e) Whether the arrangements for the regulation of the cost of capital are delivering allowed rates of return above the actual cost of capital. Ergon Energy has also passed onto customers a series of network revenue reductions as a result of the 2011 Electricity Network Capital Program (ENCAP) Review, and absorbed costs associated with Cyclones Yasi and Oswald. Ergon Energy s understanding of what our customers expect from us has also helped inform our investment plans for the next regulatory control period. As a result, we are aiming to reduce network charges in and keep subsequent increases to below inflation levels for the next five years. That is, our customers have been placed at the centre of our future investment plans and our Regulatory Proposal. Furthermore, it has always been relevant for Ergon Energy to seek an allowed rate of return to be set at a level that would be sufficient to attract private capital, regardless of our government ownership. As acknowledged by the Australian Energy Market Commission (AEMC) 9 and the AER, 10 this is also consistent with the principle of competitive neutrality, which underpinned the corporatisation of government-owned businesses, including Ergon Energy. Importantly, under the NER, DNSPs must submit forecasts which reflect the expenditure they consider necessary and the provision of false or misleading information is a beach of the NEL as noted above. Further, the AER has no ability to approve operating or capital costs, or a WACC that do not reasonably reflect the efficient costs of a prudent and efficient entity. Therefore there is no ability to seek a different level of revenue or prices based on a potential privatisation, nor ability for the AER to approve the forecasts. For further details on Ergon Energy s customer service commitments and investment plans that form part of the Regulatory Proposal, please see the documents linked to our web-site below: https://www.ergon.com.au/network/network-management/future-investment Extensive analysis and consultation on the rate of return was carried out in 2012 by the AEMC as part of its consideration of rule change requests from the AER and the Energy Users Rule Change Committee (EURCC) under the National Electricity Amendment (Economic Regulation of Network Service Providers) Rule As noted above, under current NER provisions, the allowed rate of return is based on the efficient benchmark costs of raising debt and equity from 9 Economic Regulation of NSPs Rule change, p AER (2013), Better Regulation, Explanatory Statement, Rate of Return Guidelines, December 2013, p211. page 9

11 (f) Whether the AER has actively pursued lowest-cost outcomes for energy consumers. the capital markets to fund these investments. It is not based on actual financing costs. Under an incentive based regulatory framework, actual rates of return achieved will vary due to the DNSP s performance against a set of benchmarks including operating and capital costs, costs of debt, service performance and tax assumptions. Further, these are all impacted by the differences between actual and forecast demand for network services. Any outperformance of these benchmarks could increase actual rates of return. This does not imply that the regulatory rate of return is incorrectly high. Conversely, underperformance against any of the benchmarks may result in lower returns and it would be incorrect to adjust the rate of return upwards as a consequence. Ergon Energy notes that under section 16 of Part 3, Division 1 of the NEL, the AER must perform or exercise its economic regulatory function or power in a manner that will or is likely to contribute to the National Electricity Objective (NEO). The NEO (section 7 of the NEL) aims to: promote efficient investment in, and efficient operation and use of, electricity services for the long term interests of consumers of electricity with respect to (a) price, quality, safety, reliability and security of supply of electricity; and (b) the reliability, safety and security of the national electricity system. Ergon Energy also notes that the AER must also take into account the Revenue and Pricing Principles set out in section 7A of the NEL, such as: (6) regard should be had to the economic costs and risks of the potential for under and over investment by a NSP in a distribution/transmission system with which the operator provides direct control services. (g) Whether network monopolies should have the right to recover historic overspending that has delivered unwanted and unused infrastructure. It should be noted that investment requirements across the NEM are driven in part by various state and federal jurisdictional requirements designed to ensure that customers are provided with guaranteed minimum service standards in relation to safety, security, quality and reliability of supply. Over time, there have been different levels of investment required by the network businesses to prudently and efficiently respond to the various network safety, security and reliability criteria operating in each state and territory, as well as other factors driving local network growth, such as economic conditions or the advent of page 10

12 (h) How the regulatory structure and system could be improved. disruptive new technologies, such as solar PVS and battery storage. In response to the above environment and differing jurisdictional requirements, energy market policy makers, rule makers and regulatory bodies have sought to provide certainty around the treatment of the Regulatory Asset Base (RAB). This feature of regulatory stability is a feature of regulatory frameworks across major developed economies. By lowering the risk of asset write-downs the mechanism of a predictably updated RAB provides the foundation for low cost financing of new and ongoing network investments. This allows for minimising network costs to consumers. Ergon Energy notes that the AEMC rejected a proposal by the Major Energy Users in relation to regulatory asset write downs on the basis it was inconsistent with the long term interests of consumers. As part of its considerations under the National Electricity Amendment (Economic Regulation of Network Service Providers) Rule 2012, the AEMC amended the NER to include a number of tools that the AER can apply to ensure that only capital expenditure that is efficient should enter the Regulatory Asset Base (RAB) (and be recovered from customers in future periods). These tools include: application of a Capital Expenditure Shared Scheme (CESS) to incentivise efficient capital expenditure; reviewing efficiency of past capital expenditure, including the ability to preclude expenditure from being rolled into the RAB; and deciding whether to depreciate the RAB using actual or forecast expenditure. Accordingly, Ergon Energy considers the NER provides adequate provisions to allow the AER to remove inefficiently incurred expenditure from the RAB, which would otherwise be recovered from customers in future periods, while also providing regulatory certainty. Ergon Energy notes that substantial changes were made to the regulatory framework as a result of the National Electricity Amendment (Economic Regulation of Network Service Providers) Rule At the time, the AEMC (and the AER through its Better Regulation program) extensively consulted with stakeholders on relevant issues, with a focus on promoting the long term interests of consumers. Given this framework has not been appropriately tested yet, Ergon Energy believes it is premature to consider any further fundamental changes, however, notes the challenges and opportunities identified by the ENA in its submission to this Senate Inquiry in relation to improving the overall regulatory framework for the energy supply system in Australia. page 11

13 Ergon Energy recognises that incremental changes to the NER are important to improve the flexibility and resilience of energy markets. The appropriate avenue for this is through the AEMC, as a rule change request. However, we note the challenges and opportunities identified by the ENA in its submission to this Senate Inquiry in relation to improving the overall regulatory framework for the energy supply system in Australia. For example, it is critical that network tariff reform be progressed to provide tariffs which are fairer, minimize existing cross subsidies and appropriately encourage customers for their contributions to lower network costs. Ergon Energy notes that arrangements across jurisdictions vary and supports the ENA s submission to seek the removal of existing jurisdictional regulatory barriers to cost-reflective network tariff design. Similarly, Ergon Energy supports the proposed review of the Demand Management and Embedded Generation Incentive Scheme, recommended in the Power of Choice report by the Australian Energy Market Commission. It is critical that network businesses be able to use demand management options to maintain network security and ensure that expansion of the network to offset this currently managed load is not needed Ergon Energy recognises that incremental changes to the NER are important to improve the flexibility and resilience of energy markets. The appropriate avenue for this is through the AEMC, as a rule change request. In addition to the above mentioned changes to the existing regulatory framework, Ergon Energy is reshaping its business model to create an open access platform that will enable us to actively coordinate and integrate distributed energy resources in a way that optimises our existing network assets and provides dynamic incentives (choice and control) to consumers. Ergon Energy plans to facilitate 2-way flows of energy linking buyers and sellers in a time and location manner that creates value for customers and Ergon Energy. Ergon Energy believes this will achieve the best outcome for us and our customers by providing new revenue opportunities and ultimately reducing network costs. (i) Whether the arrangements for the connection and pricing of network services is discriminating against households and businesses that are involved in their own electricity production. It should be noted that in many cases the output of the average unit installed is greater than the demand of the house. This results in energy flowing upstream on the distribution network, consuming capacity on the network. Ergon Energy does not consider the pricing of distribution services is discriminating against households and businesses that are involved in their own electricity production page 12

14 for the following reasons: Ergon Energy does not charge DUOS charges for the export of electricity generated by these users into the distribution network, consistent with clause of the NER; Customers with micro-generation facilities are charged the same network tariff for supply to their connection point as any other network customer with a similar load profile (in the absence of micro-generation), in accordance with clause (a)(3) of the NER; and Ergon Energy s prices for ACS are reflective and are developed on a user pays approach. Where a distinction is made between exporting and load only customers (e.g. our proposed application fees in the next regulatory control period), 11 this is due to the different costs involved in delivering the service. Similarly, there may be some services which only apply to exporting customers (e.g. protection and power quality assessments). Where these services are requested, the requestor should pay. Moreover, DNSPs should be able to determine their own pricing structures / arrangements to ensure the right price signals are being sent to customers. Therefore it can be seen that rather than discriminating against these customers, the regulatory framework discriminates in favour of them. Ergon Energy notes that Queensland has one of the highest penetration rates of PVs in the world. With over 100,000 systems in Ergon Energy s distribution area, this equates to approximately 2.1% of the energy traded in the grid, with owners self-consuming approximately 1.5% above total grid fed energy. It should be noted that while distributed energy resources can reduce required network expenditure in some cases (i.e. where it is integrated with coincident load), they do increase the need for network augmentation and represent a net cost to consumers. Further policies that seek to stimulate renewable energy increase costs to consumers under current pricing arrangements. Ergon Energy analysis shows that across the regulatory control period green schemes such as the Carbon Tax, Large Scale Renewable Energy Target (LRET), Small Scale Renewable Energy Scheme (SRES), Gas Electricity Certificates (GECs) and the Solar Feed in Tariff (FiT) will cost regional 11 Refer to Chapter 5 of Ergon Energy s Regulatory Proposal There are three basic or standard connection application fees, based on the work involved in assessing the application. For micro-embedded generators, the basic or standard application fee will apply plus one of the micro-embedded generator application fees (depending on whether a technical assessment is required). page 13

15 (j) Whether the current system provides adequate oversight of electricity network companies. (k) Any other related matter. Queensland customers around $1580 million. These costs are set out in Attachment A. This equates to an average liability per customer of $2,229 over the five years. Prior to the removal of the carbon tax this average liability was expected to be $2,654 per customer, noting actual impacts vary according to consumption. For the average residential customer these costs represent approximately 8.5% of their retail bill. Environmental allowances such as the LRET, SRES and GECs account for 37 per cent of the impact and the costs of the Solar FIT and associated network costs account for around 26 per cent. Specifically the estimated cost of the FiT and associated costs is $413m, with the costs of the SRES estimated to be $280m. This equates to an average cost of $ per customer over the five years, with the average cost being $ in alone. It should also be noted that as the FiT scheme exists until 2028, there exists a liability of $1.56 billion under this scheme. While the FiT costs are currently included in network costs and are increasingly responsible for increasing retail tariffs 12, Ergon Energy believes the costs of such schemes should not be treated as a network cost. Ergon Energy suggests consideration should be given to green scheme costs being presented separately on a customer s bill. Ergon Energy believes the current system does provide adequate oversight of electricity network companies - refer response to (c) above. Nil comment. 12 In its recent Draft Determination on Regulated Retail Prices the QCA noted that the costs of the Solar Bonus Scheme continue to have an impact on prices representing about 6% ($89) of the typical bill for a residential customer on tariff 11 in It should be noted that those costs relate to FiT costs incurred in given the 2 year lag that occurs in the recovery of the costs. page 14

16 Attachment A Green Scheme Costs Total FIT payments $6,619, $27,843, $75,232, $117,007, $110,531, $337,233, FIT Network Costs $7,000, $7,000, FIT Metering $1,020, $4,293, $11,600, $18,041, $17,043, $52,000, FIT Admin $2,704, $4,573, $4,564, $3,832, $1,432, $17,108, Carbon $276,352, $299,778, $0.00 $576,131, LRET $0.00 $40,800, $55,698, $57,423, $54,656, $208,578, SRES $0.00 $65,611, $86,672, $79,424, $48,291, $279,999, GEC $37,806, $8,959, $11,547, $3,459, $0.00 $61,772, RET $40,601, $0.00 $0.00 $0.00 $0.00 $40,601, TOTAL $88,752, $152,082, $521,668, $578,967, $238,954, $1,580,425, page 15

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