zilongwang/ReadingBank huggingface dataset:
Note This attachment forms part of the AER's draft decision on the access arrangement for AusNet Services for 201822. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 - Services covered by the access arrangement Attachment 2 - Capital base Attachment 3 - Rate of return Attachment 4 - Value of imputation credits Attachment 5 - Regulatory depreciation Attachment 6 - Capital expenditure Attachment 7 - Operating expenditure Attachment 8 - Corporate income tax Attachment 9 - Efficiency carryover mechanism Attachment 10 - Reference tariff setting Attachment 11 - Reference tariff variation mechanism Attachment 12 - Non-tariff components Attachment 13 - Demand Attachment 14 - Other incentive schemes
Note for the avoidance of doubt, in making a determination on a Terrorism Event, the Regulator will have regard to, amongst other things: (c) whether the Service Provider has insurance against the event; (d) the level of insurance that an efficient and prudent service provider would obtain in respect of the event; and (e) whether a declaration has been made by a relevant government authority that an act of terrorism has occurred. Part B – Reference Tariff and Reference Tariff Policy Clause 8 […] In the case of the following all Relevant Pass Through Events: a) Change in Taxes Event; b) Major Upstream Failure Event; ; c) Insurer Credit Risk Event; d) Insurance Cap Event; e) Regulatory Change Event; f) Service Standard Change Event; g) Terrorism Event; and h) Disaster Event, the relevant definitions require there is required to be a Material increase or decrease in costs as a pre-condition to there being a Relevant Pass-Through Event.
Non-tariff components The non-tariff components of an access arrangement include: the terms and conditions for the supply of reference services extension and expansion requirements—the method for determining whether an extension or expansion is a part of the covered pipeline and the effect this will have on tariffs capacity trading requirements—the arrangements for users to assign contracted capacity and change delivery and receipt points provisions for receipt and delivery point changes, and a review submission date and a revision commencement date. We accept these components of Multinet's access arrangement in full. In accepting Multinet's proposed review submission date of 1 January 2022 (which is consistent with the date of submission in this review), we note that AGN proposed a review submission date of 1 December 2021 for its Victoria and Albury access arrangement. AusNet Services has indicated it is also prepared to adopt this earlier date. This means we will be able to extend consultation on AGN's and AusNet's proposals to manage limited stakeholder availability over the Christmas and New Year holiday period. In its revised proposal we encourage Multinet to consider a 1 December 2021 review submission date as well.
Lines event rate – fault 17.09 18.91 20.84 Transformer event rate – fault 19.49 29.85 43.42 Reactive plant event rate – fault 15.9 20.39 24.09 Lines event rate – forced 13.96 19.17 23.49 Transformer event rate – forced 15.95 24.23 34.25 Reactive plant event rate – forced Loss of supply events 1 3 7 Number of events greater than 0.05 system minutes per annum 0 1 3 Number of events greater than 0.30 system minutes per annum 4.83 94.14 282 Average outage duration 15.86 20.88 27.17 Source: AER analysis Table 112 Draft decision —MIC parameter values for 2017–2022 Parameter values - MIC Indicative (2009–2015) Performance target 333 Unplanned outage event limit 57 Dollar per dispatch interval $21,344 Source: AER analysis Table 113 Draft decision — 11.1 Network capability component for 2017–2022 ($ real 2016-17) Project Indicative value Greenbank System Integrity Protection Scheme 0 Load model enhancement and validation $506,000 (real, 2016/17) Increase design temperature of two 275kV transmission lines 0 Source: AER analysis Powerlink's proposal Powerlink proposed to apply version 5 of the STPIS as follows: The service component parameter targets are set equal to average historical performance over the last five years. The service component caps and floors are set at the 5th and 95th percentiles of historic performance. The Market Impact Component (MIC) parameter values to be set using market impact data from 2009–15 in accordance with the requirements of the scheme.
Note This attachment forms part of the AER's draft decision on Powerlink's transmission determination for 2017–22. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – Maximum allowed revenue Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Pricing methodology Attachment 13 – Pass through events Attachment 14 – Negotiated services
Table .4 Powerlink’s proposed pricing structure and the NER requirements NER requirements AER assessment Requirement for separate prices for each category of prescribed transmission services—clause 6A.23.4(a) Section 6.9 of Powerlink's proposed pricing methodology complies with this requirement. Requirement for fixed annual amount prices for prescribed entry services and prescribed exit services—clause 6A.23.4(g) Section 6.9.1 of Powerlink's proposed pricing methodology complies with this requirement. Requirement for postage stamped prices for prescribed common transmission 6A.23.4(f) Section 6.9.4 of Powerlink's proposed pricing methodology complies with this requirement. Requirement for prices for locational component of prescribed TUOS services to be based on demand at times of greatest use of the transmission network and for which network investment is most likely to be contemplated—clause 6A.23.4(b)(1) Section 6.9.2 of Powerlink's proposed pricing methodology complies with this requirement. Requirement for prices for the locational component of ASRR for prescribed TUOS services not to change by more than 2 per cent per year compared with the load weighted average prices for this component for the relevant region—clause 6A.23.4(b)(2) Section 6.9.2 of Powerlink's proposed pricing methodology complies with this requirement. Requirement for prices for the adjusted component of prescribed TUOS services to be on a postage stamp 6A.23.4(e) Section 6.9.3 of Powerlink's proposed pricing methodology complies with this requirement. Setting of TUOS locational prices between annual price publications–clause 6A.23.4(b) We do not accept that section 6.12 of Powerlink's proposed pricing methodology complies with aspects of this requirement for the reasons given in section 12.4.3 of this attachment. Assessment against the pricing methodology guidelines We are satisfied that Powerlink’s proposed pricing methodology complies with the information requirements of the pricing methodology guidelines. Key features of the proposal include:
Note This attachment forms part of the AER's draft decision on Powerlink's 2017–22 transmission determination. It should be read with other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – maximum allowed revenue Attachment 2 – regulatory asset base Attachment 3 – rate of return Attachment 4 – value of imputation credits Attachment 5 – regulatory depreciation Attachment 6 – capital expenditure Attachment 7 – operating expenditure Attachment 8 – corporate income tax Attachment 9 – efficiency benefit sharing scheme Attachment 10 – capital expenditure sharing scheme Attachment 11 – service target performance incentive scheme Attachment 12 – pricing methodology Attachment 13 – pass through events Attachment 14 – negotiated services
Our draft decision is to apply our current method rather than to use the breakeven approach. We consider there are clear limitations to using breakeven approaches that result in biased estimates of expected inflation unless particular adjustments are made to these estimates. We outlined these potential adjustments in Table 3-25 in Attachment 3 to our final decision on AusNet Services 2016–20 distribution determination. So far, no stakeholder has put any material before us to discuss the limitations of the breakeven approach or how to adjust for them. Without consensus on the appropriate methods for addressing these limitations, the breakeven approach may increase uncertainty and the potential for bias as a result of regulatory gaming, relative to our current approach based on RBA forecasts. Further, market imperfections can undermine the ability of breakeven approaches to estimate the market's inflation expectations. Despite having improved since 2007, we consider that the size and liquidity of the market for indexed Australian government bonds is still limited and may cause biases in breakeven inflation estimates. Given the information currently before us, and considering the limited amount of consultation we have been able to undertake on a parameter that should apply to all service providers, we are not satisfied that changing our approach would improve our estimates of expected inflation.
Note This attachment forms part of the AER's final decision on Powerlink's transmission determination for 2017–22. It should be read with all other parts of the final decision. The final decision includes the following documents: Overview Attachment 1 – Maximum allowed revenue Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Pricing methodology Attachment 13 – Pass through events Attachment 14 – Negotiated services
© Commonwealth of Australia 2016 This work is copyright. In addition to any use permitted under the Copyright Act 1968, all material contained within this work is provided under a Creative Commons Attributions 3.0 Australia licence, with the exception of: the Commonwealth Coat of Arms the ACCC and AER logos any illustration, diagram, photograph or graphic over which the Australian Competition and Consumer Commission does not hold copyright, but which may be part of or contained within this publication. The details of the relevant licence
Note This attachment forms part of the AER's draft decision on Powerlink's transmission determination for 2017–22. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – Maximum allowed revenue Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Pricing methodology Attachment 13 – Pass through events Attachment 14 – Negotiated services
Requests and inquiries concerning reproduction and rights should be addressed to the: Director, Corporate Communications Australian Competition and Consumer Commission GPO Box 4141, Canberra ACT 2601 or publishing.unit@accc.gov.au. Inquiries about this publication should be addressed to: Australian Energy Regulator GPO Box 520 Melbourne Vic 3001 Tel: 1300 585 165 Email:
Note This overview forms part of the AER's draft decision on Powerlink's transmission determination for 2017–22. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – Maximum allowed revenue Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Pricing methodology Attachment 13 – Pass through events Attachment 14 – Negotiated services
Note This attachment forms part of the AER's draft decision on TasNetworks' distribution determination for 2017–19. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Demand management incentive scheme Attachment 13 – Classification of services Attachment 14 – Control mechanisms Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy Attachment 19 - Tariff structure statement
Note This attachment forms part of the AER's draft decision on TasNetworks' distribution determination for 2017–19. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Demand management incentive scheme Attachment 13 – Classification of services Attachment 14 – Control mechanisms Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy Attachment 19 – Tariff structure statement
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 SAIDI system average interruption duration index SAIFI system average interruption frequency index SLCAPM Sharpe-Lintner capital asset pricing model STPIS service target performance incentive scheme WACC weighted average cost of capital
Note This attachment forms part of the AER's draft decision on TasNetworks' distribution determination for 2017–19. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Demand management incentive scheme Attachment 13 – Classification of services Attachment 14 – Control mechanisms Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy Attachment 19 – Tariff structure statement
© Commonwealth of Australia 2016 This work is copyright. In addition to any use permitted under the Copyright Act 1968, all material contained within this work is provided under a Creative Commons Attributions 3.0 Australia licence, with the exception of: the Commonwealth Coat of Arms the ACCC and AER logos any illustration, diagram, photograph or graphic over which the Australian Competition and Consumer Commission does not hold copyright, but which may be part of or contained within this publication. The details of the relevant licence
Note This attachment forms part of the AER's draft decision on TasNetworks' distribution determination for 2017–19. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Demand management incentive scheme Attachment 13 – Classification of services Attachment 14 – Control mechanisms Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy Attachment 19 – Tariff structure statement
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 SAIDI system average interruption duration index SAIFI system average interruption frequency index SLCAPM Sharpe-Lintner capital asset pricing model STPIS service target performance incentive scheme WACC weighted average cost of capital
Note This overview forms part of the AER's draft decision on TasNetworks' distribution determination for 2017–19. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Demand management incentive scheme Attachment 13 – Classification of services Attachment 14 – Control mechanisms Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy Attachment 19 – Tariff structure statement
Note This attachment forms part of the AER's draft decision on ActewAGL Distribution's access arrangement for 2016–21 access arrangement period. It should be read with all other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 - Services covered by the access arrangement Attachment 2 - Capital base Attachment 3 - Rate of return Attachment 4 - Value of imputation credits Attachment 5 - Regulatory depreciation Attachment 6 - Capital expenditure Attachment 7 - Operating expenditure Attachment 8 - Corporate income tax Attachment 9 - Efficiency carryover mechanism Attachment 10 - Reference tariff setting Attachment 11 - Reference tariff variation mechanism Attachment 12 - Non-tariff components Attachment 13 - Demand
reflecting current (short term) market sentiment. SKM selected Consensus Economics forecasts as the best currently available outlook for oil prices throughout the duration of the next access arrangement period. The decision by SKM to adopt an economic forecast for oil rather than using futures highlights the uncertainty surrounding the forecasting of commodity prices. Comparison of independent expert's cost escalation factors To illustrate the potential uncertainty in forecasting real material input costs, we have compared the material cost escalation forecasts derived by the consultants as shown Table 6.9. Table 6.9 Real material input cost escalation forecasts (per cent) 2014–15 (%) 2015–16 (%) 2016–17 (%) 2017–18 (%) 2018–19 (%) Aluminium CEG SKM BIS Shrapnel Range (low to high) 4.2 4.69 13.3 4.2 to 13.3 5.8 4.88 16.6 4.88 to 16.6 5.0 3.09 1.9 1.9 to 5.0 4.2 4.42 5.1 4.2 to 5.1 3.6 2.97 3.7 2.97 to 3.7 Copper CEG SKM BIS Shrapnel Range (low to high) -0.9 -0.17 3.5 -0.9 to 3.5 1.1 0.17 9.6 0.17 to 9.6 0.3 -1.15 0.6 -1.15 to 0.6 -0.3 -0.16 3.6 -0.3 to 3.6 -0.7 -1.45 1.9 -1.45 to 1.9 Steel CEG SKM BIS Shrapnel1 Range (low to high) 0.6 2.84 2.1 0.6 to 2.1 3.2 2.45 9.2 2.45 to 9.2 0.6 -0.35 -1.3 -1.3 to 0.6 0.3 0.38 3.7 0.3 to 3.7 -0.1 -1.11 3.7 -1.11 to 3.7 Oil CEG SKM BIS Shrapnel2 -0.5 -5.11 2.8 -0.79 2.6 0.74 2.1 1.85 1.8 0.51
© Commonwealth of Australia 2015 This work is copyright. In addition to any use permitted under the Copyright Act 1968, all material contained within this work is provided under a Creative Commons Attributions 3.0 Australia licence, with the exception of: the Commonwealth Coat of Arms the ACCC and AER logos
Operating expenditure We accept APTNT’s total forecast opex of $62.8 million ($2015–16) for the 2016–21 access arrangement period. Table 9 shows our approved opex forecast—which we consider is such as would be incurred by a prudent service provider acting efficiently, in accordance with accepted good industry practice, to achieve the lowest sustainable cost of delivering pipeline services. Table 9 AER draft decision on total opex—APTNT ($million, 2015–16) 2016–17 2017–18 2018–19 2019–20 2020–21 Total APTNT's proposal 11.9 12.9 13.9 11.8 12.3 62.8 AER draft decision 11.9 12.9 13.9 11.8 12.3 62.8 Difference – – – – – – Source: APTNT, 2016-21 Access arrangement information, August 2015 – Opex model; AER analysis. This allows an eight per cent real increase from APTNT’s actual opex in the current access arrangement period. APTNT underspent relative to its opex forecast in Savings—in labour costs associated with integration into the APA Group structure, and efficiencies associated with business wide initiatives such as consolidation of engineering and finance resources—are reflected in the base year from which opex for 2016–21 has been forecast. However, these are offset by the following factors, which necessitate an increase from the current period to accommodate: Forecast changes in labour costs (but no real price changes to materials) Pigging costs, including for delays and deferrals to the pigging schedule from the current access arrangement period to 2016–21. Figure 9 compares forecast opex for the 2016–21 period to APTNT’s allowed and actual opex in 2011–16. Figure 9 APTNT’s historical and forecast opex ($million, 2015–16) Source: APTNT, 2016-21 Access arrangement information, August 2015 – Opex model; APTNT, RIN response, August 2015. Corporate income tax When determining the total revenue for APTNT, we must estimate APTNT’s cost of corporate income tax. APTNT has adopted the post-tax framework to derive its total revenue requirement for the 2016–21 access arrangement period. Under the post-tax framework, a separate corporate income tax building block is calculated, based on the
Note This attachment forms part of the AER's draft decision on AusNet Services’ revenue proposal 2017–22. It should be read with other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – maximum allowed revenue Attachment 2 – regulatory asset base Attachment 3 – rate of return Attachment 4 – value of imputation credits Attachment 5 – regulatory depreciation Attachment 6 – capital expenditure Attachment 7 – operating expenditure Attachment 8 – corporate income tax Attachment 9 – efficiency benefit sharing scheme Attachment 10 – capital expenditure sharing scheme Attachment 11 – service target performance incentive scheme Attachment 12 – pricing methodology Attachment 13 – pass through events Attachment 14 – negotiated services
Table 1.3 Building block costs Building block costs Attachments where elements are discussed Return on capital Regulatory asset base (attachment 2) Capex (attachment 6) Rate of return (attachment 3) Regulatory depreciation (return of capital) Regulatory asset base (attachment 2) Capex (attachment 6) Depreciation (attachment 5) Operating expenditure (opex) Opex (attachment 7) Efficiency benefits/penalties Efficiency benefit sharing scheme (attachment 9) Estimated cost of corporate tax Corporate income tax (attachment 8) Value of imputation credits (attachment 4) Adjustment for shared assets Maximum allowed revenue (attachment 1) Source: AER analysis. Annual revenue adjustment process The PTRM incorporates an expected inflation rate to calculate the expected MAR (excluding performance incentive scheme revenue adjustments and pass through amount that may apply to each regulatory year) in nominal dollar terms, whereas the actual MAR for each year is adjusted for actual inflation. As discussed in the return on debt appendix of attachment 3, we will update AusNet Services’ return on debt annually. This means the actual MAR for each year will also be adjusted for revised X factors after the annual return on debt update. This annual revenue adjustment process is set out below. The MAR for the subsequent year of the regulatory control period requires an annual adjustment based on the previous year’s allowed revenue. That is, the subsequent year’s allowed revenue is determined by adjusting the previous year’s allowed revenue for actual inflation and the X factor determined after the annual return on debt update: ARt = where: AR = the allowed revenue t = time period/financial year (for t = 2 (2018–19), 3 (2019–20), 4 (2020–21), 5 (2021–22)) ∆CPI = the annual percentage change in the ABS Consumer price index all groups, weighted average of eight capital cities from September in year t – 2 to September in year t – 1
Note This attachment forms part of the AER's draft decision on AusNet Services’ revenue proposal 2017–22. It should be read with other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – maximum allowed revenue Attachment 2 – regulatory asset base Attachment 3 – rate of return Attachment 4 – value of imputation credits Attachment 5 – regulatory depreciation Attachment 6 – capital expenditure Attachment 7 – operating expenditure Attachment 8 – corporate income tax Attachment 9 – efficiency benefit sharing scheme Attachment 10 – capital expenditure sharing scheme Attachment 11 – service target performance incentive scheme Attachment 12 – pricing methodology Attachment 13 – pass through events Attachment 14 – negotiated services
Average circuit outage rate Lines event rate – fault 0.1406 24.98% 0.3525 Transformer event rate – fault 0.0073 19.06% 0.3160 Reactive plant event rate – fault 0.2196 36.00% 0.5089 Lines event rate – forced 0.1192 14.67% 0.1742 Transformer event rate – forced 0.0621 10.92% 0.1456 Reactive plant event rate – forced 0.1004 26.86% 0.4282 Loss of supply events Number of events greater than 0.05 system minutes per annum 0 2 5 Number of events greater than 0.30 system minutes per annum 0 0 2 Average outage duration 3.8981 74.0311 302.3258 Source: AER analysis Table 112 Draft decision —MIC parameter values for 2017–2022 Parameter values - MIC Indicative (2008–2014) Performance target 1603 DIs Unplanned outage event limit 272 DIs Dollar per dispatch interval $3274/DI
The performance target to apply from April 2017 will be based on average performance of the median five years from 2009–15 are at Table 116. Table 116 draft decision on AusNet Services MIC for 2017–22 Calendar year adj performance count 2008 3087 2009 1417 2010 2134 2011 2687 2012 909 2013 745 2014 871 Target (draft decision, place holder) 1603 Cap for unplanned outages 272 Dollar per dispatch interval $3274/DI Source: AER analysis Network capability component We accept AusNet Services' proposed priority projects and priority project improvement targets because it is consistent with the STPIS. The total expenditure of $125,000 ($ real 2016/17) for the priority projects in 2017–22 is not greater than 1 per cent of AusNet Services' proposed average maximum allowed revenue as required by clause 5.2(b) of the STPIS. These projects were also endorsed by the transmission network planner in Victoria— the Australian Energy Market Operator.
Note This attachment forms part of the AER's draft decision on AusNet Services’ regulatory proposal 2017–22. It should be read with other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – maximum allowed revenue Attachment 2 – regulatory asset base Attachment 3 – rate of return Attachment 4 – value of imputation credits Attachment 5 – regulatory depreciation Attachment 6 – capital expenditure Attachment 7 – operating expenditure Attachment 8 – corporate income tax Attachment 9 – efficiency benefit sharing scheme Attachment 10 – capital expenditure sharing scheme Attachment 11 – service target performance incentive scheme Attachment 12 – pricing methodology Attachment 13 – pass through events Attachment 14 – negotiated services
Aluminium CEG SKM BIS Shrapnel Range (low to high) 4.2 4.69 1.4 1.4 to 4.69 5.8 4.88 5.6 4.88 to 5.8 5.0 3.09 3.9 3.09 to 5.0 4.2 4.42 11.0 4.2 to 11.0 3.6 2.97 -6.5 -6.5 to 3.6 Copper CEG SKM BIS Shrapnel Range (low to high) -0.9 -0.17 -0.9 -0.9 to 0.17 1.1 0.17 -1.5 -1.5 to 1.1 0.3 -1.15 0.3 -1.15 to 0.3 -0.3 -0.16 9.3 -0.3 to 9.3 -0.7 -1.45 -8.7 -8.7 to -0.7 Steel CEG SKM BIS Shrapnel1 Range (low to high) 0.6 2.84 5.1 0.6 to 5.1 3.2 2.45 1.0 1.0 to 3.2 0.6 -0.35 -0.2 -0.35 to 0.6 0.3 0.38 8.0 0.3 to 8.0 -0.1 -1.11 -8.9 -0.1 to -8.9 Oil CEG SKM BIS Shrapnel2 Range (low to high) -0.5 -5.11 1.4 -5.11 to 1.4 2.8 -0.79 -1.1 -1.1 to 2.8 2.6 0.74 -0.2 -0.2 to 2.6 2.1 1.85 6.5 1.85 to 6.5 1.8 0.51 -6.2 -6.2 to 1.8 Source: CEG, Escalation factors affecting expenditure forecasts, December 2013, pp. 21, 24 and 27, SKM, TransGrid Commodity Price Escalation Forecast 2013/14 - 2018/19, 9 December 2013, p. 2 and BIS Shrapnel, Real Labour and Material Cost Escalation Forecasts to 2019/20 - Australia and New South Wales, April 2014, p. iii.
NECF 6.4 6.4 New regulatory obligation Customer engagement 0.5 0.5 Capitalisation policy change Reset costs 7.9 7.9 Capitalisation policy change Annual regulatory reporting 1.9 – Not a new regulatory obligation Marketing 6.6 6.6 Efficient response to change in market conditions. Insurance premiums 0.6 0.6 Prudent change in risk management Total step changes 23.9 22.0 Source: JGN, Access Arrangement Information, June 2014, p. 76. National Energy Customer Framework JGN proposed a step change of $6.4 million to comply with the National Energy Customer Framework (NECF) from 1 July 2015. We have included this step change in our opex forecast because it is driven by a change in JGN's regulatory obligations and the costs are not captured in base year expenditure. We had regard to the supporting information JGN provided and we assessed the underlying assumptions of the forecast cost of complying with the NECF. We consider that the assumptions and method JGN used to forecast the opex step change is reasonable. The NECF governs the rights, obligations and consumer protections with respect to the retailer-customer relationship and distributor-customer relationship. Under the NECF, JGN has a direct contractual relationship with gas consumers, whereas previously retailers provided the interface between JGN and customers. Specifically, under the NECF: customers can seek a range of retail support services directly from JGN that are currently performed by, or administered through, gas retailers householders, in addition to builders and developers, can make connection applications directly to JGN rather than via retailers. Further, JGN consider they will not be able to charge connection applicants an administration fee where currently they are able to.
the imputation credit. In this situation, the study typically reports the combined value of the cash dividend and imputation credit together. The minimum value for the imputation credit component of this package will arise if the cash dividend is fully valued, and these estimates are presented in the 'notes' column. Table . Estimates of the utilisation rate from dividend drop off studies Authors Pre-2000 results Post-2000 results Notes Dividend drop off study Vo et al (2013) 0.35–0.55 (2001–2012) Range derived from large number of permutations and sensitivity tests. SFG (2013a) 0.35 (2001–2012) Author's point estimate across a number of different regression forms. SFG (2011) 0.35 (2001–2010) Minney (2010) 0.39 (2001–2009) Average of results from 2001–2005 and 2006–2009 sub-periods. For the most recent sub-period (2006–2009), utilisation rate is 0.53. Beggs and Skeels (2006) 0.20 (1992–1997) 0.57 (2001–2004) Several other pre-2000 periods are presented. Hathaway and Officer (2004) 0.49 (1986–2004) Authors suggest that estimate has increased post-2000. Bellamy and Gray (2004) 0.36 (1995–2002) Range of 0.0–0.60 is also presented. Bruckner et al (1994) 0.69 (1991–1993) Also present an earlier period (1987–1990). Brown and Clarke (1993) 0.80 (1988–1991)
Source: As specified in table. Table . Estimates of the utilisation rate from alternative market value studies Authors Pre-2000 results Post-2000 results Notes Dividend drop off study using hybrids Feuerherdt, Gray and Hall (2010) N/A (1995–2002) Combined drop off of 1.0. With dividends at full value, this is a utilisation rate of 0. Futures study (individual or index) SFG (2013b) 0.12 (2000–2013) Uses individual firms. Cannavan et al (2004) 0–0.15 (1994–1999) Uses individual firms. Cummings and Frino (2008) 0.52 (2002–2005) Uses index. Rate of return study NERA (2013b) -1.57 (1987–2000) -1.90 (2000–2012) Uses past returns. For the entire period, estimate is -1.50. Lajbcygier and Wheatley (2012) -1.57 (1987–2000) -1.68 (2000–2009) Uses past returns. For the entire period, estimate is -1.88 Siau et al (2013) -0.29–0.30 (1996–2011) Uses forecast returns. Note range is from negative 0.29 to positive 0.30. Simultaneous share trades Chu and Partington (2008) N/A (1996) Combined drop off of 1.29. With dividends at full value, this is a utilisation rate of 0.68. Walker and Partington (1999) 0.88–0.96
Figure TasNetworks' capital expenditure Source: TasNetworks revenue proposal, AER analysis Summary of analysis and reasons TasNetworks' proposed total forecast capex of $275.9 million ($2013–14). Its proposal was largely consistent with the estimate of total forecast capex produced by our own assessment. The exception to this finding relates to growth related capex. This proposed forecast included $36.8 million for growth related capex driven primarily by two individual projects: the Waddamana–Palmerston 220 kV security augmentation project, and the Newton–Queenstown security augmentation project. Based on updated information, AEMO and TasNetworks have both submitted that these projects could be prudently deferred until after the 2014-19 period. We accept that these projects are unlikely to be required in the period covered by this decision. TasNetworks also provided suggested revised forecasts of augex and repex to reflect the deferral of the two augmentation projects from the period. Our substitute estimate was informed by these revisions. The result is a $35.2 million reduction in TasNetworks' proposed augex (to $1.6 million), and a corresponding upwards revision to TasNetworks proposed forecast repex (by $5.6 million) to replace a number of aging assets that would have otherwise been replaced as part of the augmentation projects. Operating expenditure (opex) Opex includes forecast operating, maintenance and other non-capital costs incurred in the provision of transmission network services. It includes labour costs and other non-capital costs that TasNetworks is likely to require during the 2014–19 period for the efficient operation of its network. Draft decision We are satisfied that TasNetworks' total opex forecast reasonably reflects the opex criteria. Table 86 shows our draft decision, which accepts TasNetworks' proposal. This includes the 2014-15 transitional regulatory control period.
Note This attachment part of the AER's draft decision on TransGrid’s revenue proposal 2015–18. It should be read with other parts of the draft decision. The decision includes the following documents: Overview Attachment 1 – maximum allowed revenue Attachment 2 – regulatory asset base Attachment 3 – rate of return Attachment 4 – value of imputation credits Attachment 5 – regulatory depreciation Attachment 6 – capital expenditure Attachment 7 – operating expenditure Attachment 8 – corporate income tax Attachment 9 – efficiency benefit sharing scheme Attachment 10 – capital expenditure sharing scheme Attachment 11 – service target performance incentive scheme Attachment 12 – pricing methodology Attachment 13 – pass through events Attachment 14 – negotiated services
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 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
Note This attachment forms part of the AER's draft decision on TransGrid’s revenue proposal 2015–18. It should be read with other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – maximum allowed revenue Attachment 2 – regulatory asset base Attachment 3 – rate of return Attachment 4 – of imputation credits Attachment 5 – regulatory depreciation Attachment 6 – capital expenditure Attachment 7 – operating expenditure Attachment 8 – corporate income tax Attachment 9 – efficiency benefit sharing scheme Attachment 10 – capital expenditure sharing scheme Attachment 11 – service target performance incentive scheme Attachment 12 – pricing methodology Attachment 13 – pass through events Attachment 14 – negotiated services
Glossary Shortened form or term Extended form or definition AEMC Australian Energy Market Commission AEMO Australian Energy Market Operator AER Australian Energy Regulator allowance mechanism Demand Management Innovation Allowance Mechanism AR annual smoothed revenue requirement committed project has the meaning given in clause 2.2.2(1) compliance report the demand management compliance report required under clause 2.4(1) confidentiality guidelines the document published by the AER entitled "Confidentiality Guideline, November 2013", as amended or replaced by the AER from time to time. credible option has the meaning in clause 5.15.2(a) of the NER demand management for the purpose of this scheme, this relates to network demand management. This is the act of modifying the drivers of network demand to remove a network constraint. demand management contract has the meaning given in clause 2.2.2(2) demand management proposal has the meaning given in clause 2.2.2(3) distributor Distribution Network Service Provider efficient non-network option has the meaning given in clause 2.2(2) eligible project has the meaning in clause 2.2(1) EBSS Efficiency Benefit Sharing Scheme kVA A kilovolt -ampere or 1,000 volt-amperes minimum project evaluation requirements has the meaning in clause 2.2.1 MWh Megawatt hour NEO National Electricity Objective NER National Electricity Rules
for the benchmark efficient entity is below the market average. benchmark efficient entity, it would be reasonable to quantify the impacts of these differences and to make necessary adjustments. However, it is difficult to make such adjustments in a robust and transparent manner. refer to foreign proxies. Foreign proxies are likely to be subject to different regulatory, geographic, economic conditions. Ideally, the impact of these differences should be quantified and adjusted for. However, it is difficult to make such adjustments in a robust and transparent manner. Where models of the return on equity and debt are used these are on quantitative modelling that is sufficiently robust as to not be unduly sensitive to errors in inputs estimation based on quantitative modelling which avoids arbitrary filtering or adjustment of data, which does not have a sound rationale Not applicable OLS and LAD are commonly used regression techniques to estimate the equity beta. Further, the ERA introduced two new techniques, which produced consistent empirical estimates. There was no arbitrary adjustment to the data; instead we consider estimates from different comparator sets and different time periods. OLS and LAD are commonly used regression techniques to estimate the equity beta. There was no arbitrary adjustment to the data. Instead, we consider estimates from different comparator sets and different time periods. The Black CAPM is sensitive to errors in the estimation of the zero beta return. Not applicable market data and other information is used, this information is credible and verifiable comparable and timely clearly sourced Not applicable Market data used for domestic empirical estimation this criterion. Market data used for international empirical estimation meets this criterion. Not applicable Estimates from other regulators may not always be directly comparable to our estimates due to differences in the estimation approach. In particular, other regulators do not always use a benchmark efficient entity that is consistent with our definition. However, water regulators will often provide robust reasoning and clearly specify the data used for estimating their equity betas. In this respect, this data is usually verifiable and clearly sourced.
Sufficiently flexible as to allow changing market conditions and new information to be reflected in regulatory outcomes, as appropriate Not applicable We can always update the empirical estimates to take into account the latest market data. We can always update the empirical estimates to take into account the latest market data. While the theory of the Black CAPM should allow the model to accommodate changing market conditions, the difficulties in estimating the zero beta return are magnified when attempting to match current market conditions (instead of an average figure over many years). Estimates from other regulators may not always reflect prevailing market conditions, as there may be a delay between when the corresponding decisions are made. As such, these estimates may not be sufficiently flexible to allow changing market conditions to be reflected.
Identifying and committing eligible projects Clause 2.2 of the draft Scheme defines the type of projects that the Scheme will apply to ('eligible projects'). Table 1 summarises the elements of an eligible project. It also explains how each element will give effect to the rules, and how it incorporates stakeholder views. Table 1: Elements of project eligibility Element required for 'eligibility' Rationale for element Regard to stakeholder views When identifying whether a project is an efficient non-network option, a distributor has either completed a RIT–D or 'minimum project evaluation requirements' This element acts an in-built compliance check to verify that the Scheme is only incentivising efficient projects that deliver cost savings to retail customers, by: Requiring the distributor conduct a cost-benefit analysis of its credible options for addressing network constraints; and Subjecting this analysis to third party testing. We only require a distributor follow 'minimum project evaluation requirements' before accessing incentives for non-RIT-D projects. We agree with the views expressed by some stakeholders that we should not add requirements where existing processes, like the RIT-D, already address the relevant issue. For details relevant to how we the specified 'minimum project evaluation requirements', see section 5.2. It is efficient if it is a credible option to meet an identified need on the distribution network, where that credible option is the preferred option. Adopting the term 'preferred option' used in the Streamlines the assessment process with the RIT-D. Captures the concept of 'net economic benefits' referred to in NER cl. 6.6.3(c)(3). Aligns with an 'efficient option', which we interpret as needing to meet an identified need/network constraint. This position is consistent with many stakeholders' views that support efficiency assessments at the network planning stage. While some stakeholders caution against quantifying broad market benefits, others specifically supported this approach. We consider this analysis necessary to deliver the NER's intent, but note it can also be complex, costly and subjective. We have therefore developed some worked examples using 'rule of thumb' approaches to estimating broad market benefits.
Capital Expenditure Sharing Scheme Demand Management Incentive Scheme Expenditure Forecast Assessment Guideline Our Expenditure Forecast Assessment Guideline is based on a reporting framework allowing us to compare the relative efficiencies of distributors. Our preliminary position is to apply the guideline, including its information requirements, to ActewAGL in the upcoming regulatory control period. Our expenditure assessment guideline outlines a suite of assessment/analytical tools and techniques to assist our review of ActewAGL’s regulatory proposal. We intend to apply the assessment/analytical tools set out in the guideline and any other appropriate tools for assessing expenditure forecasts. Depreciation We provide an allowance for network businesses to recover the costs of their investments. The rate at which they recover the cost of their investments is determined by their depreciation profile. We have a choice of using forecast or actual depreciation. We have chosen to apply forecast depreciation in combination with the CESS as this will maintain the incentive for ActewAGL to pursue capex efficiencies. Dual function assets Some high voltage distribution assets are of use to customers outside of the distribution network. These are dual function assets that support the transmission of electricity at high voltages across Australia and not just within a distribution network. One aspect of our decision is to determine whether customers within the network should pay for these assets or whether the costs should be recovered from only those customers that benefit from their use. ActewAGL has submitted that it does operate dual function assets. Our preliminary position is to apply transmission pricing rules to 6 per cent of ActewAGL’s RAB, consistent with the current regulatory control period. ActewAGL submitted that the value of its dual function assets is now 19 per cent of its RAB. We are engaging with ActewAGL to understand the reasons for this reported increase in the value of its dual function assets. We will reflect this further engagement in our final F&A. For more information: More information can be found on our website: .
Other MIC issues AusNet Services and AEMO requested clarification on how the AER interprets the phrase. We have removed the reference to statistical outliers in clause 4.2(e) in the final decision. AusNet Services and Powerlink alerted us to some drafting issues which have been accepted and corrected.