Application by SA Power Networks
[2016] ACompT 11
•28 October 2016
AUSTRALIAN COMPETITION TRIBUNAL
Application by SA Power Networks [2016] ACompT 11
Review from: Australian Energy Regulator File number: ACT 11 of 2015 Tribunal: MIDDLETON J (PRESIDENT)
PROFESSOR KT DAVIS (MEMBER)
MR R STEINWALL (MEMBER)Intervener: South Australian Minister for Mineral Resources and Energy Date of Determination: 28 October 2016 Catchwords: ENERGY AND RESOURCES – applications under s 71B of the National Electricity Law (NEL) for review of a distribution determination by the AER – consideration of the legislative background to the NEL and the National Electricity Rules (NER) – amendments to the NER made in 2012 by the Australian Energy Market Commission (AEMC) – amendments to the NEL made in 2013 – role of the AER – national electricity objective (NEO) – consultation and notification obligations under s 16(1)(b) – conduct of consultation process under s 71R(1) – relevance of Applications by Public Interest Advocacy Centre Ltd and Ausgrid (Ausgrid) – topics for review – gamma – return on debt – forecast bushfire safety capital expenditure (capex) – forecast labour cost escalation – forecast inflation
ENERGY AND RESOURCES – gamma – building block determination – significance of the substitution of “the value of imputation credits” for “the assumed utilisation of imputation credits” in the definition of gamma – valuation of imputation credits – theoretical models – empirical evidence – relevance of the Ausgrid decision – proper use of the distribution rate, equity ownership data and tax statistics
ENERGY AND RESOURCES – return on debt – transition arrangements for the debt risk premium component of the cost of debt – gradual transition compared with immediate transition – allowed rate of return objective – promotion of efficient financing practices – bias in regulatory decision-making – historical data problems – impact of change on benchmark efficient entity and recovery of efficient financing costs – meaning of “across regulatory control periods” – windfall gains and losses
ENERGY AND RESOURCES – forecast bushfire safety capex – capex objectives and criteria – meaning of “regulatory obligation or requirement” – the nature of regulatory obligations – Electricity Act 1996 (SA) – Fair Work Act 2009 (Cth) – decisions of AER not to be approached in overly rigid way – compliance with capex criteria
ENERGY AND RESOURCES – forecast labour cost escalation – whether enterprise agreement is a “regulatory obligation or requirement” – operating expenditure (opex) objectives and criteria – capex objectives and criteria – character of enterprise agreements – relevance of the Ausgrid decision
ENERGY AND RESOURCES – forecast inflation – post-tax revenue model (PTRM) – building block determination – whether AER can consider inflation outside the PTRM
Legislation: Australian Energy Market Act 2004 (Cth)
Electricity Act 1996 (SA)
Fair Work Act 2009 (Cth)
National Electricity Rules
National Electricity (South Australia) Act 1996 (SA)
Work Health and Safety Act 2012 (SA)
Cases cited: Application by ActewAGL Distribution [2015] ACompT 3
Application by ATCO Gas Australia Pty Ltd [2015] ACompT 7
Application by ATCO Gas Australia Pty Ltd [2016] ACompT 10
Application by Energex Ltd (No 4) [2011] ACompT 4
Application by EnergyAustralia and Others [2009] ACompT 8
Application by Jemena Gas Networks (NSW) Ltd (No 2) [2011] ACompT 5
Application by South Australian Council of Social Service Incorporated [2016] ACompT 8
Applications by Public Interest Advocacy Centre Ltd and Ausgrid [2016] ACompT 1
Applications by Public Interest Advocacy Centre Ltd, Ausgrid, Endeavour Energy and Essential Energy [2015] ACompT 2
Toyota Motor Corporation Australia Ltd v Marmara [2014] 222 FCR 152
Date of hearing: 1-2, 4-5 August 2016 Date of Community Consultation: 1 June 2016 Registry: South Australia Category: Catchwords Number of paragraphs: 621 Counsel for SA Power Networks: Mr CA Moore SC with Ms C Dermody and Dr RCA Higgins Solicitor for SA Power Networks: Gilbert + Tobin Counsel for the Australian Energy Regulator: Mr M O’Bryan QC with Mr J Arnott and Mr T Clarke Solicitor for the Australian Energy Regulator: Australian Government Solicitor IN THE AUSTRALIAN COMPETITION TRIBUNAL
ACT 11 of 2015 RE: APPLICATION UNDER SECTION 71B OF THE NATIONAL ELECTRICITY LAW FOR A REVIEW OF A DISTRIBUTION DETERMINATION MADE BY THE AUSTRALIAN ENERGY REGULATOR IN RELATION TO SA POWER NETWORKS PURSUANT TO CLAUSE 11.60.4 OF THE NATIONAL ELECTRICITY RULES
BY: SA POWER NETWORKS (ABN 13 332 330 749)
Applicant
TRIBUNAL:
MIDDLETON J (PRESIDENT)
PROFESSOR KT DAVIS (MEMBER)MR R STEINWALL (MEMBER)
DATE OF DETERMINATION:
28 OCTOBER 2016
THE TRIBUNAL DETERMINES THAT:
1.The Final Decision: SA Power Networks Distribution Determination 2015-16 to 2019-20, including attachments, is affirmed.
REASONS FOR DETERMINATION
THE TRIBUNAL:
INTRODUCTION
[1]
Regulatory regime
[4]
AER distribution determination process
[14]
Impact of the 2012 changes to the NER
[14]
SAPN’s regulatory review process
[18]
LEAVE TO APPLY FOR REVIEW
[23]
Requirements for the leave application
[29]
Criteria for the grant of leave
[34]
Financial threshold (s 71F(2) of the NEL)
[39]
Serious issue to be heard and determined (s 71E(a) of the NEL)
[42]
Prima facie case on materially preferable NEO decision (s 71E(b) of the NEL)
[46]
COMMUNITY CONSULTATION PROCESS
[50]
Impact on local industry, businesses and the local community
[62]
Competition in international and domestic markets
[66]
Long term interests of the consumer
[68]
Impact on SAPN
[70]
Taxation and gamma
[71]
Capex and opex
[78]
Forecast bushfire safety capex
[81]
Forecast labour cost escalation
[84]
Consumer engagement
[88]
Role of the Tribunal and the regulatory process
[90]
GROUNDS OF REVIEW
[104]
Cost of corporate income tax (gamma)
[106]
The role of gamma in the PTRM
[113]
Regulatory background
[118]
The regulatory determination process.
[121]
Grounds of review
[131]
Consistency of approach with the PTRM framework
[139]
Dividend drop-off evidence
[160]
The role of personal costs
[172]
Estimates using shareholder nationality, company type, and tax statistics
[179]
The distribution rate
[182]
Equity ownership data
[185]
The use of taxation statistics
[191]
Conclusion
[196]
Return on debt
[203]
Background
[212]
The regulatory decision process
[221]
Debt financing practices and regulation
[226]
Implications of past financing practices and the transition approach
[235]
Efficient investment and the regulatory approach to debt costs
[239]
Alleged errors in the Final Decision
[245]
Promotion of efficient financing practices
[246]
Bias in regulatory decision-making
[247]
Historical data problems
[251]
Impact of change on BEE and recovery of efficient financing costs
[258]
Forecast bushfire safety capex
[291]
Reclosers, RAGs and CLAHs
[294]
Application of the NER
[303]
The AER’s final decision on bushfire mitigation capex
[308]
Areas of dispute
[314]
Compliance with a regulatory obligation or requirement under cl 6.5.7(a)(2) of the NER
[327]
The nature of regulatory obligations
[350]
Change in the nature of the regulatory obligations and requirements over time
[376]
The VBRC, the PBST and the Jacobs report
[394]
Distinguishing the findings in Victoria
[411]
Additional matters supporting a regulatory obligation or requirement
[421]
The ability to turn off the power supply
[425]
Increase in fire danger days
[432]
Fire-start performance
[437]
Construction of the Electricity Act and the NER
[443]
Electricity Act
[444]
Clause 5.2.1(a) of the NER
[453]
Maintaining the safety of the distribution system under cl 6.5.7(a)(4) of the NER
[458]
Compliance with the capex criteria
[465]
Business as usual bushfire risk management
[467]
Cost-benefit analysis
[478]
Augmentation versus replacement
[486]
Conclusion
[491]
Forecast labour cost escalation
[492]
Application of the NER
[502]
Areas of dispute
[507]
Regulatory obligation or requirement
[512]
Maintaining the safety of the distribution system
[530]
Compliance with the capex criteria
[547]
Conclusion
[552]
Forecast inflation
[553]
The AER’s Final Decision
[558]
Areas of dispute
[569]
Arguments advanced by SAPN
[574]
Arguments advanced by the AER
[579]
Tribunal’s consideration
[583]
The PTRM
[585]
The NER and the PTRM
[597]
Conclusion
[619]
CONCLUSION
[620]
INTRODUCTION
This is an application by SA Power Networks (‘SAPN’), pursuant to s 71B(1) of the Schedule of the National Electricity (South Australia) Act 1996 (the ‘NESA Act’), for review of a reviewable regulatory decision of the Australian Energy Regulator (‘AER’), filed with the Australian Competition Tribunal (the ‘Tribunal’) on 19 November 2015.
The decision under review is the final decision and distribution determination published by the AER on 29 October 2015 pursuant to cl 11.60.4(c) of the NER, entitled ‘Final Decision: SA Power Networks Distribution Determination 2015-16 to 2019-20’ (‘Final Decision’).
On 4 May 2016, SAPN was granted leave to apply for review of the Final Decision, with respect to the designated grounds of review referred to in an amended application for review filed with the Tribunal on 3 May 2016 (‘Review Application’). The Tribunal’s reasons for granting leave are discussed below.
Regulatory regime
SAPN is the operator of an electricity distribution network located in South Australia (‘South Australian distribution network’). SAPN is registered as a distribution network service provider (‘DNSP’) under cl 2.5.1 of the National Electricity Rules (‘NER’), and provides distribution network services by means of the South Australian distribution network.
Section 6 of the NESA Act applies the National Electricity Law (‘NEL’), set out in the Schedule of the Act, as a law of South Australia. Section 9 of the NEL gives the NER the force of law in South Australia.
Section 7 of the NEL sets out the national electricity objective (‘NEO’), which is to promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers with respect to:
(1)price, quality, safety, reliability and security of supply of electricity; and
(2)the reliability, safety and security of the national electricity system.
Section 16(1)(a) of the NEL provides that in performing or exercising an AER economic regulatory function or power, which includes a function or power performed or exercised by the AER relating to the making of a distribution determination, the AER must perform or exercise that function or power in a manner that will, or is likely to, contribute to the achievement of the NEO.
Section 16(1)(d) of the NEL provides that if the AER is making a reviewable regulatory decision and there are two or more possible reviewable regulatory decisions that will, or are likely to, contribute to the achievement of the NEO, the AER must:
(1)make the decision that the AER is satisfied will, or is likely to, contribute to the achievement of the NEO to the greatest degree (the ‘preferable reviewable regulatory decision’); and
(2)specify reasons as to the basis on which the AER is satisfied that the decision is the preferable reviewable regulatory decision.
In addition, s 16(2)(a) of the NEL requires the AER to take into account the revenue and pricing principles (‘RPP’) when exercising a discretion in making those parts of a distribution determination relating to direct control network services.
Section 7A of the NEL sets out the RPP, as follows:
(2)A regulated network service provider should be provided with a reasonable opportunity to recover at least the efficient costs the operator incurs in–
(a) providing direct control network services; and
(b)complying with a regulatory obligation or requirement or making a regulatory payment.
(3)A regulated network service provider should be provided with effective incentives in order to promote economic efficiency with respect to direct control network services the operator provides. The economic efficiency that should be promoted includes–
(a)efficient investment in a distribution system or transmission system with which the operator provides direct control network services; and
(b) the efficient provision of electricity network services; and
(c)the efficient use of the distribution system or transmission system with which the operator provides direct control network services.
(4)Regard should be had to the regulatory asset base with respect to a distribution system or transmission system adopted–
(a) in any previous–
(i)as the case requires, distribution determination or transmission determination; or
(ii)determination or decision under the National Electricity Code or jurisdictional electricity legislation regulating the revenue earned, or prices charged, by a person providing services by means of that distribution system or transmission system; or
(b) in the Rules.
(5)A price or charge for the provision of a direct control network service should allow for a return commensurate with the regulatory and commercial risks involved in providing the direct control network service to which that price or charge relates.
(6)Regard should be had to the economic costs and risks of the potential for under and over investment by a regulated network service provider in, as the case requires, a distribution system or transmission system with which the operator provides direct control network services.
(7)Regard should be had to the economic costs and risks of the potential for under and over utilisation of a distribution system or transmission system with which a regulated network service provider provides direct control network services.
Clause 6.12.1 of the NER provides that a distribution determination is predicated on a number of constituent decisions to be made by the AER. These include:
(1)a decision on the DNSP’s building block proposal in which the AER either approves or refuses to approve the annual revenue requirement for the DNSP, as set out in the building block proposal, for each regulatory year of the regulatory control period;
(2)a decision in which the AER either:
(a)acting in accordance with cl 6.5.7(c), accepts the total of the forecast capital expenditure (‘capex’) for the regulatory control period that is included in the current building block proposal; or
(b)acting in accordance with cl 6.5.7(d), does not accept the total of the forecast capex for the regulatory control period that is included in the current building block proposal, in which case the AER must set out its reasons for that decision and an estimate of the total of the DNSP’s required capex for the regulatory control period that the AER is satisfied reasonably reflects the capex criteria, taking into account the capex factors;
(3)a decision on the allowed rate of return for each regulatory year of the regulatory control period in accordance with cl 6.5.2;
(4)a decision on the value of imputation credits as referred to in cl 6.5.3; and
(5)any other amounts, values or inputs on which the building block determination is based.
Clause 6.12.2 of the NER provides that the reasons given by the AER for a final distribution determination under r 6.11 must set out the basis and rationale of the determination, including:
(1)details of the qualitative and quantitative methods applied in any calculations and formulae made or used by the AER;
(2)the values adopted by the AER for each of the input variables in any calculations and formulae, including:
(a)whether those values have been taken or derived from the provider’s current building block proposal; and
(b)if not, the rationale for the adoption of those values;
(3)details of any assumptions made by the AER in undertaking any material qualitative and quantitative analyses; and
(4)reasons for the making of any decisions, the giving or withholding of any approvals, and the exercise of any discretion, as referred to in Ch 6 of the NER, for the purposes of the determination.
The exercise of the AER’s discretion in making distribution determinations is governed by cl 6.12.3 of the NER.
AER distribution determination process
Impact of the 2012 changes to the NER
Section 15 of the NEL prescribes the functions and powers of the AER, which include the making of distribution determinations under the NER.
Certain provisions of the NER relating to distribution determinations were amended by the Australian Energy Market Commission (‘AEMC’), and were published, and took effect from on 29 November 2012 (‘2012 rule changes’).
A number of revenue determination processes due to be completed in 2014 and 2015 were delayed through transitional provisions inserted into the NER as part of the 2012 rule changes (‘transitional provisions’). This delay afforded the AER the time to develop ‘Better Regulation’ guidelines in response to the 2012 rule changes (the ‘Better Regulation Guidelines’). The Better Regulation Guidelines were published in late 2013.
Key aspects of the transitional provisions applying to SAPN’s distribution determination process are as follows:
(1)the date for submission of SAPN’s regulatory proposal was delayed by nine months, from 31 January 2014 to 31 October 2014;
(2)the AER was not required to publish a draft distribution determination in relation to SAPN’s regulatory proposal, as it would have been required to do under cl 6.10.1 of the NER, in the absence of the transitional arrangements. Rather, following appropriate consultation on SAPN’s regulatory proposal, the AER was able to proceed immediately to making a distribution determination under cl 6.11.1 of the NER;
(3)at the same time as the AER published its distribution determination under cl 6.11.1 of the NER (which it was required to by 30 April 2015), it was required to also publish an invitation for written submissions on the revocation and substitution of that distribution determination;
(4)under cl 11.60.4(b) of the NER:
(a)any person was allowed to make a written submission to the AER in relation to the revocation and substitution of the distribution determination within the time period specified by the AER, which must not be earlier than 45 business days after the making of that distribution determination; and
(b)without otherwise limiting the manner in which SAPN’s may make such submissions, SAPN was allowed to make a submission in the form of revisions to the regulatory proposal that it submitted to the AER in relation to the distribution determination that was to be revoked.
(5)by no later than 31 October 2015, the AER was required to revoke its distribution determination for the 2015-2020 regulatory control period and make a new distribution determination in substitution for the revoked determination which takes effect as at the date it is made; and
(6)in making the new distribution determination, the AER was required to have regard to:
(a)the matters it would be required to have regard to if it were making a final distribution determination under “current Chapter 6” subsequent to it making a draft distribution determination that is the same as the revoked determination including (except where (c) below applies) the regulatory proposal that was submitted to the AER in relation to the revoked determination;
(b)written submissions received in relation to the revocation and substitution of the distribution determination;
(c)any revisions to the regulatory proposal that was submitted to the AER in relation to the revoked determination and that are given to the AER under cl 11.60.4(b); and
(d)any analysis undertaken by or for the AER that is published prior to the making of the distribution determination or as part of the distribution determination.
SAPN’s regulatory review process
Pursuant to cl 6.8.2 of the NER (as modified by cl 11.60.3 of the transitional provisions), SAPN was required to submit, and on 31 October 2014 did submit, a regulatory proposal to the AER for consideration in accordance with the NER (‘Regulatory Proposal’).
On 30 April 2015, pursuant to cl 6.11.1 of the NER, the AER published a decision and distribution determination entitled ‘Preliminary Decision: SA Power Networks Distribution Determination 2015-16 to 2019-20’ (‘Preliminary Decision’).
On 3 July 2015, pursuant to cl 11.60.4(b) of the NER, SAPN submitted a revised regulatory proposal to the AER for consideration in accordance with the NER (‘Revised Proposal’).
On 29 October 2015, the AER published its Final Decision, pursuant to cl 11.60.4(c) of the NER.
On 19 November 2015, SAPN filed an application for leave and review under s 71B of the NEL.
LEAVE TO APPLY FOR REVIEW
Section 71B of the NEL provides:
71B – Applications for review
(1) An affected or interested person or body, with the leave of the Tribunal, may apply to the Tribunal for a review of a reviewable regulatory decision.
(2) An application must—
(a) be made in the form and manner determined by the Tribunal; and
(b) specify the grounds for review being relied on.
The Tribunal accepts that, for the purposes of s 71B(1) of the NEL:
(1)SAPN is an “affected or interested person or body” (as that term is defined in s 71A of the NEL); and
(2)the Final Decision, the decision that is under review in the present application, is a reviewable regulatory decision, as it is a network revenue or pricing determination that sets a regulatory period.
In addition, it is accepted that there is no issue that SAPN’s application for review was made within the 15 business-day time limit prescribed by s 71D of the NEL.
The application for leave to apply for review was unopposed by the AER.
As previously mentioned, on 4 May 2016, SAPN was given leave to apply for review of the Final Decision on the grounds set out in its Review Application.
It is worth noting that the South Australian Council of Social Service (‘SACOSS’) also applied for leave to review the Final Decision, however the Tribunal dismissed SACOSS’ application for review on 2 May 2016: see Application by South Australian Council of Social Service Incorporated [2016] ACompT 8.
Requirements for the leave application
Section 71C of the NEL sets out the following two relevant requirements for applications made under s 71B of the NEL:
71C – Grounds for review
(1)An application under section 71B(1) may be made only on 1 or more of the following grounds:
(a)the AER made an error of fact in its findings of facts, and that error of fact was material to the making of the decision;
(b)the AER made more than 1 error of fact in its findings of facts, and that those errors of fact, in combination, were material to the making of the decision;
(c)the exercise of the AER’s discretion was incorrect, having regard to all the circumstances;
(d)the AER’s decision was unreasonable, having regard to all the circumstances.
(1a) An application under section 71B(1) must also specify the manner in which a determination made by the Tribunal varying the reviewable regulatory decision, or setting aside the reviewable regulatory decision and a fresh decision being made by the AER following remission of the matter to the AER by the Tribunal, on the basis of 1 or more grounds raised in the application, either separately or collectively, would, or would be likely to, result in a materially preferable NEO decision.
It is worth repeating that, pursuant to s 7 of the NEL, the NEO is to promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers with respect to:
(1)price, quality, safety, reliability and security of supply of electricity; and
(2)the reliability, safety and security of the national electricity system.
The Tribunal accepts that SAPN’s Review Application was made only on the grounds of review specified in s 71C of the NEL.
The Tribunal has reached that conclusion having regard to the observations made in recent Tribunal decisions relating to applications for limited merits review by DNSPs in NSW and ACT. For example, the Tribunal accepts that:
… the line between the several available grounds of review is not necessarily always clear cut. Sometimes, it will be a clear line, and sometimes it will not. Moreover, there is no prescription in s 71C that, in particular facts and circumstances, there can be only one ground of review made out …
There is also no clear line between factual error, opinion, and discretionary judgment; one may feed into the other.
… error or errors – if accepted – may be a combination of error or errors of fact, wrongful exercise of discretion, and/or the outcome of an unreasonable decision. Because the characterisation of error or errors, if made out, will more clearly emerge in the course of considering the review related material and the submissions dealing with it, the Tribunal does not consider it appropriate or necessary to embark upon the careful textual analysis and criticism of the [DNSP’s] application at this point to describe the combination or permutation of alternative expressions of reviewable error in that application.
See Applications by Public Interest Advocacy Centre Ltd, Ausgrid, Endeavour Energy and Essential Energy [2015] ACompT 2 at [55], [57]; Application by ActewAGL Distribution [2015] ACompT 3 at [21].
Further, the Tribunal has had regard to the matters outlined in SAPN’s submissions on its application for leave to review (‘Leave Submissions’) and paragraphs [22]-[26] and [200]-[210] of SAPN’s Review Application. In considering these matters, the Tribunal accepted, in granting leave to apply for review, that SAPN had sufficiently addressed the manner in which a determination by the Tribunal in accordance with s 71C(1a) of the NEL may result in a materially preferable designated NEO decision.
Criteria for the grant of leave
Pursuant to s 71E of the NEL, the Tribunal must not grant leave to apply for review unless it appears to the Tribunal that:
(a) that there is a serious issue to be heard and determined as to whether a ground for review set out in section 71C(1) exists; and
(b) that the applicant has established a prima facie case that a determination made by the Tribunal varying the reviewable regulatory decision, or setting aside the reviewable regulatory decision and a fresh decision being made by the AER following remission of the matter to the AER by the Tribunal, on the basis of 1 or more grounds raised in the application, either separately or collectively, would, or would be likely to, result in a materially preferable NEO decision.
However, even where the Tribunal determines that the criteria in s 71E are satisfied, leave to apply under s 71B must not be granted “unless the amount that is specified in or derived from the decision exceeds the lesser of $5,000,000 or 2% of the average annual regulated revenue of the regulated network service provider”: s 71F(2) of the NEL.
The Tribunal may also refuse to grant leave on the grounds set out in s 71H(2) of the NEL, namely that:
…
(a) without reasonable excuse—
(i)failed to comply with a request (including a request for relevant information), or a direction, of the AER made under this Law or the Rules for the purpose of making the decision; or
(ii)conducted itself in a manner that resulted in the making of the decision of the AER being delayed; or
(b)misled, or attempted to mislead, the AER on a matter relevant to the AER’s decision.
There is no suggestion, however, by the AER or SAPN that any of the conditions contained in that provision are present to enliven the Tribunal’s discretion to refuse the granting of leave.
Each of the relevant criteria for leave in s 71E and s 71F(2) of the NEL are considered below.
Financial threshold (s 71F(2) of the NEL)
The affidavit of Luke Woodward affirmed on 19 November 2015, and made in support of SAPN’s Review Application sets out the 2% of the average annual regulated revenue of SAPN over the 2015-2020 regulatory control period specified in or derived from the Final Decision as approximately $15.9 million. As such the relevant threshold pursuant to s 71F(2) is $5 million.
As previously held by the Tribunal in Application by Energex Ltd (No 4) [2011] ACompT 4 (‘Energex (No 4)’):
(1)the “amount that is specified in or derived from the decision” should not be read literally as meaning the total revenue to be derived by the service provider, rather, the amount at issue in light of the grounds upon which the AER’s decision is challenged: Energex (No 4) at [50]; and
(2)when determining whether the financial threshold in s 71F(2) of the NEL is satisfied, all of the errors are to be taken into account; the threshold does not need to be satisfied for each ground: Energex (No 4) at [52]; see also Application by Jemena Gas Networks (NSW) Ltd (No 2) [2011] ACompT 5 at [3]; Application by ATCO Gas Australia Pty Ltd [2015] ACompT 7 at [21] (‘ATCO 2015’).
SAPN’s Leave Submissions set out the relevant amounts specified in or derived from the decision in respect of each of the topics that are the subject of grounds for review in SAPN’s Review Application. On the basis of these amounts, the Tribunal considered that the financial threshold was comfortably satisfied.
Serious issue to be heard and determined (s 71E(a) of the NEL)
SAPN adopted the submissions of Ausgrid, Endeavour Energy, and Essential Energy in Applications by Public Interest Advocacy Centre Ltd, Ausgrid, Endeavour Energy and Essential Energy [2015] ACompT 2, in relation to the legal principles relevant to the meaning of “serious issue to be heard and determined”. These submissions were accepted in ATCO 2015 at [23], where the following principles were noted as being of particular relevance:
(a)The phrase ‘serious issue to be heard and determined’ has been correlated with the phrase ‘serious question to be tried’ in the context of the grant of interlocutory injunctions: Re Application by ElectraNet Pty Limited [2008] ACompT 1 at [39]-[42];
(b)The relevant question is indeed whether an applicant has established that there is a serious issue to be heard and determined given the nature of the rights asserted by the applicant and ‘the practical consequences likely to flow’ from the grant of leave. In particular, the Tribunal has previously expressed the view that the threshold merely requires the applicant to ‘show that there is a sufficient prospect of success to justify in the circumstances it being given the opportunity’ to have the decision reviewed: Application by Envestra Ltd [2011] ACompT 12 at [21].
SAPN made extensive submissions on whether there was a serious issue to be tried in respect of:
(1)gamma
(2)allowed rate of return – return on debt
(3)forecast inflation;
(4)forecast bushfire safety capex;
(5)forecast labour cost escalation;
(6)operating expenditure (‘opex’) for increased asset inspections in bushfire risk areas; and
(7)opex for “no access” poles inspections.
SAPN ultimately decided not to apply for review of the final two topics above relating to opex.
For each of these topics, SAPN set out the background to the issue, summarised the issue as arising in SAPN’s Regulatory Proposal and in the AER’s Final Decision, and identified the specific aspects of the relevant grounds of review to demonstrate that there was a serious issue to be heard and determined.
As will be apparent from the reasons in respect of each ground of review below, there were serious issues to be heard and determined on SAPN’s Review Application.
Prima facie case on materially preferable NEO decision (s 71E(b) of the NEL)
For each of the issues in dispute, SAPN made submissions on how rectification of an error in the AER’s distribution determination – if found to be an error – could result in a materially preferable NEO decision. SAPN then submitted in its Leave Submissions at [241]:
The immediate consequence of these errors is that the overall revenue allowance determined by the AER in its Final Decision is materially below that which would be required by an efficient entity to recover at least efficient costs and provide a commercial market return to investors across the 2015-20 regulatory control period. As noted in paragraphs 198 and 199 of the SA Power Networks Application, these are individually material in terms of the overall regulated revenue SA Power Networks is permitted to earn, and in aggregate are very significant – that is, approximately, a $285.6 million ($nominal) revenue reduction.
Further, SAPN also submitted that if the Final Decision is left uncorrected:
(1)SAPN’s incentives and signals to undertake investment in the network and operations would be distorted due to a significant revenue shortfall;
(2)the shortfall in the allowances for the operating and capex may lead to an inability to recover the efficient costs of meeting regulatory (or otherwise appropriate) safety obligations and requirements of the distribution system;
(3)perceptions of regulatory risk will significantly increase; and
(4)it will set a precedent (in the non-technical sense of that term) for under-compensation of SAPN (and potentially other businesses) now and in the future.
The Tribunal considered SAPN’s submissions in this respect. The Tribunal was satisfied that SAPN has made a prima facie case in accordance with s 71E(b) of the NEL.
On the basis of the above considerations, and as will be apparent further from the reasons in respect of each of the topics below, the Tribunal considered it was appropriate to grant leave to SAPN to apply for review.
COMMUNITY CONSULTATION PROCESS
The consultation process referred to in s 71R(1)(b) of the NEL is an additional procedural step which the Tribunal must take and, ideally, be accommodated within the target time prescribed by s 71Q of the NEL.
The Tribunal, having given leave to SAPN to apply for review in this matter on 4 May 2016, sought information from the AER as to groups or persons who might have an interest in the Tribunal’s review under s 71R(1)(b) of the NEL.
The Tribunal then conducted an extensive communication process with each of those groups or persons, to invite them to indicate:
(1)whether they wished to consult with the Tribunal in relation to the Final Decision;
(2)the nature of their proposed participation; and
(3)how the consultation might best be carried out.
Having determined a protocol for the consultation, the Tribunal issued a Consultation Agenda under which it provided for those who wished to speak to the Tribunal on that occasion either personally or on behalf of an organisation, to do so.
The Tribunal conducted the consultation on 1 June 2016 at the Federal Court of Australia in Adelaide. As there was time remaining at the end of the consultation, opportunity was also provided for those who had not registered to participate, to make submissions to the Tribunal.
The transcript of that consultation process has been included by the Tribunal on its website. The following is a list of the entities and their representatives who made submissions during the consultation process, or in writing as a complement or supplement to oral submissions, or by providing written submissions after the consultation:
(1)National Irrigators’ Council – Tom Chesson (Chief Executive Officer)
(2)Central Irrigation Trust – Gavin McMahon (Chief Executive Officer)
(3)UnitingCare Australia and Uniting Communities – Mark Henley (Manager Advocacy and Communications)
(4)Business SA – Andrew McKenna (Senior Policy Adviser)
(5)Riverland Energy Association – Brenton Paige (Association Member)
(6)SACOSS – Jo De Silva (Senior Policy Officer)
(7)The South Australian Financial Counsellors Association – Wendy Shirley (Executive Officer)
(8)Riverland Wine – Chris Byrne (Executive Officer)
(9)Major Energy Users, Inc, acting for Energy Users Coalition of SA – David Headberry (Public Officer)
(10)South Australian Chapter of The Electric Energy Society of Australia – Martyn Pearce (Chairman)
(11)Jubilee Almonds and Century Orchards – Brendan Sidhu (Chief Executive Officer)
(12)The Better Drinks Co Pty Ltd – Kym Baldock (General Manager)
(13)Renmark Irrigation Trust – Barry Schier (General Manager)
(14)Energy Consumers Australia – Rosemary Sinclair (Chief Executive Officer)
(15)Consumer Utilities Advocacy Centre
(16)Bundaberg Regional Irrigators Group
All submissions at the consultation were made on behalf of organisations. For ease of reference, the contributions will be identified according to the organisation, rather than the organisation’s representative.
SAPN, the AER and the South Australian Minister for Mineral Resources and Energy (the ‘Minister’) as intervener did not participate in the consultation process. That was appropriate, of course, because they each participated in the hearing before the Tribunal.
In the course of the consultation, a number of issues of concern to consumers and consumer interests were identified and the participants’ submissions fell into several broad themes. It is, in the view of the Tribunal, helpful to summarise the submissions made in relation to the major themes, as identified by the Tribunal. It is important to note that neither the entirety of the submissions, nor every topic raised will be captured, and the broad themes as identified by the Tribunal will only be in summary form.
It is useful to note the starting point from which the majority of the submissions were made. It was generally submitted that, when considered according to the elements of the NEO – price, quality, safety, reliability and security of supply of electricity – the only element with which consumers were dissatisfied was price. As the Bundaberg Regional Irrigators Council (‘BRIG’) submitted:
In terms of the elements of the NEO, BRIG believes that price is the most important and has the greatest impact on consumers and their long term interests. Price has been neglected in favour of investment in recent determinations.
Similarly, in survey of businesses conducted by Business SA, 87% of responses ranked reduction in electricity prices as most important, with less than 1% ranking it as either the lowest, or second lowest priority.
While each of the topics for review were referred to at the consultation, those that received most attention were gamma and taxation, forecast bushfire safety capex, and forecast labour cost escalation.
Impact on local industry, businesses and the local community
The majority of the participants drew connections between the cost of electricity and its impact on the relevant industry and the broader community. One of the key messages of participants was the importance of agriculture in South Australia, and therefore, the region’s dependency on irrigation and electrical energy to operate irrigation for agricultural purposes. Participants impressed upon the Tribunal the centrality of the agricultural industry to the region’s prosperity, and therefore the importance of its protection into the future. As was submitted by The Better Drinks Co Pty Ltd, the whole Riverland region relies on what is pumped out of the river and therefore it affects all industries in the area. Participants also submitted that with other local industries, such as manufacturing, shrinking, more pressure was placed on agricultural industries to keep the local economy healthy.
The participants identified specific ways in which the cost of electricity impacted not only on their own businesses but also more broadly on the local industry and, as a result, the local community. For example, Central Irrigation Trust submitted that to absorb the higher costs of electricity, the business were required to either run down assets or reduce opex or capex. National Irrigators’ Council submitted that, for many businesses, the only place that increasing electricity prices could be “worn” was in reducing the number of employees of the business. This had the ripple effect on households, already struggling with “some of the world’s highest energy prices”, which necessarily had to reduce their spending at local shops and restaurants, in turn harming the other local industries. Similarly, BRIG submitted that:
The intentional optimization and deliberate gaming of network profitability has resulted in a rate of price escalation that is unethical and is harming business and domestic consumers across the NEM with standards of living suffering appreciably and less money available for reinvestment in our farms.
While a number of participants outlined the measures they were taking to manage increasing electricity prices, improve efficiency and remain competitive, several participants noted that electricity prices were something beyond the consumers’ control. South Australian Financial Counsellors Association (‘SAFCA’) submitted that the steep increase in electricity prices during the previous regulatory period had not been matched by the community’s capacity to pay.
A number of participants described the “Swiss cheese” effect of increased electricity prices, being that higher electricity prices were forcing some consumers to seek alternative sources of energy “off the grid”. In the long run however, this would mean fewer consumers to pay for the network. It was in this context that participants submitted that from a policy perspective, increasing electricity prices which drove consumers away from the grid seemed an “absurd” strategy for SAPN itself.
Competition in international and domestic markets
Several participants addressed the Tribunal on how increasing electricity prices, and energy costs in general, had, and would continue to undermine the competitiveness of South Australian businesses if something was not done to address them. The high export rate of produce from irrigated agriculture in South Australia meant that the almond, wine and juice producers were competing with producers from Chile, Argentina, South Africa, North America and across Europe. Therefore, to continue to be a significant wealth generator for South Australia, agriculture producers would have to remain competitive both domestically and internationally.
For businesses such as The Better Drinks Co Pty Ltd, which operated in a highly competitive market both domestically and internationally, it was submitted that there was a very limited ability to pass on increased costs to its customers, and so the increase in costs had to be absorbed by business itself. Central Irrigation Trust submitted that Australia’s competitive advantage was being quickly squandered through rising energy costs. Business SA submitted that the pending structural change on South Australia’s economy with the exit of the automotive manufacturing industry in 2017 provided further impetus for energy costs to not contribute to an already uncompetitive cost base, compared with interstate and international competitors.
Long term interests of the consumer
The notion of the “long term interests of consumers” (‘LTIC’), as the factor underpinning the NEO, was a focal point of many of the submissions. In considering the factors relevant to the LTIC, UnitingCare Australia and Uniting Communities (‘UnitingCare’) sought to juxtapose the “supply-side” perspective of the LTIC contended for in SAPN’s Review Application with the “demand-side” perspective of network users. Therefore, it was submitted that the elements of the LTIC, as specified in the NEO, should be interpreted in the following way:
·Price – end consumer pays no more than is necessary;
·Reliability – all consumers are able to afford to pay for the essential use of electricity needed to participate in contemporary society, and that people will not be cut off from electricity supply for essential purposes because it is too expensive;
·Quality – prices as well as supply are stable with no supply-side or bill shocks;
·Safety – a person’s house is not at risk of burning down because they cannot use electricity for safe lighting, cooking or heating or other unsafe practises considered in the absence of supply.
Energy Consumers Australia (‘ECA’) also directed some of their submissions to considering the appropriate interpretation of LTIC. ECA submitted that the question for interpretation is whether “efficiency” is the goal, and LTIC is just a signpost to balancing items, or whether LTIC is the goal, and efficiency is the means to achieve it. In developing its interpretation, ECA submitted that the objective of the regulatory regime is to deliver the outcomes that are equivalent to those that would be delivered if there were competition achieved in the electricity market. ECA identified such outcomes as the consumer interests, price, quality, safety, reliable and secure supply services – in essence, the elements of the NEO, through which the LTIC must be achieved.
Impact on SAPN
Some of the participants submitted that SAPN’s Regulatory Proposal would ultimately work against SAPN’s interests as it would force a significant proportion of consumers off the grid through increased prices. This would thereby reduce SAPN’s customer base and impact on its ability to run its business. A number of participants noted that they were investigating alternative energy sources to run their businesses such as through diesel generation and solar energy.
Taxation and gamma
An issue raised by a number of the participants at the consultation was the amount of tax paid by SAPN. Many consumers called for an explanation for why consumers were paying for an income tax equivalent of “over $400 million” when, as the participants submitted, it did not appear to reflect the amount of tax SAPN was actually paying. As UnitingCare submitted, the Consumer Challenge Panel (established by the AER to assist with the AER’s regulatory determinations) noted that SAPN has historically paid minimal tax to the Australian government despite increases in the regulatory revenue allowance from 2011. UnitingCare emphasised that it was not suggesting anything improper on the part of SAPN. However, it raised the issue to ensure consumers were not paying more as a result of a “more-than-generous” credit arrangement in favour of SAPN.
In seeking clarity and transparency around the amount of tax paid by SAPN, the participants also called for an indication of taxation allowances for privately owned distributors to determine whether this properly represented their actual tax costs. In support of this submission, National Irrigators’ Council referred to the Minister’s criticism of SAPN for making “super profits” from its customers.
Consumer Utilities Advocacy Centre (‘CUAC’) considered the relationship between gamma and the LTIC in two respects. First, submitting that the value for gamma proposed by SAPN “relies on a single methodology that produces statistically unstable results because it is highly sensitive to underlying assumptions”, CUAC urged the Tribunal to consider
whether it is in the best interests of consumers for the regulator to rely on this single measure and methodology, rather than considering a wider range of evidence drawn from different methodologies to produce a more robust value for gamma, as has been done by the AER in their guideline paper.
Secondly, CUAC noted the recent changes in the NEL, as stated in the second reading speech of the Statues Amendment (National Electricity and Gas Laws – Limited Merits Review) Bill 2013, which sought to ensure
consumers do not pay more than necessary for the quality, safety, reliability and security of supply of electricity and natural gas under the national energy laws.
However, CUAC queried how this would be reflected and implemented if SAPN’s own estimate of their proposed gamma value would cost consumers $85.2 million over the 2015-2020 period.
Central Irrigation Trust submitted that the effect of the AER’s determination in the Final Decision in respect of gamma was viewed to be a transfer of money from their own business to SAPN. Renmark Irrigation highlighted that even small changes in the value of gamma would mean “big returns” for SAPN. It was considered to be in the best interests of consumers for the AER’s gamma methodology to be ratified by the Tribunal.
Major Energy Users (‘MEU’) considered gamma in the context of the incentive nature of the regime. MEU submitted that not only have companies been willing to invest in SAPN with a gamma of 0.5 or 0.4 over many years, but it was also submitted that the current owner of SAPN was prepared to invest in the distributor with a gamma of 0.4. It followed, on MEU’s submission, that there was no reason to change it as a disincentive could not be identified.
Capex and opex
In raising issues about the specific topics for review, a number of participants voiced concerns about capex and opex generally.
Business SA submitted that a broad concern was that substantial increases in the AER’s determination both in relation to capex and opex will lock in significant additional electricity costs over the next five years and beyond, as they would be incorporated into the regulatory asset base and opex used in future calculations. It was further submitted by Business SA that it considered it to be “inconceivable” for capex and opex to be increasing as it submitted that the demand on the electricity network was static, if not in decline. More fundamentally, SACOSS expressed concern that SAPN was attempting to expand the meaning of its regulatory obligations to justify additional expenditure in relation to capex and opex.
Drawing a connection with the concern around consumers abandoning the network in favour of alternative energy sources, Riverland Energy Association posed the question of who would be paying for existing and new assets proposed by SAPN if future customers would be seeking alternative energy sources and deserting the traditional network supply base.
Forecast bushfire safety capex
One of the main issues raised by participants at the consultation in relation to the bushfire mitigation capex was the absence of legislative changes by the South Australian government to warrant or require SAPN’s increase in spending on bushfire mitigation over the relevant regulatory period. SACOSS submitted that the AER was correct to conclude that the regulatory obligations imposed by Electricity Act 1996 (SA) (‘Electricity Act’) and Work Health and Safety Act 2012 (SA) (‘WHS Act’) in relation to the bushfire mitigation measures had not been expanded by the outcome of the Victorian Bushfire Royal Commission and Powerline Bushfire Safety Taskforce, as had been suggested by SAPN. Further, SACOSS submitted that, in any event, SAPN had failed to demonstrate how the additional expenditure proposed in their Regulatory Proposal was prudent and efficient. Similarly, MEU emphasised that the amount allowed for bushfire mitigation capex should not simply be the cost of service but what is efficient.
Business SA submitted that as SAPN’s proposal on bushfire mitigation capex had been made independent of comprehensive policy consideration, it did not represent optimal public policy outcomes. Participants warned against allowing SAPN to become an “arbiter” on what constitutes good industry practice in relation to bushfire mitigation, and disregarding the AER’s views on the basis that is “merely” an economic regulator. MEU submitted that such an approach would risk shifting from an incentive-based regime, which was specifically required by the legislation, to a regime driven by cost of service.
A contrasting perspective was provided by the South Australian Chapter of the Electricity Energy Society of Australia (‘EESA’). EESA acknowledged that SAPN had been achieving good results in bushfire mitigation controls. However, EESA submitted that SAPN, with whom lay a large portion of the responsibility for protecting the community during bushfires, had to demonstrate continuous improvement to its practices to address “reasonably foreseeable” events causing bushfires. Otherwise, as EESA submitted, such organisations would become vulnerable to litigation, particularly in light of the findings and changes brought about in this sphere following the Victorian Bushfires Royal Commission. It was submitted that the cost of litigation in circumstances where negligence and the “reasonable foreseeability” test were made out, would be in excess of $12 million. In light of this, and the public expectation that EESA considered existed for such measures to be implemented, EESA contended for the program of bushfire mitigation proposed by SAPN to be approved.
Forecast labour cost escalation
Forecast labour cost escalation received significant attention during the consultation. Participants submitted that SAPN’s proposal to increase the terms of the enterprise bargaining agreement (‘EA’ or ‘EBA’) governing SAPN’s employees was at odds commercially with other EAs across Australia, particularly in light of what were considered to be already favourable EA terms. A number of participants queried why increases in allowances for labour costs would be required where there had been no indication of increases in productivity. As CUAC submitted:
It is questionable whether any increases in real labour price growth are appropriate – and in the long term interests of consumers – without a corresponding increase in productivity growth. As stated by in the [Victorian Energy Consumer and User Alliance] submission, “productivity and labour price increases are inextricably linked”. This is particularly pertinent given that the AER has accepted the networks in both states have proposed zero productivity growth (with the exception of Jemena in Victoria), despite the significant capital expenditure over the previous period. CUAC notes that SAPN proposed that the AER adopt negative productivity growth forecasts in its alternative estimate of opex.
Business SA submitted that while the shareholders in SAPN were free to remunerate their labour force as they saw fit, electricity consumers would not be willing to absorb any costs considered above the efficient rate in relation to market conditions in South Australia.
SACOSS noted its support for the AER’s decision to use the wage price index to escalate cost rather than basing the escalation on SAPN’s EA. MEU identified the risk with allowing SAPN to determine the escalation, rather than using an external benchmark: there would be no competitive pressure on SAPN to negotiate an EA on terms most favourable to consumers. This is particularly the case given that, as MEU submitted, without an external competitor, the unions, with whom SAPN would be negotiating, could argue that the business could just pass on its costs to clients.
SACOSS further submitted that, if an error in the AER’s decision were identified, the Tribunal should still consider whether, in any event, it would be a materially preferable NEO decision to reverse the AER’s decision when the reviewable regulatory decision was considered as a whole.
Consumer engagement
The 2012 rules changes required DNSPs to improve their engagement with electricity consumers to ensure that capex and opex forecasts include expenditure to address consumers’ concerns. The consumer engagement process (‘CEP’) conducted by SAPN received some criticism from participants. Riverland Energy Association contended that the “cornerstone” of SAPN’s Review Application was based on the AER failing to giving significant weighting to the views of the consumer expressed in SAPN’s CEP. However, Riverland Energy Association identified the methods adopted by SAPN for determining the consumers’ priorities to be self-fulfilling “in the extreme”. SACOSS claimed, both at the consultation and in written submissions filed with the Tribunal subsequently, that as the CEP undertaken by SAPN was conducted in respect of areas not the subject of review before the Tribunal, it should be not be relied upon by SAPN to demonstrate the LTIC, nor be given any weight in the Tribunal’s considerations in this review. SACOSS submitted that its only relevance was to highlighting the consumer concern about potential cost increases, and directed the Tribunal’s attention to SAPN’s research findings relating to the consumers’ willingness to pay, namely that:
there is significant community concern about potential cost increases. Half of the customers surveyed are very concerned about the prospect of rising electricity costs.
MEU also identified problems with consumer engagement in the regulated energy distribution sphere more generally. For example, it was claimed that there was insufficient time to engage with consumers, consumers had inadequate knowledge to be able to make an informed contribution or recommendation, and the majority of time spent engaging with consumers was explaining the role of a network distributor, and distinguishing it from a network retailer. MEU considered this to be detracting from a discussion of the substantive issues.
Role of the Tribunal and the regulatory process
Participants also addressed the Tribunal on their perceptions of the regulatory process and what they considered to be the role of the Tribunal in the process.
A number of participants articulated that they saw the Tribunal as a “final backstop for consumers.” One participant “challenged” the Tribunal to bring electricity prices in South Australia back to the bottom quartile of prices amongst countries forming the Organisation for Economic Co-operation and Development (‘OECD’). SAFCA submitted that for the Tribunal to achieve the materially preferable NEO decision, it is required to take into account real-life experiences of large numbers of low and modest income households.
Some comments were made about the regulatory process more generally. Some participants submitted that they felt let down by the regulatory process given the sharp rise in SAPN tariffs over the last regulatory period. UnitingCare submitted that consumer behaviour over recent years put paid to the notion that regulation of network monopolies successfully functioned as a proxy for competitive and efficient markets. UnitingCare cited a number of statistics to support this argument, including that:
·31,666 South Australian households had an electricity debt, with the average debt being $758;
·3,174 South Australian small businesses had an electricity debt, with the average debt being $1,559; and
·South Australia has highest rate of energy customers on hardship programs.
BRIG also expressed their dissatisfaction with the regulatory process:
The network price setting process is deeply flawed. In BRIG’s experience, it has been a one sided process that has no regard for impact on consumers or the wider economy. If the AER’s increased powers are greatly reduced by the decisions of this Tribunal, we fear this will continue to be the case.
In relation to the regulatory review process, participants submitted that they considered it to be adversarial, intimidating and complex. Others noted that as it took significant time to understand the technical and complex concepts such as theta, gamma, and regulatory asset bases, the process itself became costly and time consuming for businesses to participate in it effectively.
The incentive-focus of the regulatory regime was also raised as an issue. MEU contended that the AEMC “cleverly” characterised the LTIC as being achieved by ensuring there is incentive for investors to invest in the networks, and disincentive when investment is not required. MEU considered that this emphasis on investment and investors took the focus away from the interests of the consumers who were required to pay for the network services and the impact that electricity prices had on their daily lives.
ECA devoted a significant portion of their submissions to the new limited merits review process, addressing what they considered to be intended from the introduction of the process. For example, ECA submitted that while SAPN does have a responsibility to meet its regulatory and other obligations, the question before the Tribunal is whether SAPN’s Regulatory Proposal represents the most efficient way of meeting such responsibilities and obligations. In this respect, ECA referred to the aim of the energy market reforms, identified by the (former) Standing Council on Energy and Resources (now COAG Energy Council), to “restore the focus of the electricity market on serving the long term interests of consumers”.
ECA also contrasted this case before the Tribunal with that of a NSW and ACT proceeding with respect to the absence of a consumer advocacy group as a party to the proceeding, noting that in Applications by Public Interest Advocacy Centre Ltd and Ausgrid [2016] ACompT 1 (‘Ausgrid’), the Tribunal held at [64]:
Given the role of PIAC, and the relevance of its submissions to the Tribunal’s functions and responsibilities under the legislation, the Tribunal has not needed in these matters to address separately the matters which emerged in the course of the consultation process. The role and submissions of PIAC have encompassed those matters.
As such, ECA submitted that it was particularly important for the Tribunal to carefully consider and place weight on the submissions of SACOSS put forward in the consultation.
Relevantly, in its written submissions, SACOSS urged the Tribunal to continue to
consider its consultation obligations once the parties have had an opportunity to respond to matters raised at the public forum, and demonstrates in its reasons for decision on the review how the submissions made through the consultation process have been considered by the Tribunal.
Before going to this issue, the Tribunal makes mention of the submissions of the Minister. It was the Minister’s contention that the Tribunal should affirm the Final Decision. In the course of these reasons, the Tribunal traverses the issues raised by the Minister, although without specific attribution to the Minister as intervenor. These issues were effectively argued by both SAPN and the AER, and need no repetition. Nevertheless, one submission of the Minister does require specific mention relevant to the consultation process.
The Minister submitted that the efforts of the consumers who took the time to participate in the community consultation should be recognised and their submissions to the Tribunal must be considered as part of the review. The Tribunal accepts this submission, and acknowledges that the participants in the consultation took time out of their own businesses and life to be part of the review, representing various consumer interests.
In light of the ultimate decision of the Tribunal, it is unnecessary to otherwise comment on the Minister's helpful submissions.
It should also be observed, as the following reasons indicate, the decision of the Tribunal has been reached on the basis of the contentions made by SAPN and the AER, and not by direct reference to submissions made during the consultation process. This is not because such submissions are not relevant to the review, but because in this review the decision to affirm the Final Decision has been readily arrived at by focussing on the submission of the parties and in determining whether any error had occurred on the part of the AER. Nevertheless, the consultation process and the submissions of consumers (and the Minister) may have become particularly significant (if error had been found in the Final Decision) in the consideration of the materially preferable NEO decision. This has been unnecessary in this review as no error has been found to occur.
GROUNDS OF REVIEW
SAPN has identified multiple grounds of review in respect of each of the topics for review. In Application by ATCO Gas Australia Pty Ltd [2016] ACompT 10 (‘ATCO 2016’), the Tribunal outlined the nature and scope of each of the relevant grounds of review: error or errors of fact, incorrect exercise of discretion, and that the decision under review is unreasonable: see ATCO 2016 at [36]-[48]. The Tribunal considers these principles to be applicable in respect of the present application by SAPN.
The Tribunal now turns to consider in detail each ground of review by reference to the submissions of the parties. There was a substantial degree of repetition and overlap in the submissions dealing with each ground of review, and the Tribunal has attempted to address the significant and determinative issues to arrive at its decision.
Cost of corporate income tax (gamma)
Gamma is one of the required parameter inputs into the post -tax revenue model (‘PTRM’) used under the NER for the determination of allowable revenues for a DNSP. It represents the “value” of imputation (tax) credits arising from company tax payments which are distributed with dividends to shareholders. These can be expected to reduce the required return on equity of shareholders (relative to receiving returns without such tax credits attached).
However, in the PTRM, rather than applying an estimated value of gamma to adjust the required rate of return on equity, the estimate is instead applied to reducing the revenue required to compensate the company for corporate tax paid. Consequently the return on equity incorporated into the allowed rate of return is calculated ignoring the imputation credit component of returns to shareholders. This approach draws on a demonstration by Professor Bob Officer (The Cost of Capital of a Company under an Imputation Tax System, Accounting and Finance, May 1994) of the equivalence of several such alternative approaches to valuation of company cash flow streams.
Because gamma is unobservable, and also because of conflicting interpretations of the word “value” in its definition, there has been ongoing debate over the appropriate numerical value to use in the PTRM. In its Final Decision, the AER applied a value for gamma of 0.4, whereas the applicant SAPN argued for a value of 0.25. This difference has a significant negative impact on the allowable revenue for SAPN over the regulatory control period which it estimates to amount to $85.2 million. The AER argues that the effect would be less than this because of the need to adjust other parameters accordingly in the PTRM, as discussed later. SAPN argues that the AER made errors in determining to use a value of 0.4 for gamma, and contends that it should have accepted the proposed value of 0.25.
This same issue arose in the 2015 determinations by the AER for the NSW DNSPs, which was also appealed to the Tribunal by the affected parties (arguing for a gamma value of 0.25 rather than the AER’s use of 0.4). That (differently constituted) Tribunal ruled on 26 February 2016 in the Ausgrid decision in favour of the applicants, and remitted the matter back to the AER to recalculate allowable revenues using a gamma value of 0.25. The AER has, in turn, appealed that decision to the Full Court of the Federal Court. No determination has yet been made by the Full Court.
This Tribunal determined that despite the existence of that appeal, it was appropriate for it to hear this review rather than leave the matter to be determined conditional on the outcome of the hearing of the Full Court of the Federal Court. The Tribunal has a legislative responsibility to hear and determine the review (within a statutorily delineated period of time), and should proceed accordingly.
It was also contended by SAPN that this Tribunal should follow the Ausgrid decision, or alternatively, treat it as highly persuasive. Undoubtedly, each differently constituted Tribunal should consider the importance of consistency between Tribunal decisions, but this is not the sole determinative factor nor is consistency an unqualified value. Consistency may lead to arbitrariness of decision-making, and may not produce the correct legal and just result in the particular case before the Tribunal. Each Tribunal, considering the application before it, and dealing with the relevant parties, must in accordance with the law, the issues before it, and the evidence, consider and determine the matters raised before the Tribunal.
It is to be recalled the Tribunal is an administrative decision-maker, not a court of law. The Tribunal cannot conclusively decide questions of law. The general statements of principle the Tribunal articulates will not and cannot have the same force as the development of principles of general law determined by the courts. The function of the Tribunal is a reviewer of decisions, and is not a primary decision-maker. The Tribunal has a responsibility to determine individual cases based upon the evidence and arguments put before it. This Tribunal proceeds accordingly.
The role of gamma in the PTRM
The NER (r 6.3) specify that the DNSP’s revenue requirement is to be calculated using the “building block” approach. Rule 6.4 provides detail on the building block components. Two components are relevant in this matter. One is the allowed rate of return on capital which is to be calculated in accordance with cl 6.5.2. The NER (cl 6.5.2(d)(2)) specifies that the allowed rate of return “must be … determined on a nominal vanilla basis that is consistent with the estimate of the value of imputation credits referred to in clause 6.5.3.” The second component (cl 6.4.3(b)(4)) is that “the estimated cost of corporate income tax is determined in accordance with clause 6.5.3”.
Clause 6.5.3 of the NER states that:
The estimated cost of corporate income tax of a Distribution Network Service Provider for each regulatory year (ETCt) must be estimated in accordance with the following formula:
ETCt = (ETIt × rt) (1 – γ)
where:
ETIt is an estimate of the taxable income for that regulatory year that would be earned by a benchmark efficient entity as a result of the provision of standard control services if such an entity, rather than the Distribution Network Service Provider, operated the business of the Distribution Network Service Provider, such estimate being determined in accordance with the post-tax revenue model;
rt is the expected statutory income tax rate for that regulatory year as determined by the AER; and
γ is the value of imputation credits.
Thus, the value of imputation credits provided to shareholders is deducted from that part of the allowed cash flows required to meet tax obligations. Under the “vanilla” WACC approach, those tax obligations are calculated after allowing for the effect of the tax deductibility of interest on debt. Consistency of approach means that the allowed rate of return on the regulatory asset base (another component of allowed cash flows) is calculated as a “vanilla” WACC. This is a weighted average of a cost of debt (pre company tax – ie ignoring the tax deductibility of interest at the company level) and the cost of equity (ignoring returns to shareholders in the form of imputation credits). This “vanilla” WACC is also used to convert cash flows over, and the regulatory asset base at the end of, the regulatory control period to a present value to achieve a zero NPV condition for a smoothed set of revenues or prices over the regulatory control period.
This “vanilla” WACC approach, for use under an imputation tax system, has its genesis in the aforementioned paper by Professor Officer, in which he demonstrated the equivalence of a zero NPV condition for a set of future cash flows under alternative approaches. One was the “vanilla WACC” approach in which net cash flows to be valued have company tax payments (allowing for tax deductibility of interest) deducted. This involved company tax being defined as net of the value of imputation credits distributed to shareholders. For consistency, required rates of return (the discount rates) ignore personal tax consequences, including the effects of imputation. Among the alternative approaches was a dividend imputation version of the standard textbook approach. In that, cash flows are calculated, after company tax, “as if” the company were unlevered, such that there is no tax deduction for debt interest allowed. Rather, the required return on debt is the after-company-tax cost of debt. Moreover, the company tax figure ignores imputation credit implications, and the required return on equity is lowered by some amount related to the value of imputation credits.
Two important considerations flow from this. One is whether the nature of the Officer approach has explicit implications for the interpretation of the term “value of imputation credits” used in the PTRM and the NER. The second is how a “value” of imputation credits should be estimated given the interpretation which is (or should be) adopted. These are the two issues at the heart of the dispute between SAPN (and other DNSPs) and the AER.
Regulatory background
The dispute over gamma needs to be placed in the context of changes made to the NER in November 2012 which changed the terminology used to describe gamma. Prior to that change, gamma was defined as “the assumed utilisation of franking credits”. Subsequently it has been defined (NER cl 6.5.3) as “the value of imputation credits”. No specific definition of what that term means, or how it is to be estimated, is given, other than that it needs to be consistent with the “vanilla WACC” approach.
Those rule changes also gave increased flexibility to the regulator in determination of the value to be chosen for gamma. “The current prescription of the gamma value of 0.5 in clause 6A.6.4 has also been removed to allow the regulator the ability to estimate an appropriate value that reflects the best available evidence at the time of a decision and would therefore result in a rate of return that meets the overall objective.” (AEMC, Rule Determination: National Electricity Amendment (Economic Regulation of Network Service Providers) Rule 2012, p 68).
Other than this statement, there appears to be no other explanation given for the change in terminology from “assumed utilisation” to “value”, although the latter term (even though not specifically defined) is more consistent with the flexibility given to the regulator and requirement (NER cl 6.5.2(e)) that:
In determining the allowed rate of return, regard must be had to:
(1)relevant estimation methods, financial models, market data and other evidence;
(2)the desirability of using an approach that leads to the consistent application of any estimates of financial parameters that are relevant to the estimates of, and that are common to, the return on equity and the return on debt; and
(3) any interrelationships between estimates of financial parameters that are relevant to the estimates of the return on equity and the return on debt.
The regulatory determination process.
In its initial proposal, SAPN proposed a value for gamma of 0.25, calculated as the product of a distribution rate of 0.7 and a “theta” value (“the value of distributed imputation credits to investors who receive them”: SAPN, Regulatory Proposal, p 320) of 0.35. It noted that the latter figure (0.35) was different to that contained in the AER Rate of Return Guideline (‘ROR Guideline’) (where 0.7 is proposed) and also argued that the interpretation adopted by the AER of the “value of imputation credits” in those guidelines was incorrect.
It argued that the AER had inappropriately discarded a correct (in SAPN’s view) prior approach which interpreted theta as the “value” of imputation credits, and which led to emphasis being given in its estimation to “market value studies” (such as dividend drop-off studies). Instead it had adopted an approach based on a “utilisation” rate. SAPN argued that rather than seeking to estimate the value of distributed imputation credits, the AER instead seeks to estimate what it refers to as “the before-personal-tax reduction in company tax per one dollar of imputation credits that the representative investor receives”. Elsewhere in the Explanatory Statement, the AER refers to its conceptual definition of theta as “the expected ability of equity holders to use the imputation credits they receive to reduce their personal tax”. (The references are to AER, Explanatory Statement: Rate of Return Guideline, December 2013, pp 165 and 174 respectively). By incorrectly (in SAPN’s view) adopting this approach, the AER placed more weight on information from equity ownership and tax statistics than market value studies.
It is worth referring back to the Explanatory Statement of the ROR Guideline (pp 166-7) from which those statements have been extracted, since fuller reading of the document makes clear both the AER’s approach and conceptualisation of theta, and also its perspective on earlier interpretations of gamma and theta by the Tribunal and others:
We consider the relationship between the representative investor in the market and the implied representative investor from estimation methods such as tax studies and dividend drop off studies). We consider this relationship is critical in assessing what we are estimating and which estimation methods are fit for purpose.
To answer the question of the appropriate representative investor, we considered afresh:
* the Sharpe-Lintner CAPM framework under imputation as derived in Officer, Monkhouse, Lally and Van Zijl, and Lally
* analysis of this conceptual framework by academic experts
* the construction of the corporate tax building block in the rules and how this interacts with the Officer framework used within the rate of return.
Our analysis of these issues is set out in section 9.3.1, and further in appendix H. Having undertaken this analysis, we conclude that we did not fully adopt or address important aspects of this analysis during the 2009 WACC review. As a result, the Tribunal review focused only on the particular suitability of tax value studies and dividend drop off studies. This was with an incomplete conceptual framework. The Tribunal acknowledged this incomplete framework at several points in its reasons.
We conclude that the representative investor:
* Is the weighted average of investors within the defined market, where the weightings reflect market participation (equity ownership value) and risk aversion.
* In this context, the defined market is investors in Australian equity, either domestic or foreign.
* Is the representative investor at any hypothetical point during a trading year – that is, it does not disproportionately reflect an investor or set of investors at a particular point in time. This is because investors may invest at any point during the year. If a benchmark parameter is set using data from a short period in systematically different trading circumstances to the rest of the year, it produces an estimate that is only relevant to those circumstances.
Having reached this view, we consider it has important implications for the practical task of estimating the value of imputation credits. The most important implication of this relationship is that the source of evidence the Tribunal adopted for the utilisation rate (a dividend drop off study) does not produce an estimate for the representative investor. This is because dividend drop-off studies give the value weighted investor’s valuation of imputation credits:
* Based on the combined package of imputation credits, dividends, and other entitlements (unless adjusted for). That is, a value for imputation credits is not available via simple observation of the dividend drop off in these studies. The implied values for the franking credit and the cash component must be econometrically separated, which is difficult to do reliably. We discuss this further in appendix H.
* For trades around the time of dividend distribution – that is, these studies only reflect trading around the cum-dividend and ex-dividend dates.
In its preliminary decision, the AER rejected SAPN’s proposal and determined that the value attributed to gamma should be 0.4, which was a departure from its ROR Guideline figure of 0.5. It explained that change as reflecting the available current information, and being based primarily on data from equity ownership and taxation statistics. These indicate (respectively) potential and actual utilisation of imputation credits. The AER argued that little weight should be given to market value studies due to a range of factors potentially affecting the robustness and interpretation of their results. The AER also departed from its ROR Guideline in dropping from the list of alternative approaches the “conceptual guidelines” approach. The preliminary decision incorporated an extensive evaluation of alternative approaches to estimation of gamma and arguments provided by a range of experts and related evidence.
In the opening part of this passage it said:
Thus, although the EBAs may lack either the NEL’s s 2D jurisdictional foundation or the genus of a safety or reliability standard etc of a r 6.5.6(a)(3) “regulatory requirement or obligation”, the Networks NSW DNSPs are bound by their EBAs as a matter of law.
The Tribunal is there suggesting that an EA does not attract the regulatory obligation of s 2D or indeed the safety and reliability standard of cl 6.5.6(a)(3). This of course also lends further support to our view that SAPN’s EA is not a regulatory obligation. It is then said “Networks NSW DNSPs are bound by their EBAs as a matter of law”. Having already rejected the application of s 2D and cl 6.5.6(a)(3), the Tribunal must be referring to the fact that a DNSP is bound by an EA only in the sense that a failure to comply would constitute a breach and attract penalties under the FW Act. That interpretation is supported by the remainder of the passage where the Tribunal discusses the limited rights to terminate an EA – reinforcing the point that an EA is binding on a DNSP as a matter of law.
It is after this discussion that paragraph [436] of the Tribunal’s reasons emerge on which SAPN relies. When the Tribunal refers in that paragraph to “the policy of the legislative arm of government that, to the extent that the EBA’s are (if they are) an inefficient imposition on the DNSPs, nevertheless they are a cost to be borne by the consumers of electricity”, it is referring to the fact that an EA is binding in the sense in which they had previously used it. That is, the Tribunal is suggesting it could not have been the policy intent of the legislature to permit the AER (relevantly when applying the EI model) to ignore the binding nature of an EA and to treat it wholly as an endogenous factor which could be ignored by the AER. It is not suggesting that the cost impacts of an EA should, as matter of policy expressed by the legislature, be disregarded entirely or conversely, automatically adopted.
Accordingly the Tribunal rejects SAPN’s reliance on this aspect of the Ausgrid decision.
Even if our assessment of Ausgrid is incorrect, SAPN’s argument that the EA is necessary to maintain the safety of the distribution system and falls within the opex and capex objectives of the NER should be rejected.
First, the provision still requires that SAPN demonstrate that the EA is necessary to “maintain the safety of the distribution system through the supply of standard control services”. As explained in the earlier consideration of cl 6.5.6(a)(2) and s 2D, there must be a direct connection between the EA and the delivery of standard control services. That connection is the labour employed to deliver those services, not the mechanism chosen to provide that labour.
Secondly, the capex and opex objectives apply to the total estimates for capex and opex. The labour cost escalator is one such factor. It cannot be assumed that any error with respect to the labour cost escalator would completely undermine the capex and opex objectives applying to the safe delivery of standard control services.
Compliance with the capex criteria
As SAPN’s contention that the EA is a regulatory obligation or is otherwise necessary to maintain the safety of the distribution system under the opex and capex objectives is rejected, it is unnecessary to consider whether the EA satisfies the capex criteria. Were it necessary to do so, the Tribunal would find that the capex criteria is not satisfied. The Tribunal sets out briefly its reasons for this view.
SAPN argues that its EA was negotiated at arm’s length in good faith and represents current market conditions for electricity workers in South Australia. Its labour escalations cover almost 95% of its employees, and others (such as contractors) are effectively bound to the EA through a contractor parity clause requiring the payment of EA rates of pay. SAPN also submits that the use of the benchmark EAs is a preferable methodology than the EGWWS WPI suggested by the AER and provides a more reasonable and transparent forecast for the labour price rate of change.
It should be noted that the labour cost escalator is applied to a broader category of costs than simply internal labour. To forecast price growth, the AER uses a weighted average of forecast labour price growth and forecast non-labour price growth. The implications therefore extend beyond SAPN’s EA issues alone.
The EA must satisfy the prudency and efficiency tests under the opex and capex criteria. The mere negotiation of an EA, albeit in good faith and at arm’s length, is not itself an adequate foundation for discharging the opex and capex criteria. As earlier explained, the nature of an EA leaves itself open to considerable management discretion on terms, even if they may arise from employee demands. It would be important, for example, to demonstrate productivity and other improvements, consistent with wage conditions in the industry.
Finally SAPN has not mounted a compelling challenge in face of the considerable sectoral wage growth data and wage growth trends relied on by the AER.
Conclusion
For the reasons given, the Tribunal concludes that the AER did not make an error of fact or facts that was material to the making of the decision, that the exercise of the AER’s discretion was not incorrect or the decision unreasonable, having regard to all the circumstances.
Forecast inflation
Under cl 6.4.3(a) of the NER, the annual revenue requirement for a DNSP for each regulatory year of a regulatory control period must be determined using a building block approach.
The indexation of the regulatory asset base building block is in effect, a deduction from the annual revenue requirement equal to the amount that is referred to in cl S6.2.3(c)(4) – that is, the amount necessary to maintain the real value of the regulatory asset base as at the beginning of the subsequent year by adjusting that value for inflation.
The deduction from the annual revenue requirement is needed to avoid “double counting” of inflation. Under the NER, a nominal rate of return is used in combination with an inflation-adjusted regulatory asset base. Thus, without any adjustment, service providers would be compensated twice for the effects of inflation – once through the rate of return and again through indexation of the regulatory asset base. The way this is addressed in the NER is to provide for a negative adjustment as described.
If there is a mismatch between forecast and actual inflation, there will be an inconsistency between the amount by which the regulatory asset base is increased over time to account for inflation and the corresponding deductions from the revenue allowance.
The AER is required to specify appropriate methods for the indexation of the regulatory asset base and any other amounts, values or inputs on which its building block determination is based. It is therefore necessary for the AER to determine an appropriate forecast of inflation as part of each distribution determination.
The AER’s Final Decision
In its Regulatory Proposal, SAPN adopted an inflation forecast of 2.55%. This was based on the method applied by the AER in its distribution determination for the prior regulatory control period, which is to take a geometric mean 10-year forecast based on:
·for the first two years of the regulatory control period, the mid-point of the RBA forecast range for CPI inflation; and
·for subsequent years, the mid-point of the RBA target range for CPI inflation.
SAPN submitted a Revised Proposal in light of what it says were concerns that the method it adopted in its Regulatory Proposal was no longer producing accurate forecasts.
In its Revised Proposal, SAPN adopted a different forecasting method which produced an inflation forecast of 2.06% for the 2015-2020 period. The revised forecasting method was based on a report by consultant Competition Economists Group (‘CEG’) “Measuring expected inflation for the PTRM” June 2015 and is referred to as the “breakeven” inflation forecasting method. Under the CEG “breakeven” method, an estimate of expected inflation is derived from the difference in yields on nominal and inflation-indexed Commonwealth Government Security (‘CGS’) of the same maturity.
SAPN’s concern and that of CEG was that due to changes in market conditions, it was no longer reasonable to expect inflation to revert to the middle of the RBA target range over the medium term. The evidence presented by CEG indicated that over the medium term, inflation is likely to be below the mid-point of the RBA target range. Therefore in current market conditions a methodology that assumes medium-term inflation would be at or around the mid-point of the RBA target range is likely to overestimate forecast inflation.
SAPN’s alternative methodology presented in its Revised Proposal was said to overcome this limitation by relying on market-based measures of inflation expectations. The “breakeven” inflation forecasting method does not involve any assumption as to medium-term inflation. Rather, the “breakeven” method is a measure of market expectations of inflation, as indicated by the difference in market yields on nominal and inflation indexed CGS of the same maturity.
In the Final Decision, the AER adopted an inflation forecast of 2.5% for the 2015-2020 regulatory control period. This was based on the methodology that had been adopted by the AER in its prior determination, namely:
·for the first two years of the regulatory control period, taking the mid-point of the RBA forecast range for CPI inflation. At the time of the AER’s Final Decision, the RBA had published a forecast range of 2-3% for these two years, with a mid-point of 2.5%; and
·for subsequent years, taking the mid-point of the RBA target range for CPI inflation, also 2.5%.
The AER provided the following reasons for rejecting SAPN’s alternative methodology (Final Decision, Attachment 3, pp 253-4):
We do not accept SA Power Networks’ new method for the following reasons:
•Changing the method after we accepted the original proposal in the preliminary determination is inconsistent with the intent of the regulatory process. Stakeholder submissions on our preliminary determination were made on the basis that the inflation estimation method is not under consideration in the final decision.
•The rules mandate a nominal vanilla WACC. Consequently, the inflation estimate is not a direct input parameter for deriving the rate of return that contributes to the achievement of the allowed rate of return objective. This is consistent with a broader reading of the NER, and in particular the express requirement for inflation and taxation to be addressed through the PTRM.
•An amendment to the PTRM is a distinct and separate process to the assessment of an NSP’s proposal. It must follow the specific timeframes set out by the distribution consultation procedures. Moreover, good regulatory practice requires a comprehensive consultation process as a prerequisite before changing the method for estimating a parameter that impacts all NSPs and users across multiple building blocks thereby affecting total revenue estimates.
The AER then explored features of the model used by SAPN and considered that the research, analysis and reasoning submitted to the AER should be subject to review through a comprehensive process allowing effective engagement with all stakeholders. The AER then pointed to the importance of the PTRM process in determining forecast inflation (Final Decision, Attachment 3, p 255):
Under both the NER and NGR, an inflation forecast is required for modelling revenue over the next regulatory control period. The NER mandates the use of the AER’s Post tax revenue model (PTRM). The NGR does not mandate the use of the PTRM, but requires service providers to provide financial information on a nominal basis or real basis or some other recognised basis for dealing with the effects of inflation. Under the NER, the AER’s published PTRM must include a method the AER determines is likely to result in the best estimate of inflation. Under the NGR, a service provider must propose an estimate on a reasonable basis which is the best forecast or estimate possible in the circumstances. United Energy stated that the appropriate approach to address concerns with our current method was to undertake an amendment to the PTRM.
Any changes/amendments to the PTRM must be done in accordance with the distribution consultation procedures.
The AER indicated that under cl 6.5.2(d)(2) of the NER, subject to achieving the rate of return objective, it is required to determine a rate of return on a nominal vanilla weighted average cost of capital basis. The AER said that under the nominal vanilla approach an inflation forecast is therefore not a direct input in determining the allowed rate of return.
The AER also expressed its satisfaction with its current approach as reflecting the views of stakeholders (Final Decision, Attachment 3, p 256):
In our recent rate of return guideline development consultation process we raised the inflation method as an issue for potential review. We noted that the indexed bond market had changed since we departed from the Fisher equation, and asked for submissions on whether we should change the approach. We also noted different methods and what other regulators were adopting. In response, stakeholders endorsed the continuation of the current approach. We therefore are satisfied that the current approach is the appropriate approach for this determination.
For these reasons the AER did not consider the method for forecasting inflation as part of its distribution determination for SAPN. The AER did not rule out a change to the method of inflation forecasting. However in its view this needed to be undertaken in accordance with the consultation processes mandated by the NER. The next rate of return guideline review was considered a more suitable process for reviewing the inflation forecasting method.
Areas of dispute
SAPN contends that the AER incorrectly exercised its discretion in failing to consider the merits of SAPN’s methodology and in rejecting the proposed methodology on the basis that it was different to that originally proposed by SAPN.
SAPN also contends that the AER made a number of errors of fact including forming an opinion as to the existence of future inflation. The AER rejects this as not an issue of fact but rather a statement of opinion.
SAPN also points to other errors made by the AER.
It is unnecessary to go into more detail about the errors contended by SAPN. This is because counsel for both parties acknowledged that the dispute now had a fairly narrow scope. It is whether the PTRM is binding such that the AER cannot consider inflation outside an amendment to the PTRM or whether, as SAPN contends, although there is a reference to inflation in the PTRM, the AER in fact has to give separate consideration to that issue under the NER in making its Final Decision.
The dispute will therefore be resolved on the correct interpretation of the NER. For this reason it is also unnecessary to consider the suitability of SAPN’s alternative methodology or indeed the inflation forecasts derived under that methodology.
Arguments advanced by SAPN
SAPN accepts that the inflation estimate is not a direct input parameter for deriving the nominal rate of return under cl 6.5.2. However, SAPN argues that just because it is not an input into the nominal rate of return does not mean that the inflation forecasting methodology cannot fall for consideration by the AER as part of making a distribution determination.
SAPN argues that the NER does not require that the inflation forecast used to calculate the indexation of the regulatory asset base building block be determined in accordance with the inflation forecasting method specified in the PTRM.
On the contrary, SAPN says that as part of each distribution determination the AER is required to specify appropriate methods for the indexation of the regulatory asset base and any other amounts, values or inputs on which its building block determination is based. It is therefore necessary, as part of each distribution determination, for the AER to determine an appropriate forecast of inflation.
For consistency with their context and purpose, SAPN submits that the relevant provisions of Ch 6 are to be read as requiring the AER to determine an appropriate forecast of inflation as part of each distribution determination. In contrast, the AER’s approach is said to be rigid and will produce an inflation forecast that is too high resulting in a total revenue allowance (all other things being equal) that is less than what is required to promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers.
SAPN also points out that under the AER’s approach, the inflation forecasting method is one input that can be effectively locked in by the AER, without any opportunity for stakeholders to have that method reviewed. The AER recognises that the methods used to determine other inputs (eg gamma, rate of return inputs and expenditure forecasting methods) must be considered as part of each determination. It is therefore unclear why the method for forecasting inflation should be treated any differently.
Arguments advanced by the AER
Contrary to SAPN’s position, the AER submits that the NER requires the inflation forecast used to calculate the indexation of the regulatory asset base building block to be determined in accordance with the inflation forecasting method specified in the PTRM. This is said to flow from cl 6.3.1 and cl 6.4.2 of the NER.
Clause 6.3.1(c)(1) stipulates that a building block proposal must be prepared in accordance with the PTRM and cl 6.4.2(b)(1) stipulates that the PTRM must include a method that the AER determines is likely to result in the best estimates of expected inflation. The PTRM published by the AER includes a method for forecasting inflation and the AER applied that method in its building block determination under cl 6.12.1.
As noted, SAPN relies on various clauses in the NER to argue that the inflation method specified in the PTRM is not mandatory. The AER submits that those other clauses cannot be read in a manner that contradicts the plain meaning of cl 6.3.1(c)(1) and cl 6.4.2(b)(1). For example, SAPN relies on cl 6.12.1(2)(i) which provides that one of the constituent decisions of the overall distribution determination is a decision on the DNSP’s current building block proposal in which the AER either approves or refuses to approve the annual revenue requirement for the DNSP as set out in the building block proposal. However the AER says that the contents of the building block proposal are governed by Pt C of Ch 6, and cl 6.3.1(c) stipulates that the building block proposal must be prepared in accordance with the PTRM.
The AER also points out that the PTRM provides certainty, consistency and continuity to DNSPs in the regulation of required revenue. Although the PTRM is not fixed, nevertheless the NER establishes a consultation process for amendment which involves all DNSPs as all DNSPs are impacted by the PTRM. The AER’s position is not that it could never consider a change to the PTRM at the same time as a distribution determination. However it maintains it is required to comply with the distribution consultation procedures, which evidence an intention on the part of the rule makers that broad consultation occur across the industry before any change is made.
Tribunal’s consideration
The AER concedes there is no express provision in the NER that prohibits it from considering inflation forecasts outside the PTRM process. Rather its position follows from the overall construction of the NER. Equally SAPN did not point to a provision of the NER that expressly requires the AER to consider its inflation forecast, other than as part of the usual considerations that should inform the AER’s decision-making, like other factors it considers in making its Final Decision.
Therefore the position of both parties ultimately turns on the overall construction of the NER.
The PTRM
It is useful at the outset to gain some understanding of the PTRM.
The PTRM is defined in the NER Glossary as the model prepared and published by the AER in accordance with cl 6.4.1.
The AER must, in accordance with the distribution consultation procedures, prepare and publish a PTRM: cl 6.4.1(a). The AER must ensure that a PTRM is in force at all times: cl 6.4.1(c).
The PTRM must set out the manner in which the DNSP’s annual revenue requirement for each regulatory year of a regulatory control period is to be calculated: cl 6.4.2(a).
The contents of the PTRM must include (but are not limited to the following (NER cl 6.4.2(b)):
(1) a method that the AER determines is likely to result in the best estimates of expected inflation; and
(2) the timing assumptions and associated discount rates that are to apply in relation to the calculation of the building blocks referred to in clause 6.4.3; and
(3) the manner in which working capital is to be treated; and
(4) the manner in which the estimated cost of corporate income tax is to be calculated.
The AER may amend the PTRM from time to time, in accordance with the distribution consultation procedures: cl 6.4.1(b). The distribution consultation procedures are those procedures set out in Pt G of Ch 6. Broadly, the distribution consultation procedures specify the consultation steps the AER must employ, including the use of explanatory materials and the requirement to seek comments from interested parties before making a relevant decision.
In practical terms, the PTRM is an excel spreadsheet. The Tribunal was taken to a brief demonstration of its application. From the illustration (and as counsel explained) the PTRM is a excel file that contains various cells corresponding to various parameters required in arriving at a final decision on building blocks. A DNSP is required to input numbers into various cells. As we understand, other aspects of the PTRM have been preset within the model, for example the inflation forecast. When the model is run those preset features apply to the remainder of the inputs made by a DNSP.
In that way the AER can assess the responses consistently across all DNSPs, with the knowledge that the features of the model will automatically have been incorporated, including the preset parameters.
It should be noted that although the Tribunal was provided with a brief illustration of an extract of the PTRM, the full PTRM, the process by which it is determined and practically applied was not the subject of any significant evidence. Given the way in which the arguments were presented, presumably a greater understanding of the PTRM is not required as ultimately the issue turns on the proper place of the PTRM in the scheme of regulation under the NER.
The PTRM is expressly employed in some parts of the NER. For example, the formula specified in cl 6.5.3 in estimating the cost of corporate income tax expressly requires that the estimate of taxable income be determined using the PTRM. It is also used to calculate incremental revenue in circumstances where a DNSP has applied under cl 6.6.2 to vary a determination where a trigger event for a contingent project in relation to that determination has occurred.
One immediate observation to make is that the rule makers sought to expressly include a PTRM in the NER, specified the matters it should contain and how the PTRM should be amended. Having gone to those lengths, there is a strong suggestion that the rule makers intended the PTRM to occupy a particular place in the scheme of regulation in the NER.
It appears that the first PTRM was published in 2008, the second version in 2009 and the current version (version 3) was published in January 2015.
The NER and the PTRM
As indicated, cl 6.3.1(c)(1) directs that a building block be prepared in accordance with the PTRM. For the AER this indicates that a DNSP cannot depart from a parameter preset in the PTRM. However SAPN places a different construction on the clause having regard to the practical workings of the PTRM itself. For SAPN, what that clause requires is only that a DNSP submit numbers in accordance with that model so that the AER can coherently consider the data at its end. That is, the direction given by cl 6.3.1(c)(1) is only to use the model, not that the preset parameters themselves are beyond challenge in submitting a proposal to the AER.
To reconcile the direction given by cl 6.3.1(c)(1) with a different inflation forecast to the PTRM, SAPN distinguishes between two phases of a proposal. Under the first phase, the building block proposal must, as required by cl 6.3.1(c)(1), be submitted in terms of the model that is the PTRM. But then different considerations are said to apply in the second phase – the making of the determination.
Clause 6.3.2 in this second phase specifies the matters that must be considered in making a building block determination. One of those matters is in cl 6.3.2(a)(2) – the appropriate methods for the indexation of the regulatory asset base. SAPN says that provision stands alone and is not constrained by the PTRM. Certainly there is no express reference there to the PTRM. Of course the AER’s response is that there is no need to mention it because if a DNSP complies with cl 6.3.1(c)(1), then the PTRM will have dealt with the issue through the preset parameters in the PTRM.
Chapter 6 does step through the process for the making of a building block determination in fairly a sequential way. It starts as both parties acknowledge, with a DNSP submitting a building block proposal to the AER under cl 6.3.1(b). The sequential nature of the process is effectively described in that provision. It also then notes that Pt E will apply to the making of the building block determination.
As noted, cl 6.3.1(c)(1) directs that the proposal “be prepared in accordance with the post-tax revenue model”. It is significant that cl 6.3.1(c)(1) employs the word “prepared”. If all that were required is that a DNSP simply submit its proposal under the form of the PTRM, then the NER could simply have directed that a proposal be submitted using the PTRM framework or some similar form of words. It does not do that. It suggests that the PTRM is more than simply an excel template to be used by each DNSP. The PTRM carries substantive parameters that must be employed by a DNSP in submitting a proposal.
Immediately following is r 6.4 which deals with the contents of the PTRM referred to above. In one sense, having introduced the concept of a PTRM in cl 6.3.1 it is obviously sensible to describe what it should contain. However, it would have been easy for the drafters of the NER to deal with the PTRM in a schedule or elsewhere in Ch 6. However they choose to interpose it between the contents of a building block determination and the building block approach. This is also because the PTRM is more than a mere tool in which to submit a proposal.
The drafting of r 6.4 also lends support to this view. First, cl 6.4.1(c) requires the PTRM to be “in force” at all times. It is not merely that the PTRM be available for use. Secondly, the PTRM cannot be amended at a whim. It can only be amended under the distribution consultation procedures. There would be little point in the rule makers establishing such a significant “gatekeeping” requirement if the PTRM were little more than a tool in which to submit a proposal. Finally, the PTRM must establish a “method” that the AER determines is likely to result in the best estimates of expected inflation (cl 6.4.2(b)(1)). The requirement to establish a “method” is a far stronger and significant direction than simply to establish a tool by which to submit a proposal.
Following this sequence, cl 6.4.3(a)(1) then specifies that one of the building blocks in calculating the annual revenue requirement is the indexation of the regulatory asset base. For the purposes of indexing the regulatory asset base cl 6.4.3(b)(1) provides that the regulatory asset base is to be calculated under cl 6.5.1 and Sch 6.2 and that the building block comprises a negative adjustment equal to the amount referred to in cl S6.2.3(c)(4) for that year. This is the source of the negative adjustment referred to earlier.
It is in the context of the roll forward of the regulatory asset base that S6.2.3(c)(4) provides:
(c) Method of adjustment of value of regulatory asset base
The value of the regulatory asset base for a distribution system as at the beginning of the second or a subsequent year (the later year) in a regulatory control period must be calculated by adjusting the value (the previous value) of the regulatory asset base for that distribution system as at the beginning of the immediately preceding regulatory year (the previous year) in that regulatory control period as follows:
…
(4) The previous value of the regulatory asset base must be increased by an amount necessary to maintain the real value of the regulatory asset base as at the beginning of the later year by adjusting that value for inflation.
It will be seen that what cl S6.2.3(c)(4) directs is that the regulatory asset base be adjusted for the effect of inflation.
Clause 6.5.1(b) requires that the AER in accordance with the distribution consultation procedures, develop and publish a model (the ‘roll forward model’) for the roll forward of the regulatory asset base. The AER may amend or replace the roll forward model from time to time in accordance with the distribution consultation procedures: cl 6.5.1(c). The purpose of the roll forward model (as the name suggests) is to deal with movements from one regulatory control period to the next. Clause 6.5.1(e)(3) requires in particular that the roll forward model set out the method for determining the roll forward of the regulatory asset base for distribution systems under which:
(3) the roll forward of the regulatory asset base from the immediately preceding regulatory control period to the beginning of the first regulatory year of a subsequent regulatory control period entails the value of the first mentioned regulatory asset base being adjusted for actual inflation, consistently with the method used for the indexation of the control mechanism (or control mechanisms) for standard control services during the preceding regulatory control period.
The clause refers to adjustments for actual inflation in the case of the first roll forward. Clause 6.5.1(f) provides that “[o]ther provisions relating to regulatory asset bases are set out in schedule 6.2”. In other words, there is a reference to Sch 2 in both cl 6.4.3(b) dealing with the specification of the building blocks and also through cl 6.5.1.
It should be noted that neither cl S6.2.3(c)(4) nor cl 6.5.1(e)(3) expressly refer to the adjustment for inflation or the roll forward of the regulatory asset base occurring consistently with the PTRM. SAPN argues that the AER should therefore determine an appropriate forecast for inflation without being constrained by the PTRM. For if it were constrained by the PTRM that rigid approach would be inconsistent with the framework of the NER that looks to a revenue allowance that allows a DNSP to recover efficient costs. An inflation forecast that is too high or low (through slavish reliance on the PTRM) would be inconsistent with that framework. The AER’s response is that these provisions do not deal with inflation because inflation is embedded in the PTRM from the first moment a DNSP is directed to submit its building block proposal.
To understand the AER’s argument it is necessary to return to the next step in the sequence in the making of a determination. The remaining provisions in Pt C then proceed to address features of the other building blocks such as the return on capital and depreciation. Having dealt with those building blocks, Pt E then logically addresses the determination process. That starts with a DNSP submitting a regulatory proposal to the AER under cl 6.8.2. The regulatory proposal must include a building block proposal: cl 6.8.2(c)(2). Following consultation the AER is required to publish a draft determination which also includes a consultation process: cl 6.10.1(a). A DNSP is required to respond to a draft determination by submitting revisions “so as to incorporate the substance of any changes required to address matters raised by the draft distribution determination or the AER’s reasons for it”: cl 6.10.3(b). A related criticism made by the AER is that this precludes SAPN submitting a new inflation methodology as it is not in truth a response to the draft determination. In view of the Tribunal’s ultimate conclusion, it is unnecessary to consider the merits of that argument.
The final stage in the sequence is the making by the AER of a final determination: cl 6.11.1.
Clause 6.12.3 deals with the extent of the AER’s discretion in making a distribution determination. Clause 6.12.3(a) provides:
Subject to this clause and other provisions of this Chapter 6 explicitly negating or limiting the AER’s discretion, the AER has a discretion to accept or approve, or to refuse to accept or approve, any element of a regulatory proposal or proposed tariff structure statement.
One aspect of the AER’s discretion in approving the annual revenue requirement is dealt with in cl 6.12.3(d):
The AER must approve the total revenue requirement for a Distribution Network Service Provider for a regulatory control period, and the annual revenue requirement for each regulatory year of the regulatory control period, as set out in the Distribution Network Service Provider’s current building block proposal, if the AER is satisfied that those amounts have been properly calculated using the post-tax revenue model on the basis of amounts calculated, determined or forecast in accordance with the requirements of Part C of this Chapter 6.
(Emphasis added).
The effect of cl 6.12.3(d) is that the AER has no discretion but to approve the total revenue requirements for a DNSP if it is satisfied that it has been calculated using the PTRM. It is significant that the clause requires the amounts to have been “calculated” using the PTRM. That expression ascribes to the PTRM a status more than merely a device or tool in which a proposal should be submitted. Ultimately it plays a material part in the determination of the total revenue requirement. It is also significant that both SAPN and the AER are bound by the PTRM through this clause. It is no more open to the AER to substitute an alternative inflation forecast through the building blocks than it is for SAPN. This is because the AER has no discretion but to approve a revenue requirement that has been calculated using the PTRM.
What this journey reveals is that the PTRM features at the very beginning of the determination process (when a DNSP is directed to submit a building block proposal that complies with the PTRM) and at the very end of the process when the AER is obliged to approve a revenue requirement (reflecting the building blocks) calculated using the PTRM. The common link between the start and end of the process is the PTRM. Having given the PTRM such a central place the rule makers did not see a need to expressly refer to it again in any of the intermediate stages or for example in dealing with the roll forward provisions.
At this stage it is worth returning to SAPN’s fundamental criticism of AER’s approach – that it is too rigid and will produce and inflation forecast that is too high resulting in a total revenue allowance (all other things being equal) that is less than what is required to promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers. There are several difficulties with this argument. First it assumes that SAPN’s methodology and the inflation forecast it derives is correct. That has not been established. Indeed the distribution consultation procedures ensure that these arguments can be fully ventilated and debated before a new PTRM is established. SAPN has the opportunity to put forward the model and have it “tested” as part of that process.
Secondly, the rule makers have determined to give the PTRM an express role within the NER as we have explained – presumably to ensure consistency between DNSP’s and regulatory decisions. Having done so, the AER must comply. That is no more rigid an approach than the requirement to comply with other directives in the NER.
Finally, cl 6.4.1(b) permits the AER to amend or replace the PTRM from time to time. There are no limits on how many times it may do so. Further the distribution consultation procedures do not appear to preclude a review of the PTRM occurring during the distribution determination process, if there is adequate time within the consultation procedures in which to do so. In that way a DNSP need not be prejudiced should it wish to advance an alternative model as SAPN sought to do.
Conclusion
For the reasons given, the Tribunal concludes that the PTRM is binding on SAPN and the AER such that AER cannot consider inflation outside the PTRM, as proposed by SAPN. Accordingly the Tribunal concludes that the AER did not make any error.
CONCLUSION
As no error has been found in the Final Decision, it is unnecessary to consider the operation of s 71P(2a)(c) of the NEL.
In view of the above reasons, the determination of the Tribunal is that the Final Decision is affirmed.
I certify that the preceding six hundred and twenty one (621) numbered paragraphs are a true copy of the Reasons for Determination herein of the Honourable Justice Middleton, Professor KT Davis and Mr R Steinwall. Associate:
Dated: 28 October 2016
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