4.3 (TNSP) MD – spatial – weather correction for connection points Transend stated historical weather corrected 10% and 50% PoE data for connection points are not available. It can derive this data for each connection point, but with a considerable amount of effort. Transend recommended the AER reconsider the need for this data (attachment). Powerlink stated it has around 100 individual customer load connection points. Powerlink considers it would be excessively onerous to require weather correction for demand at each connection point. This includes data going forward as well as historically (appendix, p. 3). ElectraNet stated it does not maintain historic temperature corrected data and is not aware of an applicable normalisation methodology (attachment). Consistent with the economic benchmarking RIN, the final RINs now require NSPs to provide historical weather corrected demand only where it has calculated such figures. 5.4 (DNSP) 4.3 (TNSP) MD – spatial – providing different MD measures SAPN stated SCADA on HV feeders and some zone substations is typically measured in Amps. It will need to make assumptions on the power factor to provide the information requested (p. 11). Transend stated it does not produce MVA forecasts for connection points but derive it based on assumptions about future power factors. It can provide MVA values at (each connection point) based on estimated power factors (attachment). ElectraNet stated it does not currently record transmission system non-coincident demand on an MVA basis, but can provide on an MW basis. The MVA reporting requirement will require changes to its reporting systems. ElectraNet can assume a power factor but no audit assurance would apply. Extensive analysis is expected to be required to provide this information at the connection point level (attachment). TNSPs/DNSPs are required to provide, using best endeavours, estimates of maximum demand information where they do not keep and maintain particular information requested in the final RIN templates, for example, by applying a power factor conversion as an approximation based on best engineering estimates.
For example, a DNSP must report maximum demand information for all of the zone substations in its network for a given regulatory year. If one of those zone substations is de-commissioned the following year, the DNSP no longer has to report maximum demand for that zone substation. Where load for that substation is transferred to other zone substations, it would result in new normal system conditions for the receiving zone substations. We have added the following instruction to clarify this position: TNSP/DNSP must insert rows into the tables for each component of its network belonging to that segment. TNSP/DNSP must note instances where it de-commissions components of its network belonging to that segment in the basis of preparation. 4.3 (TNSP) MD – spatial – other spatial levels Powerlink stated each emerging network limitation has its own unique spatial definition and it is not possible to provide this information in a way that would meet the requirements of the draft RIN (appendix, p. 3). As discussed previously, the final RINs for TNSPs now require TNSPs to provide spatial maximum demand information only for transmission connection points. We recognise each emerging network limitation has its own unique spatial definition because of network configuration. We consider such information is relevant when assessing particular sections of the network in more detail, such as when assessing forecast expenditure for specific areas of the network. We consider such assessments are more appropriate during a regulatory determination. 5.4 (DNSP) MD – spatial – no SAPN stated for substations which do not have SCADA, actual demand values are not NSPs are required to input estimates of maximum demand information
Appendix F p.51 purposes of this definition only operating sticks are not considered tools.(Submission p.5) earthing switches, low voltage links, links within LV pillar, underground link boxes etc. For clarification, this does not include circuit breakers. Circuit breaker: Automatic switches that provide system protection functions by opening a network connection and breaking fault current. This includes reclosers Template 2.2/5.2 for DNSPs Service lines In bilateral discussions, Ausgrid considered it would have difficulty identifying the end user of some of the service lines categories. Ausgrid noted that the load type in the zone is reportable but in certain instances distinguishing the customer type would be difficult. We acknowledge that NSPs will need to use estimation techniques and apply allocations, such as allocating customers from billing systems, to provide the data in accordance with the asset categories. Template 2.2/5.2 for DNSPs Public lighting UED queried why luminaires (i.e. globes) are included in the repex model as it seems more appropriate to expense these, noting that it does not have asset installation information for these assets In accordance with our guidelines the AER considers pubic lighting is an asset group for which the repex model can reliably forecast volumes. NSPs must report expenditure only relating to capex incurred for public lighting assets in template 2.2. Instances where an NSP expenses these assets as operating expenditure will be reflected by the difference in total public lighting replacement reported in template 4.1 and that contained in template 2.2. Template 4.1 captures all expenditure both capex and opex.
per cells as required by public lighting code and all other costs as non-routine maintenance. (Submission, p. 7) RIN. We will accept estimates of the number of new lights and poles associated with new customer requests and bulk replacement and installation programs. CP/PC should disclose its estimation method in the basis of preparation. 4.1 4.1.1 (General difficulties in estimating descriptor metrics) SP AusNet cannot estimate number of poles maintained. (Submission, spreadsheet) SP AusNet noted some estimation was required to populate light installation categories. (Submission, spreadsheet) SP AusNet noted that estimation would be particularly required for 2008/09 and 2009/10 years. (Submission, spreadsheet) CP/PC do not record number of new lights with each customer request. (Submission, p. 7) CP/PC do not record number of new public light poles installed in conjunction with a customer requesting a new light. (Submission, p. 7) We will accept estimates of expenditure and metrics against the connections categories in the category analysis RIN. DNSPs should disclose its estimation method in the basis of preparation. 4.1 4.1.2 (Clarification of gross versus net expenditure) JEN noted that a portion of cost recovery for public lighting services was made through customer contributions, so asked how this should be reflected in the category analysis templates (Bilateral meeting) The final RIN specifies that the cost data collected reflects DNSPs’ gross expenditures. That is, expenditure which is not netted for customer contributions. 4.1 4.1.2 (General difficulties in estimating descriptor Ergon does not report public lighting expenditure in the format requested in the AER’s category analysis templates, and some We intend to have unit costs reported in same way as prices listed in annual tariff proposals. This provides transparency to consumers as to the costs of public lighting
metrics) assumptions will need to be made to estimate data. (Submission, p. 25) services. 4.1 4.1.2 (General difficulties in estimating descriptor metrics) Aurora can report unit cost for installation, replacement and maintenance of public lighting services. Capex costs associated with assets not owned by Aurora are not recorded and excluded from unit rate calculations. (Bilateral meeting) Aurora (and DNSPs generally) will need to confirm which asset types (i.e. poles, cabling, luminaires and lights) are included unit cost calculations for installation, replacement and maintenance public lighting services. Disclosure of these calculations can be made in the basis of preparation. 4.1 4.1.2 (General difficulties in estimating descriptor metrics) Ergon does not separately capture repair and replacement expenditure. Estimation and apportionment required to calculate values. (Submission, p. 25) SP AusNet noted that some estimation would be required to report expenditure data for years 2008/09 and 2009/10, but that all other years can be reported. (Submission, spreadsheet) We will accept estimates of the time taken to rectify public lighting services. DNSPs should disclose their estimation methods in the basis of preparation. Table 6.4 Detailed issues and responses – Metering services (distribution) Template number Description of data/ cells NSP comments AER Response 4.2 4.2.1 (Double-counting of meter types) Ergon noted that CT/direct connect meter categories may be some combination of single/multiphase. Ergon suggested that the AER’s categories could be re-cast so as to avoid We acknowledge that CT and direct connect meters may be some combination of single and However, the template requires DNSPs to report the volume of the meter population which is either CT or direct connect meters; and separately the volume of the meter population which is
information as per the category analysis RIN. Table 6.5 Detailed issues and responses – Fee-based and quoted services Template number Description of data/ cells NSP comments AER Response 4.3 4.3.1 (Provide guidance on estimation of and Aurora sought clarity on the definition of energisation, and re-energisation. Aurora explained that its current practice was to define a change in customer at a single premises to be both a de-energisation and a (Bilateral meeting) For guidance we point to the definitions of energisation, de-energisation and re-energisation in appendix F of the draft category analysis RIN and appendix F of the final category analysis RIN. 4.3/4.4 4.3.1/4.4.1 (General issues reporting fee-based and quoted services expenditure) Ergon noted it was investigating ability to populate template, and a high level of estimation and apportionment is required. Extraction direct from current systems is not expected. (Submission) Aurora has only just started to provide services classified as quoted services since 2013. (Bilateral meeting) Energex cannot provide data for years 2008/09 and energisation We accept that some estimation may be required to report some fee-based and quoted services expenditures. DNSPs should disclose their estimation method in the basis of preparation. We expect DNSPs to list the fee and quoted services as per their annual tariff proposals. This provides transparency to consumers as to the costs of fee-based and quoted services. energisation re-
2009/10 due to reclassification of services. (Submission, pp. 13–14) Energex noted that is not a fee-based service for it. (Submission, p. 13) CP/PC noted that assumptions need to be made to estimate volumes for 2009 and 2010 for other miscellaneous fee based services. (Submission, p. 8) 4.3.5 (Difficult to calculate reconciliation table) Energex does not have dedicated staffing team for fee based services and will be difficult to breakdown cost. Data could be generated if multiple assumptions are made. (Submission, p. 13) See separate section on labour cost tables. 4.3.1/4.4.1 and 4.3.2/4.4.2 (Classification of fee-based and quoted services) SAPN noted that most fee-based services are classified as negotiated and will not be reported. (Submission, p. 5) We will not collect information for fee-based and quoted services classified as negotiated services. 4.3.1 (Specific questions on estimating fee-based service costs) CP/PC asked whether this only includes alternative control services. (Submission, p. 8) CP/PC asked: how de-energisation, re-energisation and differed from new meter installation category specified in We consider that fee-based services are typically classified as alternative control services in Victoria. To the extent that there is some overlap between the provision of fee-based services with standard control services, we expect fee-based services to be reported separately. The category analysis templates have been amended to allow DNSPs to distinguish fee-based services between standard and alternative control services.
Energex considers that due to the likely variance in estimation methodologies, the AER should engage a contractor to undertake the estimation work themselves. This is to ensure that we don’t assess expenditure based on perceived variances that don’t actually exist. (p. 9). Transend suggested that the AER could collect this data on a per hectare basis. (bilateral meeting). density. Having some indication of tree density along a NSPs maintenance span is vital as tree density is a significant cost driver of tree trimming costs. Cost is driven by the density of the vegetation being managed and the area of the land being managed – we are capturing both. Businesses with a low cost per area maintained at a given vegetation density would be more efficient than a business with a higher cost per area maintained at the same (or similar) vegetation density. The immateriality of tree density to clearance costs assumes a particular approach to maintenance of the vegetation management corridor. We need to be able to compare these different approaches – hence we need both density and area metrics. We will collect data by length and width rather than by hectare as it will allow us to consider both dimensions of a vegetation corridor and examine any differences is corridor width that way. 2.6 2.6.3 Vegetation management metrics - general Transend suggests that vegetation maintenance around communication sites should not be included in the transmission line metrics. (p. 3). We will make changes in accordance with Transend's submission, and make it clear that we are not after vegetation management work around communication sites. 2.6, 6.3 6.3.1 Interruptions to supply – vegetation blow-ins and (outages and fire starts) JEN suggests that the AER focus on collecting information on the party responsible for the vegetation that causes the outage, rather than capturing the outage by specific cause. (p. 7). SAPN state that they don’t collect We will incorporate JEN’s comment into template as well, recognising that the NSP themselves may not be directly responsible for some outages. We will continue to collect outages by cause (grow-ins and as well as the number of fire starts. NSPs will be provided the option to not provide this data initially if they do not collect it, but it will be required in future years.
2.8 Protection equipment maintenance SAPN queried where maintenance of protection equipment should be recorded – in the Maintenance tab or Non-network tab? (Submission p. 4) Protection Systems Maintenance is included in the Maintenance template as a distinct subcategory. 2.8 Sub-transmission asset maintenance Ausgrid queried what the definition is for dual function assets in 'Sub-transmission asset maintenance (dual function assets)'. (bilateral meeting) The definition of dual function assets is included in the RIN definitions and has the meaning prescribed in the NER. 2.8 Other Maintenance Activity (distribution) Ausgrid queried whether additional rows can be added for Voltage Regulators/Capacitors' under 'Other Maintenance Activity'. (bilateral meeting) Yes. NSPs have discretion to add rows for other material subcategories as ‘Other Maintenance Activity’: 2.8 Transmission Lines Maintenance TransGrid suggested the following changes (bilateral meeting): Steel Towers, Tower Structures, Conductors – Transend suggested the following changes: ‘Steel towers and conductors’ to be renamed ‘Steel structures’ ‘Tower structures’ to be renamed ‘Wood structures’ ‘Conductors’ to be a separate subcategory Based on subsequent submissions from TNSPs on repex asset categories (refer to Table 5.1), we have revised the transmission maintenance template to show the following: Transmission towers Transmission tower support structures Conductors Transmission cables.
Other DNSPs commented that a MED is not limited to weather events, and they will have to examine each MED to ensure it is related to a weather event. Further, there could be severe weather events that do not reach the required MED threshold but incur a significant amount of expenditure. While it may be difficult for all DNSPs to report costs associated with individual MEDs, we consider it necessary to understand the costs of these 'extreme events' and exclude them from the everyday operational costs in order to examine underlying trends in emergency response opex. In response to DNSPs' concerns and difficulties in collecting the data, we have inserted instructions in the RIN regarding the reporting of MED costs via the following processes: reporting of MED costs via direct cost capture reporting (i.e. specific allocated cost code) if available reporting of MED costs via capturing operating and maintenance (O&M) costs that were booked to the O&M codes on those days. While it may not capture all costs caused by the major events on those MED days, this will provide a good approximation. Customer outage minutes In addition to the data requirement on major storms and MEDs, we will use data on customer outage minutes for each regulatory year. These data will be used to assess the annual emergency response expenditure of each DNSP. These data are collected in template 6.3 of the regulatory templates. Outage data can be used to establish an emergency response workload-cost correlation model, which can serve as an alternative solution if DNSPs fail to provide good quality MED cost data, or it can be used to verify DNSPs' emergency response cost data estimates.
We have amended the RIN instructions and template to make the above clearer. 2.8 Tx Overhead cost allocation Powerlink commented that its overhead costs are applied in accordance with the AER approved Powerlink CAM. It is unclear what is intended to be reported. Further clarification is required. (Submission p. 3) Tab 2.8 Overheads require the following data: Overheads before they are allocated and capitalised, i.e. strip back allocated overheads and place them back in the overhead cost pool Opex that is capitalised Related-party expenditure (a subset of total opex) 2.8 Tx Cost comparison; Capitalisation ElectraNet notes that the AER will not prescribe a standardised cost allocation method and NSPs are to report consistent with their current methods and policies. This will make it difficult for the AER to make any meaningful cost comparisons between NSPs. It questions why the AER require negotiated and un-regulated costs as well. Cost comparison should only be related to regulated costs. ElectraNet is unaware of the meaning of capitalised maintenance support. (Submission, spreadsheet) Comparing the total overhead cost pools before these are allocated to direct cost categories is expected to address the problem of different approaches by NSPs to cost allocation. Data for negotiated and unregulated services are required only for reconciliation with annual regulatory reports, and no detail is needed aside from total Negotiated Services and total Unregulated Services. Capitalised opex means opex that may be significant/material and the business decides to classify this as capex based on its capitalisation policy.
The information on labour costs in the final RINs will allow us to examine actual labour costs and employment practices as they are reflected in their expenditure and identify potential inefficiencies for further analysis. We consider NSPs should generally record this information at this level and be able to report this information. The labour classifications have been refined following discussions with NSPs since the draft RIN and now reflect grades of employees reflective of field and corporate activities. Input cost tables NSPs did not comment on the collection of total input costs by expenditure category: Direct labour Direct materials Contracts (with non-related parties) Contracts (with related parties) Margins (on contracts with related parties) Other direct costs. We have moved and combined these tables in a separate template.