zilongwang/ReadingBank huggingface dataset:
Note This attachment 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 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
The need to re-evaluate gamma "Further, the Tribunal notes that estimation of a parameter such as gamma is necessarily, and desirably, an ongoing intellectual and empirical endeavour. Its decision in these proceedings is based on the material before it.” Consistent with this comment, we have not sought to apply the Tribunal's previous considerations in this final decision. Instead, we adopt a value of imputation credits that is based on our assessment of the merits of the evidence before us, which includes a large amount of material that was not before the Tribunal in these proceedings. Also see our response above in section A.3.2 under 'The need to gamma '. Source: As specified in table.
Note This overview 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 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 this 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 – 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
AusNet Services proposal Table B2 shows AusNet Services' proposed cumulative change in opex for each rate of change component reported in its reset RIN. AusNet Services' rate of change methodology is different to ours because it adopted a different approach to forecasting price growth. AusNet Services proposed opex by rate of change drivers ($'000, 2015) 2016 2017 2018 2019 2020 Price growth 3612.3 6671.7 9732.7 12918.6 16279.9 Output growth 2674.8 5314.7 7928.7 12997.8 Productivity growth – – – – – Source: AusNet Services RIN table 2.16.1. We discuss how AusNet Services forecast each of the rate of change components below. Forecast price growth AusNet Services proposed price growth for the following categories: internal labour costs external labour costs non-labour costs. Table B3 outlines the consultants AusNet Services engaged for each price growth category and the methodology proposed by each consultant. Table B4 shows AusNet Services' annual percentage change for each of its proposed price growth categories. Table AusNet Services forecast price growth consultants and proposed methodology Price growth Consultant Method Internal labour Centre for International Economics AusNet Services' existing EAs up until the expiry of those EAs. Following the expiry of the EAs, AusNet Services used the forecast change in the WPI for the EGWWS sector as forecast by CIE. External labour Centre for International Economics Forecast change in the WPI for the construction sector as forecast by CIE. Non-labour Not applicable AusNet Services assumed non-labour prices will grow with the CPI. Source: AusNet Services, Regulatory proposal, p. 187.
We accept CitiPower's proposed $9.419 million ($2015) forecast and have included this amount in their replacement capital expenditure. In coming to this view, we have assessed the CitiPower bushfire safety proposals. Based on our assessment, we find that the proposed capex for the bushfire safety programs reasonably reflect the capex objectives and therefore we have included the proposed capex in our estimate of CitiPower's capex requirements. Our assessment of this program is contained in the section below. This proposed amount for the program is incremental to CitiPower's business as usual capex related to bushfire risk management. Table 6.20 sets out the proposed components of the program. Table . CitiPower's proposed capex for a fire mitigation program ($2015, million, excluding overheads & escalation) Strategy Proposed LBRA Armour Rods & Dampers Retrofit 7.674 LBRA Multi-circuit survey cost 0.635 LBRA Multi-circuit Repairs (Fitting of Spacers) 0.379 LBRA Multi-circuit Rebuilds 0.732 9.419 Source: CitiPower, PUBLIC MOD 1.17 - CP Capex consolidation, 'Base Capex Forecast', FC 167 – VBRC, April 2015. AER assessment approach For bushfire safety related capex there are three potential bases for consideration of a funding requirement. These are: Business As Usual (BAU): Capex which we assess along with other capex in attachment 6. We use the tools outlined in attachment 6 to assess the efficiency of the forecast. These capex projects relate to maintaining the quality, reliability or security of supply of standard control services or the reliability or security of the distribution system through the supply of standard control services or the safety of the distribution system through the supply of standard control services. Approved projects are set out in the companies’ Electrical Safety Management Scheme (ESMS) or Bushfire Mitigation Plan (BMP). We rely on Energy Safe Victoria to establish need. We then assess the efficiency of the forecast cost. projects are assessed in accordance with the capital expenditure objectives to determine if they are necessary to comply with applicable regulatory obligations or requirements associated with the provision of standard control services. Pending regulations from the Victorian Government which will implement aspects of recommendation 27 of the Victorian Bushfires Royal Commission (VBRC). The
Note This document forms part of the AER's preliminary decision on CitiPower's revenue proposal, 2016–20. It should be read with all other parts of the preliminary decision. The preliminary 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 – f-factor scheme
Note This attachment forms part of the AER's preliminary decision on Energex's 2015–20 distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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
RFM roll forward model RIN regulatory information notice RPP revenue 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
© Commonwealth of Australia 2015 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 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 preliminary decision on Energex's 2015–20 distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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 preliminary decision on Ergon Energy's distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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 preliminary decision on Ergon Energy's distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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
© 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 preliminary decision on Ergon Energy's distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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
Note This attachment forms part of the AER's preliminary decision on Ergon Energy's 2015–20 distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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 preliminary decision on Ergon Energy's distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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 20
Note This overview forms part of the AER's preliminary decision on Ergon Energy's 2015–20 distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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
We were not satisfied Ergon Energy had demonstrated it faced increased regulatory obligations or requirements in the forecast period. The proposals were for costs which we would typically consider to be business as usual expenses, and therefore taken into account in our estimate of base opex. Corporate income tax The NER requires us to make a decision on the estimated cost of corporate income tax for Energy's 2015–20 regulatory control period. The estimated cost of corporate income tax contributes to our determination of the total revenue requirements for Ergon Energy over the 2015–20 regulatory control period. It enables Ergon Energy to recover the costs associated with the estimated corporate income tax payable during that period. We forecast Ergon Energy's corporate income tax allowance at $204.2 million ($ nominal) over the 2015–20 regulatory control period as set out in table 10. This is instead of Ergon Energy's proposed cost of corporate income tax allowance of $621.4 million. Our preliminary decision is 38.5 per cent of the amount Ergon Energy proposed. Table 10 AER's preliminary decision on Ergon Energy's cost of corporate income tax allowance for the 2015–20 regulatory control period ($ million, nominal) 2015–16 2016–17 2017–18 2018–19 2019–20 Total Tax payable 60.5 64.6 68.6 74.6 71.9 340.3 Less: value of imputation credits 24.2 25.8 27.5 29.9 28.8 136.1 Corporate income tax allowance 36.3 38.8 41.2 44.8 43.1 204.2 Source: AER analysis. Our preliminary decision reflects our amendments to some of Ergon Energy's proposed inputs for forecasting the cost of corporate income tax such as the opening tax asset base, and the remaining tax asset lives. It also reflects our preliminary decision on the value of imputation credits (gamma) discussed in attachment 4. Our preliminary decision changes to other building block costs that affect revenues also impact the tax calculation. Details of our preliminary decision on the corporate income tax allowance are set out in attachment 8.
Note This attachment forms part of the AER's preliminary decision on Jemena Electricity's 2016–20 distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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 – F Factor Scheme
before or after 2000, when the change in tax law entitled eligible investors to a full refund of excess imputation credits. Table 411 is the equivalent table for alternative implied market value studies. In this table, several results are recorded as 'N/A', even though there is a specific date range provided. In such cases, that particular technique (or data limitations) did not permit the disaggregation of the value of the dividend component and 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 410 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 Brown and Clarke (1993) 0.80 (1988–1991) Source: As specified in table.
(incl. Insulators) Bare Conductors (Al) 1.023 1.023 1.020 0.999 1.003 Insulated Conductors - LV 1.022 1.028 1.021 0.982 0.991 Bare conductors (steel) 1.014 1.014 1.016 1.008 1.013 Underground Cables and Cablehead - HV, XLPE 1.012 1.018 1.014 1.003 1.008 Underground Cables and Cablehead - LV, XLPE 1.013 1.016 1.015 1.011 1.013 Supervisory Cable - Fibre Optic 1.014 1.016 1.015 1.016 1.019 Capacitor Banks 1.014 1.016 1.016 1.006 1.011 Transformers - Zone Substation 1.016 1.018 1.015 0.993 1.003 Power Transformers - Distribution 1.016 1.018 1.015 0.990 1.000 Circuit Breakers - Indoor 1.007 1.007 1.007 1.010 1.010 Circuit Breakers - Outdoor 1.007 1.007 1.008 1.012 1.011 Outdoor Buses 1.003 1.005 1.008 1.011 1.012 CT's and VT's - Zone Substation 1.008 1.008 1.008 1.012 1.012 Neutral Earthing Resistor 1.012 1.014 1.017 1.015 1.014 Earth Grid Conductors 1.016 1.023 1.016 0.998 1.005 Zone Substation 1.007 1.008 1.008 0.999 1.005
Note This document forms part of the AER's preliminary decision on Jemena's revenue proposal, 2016–20. It should be read with all other parts of the preliminary decision. The preliminary 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 – f-factor scheme
: 24 Test 5 Aeneid XII 723-741 a) ‘non aliter’ ; in the simile that precedes this passage, (i) to what have Tros Aeneas and Daunius heros been compared? 1 (ii) what caused the noise that corresponded to fragor here? 1 b) ‘Iuppiter…deorum’; explain exactly what Jupiter does in these 2 lines. 4 c) ‘quem…letum’ translate this line. 3 d) In the original Homeric version of this image, who are the 2 heroes involved and which of them is the loser? 2+1 e) ‘impune putans’ ; what does this phrase mean and to whom does it refer? 2 f) ‘alte sublatum…ferit’ ; (i) How does the rhythm of these 2 clauses reinforce the sense? 3 (ii) translate from ‘corpore toto….ferit’. 3 g) ‘at perfidus ensis……..fragmina harena’ (i) Explain everything that is done by/happens to the sword in these lines. (Restrict your answer to just the information required by the question.) 6 (ii) What was it, according to this passage, that caused the sword to be ‘perfidus’? 4 30 Test 7 Aeneid XII 766-790
Note This attachment forms part of the AER's preliminary decision on SA Power Networks' 2015–20 distribution determination. It should be read with all other parts of the preliminary decision. The preliminary 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
Annual charge (Provision Reading and Data Type 5-6 WC Manually Read Meter) 33 37 41 45 49 Source: SA Power Networks, Regulatory Proposal 2015-20, Table 29.9, p. 356. SA Power Networks has proposed a significant new tariff and metering program which they suggest will meet the challenges of transitioning from: a one-way energy distribution system to an active two-way grid that connects a dynamic web of distributed consumption and generation resources, by: transitioning to more cost-reflective network tariffs. The new tariff is based on maximum demand and will be introduced on an opt-in basis from July 2015. From July 2017, SA Power Networks proposes to make this tariff mandatory for all new connections and customers choosing to upgrade their supply arrangements (for example, moving to solar PV) installing smart ready interval meters as the standard meter for new and replacement installations upgrading some smart ready interval meters to have a telecommunications module to monitor power quality in the low voltage network. The three cost components related to the above tariff and metering program that feed into alternative control metering service charges are: Installing smart ready interval meters as the default meter for new and replacement meter situations (forecast capital expenditure—$11.0 million) IT costs for handheld meter reading devices (forecast capital expenditure—$2.5 million) Monthly reads (operating expenditure step change—$25.5 million). Other costs related to the tariff and metering program include upgrading smart ready meters to be remotely read to enable power quality and other operational benefits. It also includes new IT systems. These IT capital costs are discussed in Attachment 6 (capex). Upfront capital charges SA Networks proposed ad hoc installation charges for a customer initiated meter alteration or addition. These would be upfront charges to recover all the costs incurred in providing a meter upgrade (instead of adding to the metering asset base and recovering annually). Table . - SA Power Networks proposal - Ad hoc installation charges for customer upgrades ($, nominal) 2015-16 2016-17 2017-18 2018-19 2019-20
Benchmarked calibrated replacement lives We developed benchmark calibrated lives by first using the repex model to calculate calibrated lives based on the replacement data from all NEM distributors. For model inputs we again used the average, third quartile (above average), and longest of the calibrated lives of all NEM distributors for each category. We discuss how we prepared this data in appendix E. When applied to the repex model, compared to using calibrated replacement lives based on United Energy’s data the: average benchmark and third quartile calibrated replacement lives produced higher outcomes longest benchmark calibrated replacement lives produced lower outcomes. When applied to the repex model, compared to United Energy’s proposed forecast repex for the modelled categories the: benchmark average calibrated lives produced a higher outcome benchmark third quartile and longest calibrated lives produced lower outcomes. The calibrated benchmark replacement may reflect to some extent the particular circumstances of a distributor and this may not be applicable to the business under review. These inputs provide us with a check that United Energy's calibrated replacement lives were reasonable against its peer service providers in the NEM. Further, these outcomes support our view that United Energy's forecast for the modelled categories is likely to be a reasonable estimate of business as usual repex. Benchmarked unit costs We developed industry benchmark unit costs using the data collected from all NEM distributors in the category analysis RINs. For model inputs we used the average, first quartile (below average), and lowest unit costs of all NEM distributors for each asset category. We discuss how we prepared this data in appendix E. When applied to the repex model, compared to using United Energy’s unit costs the: average benchmark unit costs produced a similar but slightly higher outcome first quartile and lowest benchmark unit costs produced lower outcomes. We consider the benchmark unit costs provide a useful comparison with the cost of other distributors in the NEM. United Energy’s predictive modelling United Energy submitted a report by Nuttall Consulting which we respond to in the remainder of this section. We reviewed the submissions of United Energy and Nuttall Consulting and continue to consider that our predictive modelling is a useful and important technique when assessing United Energy’s forecast of repex against the capex criteria. Our predictive modelling approach is well established having been used
Other issues raised in submissions Investor reference group (IRG) Both the ENA and Infrastructure submitted that we should consider forming an investor reference group to participate in the review process. We agree with this recommendation and will seek to form an IRG. As part of its submission, Spark Infrastructure identified a series of institutional investors that are interested to participate in this group. Using this as a starting point, we will go out and seek interest from investors more widely to constitute the group. In particular, we see this as a useful opportunity to understand the priorities of institutional investors, and the characteristics of an estimation process that are important from the perspective of capital providers. Like the CRG, we propose that a monthly discussion between AER and the IRG would be useful in addition to participation at the major forums and workshops during the review process. We will publish a notice calling for interested parties on our website and will also seek interested parties directly. If you are an investor and you are willing to participate in our investor reference group, please email: . Retailer reference (RRG) Similarly, we have had several retailers express interest in the rate of return guideline review process. In our view, retailers are a distinct group of stakeholders in the process and could potentially provide valuable insight about estimation of the rate of return and on the process of implementing that rate of return in determinations and in annual pricing updates. We also plan to approach retailers with the intention of setting up such a group. Like the CRG, we propose that a monthly discussion between AER and the RRG would be useful in addition to participation at the major forums and workshops during the review process. We will publish a notice calling for interested parties on our website and will also seek interested parties directly. If you are an energy retailer and you are willing to participate in a retailer reference please email: Sharing data Some stakeholders have recommended that all parties to the review seek where possible to agree on shared data series and to make those data series publicly available. We are open to this idea and will engage more with stakeholders in considering how it might be implemented. In some we will be unable to publish the data series because of its proprietary nature. An example of this is the Bloomberg, Standard and Poor’s and Thomson
Unplanned outage circuit event rate: 0.75 Lines event rate – fault 0.20 Transformer rate – fault 0.20 Reactive event rate – fault 0.10 Lines event rate – forced 0.10 Transformer event rate – forced 0.10 Reactive plant event rate – forced 0.05 Loss of supply event frequency: 0.30 > (x) system minutes 0.15 > (y) system minutes 0.15 Average outage duration 0.20 Proper operation of equipment 0.00 32: Parameter weighting, Murraylink and Directlink Parameter Weighting (MAR %) Unplanned outage circuit event rate: 1.25 Circuit event rate – fault 0.75 Circuit event rate – forced 0.50 Proper operation of equipment 0.00
unplanned outages from all causes including emergency events and extreme events forced outages on the prescribed network where notification to affected customers and/or AEMO was less than 24 hours (except where AEMO reschedules the outage after notification has been provided). Exclusions outages on assets that are not providing prescribed transmission service any unplanned outages shown to be primarily caused or initiated by a fault or other event on a third party system — e.g. intertrip signal, generator outage, customer installation any unplanned outages caused by a direction from emergency services or AEMO planned outages transient interruptions (less than one minute duration) interruptions of infrequent, occasional (such as pumping stations) where accurate estimate of load profiles is unreliable majeure events NOTE: the TNSP must provide a list to the AER each year of the events that the TNSP considers should be excluded from performance results, including reasons and how the event meets the relevant exclusion definition. The AER may reject the TNSP’s exclusion claims where it considers the TNSP has provided insufficient justification. Parameter 3 Average outage duration Sub-parameter average outage duration Unit of measure minutes Source of data TNSP outage reports and system Definition/formula formula: Aggregate duration (in minutes) of all unplanned outages with a loss of supply No. of events
Note This attachment part of the AER's final decision on TasNetworks' distribution determination for 2017–19. It should be read with all other parts of the final decision. This final decision consists of an Overview and 8 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 asset base Regulatory depreciation Capital expenditure Operating expenditure Corporate income tax Capital expenditure sharing scheme Service target performance incentive scheme Demand management incentive scheme Classification of services Pass through events Connection policy. 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 decision therefore includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 3 – Rate of return Attachment 4 – of imputation credits Attachment 9 – Efficiency benefit sharing scheme Attachment 14 – Control mechanisms Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 19 – Tariff structure statement
Annual changec –159 (–8.3%) 22 (1.3%) Small business annual bill 3229b 2962 2999 Annual changec –268 (–8.3%) 37 (1.3%) Source: AER analysis; AEMC, Final report: 2016 Residential Electricity Price Trends, 14 December 2016, p. 160; AER, ; OTTER, Information paper: Typical electricity customers, May 2014. (a) Annual bill for 2016–17 is sourced from AEMC's 2016 residential electricity price trends report and reflects an annual consumption of 8550kWh for a residential customer in Tasmania. (c) Annual bill for 2016–17 is sourced from the AER's Energy Made Easy website and reflects an average annual consumption of 10252kWh for small business customers using tariff 22 in Tasmania. (b) Annual change amounts and percentages are indicative. They are derived by varying the distribution component of 2016–17 bill amounts in proportion to yearly expected revenue divided by forecast energy as proposed by TasNetworks. Actual bill impacts will vary depending on electricity consumption and tariff class.
Note This overview forms part of the AER's final decision on TasNetworks' distribution determination for 2017–19. 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 – Connection policy Attachment 19 – Tariff structure statement
Small Business – Low Voltage Time of Use (TAS94) $13,531 $10,254 –$3,277 24.2% lower Large Business – Low Voltage (TAS82) $28,594 $22,305 –$6,289 22.0% lower Large Business – High Voltage (TASSDM) $97,240 $79,238 –$18,002 18.5% lower Irrigation TAS75) $7,315 $5,694 –$1,621 22.1% lower PAYG (TAS101) $706 $651 –$55 7.7% lower Source: TasNetworks, Tariff structure statement: Background and explanation, December 2016, p. 67. Figure . TasNetworks' customer impacts for residential and small business customers moving to the time of use demand network tariffs Source: TasNetworks, Tariff structure statement: Background and explanation, December 2016, p. 67.
Publication of AER placeholder determination By 30 April 2014 Source: AER analysis. Protected information submitted to the AER We are committed to treating protected information received from DNSPs and other stakeholders in accordance with the NEL. The NEL allows us to disclose protected information in certain circumstances. This decision contains no sensitive information. Structure of this document The remaining parts of this placeholder determination are set out as follows: Section 3: AER’s approach Section 4: Indicative annual revenue requirement Section 5: Other constituent decisions
Negotiated transmission service criteria National Electricity Objective The and conditions of access for a negotiated transmission service, including the price that is to be charged for the provision of that service and any access charges, should promote the achievement of the national electricity objective. Criteria for terms and conditions of access Terms and conditions of access The terms and conditions of access for a negotiated transmission service must be fair, reasonable, and consistent with the safe and reliable operation of the power system in accordance with the NER. The terms and conditions of access for negotiated transmission services, particularly any exclusions and limitations of liability and indemnities, must not be unreasonably onerous. Relevant considerations include the allocation of risk between the TNSP and the other party, the price for the negotiated transmission service and the cost to the TNSP of providing the negotiated service. The terms and conditions of access for a negotiated transmission service must take into account the need for the service to be provided in a manner that does not adversely affect the safe and reliable operation of the power system in accordance with the NER. Price of services The price of a negotiated transmission service must reflect the cost that the TNSP has incurred or incurs in providing that service, and must be determined in accordance with the principles and policies set out in the Cost Allocation Methodology. Subject to criteria 7 and 8, the price for a negotiated transmission service must be at least equal to the avoided cost of providing that service but no more than the cost of providing it on a stand alone basis. If the negotiated transmission service is a shared transmission service that: exceeds any network performance requirements which it is required to meet under any relevant electricity legislation; or exceeds the network performance requirements set out in schedule 5.1a and 5.1 of the NER then the difference between the price for that service and the price for the shared transmission service which meets network performance requirements must reflect the TNSP’s incremental cost of providing that service (as appropriate). For shared transmission services, the difference in price between a negotiated transmission service that does not meet or exceed network performance requirements and a service that meets those requirements should reflect the TNSP’s avoided costs. Schedule 5.1a and 5.1 of the NER or any relevant electricity legislation must be considered in determining whether any network service performance requirements have not been met or exceeded.
Pay Unit Item No. Item Description Quantity Deficiency (see attached reference sheet): Comments: OK Critical Deficiency Non-Critical Deficiency Pay Unit Item No. Item Description Quantity Deficiency (see attached reference sheet): Comments: OK Critical Deficiency Non-Critical Deficiency Pay Unit Item No. Item Description Quantity Deficiency (see attached reference sheet): Comments: OK Critical Deficiency Non-Critical Deficiency Pay Unit Item No. Item Description Quantity Deficiency (see attached reference sheet): Comments: OK Critical Deficiency Non-Critical Deficiency
Contract Time Suspension / Resumption Notification Airport: IL Project No.: Contractor: AIP Project No.: Project Description: Temporary Suspension of Work Reason for Notification (See Standard Specifications 80-07, 80-08) Start Date Stop Date Substantial Completion: Date Start Punchlist Work: Date Finish Punchlist Work: Date Initial submittal of this form and updated submittals will be scanned and emailed to the appropriate IDA Construction Engineer. Recommended Approval: Resident Engineer Signature Printed Name Date
Bituminous Nuclear Density Testing Start Finish Airport: Date: Date: Mix Design No.: Consultant: Project: Contractor: A.I.P. Project: Producer: Number: Lot Quantity (tons): Random Test Sub Station Ref Thick Gmb Gmm % Density Average Results test Density Pass/Fail Density a #1 b (Average of c 5 “across Mat” d nuc. ) e Density a #2 b (Average of c 5 “across mat” d nuc. ) e Note: Requirement of two (2) Nuclear Density Tests (average of five readings across mat) per 500 ton of bituminous mix for projects under 2,500 tons. Test No.: 1a 1b 1c 1d 1e 2a 2b 2c 2d 2e Date Laid Station Reference Thickness Density Count Moisture Count Wet Density Moisture (pcf) (M) Moisture % (%M) Standard Maximum Density % Compaction Remarks: Inspector:
Contractor's Performance Evaluation Report for (year) Contractor No.: Contractor Name: Airport: IL Project No.: AIP Project No.: BCM Contract No.: Approx. Dollar Amt. - Completed (in 1,000’s) (Example: $20,000 = 20) Prime Sub Rate the Contractor’s performance using the numerical rating guidelines for each category. 8.0 = Excellent 7.0 = Good 6.0 = Satisfactory 4.0 = Marginal 2.0 = Poor Quality of Work Execution of Work Category (See list on next page) Rating Category Rating Organization/Prosecution Cooperation Traffic Control/Site Protection EEO/Labor Compliance Erosion Control QC/QA A rating of less than six (6.0) must be explained. Comments: Prepared by Consultant: Resident Engineer Resident Technician Date Reviewed by Div. of Aeronautics: Airport Construction Engineer Date Work Categories
Weekly Statement of Compliance and Certified Transcript of Payroll Contractor or Subcontractor & No. Airport Contract No. Payroll No. Address IL Project No. Federal Project No. For Week Ending No Work Suspended Completed (1) (2) (3) (4) St (5) (6) (7) (8) (9) (10) (11) Name and Individual or Hours and Days Worked Total Rate Amount Total Deductions Wages Identification Number OT Hours of Pay Earned Earned Federal WH Tax FICA State WH Tax Other Total Deduction Paid for Week S 0.00 0.00 0.00 O 0.00 0.00 0.00 0.00 S 0.00 0.00 0.00 0.00 O 0.00 0.00 0.00 0.00 S 0.00 0.00 0.00 0.00 O 0.00 0.00 0.00 0.00 S 0.00 0.00 0.00 0.00 O 0.00 0.00 0.00 0.00 S 0.00 0.00 0.00 0.00 O 0.00 0.00 0.00 0.00 S 0.00 0.00 0.00 0.00 O 0.00 0.00 0.00 0.00 The submitted payrolls shall be initialed and dated by the Resident Engineer, as an acknowledgment of the date and submission of the payrolls. Resident Engineer Date * See instruction page for codes to be entered NOTE: A certified copy of each weekly payroll must be submitted by the prime contractor within seven (7) days of the regular payment date.
Item # / BMP YES NO N/A 13. Concrete Washout Areas: Are concrete washout areas adequately signed and maintained? Has all washout occurred only at designated washout locations? 14. Staging/Storage Areas: Are all staging/storage facilities free of litter, leaking containers, leaking equipment, spills, etc? 15. Fuel/Chemical Storage: Are all fuels and chemicals stored only in designated locations? Are all designated locations free of evidence of leaks and or spills? 16. Previous Inspection Follow Up: Have all corrections from the last report been properly completed? If not, has a NPDES/ESC Deficiency Deduction been assessed? 17. Update SWPPP: Have all changes to the projects SWPPP been noted on the graphic site plan, signed and dated? 18. Off-site Dischare of Sediment: Has sediment or other pollutants of concern been released from the project site? If Yes, has the Illinois Environmental Protection Agency been notified within 24 hours of your observation of the discharge and an Incidence of Non-Compliance (ION) mailed within 5 days? Specific Instructions Related to “No” Answers From Above: Item # Station or Station to Station Practice Comments/Actions Required Time for Repair Other Comments: Additional Pages (Attached As Needed) Outfalls / Receiving Waters Other: Drainage Structure/Ditch Check Locations Additional Instructions to Contractor If the answer to any of Items 1-16 above is “No”, the contractor is hereby ordered to correct the deficiency. Repairs and stabilization are to be completed within 24 hours of this report (or as indicated above) or the DAILY NPDES/ESC Deficiency Deduction will be assessed for each noted deficiency until the required action is completed. Inspector’s Signature Date/Time: Contractor’s Signature Date/Time: Original: Project File cc: Contractor