zilongwang/ReadingBank huggingface dataset:
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 and Clarke (1993) 0.80 (1988–1991) Source: As specified in table. As is evident in the table above, dividend drop off studies suggest that the utilisation value is in the range of 0.35 to 0.57 when using post 2000 data and is in the range of 0.2 to 0.8 when using pre 2000 data. This is consistent with the finding in Ainsworth, Partington and Warren (2015) which considers that the dividend drop-off and comparative pricing studies they examine would suggest that imputation credits are partially priced at about $0.38 in the dollar. Table 418 Estimates of the utilisation rate from alternative market value studies Authors Pre-2000 results Post-2000 results Notes Dividend drop off 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 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
progressively downgraded its demand forecasts since its initial regulatory proposal for the previous 2009–14 regulatory control period. In October 2014, Ausgrid stated that improvements in its forecasting process, and not just economic growth forecasts, explained its lower demand forecasts. Ausgrid has improved its forecasting methodology to take better account of top down econometric factors and to incorporate a revised normalisation approach. Ausgrid's revised normalisation approach improves its calculation of its weather correction metric and is carried out at the substation level on a seasonal basis. As a result, the starting point at many zone substations has changed. This, combined with a lower underlying growth projection, has resulted in a reduction in forecast demand at most points on the system. The AEMO forecasted similar trends of low system demand growth for Ausgrid's network and for the NSW region more generally. We note that AEMO had downgraded its demand forecast for the NSW region in its most recent report. Ausgrid's regulatory proposal described its demand forecasting methods, including approaches to: weather correction accounting for spot loads accounting for transfers accounting for embedded generation. As part of our final decision on system demand forecasts, we compared Ausgrid's revised system demand forecast to the sum of AEMO's connection point (CP) forecasts for Ausgrid's network. Figure 611 and Table C1 provide an overall system level view of Ausgrid's revised demand forecasts, the changes made since its regulatory proposal and a comparison of the AEMO forecasts. Figure Maximum system demand (summer coincident) Table Maximum system demand - Weather corrected (50% PoE) (MW) 2014-15 2015-16 2016-17 2017-18 2018-19 Average annual growth (2014-19) Regulatory proposal (May 2014) - Summer 5594 5591 5667 5778 5878 0.70% Revised proposal (January 2015) - Summer 4888 4812 4750 4719 4716 -0.21%
Note This attachment part of the AER's final decision on AusNet Services' distribution determination for 2016–20. It should be read with all other parts of the final decision. The final 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 – f-factor scheme
© Commonwealth of Australia 2016 This work is copyright. In addition to any use permitted 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
Note This attachment forms part of the AER's final decision on AusNet Services' distribution determination for 2016–20. It should be read with all other parts of the final decision. The final 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 – f-factor scheme
(A minus B) Under/over recovery of revenue for regulatory year –495 2162 –1676a Jurisdictional scheme amount unders and overs account Nominal WACC (per cent) 5.00% 5.50% 6.00% Opening balance –52 –562b 1628 Interest on opening balance –3 –31 98 Under/over recovery of revenue for regulatory year –495 2162 –1676a Interest on under/over recovery for regulatory year –12 59 –50 Closing balance –562 1628 0c Notes: (a) Approved jurisdictional scheme amounts revenue under/over recovery for regulatory year t. (b) Opening balance is the previous year's closing balance. (c) AusNet Services is expected to achieve a closing balance as to zero as practicable in its jurisdictional scheme amount unders and overs account in each forecast year in its annual pricing proposals in the 2016–20 regulatory control period.
Note This attachment forms part of the AER's final decision on AusNet Services' distribution determination for 2016–20. It should be read with all other parts of the final decision. The 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 – f-factor scheme trial
Table 6.7 compares forecasts across the decision making process between the initial proposal and our final decision. Table . AusNet Services augex forecasts comparisons ($2015 million, excluding overheads) 2016 2017 2018 2019 2020 Initial augex forecast 82.5 64.7 60.8 53.0 52.8 313.8 AER preliminary decision 48.4 61.6 57.7 49.9 49.7 267.4 Revised proposal 70.1 81.1 61.6 57.0 59.1 328.8 AER forecast 63.9 76.0 61.6 55.5 52.3 309.3 Source: AER analysis. Our reasons for our decision on AusNet Services' revised augex proposal are set out in sections B.2.4 and B.2.5. AusNet Services' revised proposal AusNet Services' revised proposal is $328.8 million ($2015). As set out in Table 6.8, AusNet Services' revised augex forecast is comprised of capex to meet forecast maximum demand, capex related to the Victorian Bushfire Royal Commission (VBRC) recommendations, and other safety augex. Table . AusNet Services' proposed augex ($2015, million, excluding overheads) Category 2016 2017 2018 2019 2020 Total VBRC 28.6 27.9 28.1 28.3 28.5 141.4 Safety 31.4 30.3 15.1 13.6 13.3 103.8 Demand 10.0 22.8 18.4 15.1 17.2 83.6 Total augex proposal 70.1 81.1 61.6 57.0 59.1 328.8 Source: AusNet Services revised regulatory proposal AusNet Services' revised augex forecast is $15 million ($2015), or 4.8 per cent, higher than its initial proposal. In developing its revised forecast, AusNet Services': revised its demand-related capex upwards by 23 percent, to reflect revised maximum demand forecasts provided additional supporting information about its proposed safety programs.
Note This attachment forms part of the AER's final decision on AusNet Services' distribution determination for 2016–20. It should be read with all other parts of the final decision. The final 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 – f-factor scheme
Attachment 2 – Regulatory 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 – f-factor scheme Contents
Note This attachment forms part of the AER's final decision on CitiPower's distribution determination for 2016–20. It should be read with all other parts of the final decision. The final 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 – f-factor scheme
Note This attachment forms part of the AER's final decision on CitiPower's distribution determination for 2016–20. It should be read with all other parts of the final decision. The 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 – f-factor scheme
Note This attachment forms part of the AER's final decision on Directlink's revenue proposal 2015–20. It should be read with 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 and negotiated services Attachment 13 – pass through events
Note This attachment forms part of the AER's final decision on Directlink’s revenue proposal 2015–20. It should be read with 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
Preliminary enquiry service For services provided to connection applicants making a preliminary enquiry requiring site-specific or written response Alternative control Standard control Connection offer service (basic or standard) For services provided by distributors in assessing the applicant’s connection application and making a basic or standard connection offer Alternative control Standard control Carrying out planning studies and analysis relating to distribution (including sub-transmission and dual function assets) connection applications This service undertakes necessary planning studies and associated technical analysis to help determine suitable/feasible connection options for further consideration by proponents. Alternative control Standard control Customer interface coordination for contestable works This service is proposed customer connections or asset relocations may require a high level of distributor involvement in order to coordinate a range of inputs from the distributor to help establish the connection. Alternative control Standard control AER Service group—Connection services Premises connection assets Includes any additions or upgrades to the connection assets located on the customer's premises which are contestable (Note: excludes all metering services). Premises connection assets can be further described as: A. Design and construction of premises connection assets (where these services are provided contestably) A. Unclassified B. Standard control A. Unregulated B. Standard control
Table 191 Revenue and cost inputs for the four scenarios Scenario 1 Scenario 2 Scenario 3 Scenario 4 Revenue Smoothed revenue from the decision Smoothed revenue from the indicative final decisiona including debt convergence. Smoothed revenue from the indicative final decision a including debt convergence Smoothed revenue from the indicative final a decision including debt convergence Costs All costs from revised proposal except for hybrid tax calculation. All costs from revised proposal except for: hybrid tax calculation debt convergence Based on revised proposal except for: hybrid tax calculation debt convergence 10 % per reductions between forecast opex costs and benchmark efficient opex allowance Based on revised proposal except for: hybrid tax calculation debt convergence 20 % per annum reductions between forecast opex costs and benchmark efficient opex allowance Comment case scenario. Importantly, this scenario excludes the effects of debt convergence. Excluding debt convergence artificially worsens the outcomes. More favourable to Endeavour Energy than Scenario 1. This scenario is more closely reflective of the final decision circumstances than scenario 1. More favourable to Endeavour Energy than Scenario 2. This scenario reflects partial efficiency savings by Endeavour Energy to reduce the difference between its proposed opex costs and our final decision opex determination. More favourable to Endeavour Energy than Scenario 3. This scenario reflects faster opex efficiency savings than scenario 2. In combination, scenarios 3 and 4 illustrate the sensitivity of the outcome to the ability to make efficiency savings. (a) At the time this analysis was provided to RSM Bird Cameron, decision inputs were not completely finalised. However, they are closely reflective of the final decision inputs.
Note This attachment part of the AER's final decision on Energex's 2015–20 distribution determination. It should be read with all other parts of the final decision. The decision includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 2 – Regulatory 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 mechanism Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy
AER Service lighting services Provision, construction and maintenance of public lighting Application assessment, design, review and audit public lighting services. Provision, construction and maintenance of new street lighting services. Alteration, repair, relocation, rearrangement or removal of existing street light assets and energy efficient retrofit. Provision of glare shields, vandal guards, luminaire replacement with aero screens. A fee for the residual asset value of non-contributed public lights when removed from service before the end of their useful life at the request of the customer. Operating street lighting assets including handling enquiries and complaints and dispatching to repair assets. Alternative control Alternative control Emerging public lighting technology New public lighting technologies, including trials. Energy efficient retrofit (including where customer requests to retrofit existing assets before end of life). Alternative control Unclassified Unclassified distribution services
© 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 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
Note This attachment forms part of the AER's final decision on Energex's 2015–20 distribution determination. It should be read with all other parts of the final decision. The final 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 mechanism Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy
Note This attachment forms part of the AER's final decision on Energex's 2015–20 distribution determination. It should be read with all other parts of the final decision. The final 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 mechanism Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy
Note This attachment forms part of the AER's final decision on Energex's 2015–20 distribution determination. It should be read with other parts of the final decision. The final 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 mechanism Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy
Note This overview forms part of the AER's final decision on Energex's 2015–20 distribution determination. It should be read with all other parts of the final decision. The final decision includes the following documents: Overview Attachment 1 – Annual revenue requirement 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 – Demand management incentive scheme Attachment 13 – Classification of services Attachment 14 – Control mechanism Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy
Note This attachment forms part of the AER's final decision on Ergon Energy's 2015–20 distribution determination. It should be read with all other parts of the final decision. The final 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 mechanism Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy
Emergency recoverable works Work to repair damage to the distribution network caused by an identifiable third party from whom costs may be recovered. Unclassified Alternative control Type 1 to 4 metering Contestable metering services. Unclassified Unclassified Watchman Unmetered light mounted on customer’s property or distribution pole for security purposes. Unclassified Unclassified Distribution services provided in unregulated isolated networks Ownership and operation of isolated supply networks, than the Mt Isa-Cloncurry supply network (Ergon Energy). Unclassified Unclassified High load escorts Request by customer to an appropriate route and lift wires to allow passage of high vehicles. Unclassified Alternative control / Unclassified Hayman Island undersea cable Unclassified Unclassified Non-distribution services that are unregulated Rental and hire services Rental of distributor owned property (e.g. plant hire and asset leasing). Unregulated Unregulated Test, inspect and calibrate Calibration and testing of equipment for external products. Unregulated Unregulated Property services Customers request the distributors undertake conveyancing property searches, conduct easement negotiations or purchase negotiations. Unregulated Unregulated
Note This attachment forms part of the AER's final decision on Ergon Energy's 2015–20 distribution determination. It should be read with all other parts of the final decision. The final 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 mechanism Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection policy
Note This attachment forms part of the AER's final decision on Jemena's distribution determination for 2016–20. It should be read with all other parts of the final decision. The final decision includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 2 – Regulatory 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 – 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 – f-factor scheme
Note This attachment forms part of the AER's final decision on Jemena's distribution determination for 2016–20. It should be read with all other parts of the final decision. The final 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 – f-factor scheme
Note This attachment forms part of the AER's final decision on Jemena Gas Networks' 2015–20 access arrangement. It should be read with other parts of the final decision. The final 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
Note This attachment forms part of the AER's final decision on Jemena Gas Networks' 2015–20 access arrangement. It should be read with other parts of the final decision. The final 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 – 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
(NEO). Our rate of return and Powercor's proposed rate of return are set out in the following Table 6. 6 Final decision on Powercor's rate of return (% nominal) AER previous decision Powercor revised proposal (2016) AER final decision (2016) Allowed return over 2016–20 regulatory period Return on equity (nominal 10.28 9.89% 7.0 Constant (7.0%) Return on debt (nominal pre–tax) 8.97 7.76 5.51 Updated annually Gearing 60 60 60 Constant (60%) Nominal vanilla WACC 9.49 8.61 6.11 Updated annually for return on debt Expected inflation 2.57 2.50 2.32 Constant (2.32%) Source: AER analysis; Powercor, Revised regulatory proposal 2016 to 2020, 6 January 2016; AER, Powercor Australia Ltd distribution determination 2011–2015: Pursuant to Orders of the Australian Competition Tribunal in Application by United Energy Distribution Pty Limited (No 2) [2012] ACompT 8, October 2012, p. 28. Our return on equity estimate is 7.0 per cent. Consistent with the Guideline, the return on equity remains constant over the regulatory control period. Our return on equity point estimate and the parameter inputs are set out in Table 7. Powercor proposed departing from the approach in the Guideline. We are not satisfied that doing so would result in an outcome that better achieves the allowed rate of return objective. We do not agree with Powercor that our method applied in the preliminary decision will result in a return on equity which is inconsistent with the allowed rate of return objective. Our return on equity preliminary decision and this final decision is largely consistent with the views in the Guideline. Table 7 Final decision on Powercor's return on equity (nominal) AER previous decision (2011–15) Powercor revised proposal (2016–20) AER decision (2016–20) Nominal risk free rate (return on equity only) 5.08% 2.75%* 2.48%** Equity risk premium 5.20% 7.17% 4.55% MRP 6.50% 7.88% 6.50% Equity beta 0.8 0.91 0.7
Note This Attachment forms part of the AER's final decision on TransGrid’s revenue proposal 2015–18. It should be read with 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 – 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 final decision on TransGrid’s revenue proposal 2015–18. It should be read with 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
We are unaware of any RIT–T project being submitted by TransGrid. Any other factor the AER considers relevant and which the AER has notified the service provider in writing, prior to the submission of its revised Revenue Proposal under 6A.12.3, is an operating expenditure factor. We have used our benchmarking data sets including, but not necessarily limited to data contained in any economic benchmarking RIN, category analysis RIN, reset RIN or annual reporting RIN. Source: AER analysis. * The opex factors are set out in NER cl. 6A.6.6(e). The NER require that we notify the service provider in writing of any factor we identify as relevant to our assessment, prior to the service provider submitting its revised revenue proposal. We identified the factors in table 7.5 our draft decision. Table 7.5 Other factor we have had regard to Opex factor Consideration Our benchmarking data sets, including, but not necessarily limited to: data contained in any economic benchmarking RIN, category analysis RIN, RIN or annual reporting RIN data sets that support other assessment techniques consistent with the approach set out in our Guideline as updated from time to time. This information may potentially fall within opex factor (4). However, for absolute clarity, we are using data we gather from NEM service providers to provide insight into the benchmark operating expenditure that would be incurred by an efficient and prudent transmission network service provider over the relevant regulatory period.
Note This attachment forms part of the AER's final decision on TransGrid’s revenue proposal 2015–18. It should be read with 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
Where a distributor processes changes in its IT systems to reflect a tariff change request. Services provided in relation to a Retailer of Last Resort (ROLR) event The distributors may be required to perform a number of services as a distributor when a ROLR event occurs. For example: Preparing of affected sites and reconciling data with AEMO listings, arranging estimate reads for the date of the ROLR event, preparing final invoices and miscellaneous charges for affected customers, extracting customer data, providing it to the ROLR and handling subsequent enquiries. Alternative control Alternative control (specific monopoly service) Planned Interruption – Customer requested Where the customer requests to move a planned interruption and agrees to fund the additional cost of performing this distribution service outside of normal business hours. N/A Alternative control (specific monopoly service) Attendance at customers' premises to perform a statutory right where access is prevented. A follow up attendance at a customer's premises to perform a statutory right where access was prevented or declined by the customer on the initial visit. This includes the costs of arranging, and the provision of, a security escort or police escort (where the cost is passed through to the distributor). Alternative control Alternative control (specific monopoly service) Provision of training to third parties for network related access Training services provided to third parties that result in a set of learning outcomes that are required to obtain a distribution network access authorisation specific to a distributor’s network. Such learning outcomes may include those necessary to demonstrate competency in the distributor’s electrical safety rules, to hold an access authority on the distributor’s network and to carry out switching on the distributor’s network. Examples of training might include high voltage training, protection training or working near power lines training. N/A Alternative control
About the framework and approach The Australian Energy Regulator (AER) is the economic regulator for transmission and distribution services in Australia's national electricity market (NEM). We are an independent statutory authority, funded by the Australian Government. Our powers and functions are set out in the National Electricity Law (NEL) and National Electricity Rules (the rules or NER). The framework and approach (F&A) is the first step in a process to determine efficient prices for electricity distribution services. This paper sets out our proposed approach on which services we will regulate and how we propose to apply the relevant incentive schemes. It also assists network service providers to prepare regulatory proposals. TasNetworks Distribution (formerly Aurora Energy) is a licensed regulated operator of the Tasmanian monopoly electricity distribution network. The network comprises the poles, wires and transformers used for transporting electricity across urban and rural population centres to homes and businesses. TasNetworks Distribution (TasNetworks) designs, constructs, operates and maintains the distribution network for Tasmanian electricity consumers. We regulate a variety of services provided by TasNetworks. Where there is considerable scope to take advantage of market power, our regulation is more prescriptive. Less prescriptive regulation is required where the prospect of competition exists. In some situations we may remove regulation altogether. In 2015 we decided to replace the current Tasmanian F&A for the next regulatory control period. This decision arose following consultation with stakeholders. Our main reason for this decision was because of significant changes to the rules to introduce new incentive schemes and revised regulatory requirements, making elements of the current F&A no longer relevant. TasNetworks sought a new or amended F&A. Submissions received also supported the amendment or replacement of the current F&A. Copies of all submissions are available at http://www.aer.gov.au/node/30748. The current five year Tasmanian distribution regulatory control period concludes on 30 June 2017. This paper relates to the two year regulatory control period commencing 1 July 2017 and sets out our proposed approach on: distribution service classification services are to be regulated) control mechanisms (how will prices be determined) and the formulae that give effect to the control mechanisms service target performance incentive scheme efficiency benefit sharing scheme capital expenditure sharing scheme demand management incentive scheme application of the expenditure forecast assessment guidelines whether depreciation will be based on forecast or actual capital expenditure jurisdictional and legacy issues.
The businesses submit that the current network is ageing. Our general expectation is that repex levels should remain relatively constant over time. This is because the application of financial and asset management techniques can even out fluctuations in replacement rates of aging assets. We consider an important factor in controlling asset maintenance costs is the use of condition based assessment techniques when managing deteriorating assets. We note that a particular driver of replacement expenditure in Victoria is initiatives being undertaken to implement the findings of the Victorian Bushfire Royal Commission, which examined the safety of electricity networks following the bushfires in 2009. The Royal Commission made a number of recommendations that affect the design and construction of the Victorian electricity distribution networks, particularly in areas of high bushfire risk. As a consequence, there have been a number of network design changes mandated by the Victorian Government which are unique to Victoria and which directly affect replacement expenditure costs. Steps are also underway for Victoria to complete the implementation of further recommendations, which would also impact future network design and replacement costs. Do stakeholders consider the cost of improving the fire safety of the Victorian electricity distribution network is reasonable, given it is expected to be a significant factor in the increase in replacement expenditure? Table 4.2 summarises the total replacement expenditure (repex) forecast proposed by each of the distributors for the 2016–20 period. Table .2 Victorian distributor replacement capital expenditure proposals Distributor 2016–20 repex ($million, 2015) Proportion of total capex (per cent) Change from actual repex in 2011–15 period AusNet Services 901 46 214 CitiPower 260 26 107 Jemena 224 27 61 Powercor 722 33 279 United Energy 585 49 179 Source: Distributor regulatory proposals and RINs. Responding to growth The distributors have to augment the shared network to ensure that there is sufficient capacity to meet forecast future demand from new and existing customers. As shown in section 3, maximum demand has been relatively flat over the 2011–15 regulatory period, and is not expected to grow significantly across Victoria over the 2016-20
Incentive schemes The AER determines that the efficiency benefit sharing scheme (EBSS) that will apply to Ausgrid for the transitional regulatory control period is that applied to Ausgrid in the current regulatory control period, with modifications to align it with version 2 of the EBSS and applied as if the transitional regulatory control period was the first year of the subsequent regulatory control period. This is consistent with the Stage 2 framework and approach paper. The AER determines that no: capital expenditure sharing scheme (CESS), or scale investment scheme, is to apply to Ausgrid in the transitional regulatory control period. The AER determines that Part A of the demand management innovation allowance (DMIA), which applied to Ausgrid in the current regulatory control period, applies to Ausgrid in the transitional regulatory control period. However, Part B of the DMIA and the D-Factor scheme for NSW distributors do not apply in the transitional regulatory control period. The DMIA is a component of the demand management incentive scheme (DMIS). The rules have since changed the name from DMIS to demand management and embedded generation connection incentive scheme (DMEGCIS). The revenue rewards and penalties of the service target performance incentive scheme (STPIS) did not apply to Ausgrid in the current regulatory control period and the AER determines that they will not apply in the transitional regulatory control period. However, the reporting obligations did apply in the current regulatory control period and the AER determines that they continue to apply. Appropriate amounts, values or inputs The AER determines that all appropriate amounts, values and inputs are as set out in this determination. Control mechanisms Standard control services The relevant control mechanism and formulae for standard control services is as set out in the Stage 1 framework and approach paper. The AER determines to apply a revenue cap with a basis of CPI-X form to standard control services for the transitional regulatory control period. Alternative control services The AER determines to price cap regulation to alternative control services in the transitional regulatory control period. Alternative control service prices in the transitional regulatory control period must be the current prices escalated by CPI. The AER determines to the following formulae to alternative control services, which remain classified as alternative control services. The AER considers that the formula gives effect to the cap on the prices of individual services: i=1,...,n and t=1,2,3,4
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. This final decision consists of an Overview and 11 attachments. As many issues were settled at the draft decision stage or required only minor updates we have not prepared final decision attachments for: Regulatory depreciation Operating expenditure; and Corporate income tax. The AER's final decision on these matters is set out in the Overview. For ease of reference the remaining attachments have been numbered consistently with the attachment numbering in our draft 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 6 – Capital expenditure 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