Tasnetworks Transmission Determination

FINAL DECISION

TasNetworks transmission determination

2015−16 to 2018−19

April 2015

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1 Final decision | TasNetworks transmission determination2015–19

Contents

Shortened forms

1Our final decision

1.1Decision and impact

1.2Indicative impact of transmission charges on electricity bills in Tasmania

2Final decision on TasNetworks' revenue determination

2.1Final decision

2.2Key elements of the building blocks

3Other components of this final decision

3.1Final decision

4Regulatory framework

4.1Understanding the NEO

4.2The 2012 framework changes

4.2.1Interrelationships

5Process

5.1Better Regulation program

5.2Our engagement during the decision making process

AConstituent components of this decision

BList of submissions

CSummary of submissions

Shortened forms

Shortened form / Extended form
AARR / aggregate annual revenue requirement
AEMC / Australian Energy Market Commission
AEMO / Australian Energy Market Operator
AER / Australian Energy Regulator
ASRR / annual service revenue requirement
augex / augmentation expenditure
capex / capital expenditure
CCP / Consumer Challenge Panel
CESS / capital expenditure sharing scheme
CPI / consumer price index
DRP / debt risk premium
EBSS / efficiency benefit sharing scheme
ERP / equity risk premium
MAR / maximum allowed revenue
MRP / market risk premium
NEL / national electricity law
NEM / national electricity market
NEO / national electricity objective
NER / national electricity rules
NSP / network service provider
NTSC / negotiated transmission service criteria
opex / operating expenditure
PPI / partial performance indicators
PTRM / post-tax revenue model
RAB / regulatory asset base
RBA / Reserve Bank of Australia
repex / replacement expenditure
RFM / roll forward model
RIN / regulatory information notice
RPP / revenue and pricing principles
SLCAPM / Sharpe-Lintner capital asset pricing model
STPIS / service target performance incentive scheme
TNSP / transmission network service provider
TUoS / transmission use of system
WACC / weighted average cost of capital

1Our final decision

The Australian Energy Regulator (AER) is responsible for the economic regulation of electricity transmission and distribution systems in all states and territories except Western Australian and the Northern Territory. TasNetworks is the Transmission Network Service Provider (TNSP) and Distribution Network Service Provider (DNSP) responsible for providing electricity transmissionand distribution services in Tasmania.We regulate the revenues TasNetworks can recover from customers. This decision deals with TasNetworks' transmission network and the services it provides as a TNSP.[1]

The NEL and NER provide the regulatory framework under which we operate. These set out how we must assess a revenue proposal and make our decision. In this section we set out some key aspects of this framework.

The NEO is the central feature of the regulatory framework. The NEO is to promote efficient investment in, and efficient operation and use of, electricity services for the long term interests of consumers of electricity with respect to—

price, quality, safety, reliability and security of supply of electricity; and

the reliability, safety and security of the national electricity system.[2]

Under the NER,TasNetworks must submit a revenue proposal to us for approval.[3]The central component of a revenue proposal is the amount of revenue TasNetworks proposes to recover from consumers over the 2014–19 period.[4]We must assess TasNetworks'proposal, using the NER's detailed rules about constituent components of a regulatory proposal. We must decide whether to accept TasNetworks' revenue proposal. If we do not accept that TasNetworks' revenue proposal complies with therequirements of the NER, we must substitute an alternative amount of revenue that we are satisfied does comply.[5]We must undertake this assessment and make this decision in a manner that will or is likely to contribute to the achievement of the NEO and, where appropriate, contribute to the greatest degree.

We regulate TasNetworks' revenue, not its costs. TasNetworksmust then decide how best to use this revenue in providing transmission services and fulfilling its obligations. This provides incentives for TNSPs, such as TasNetworks, to operate their businesses efficiently and, in the long run, at least cost to consumers. It also provides incentives for TNSPs to innovate and invest in response to changes in consumer needs and productive opportunities.[6] This is consistent with economic efficiency principles. It also means that the person who is best able to manage a risk generally carries that risk.

TasNetworks submitted its revenue proposal to us in June 2014. In November 2014 we made a draft decision that largely accepted TasNetworks' revenue proposal.

In addition to its revenue proposal, TasNetworks must submit a proposed pricing methodology and negotiating framework for approval. Our draft decision also accepted these proposals and set out negotiated transmission service criteria for TasNetworks.

In January 2015, TasNetworks submitted a revised proposal adopting our draft decision and each of its constituent components in full. TasNetworks in its revised proposal noted that it held some in-principle objections to some aspects of our draft decision on its revenue proposal (rate of return and taxation; treatment of provisions; benchmarking[7]) but nonetheless adopted our draft decision on those aspects.[8]We also received submissions from other stakeholders, including the Consumer Challenge Panel (CCP), on TasNetworks' initial and revised proposals as well as our draft decision.

This document is our final decision on TasNetworks' proposal and its transmission determination for the 2015–19 regulatory control period.

We accept TasNetworks revised proposal on each of the constituent components (as set out in Appendix A) for the reasons in our draft decision and in this final decision.[9] As such, our draft decision reasons form part of this final decision. In addition, we are required under the NER to accept elements of the revised proposal in certain circumstances. To the extent that some submissions did not accept our reasons in our draft decision or raised new issues, we have addressed those points in our reasoning set out in section 2and Appendix C. We have also addressed TasNetworks' in-principle objections in those sections.We set out greater detail on the process we have undertaken in making this decision in section5 below.

1.1Decision and impact

Our final decision is that TasNetworks can recover $693.9 million ($ nominal) from consumers over the 2015–19 regulatory control period, or $880.8 million for the 2014-19 period, including the 2014-15 transitional year.[10]This is $37.3 million (or 5.1 per cent) less than the indicative total revenue cap in our draft decision and TasNetworks' revised proposal. This differenceis a result of updated calculations for the rate of return that were part of our draft decision, and formed part of TasNetworks' revised proposal. This updated information was not available at the time of our draft decision or when TasNetworks submitted its revised proposal and indicative allowance.

Figure 1illustrates our overall decision on TasNetworks' total revenueallowance.

Figure 1TasNetworks' past total revenue and AER total revenue allowance ($ million, 2013–14)

Source: AER analysis.

1.2Indicative impact of transmission charges on electricity bills in Tasmania

Our final decision ultimately affects the annual electricity bills paid by customers. These electricity bills reflect a number of cost components—transmission, distribution, wholesale and retail costs.

In Tasmania, transmission charges represent approximately 15per cent of a customer's average annual electricity bill.[11] If the lower transmission charges flowing from our decision for TasNetworks are passed through to customers, we would expect the average annual electricity bill for residential and small business customers to reduce in 2015–16. However, other factors also affect a customer’s electricity bill, such as the wholesale price of electricity.

Table 1shows the estimated impact of our final decision on the average residential and small business customers over the 2014–19 period.

Table 1Estimated impact of final decision on the average residential and small business customers' electricity bills in Tasmania for the 2014–19 period ($nominal)

2013–14 / 2014–15 / 2015–16 / 2016–17 / 2017–18 / 2018–19
Residential annual billa / 2256 / 2219 / 2195 / 2197 / 2199 / 2202
Annual change / –37(–1.6%) / –24 (–1.1%) / 2 (0.1%) / 2 (0.1%) / 3 (0.1%)
Small business annual billb / 3782 / 3720 / 3680 / 3683 / 3687 / 3691
Annual change / –62 (–1.6%) / –41 (–1.1%) / 3 (0.1%) / 4 (0.1%) / 4 (0.1%)

Source:AER analysis; OTTER, 2013 Aurora Pay As You Go price comparison report (APAYG rates from 27 July 2013), August 2013; Comparison of 2014 Australian standing offer energy prices, March 2014. OTTER, Typical electricity customers 2010–information paper, September 2010, pp. 11–12. AER, Energy Made Easy.

(a)The average annual electricity bill for Tasmania is based on a typical annual usage of approximately 8800kWh in Tasmania. It reflects the weighted average of the typical regulated tariff customer's annual electricity bill and typical Aurora PAYG tariff customer's annual electricity bill as published by OTTER and the Energy Made Easy website. The weighting assumptions we have adopted are 85 per cent for regulated tariff customer bills and 15 per cent for Aurora PAYG tariff bills (source: OTTER, 2013 Aurora Pay As You Go price comparison report (APAYG rates from 27 July 2013), August 2013, p. 4.). We also incorporated the annual electricity bills of customers that are entitled to a concession. In Tasmania, one in three regulated tariff customers will receive a concession and about 47 per cent of Aurora PAYG customers will receive a concession (source: OTTER, Comparison of 2014 Australian standing offer energy prices, March 2014, p. 8; OTTER, 2013 Aurora Pay As You Go price comparison report (APAYG rates from 27 July 2013), August 2013, p.4.).

(b)The weighted average annual electricity bill for small businesses in Tasmania is based on typical annual usage of 11 MWh in Tasmania and sourced from the Energy Made Easy website based on the annual consumptions of typical business customers using only tariff 22 (General) as published by OTTER.

2Final decision on TasNetworks' revenue determination

The total revenue cap represents our forecast of the efficient costs a prudent and efficient service provider would incur in providing transmission network services for the 2015–19 regulatory control period.

2.1Final decision

The constituent components of our decision include the building blocks we use to determine the revenue that TasNetworks may recover from its customers.[12]

In setting our overall revenue for TasNetworks of or $880.8 million ($nominal) for the 2014-19 period we:

apply relevant tests under the NER, the assessment methods and tools developed as part of our Better Regulation guidelines[13] (see section5.1). We also consider information provided by TasNetworks, the CCP, consultants and stakeholder submissions
consider our overall revenue against section 16 of the NEL, including the constituent decisions and the interrelationships.

Table 2shows our final decision on TasNetworks' building block costs and the resulting revenues (both smoothed and unsmoothed).[14]There is a full list of the constituent components of this decision in Appendix A.

Table 2AER's final decision on TasNetworks'revenues ($million, nominal)

2014–15 / 2015–16 / 2016–17 / 2017–18 / 2018–19 / Total
Return on capital / 91.4 / 92.0 / 94.9 / 96.9 / 98.4 / 473.6
Regulatory depreciationa / 19.4 / 22.9 / 26.3 / 26.2 / 27.4 / 122.3
Operating expenditure / 45.1 / 45.5 / 46.8 / 48.2 / 48.8 / 234.4
Efficiency benefit sharing scheme (carryover amounts) / 12.5 / 8.8 / 7.2 / 4.5 / 0.0 / 33.0
Net tax allowance / 3.6 / 3.9 / 4.2 / 4.2 / 4.6 / 20.4
Annual building block revenue requirement (unsmoothed) / 172.0 / 173.0 / 179.5 / 180.0 / 179.2 / 883.7
Annual expected MAR (smoothed) / 186.9 / 172.6 / 173.2 / 173.8 / 174.3 / 880.8
X factor (%) / n/ab / 9.81%c / 2.00%d / 2.00%d / 2.00%d / n/a

Source: AER analysis.

(a) Regulatory depreciation is straight-line depreciation net of the inflation indexation on the opening RAB.

(b)TasNetworks is not required to apply an X factor for 2014–15 because we set the 2014–15 MAR in this decision. We have set the 2014–15 MAR equal to TasNetworks' targeted revenue ($186.9 million) for 2014–15. We note that TasNetworks applied a lower revenue than the placeholder MAR of $205.1 million for 2014–15 pricing purposes. The MAR for 2014–15 ($186.9 million) is around 26.4 per cent lower than the approved MAR ($247.9 million) in the final year of the 2009–14 regulatory control period (2013–14) in real terms, or 24.6 per cent lower in nominal terms.

(c)Applying the X factor for 2015–16and the actual CPI of 1.72 per cent in accordance with the annual revenue adjustment formula set out in the transmission determination, the MAR for 2015–16 is $171.5 million.

(d)The X factor will be revised to reflect the annual return on debt update.

Figure 2shows the size of the changes in the building block costs from our final decision for TasNetworks, and how these impact on revenues on average. The actual revenue for 2013–14 is used as a base from which the impact of the changes can be shown. For example, the most significant change is to the return on capital allowance that reduces the annual building block revenue requirement on average by about $35million ($ 2013–14).

Figure 2AER's final decision on building block costs ($ million 2013–14)

Source:AER analysis.

2.2Key elements of the building blocks

We accept TasNetworks' revised proposal on each of the constituent components (as set out in Appendix A):

for the reasons in our draft decision, and
with regard to:

TasNetworks' revised proposal and written submissions from stakeholders and the consumer challenge panel (CCP), and
circumstances in which the NER require us to accept elements of the revised proposal.

The NER provide that we must accept the forecast of capital and operating expenditure (capex and opex) proposed by TasNetworks in its revised revenue proposal if TasNetworks includes the same amount of capex and opex as we estimated in our draft decision.[15]We can only reject those amounts if TasNetworks' revised revenue proposal includes other changes or different information, such that we are not satisfied that the proposed capex or opex meets the capex or opex criteria. TasNetworks has not included any changes or information of this kind (relevantly, the changes made by TasNetworks to its capex after submission of its initial proposal merely reflect updated demand forecasts). Also, we have not received any submissions which impact upon our reasoning as set out in the draft decision. We therefore accept the forecast capex and opex proposed by TasNetworks.

TasNetworks' revised proposal noted that we would update the RAB roll forward for actual 2013–14 capex. Following this update, our final decision on TasNetworks' opening RAB at 1 July 2014 is $1410.3 million.

We have also maintained our draft decision positions in relation to other elements of the building blocks.

We received a number of submissions on the rate of return and value of imputation credits in particular. Consideration of these submissions along with the underlying expert reports is included in each of the final decisions for those service providersthat did not accept the AER’s draft decisions on these issues.[16] Our reasons as set out in those decisions also form part of this final decision for TasNetworks also.

Our final decision on the rate of return and value of imputation credits applies the same approach and methodology as our draft decision. This is consistent with TasNetworks' adoption of our draft decision.

A list of all submissions received, and a summary of key issues raised, is provided in Appendices B and C.

3Other components of this final decision

Our transmission determination for TasNetworks must also include a determination on the pricing methodology, negotiating framework and negotiated transmission services criteria that will apply to TasNetworks for the 2015–19 regulatory control period.

3.1Final decision

In our draft decision we accepted TasNetworks' proposed pricing methodology and negotiating framework and set out negotiated transmission service criteria for the 2015–19 regulatory control period. TasNetworks did not seek to amend any of these in its revised proposal, and submissions (discussed in Appendix C) have not raised any issues which impact upon our reasoning as set out in the draft decision.[17]We thereforeaccept the pricing methodology, negotiating framework and negotiated transmission services criteria in TasNetworks' revised proposal.

4Regulatory framework

As explained in section 1, the NEL and NER provide the regulatory framework under which we operate. These set out how we must assess a revenue proposal and make our decision. In this section we set out some key aspects of this framework.

price, quality, safety, reliability and security of supply of electricity; and

the reliability, safety and security of the national electricity system.[18]

The NEL also includes the revenue and pricing principles (RPP), which support the NEO.[19] As the NEL requires,[20] we have taken the RPPs into account throughout our analysis. The RPPs are:

A regulated network service provider should be provided with a reasonable opportunity to recover at least the efficient costs the operator incurs in—

providing direct control network services; and
complying with a regulatory obligation or requirement or making a regulatory payment.

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—

efficient investment in a distribution system or transmission system with which the operator provides direct control network services; and
the efficient provision of electricity network services; and
the efficient use of the distribution system or transmission system with which the operator provides direct control network services.

Regard should be had to the regulatory asset base with respect to a distribution system or transmission system adopted—