SERVICE ENGAGEMENT PAPER 2

Transcription

1 SERVICE ENGAGEMENT PAPER 2 April 2017

2 Contents Introduction... 2 Request for feedback... 2 Part A... 3 Engagement Process... 3 Feedback to date... 4 Part B... 6 Refresh and evolution of the performance measures... 6 Background and current measures... 6 Summary of the proposed measures for RCP Proposed refinements to the Grid Performance measures GP1 to GP Refinement Proposal Changes to the POS categorisation N-security sites Generator categorisation to remain the same Proposed refinements to the Asset Performance measures AP1 and AP AP1 HVDC Availability AP2 HVAC Availability Proposed refinements to the PMD measures Customer Service Appendix A - Summary of consultation questions Appendix B - Definition of the existing measures Appendix C Map of RCP2 points of service and critical circuits SERVICE ENGAGEMENT PAPER 2: APRIL

3 Introduction We are in the process of refreshing and evolving our service performance measures and targets for the five-year regulatory control period from 2020 to 2025 (known as RCP3). Our approach to refreshing the service performance measures involves seeking your feedback on the refinements we are proposing to make. We are appreciative of the feedback so far and for the support we have received on the engagement process. This is our second engagement paper in the process. It incorporates the feedback we received from our first engagement paper, dated October 2016 (2016 paper), and our stakeholder focus group held in February It explains in more detail the components of the proposed RCP3 service performance measures and the methodologies by which they would be calculated. We have designed this paper to make it understandable and informative to a wide-ranging stakeholder audience. Our aim is to be as efficient as possible while providing sufficient supporting information, recognising the different levels of understanding across our stakeholders, and how busy some are with other regulatory processes. Accordingly, like the 2016 paper, we have structured this paper into two parts to allow readers to be selective in what they read: Part A provides an overview of the engagement process and the feedback received to date Part B provides more detail on the proposed refinement to the measures. The service performance measures that are developed through this engagement will form part of our proposal to the Commerce Commission (Commission) for RCP3. As noted in the 2016 paper, this paper does not cover our work on Asset Health measures as these are still being developed and covered through other work streams. We are committed to establishing service performance measures for RCP3 that are meaningful and valued by our customers and end-consumers. We thank you for engaging with us on this journey. If you have any questions or would like further information, you are welcome to contact Stephen Jones 1. Request for feedback We welcome feedback from our stakeholders, customers, end-consumers and their representatives. This paper includes a feedback form (Appendix A). So we can consider your feedback we need to receive it by 5:00pm 28 th April. Please send your feedback to: communications@transpower.co.nz. 1 Stephen Jones, Strategic Asset Manager Ph , Stephen.Jones3@transpower.co.nz SERVICE ENGAGEMENT PAPER 2: APRIL

4 Part A Engagement Process This Part provides an overview on the engagement process we have undertaken to date and provides a summary of the feedback received so far. As mentioned in our 2016 paper we are conscious of the extensive involvement many of our customers and stakeholders have in current regulatory processes and consultations. Therefore, we wish to ensure that this engagement is targeted, not over taxing, but at the same time is comprehensive. The feedback we received on the outlined process in the 2016 paper has been positive and as such we intend to continue forward along the lines communicated in that paper. To date, we have: 1. Published the 2016 paper: The 2016 paper sought feedback on the engagement process and areas where further evolution of the service performance measures might be worth considering. It also provided additional supporting material for those new to this subject area. 2. Held the focus group meeting: A focus group of representatives from a cross section of our customers and consumer representatives was held in February The focus group discussed possible evolution of the measures and provided their views on what works in practice and what doesn t. 3. Published this paper: This paper provides more detail on the proposed RCP3 service performance measures, and the proposed methodologies by which the measures will be calculated. It also seeks your formal written feedback. From here the engagement process involves: 4. April 2017: We are presenting the methodologies set out in the paper and will be seeking feedback from participants during a session at the System Operations Industry Workshops which will take place in the first week of April These workshops will cover a variety of system operations and grid topics relevant to industry. The Christchurch workshop will be held on Monday 3 April; Wellington on Thursday 6 April and Auckland on Friday 7 April. Each workshop is a whole day session; lunch will be provided. To attend please register online via the System Operations stakeholder interactions page on our website SERVICE ENGAGEMENT PAPER 2: APRIL

5 5. September 2017: We will publish a Services Report as part of our Integrated Transmission Plan 2017 submission. In addition to reporting on our performance on the RCP2 measures, the Services Report will contain our proposal for RCP3 measures that incorporates the outcomes from this engagement. Feedback to date Our 2016 Paper was the first step in the process to ensure that our service performance measures for RCP3 represent the service attributes that our customers and end-consumers value the most. The purpose of the 2016 Paper was to outline the history of our service performance measures and to seek feedback on the potential evolution of the current measures for RCP3 and beyond. We also sought feedback on the proposed engagement process. We received feedback from 12 submitters. All but one submitter appreciated the early engagement and considered the outlined process struck the right balance between being comprehensive without being overly taxing. It was noted by one submitter that they thought the electricity sector is currently in regulatory overload, and they would prefer us to engage through our Customer Solutions team rather than introducing another layer of engagement. There was support in principle of a review of the Points of Supply (POS) categorisation criteria based on their importance and the economic consequences from a loss of supply. All but one submitter saw value in exploring alternatives to the current availability measure. They considered the exploration of alternatives to the availability measure should include a price separation approach as well as any others suggested by submitters. There was generally support for the changes to the measures that we proposed, with further dialogue on the detail as they develop. The overarching theme was that the measures should be kept simple, be meaningful, and reflect outcomes that are valued by customers and end-consumers. There was acknowledgment that individual customer expectations may vary. Submitters saw merit in the use of service targets as a driver for grid planning. The submissions received along with a summary of submissions can be found here 3. We held the focus group session in February Attendees were representatives from a range of EDBs, consumer representatives and the Commission who attended as an observer. The feedback received at the focus group followed similar themes to the written responses, with parties acknowledging the benefits of the process that was being undertaken. The general themes of the discussion at the focus group included: Agreement that the measures should be focused and targeted on service outcomes 3 SERVICE ENGAGEMENT PAPER 2: APRIL

6 A review of the mechanism for categorising POS for the grid performance (reliability) measures was supported. The suggestion was made that we could consider splitting the generator category into two groups to highlight important generator POS compared to standard sites The effectiveness of the availability measures was debated with the primary feedback being that the core consideration for a measure on outage planning for network assets needs to incentivise efficient and optimised outages within a planning horizon Measures that report on the extent that we keep to planned timeframes for planned outages should be weighted towards dis-incentivising late restoration. Early restoration of outages benefits consumers It was proposed that for some of the measures that focused on information reporting, e.g. PMD7 - energy not supplied, would be better served through reporting closer to real time information on our website There was support for covering the event communication related PMD measures through the current survey mechanisms we already have in place and thereby enabling more valuable qualitative information to be gathered and acted upon. Focus group participants noted that currently operational communications between us and our customers works very well. This paper incorporates the responses and feedback we have received from stakeholders. Our proposal for the RCP3 measures is detailed in the next section of this paper. SERVICE ENGAGEMENT PAPER 2: APRIL

7 Part B Refresh and evolution of the performance measures This Part describes the evolution of the service performance measures we are proposing for RCP3. As we noted in our first engagement paper, we have been on a journey to establish measures of our performance for a number of years. This process started prior to RCP1, but was crystallised with the establishment of general performance measures for RCP1, and then developed further into more specific measures in RCP2, some of which are linked to revenue. Drawing on our experience with the RCP2 service performance measures so far, and the feedback received from the engagement process to date, we have described where we propose to evolve and target the measures to better reflect what is important to our customers and end-consumers. Background and current measures RCP2 saw a change in emphasis from grid based measures of average system performance, towards customer-facing performance measures that reflect the service our customers and end-consumers receive. The purpose of this change was to provide incentives to target our expenditure across the grid and focus on the delivery of the service outcomes expected by our customers and endconsumers. These customer-facing performance measures were established based on the feedback we received during our RCP2 consultation process, which the Commission accepted and incorporated within their RCP2 determination. For RCP2 we have 23 revenue-linked grid output measures. They consist of: Fifteen grid performance measures Two asset performance measures Six asset health (works delivery) measures. The targets for these measures were based on forward looking service expectations rather than historical averages. In establishing the RCP2 targets for the service performance measures the Commission also made further adjustments to derive the targeted levels of performance we operate under today. For further information, the definition of these measures is included in Appendix B In its RCP2 Determination, the Commission also suggested nine additional measures for development (known as performance measure development, PMD 1 to PMD 9). We have been measuring and trial reporting on these development measures since RCP2. The PMDs are: PMD1 Time to provide initial information following an unplanned interruption SERVICE ENGAGEMENT PAPER 2: APRIL

8 PMD2 Time to provide updated information following an unplanned interruption (greater than 30 minutes) PMD3 Accuracy of notified restoration times following unplanned interruptions PMD4 Extent that Transpower meets planned outage restoration times PMD5 Extent that Transpower places customers on N security PMD6 Number of unplanned momentary (of less than one minute) interruptions PMD7 Energy not supplied for each point of service for each unplanned interruption PMD8 Extent that Transpower meets planned outage start times for critical circuits and equipment PMD9 Extent that Transpower provides its reports to affected parties on unplanned interruptions within 15 working days of the interruption. Transpower will report any expectations on the number of times it did not meet the timeframe. Overall, we have been monitoring and internally reporting on 32 measures of our performance. While this has been comprehensive and informative, experience and customer feedback has shown that not all the measures are valuable as performance measures and that many (in particular the development measures) can be improved upon, or utilised and communicated in a more meaningful manner through more effective channels. A general discussion on the direction of our thinking on these measures was set out in the 2016 paper. The feedback received so far, and our experience with the measures forms the basis for our proposed refresh and evolution. Given the relatively short time the measures have been in place and the absence of any significant issues with the RCP2 measures we believe an evolutionary approach to refining the measures is appropriate rather than attempting a wholesale change. Submitters on our 2016 paper and the forum participants supported this approach. Accordingly, our intention with the proposed RCP3 measures is to further refine the measures to target the outcomes more specifically sought by our customers. Summary of the proposed measures for RCP3 As we noted in the 2016 Paper, there were three potential areas where we considered the performance measures could be evolved: Refinement of the grid performance measures by reviewing the way POS are categorised and whether the P90 measure is meaningful in practice Whether changes to the asset performance availability measures should be considered. The purpose of the asset performance measures is a proxy for market availability of the grid to facilitate the lowest cost sources of generation supply to meet demand. However, there is a desire from some stakeholders for us to demonstrate incentivised efficiency and the optimisation of planned outages of key network assets SERVICE ENGAGEMENT PAPER 2: APRIL

9 Review of the PMD measures to determine which should be adopted, evolved, or dropped to ensure that collectively the measures are fit for purpose. Drawing on both the feedback we have received from stakeholders and our experience, our proposal for refining customer facing RCP3 measures is, in summary, to: a. Retain the grid performance measures GP1 and GP2, which establish the reliability of POS by category. We propose to refine the categorisation of POS by more explicitly allocating each POS to a category based on the estimated cost of an average interruption. The estimated cost of an average interruption at each POS would be calculated by using Value of Lost Load (VoLL), the level of demand, and the type of load supplied. We are also considering if we should reduce the number of categories for N-1 POS and expand the number of categories for N POS. b. We propose to discontinue GP3, the P90 reliability measure. In practice, the number of events in several of the categories is too small for a P90 calculation to give logical answers. Moreover, large events are very rare, and as such in our view there is insufficient baseline data for the P90 value to be meaningful. Experience has also shown that during the very long outages there are specific circumstances that typically drive the outage length. c. Retain the asset performance measure AP1, HVDC availability. Stakeholder feedback has indicated that the effectiveness of the HVDC availability is restricted by the exclusion of equipment that impacts on the reserve capability of the HVDC. While we considered changes to the HVDC measure to account for this, there are physical changes to the HVDC control system planned to be implemented in 2017 that will eliminate the issue, meaning that the measure itself will be effective as it is currently defined. d. Retain and evolve the asset performance measure AP2, HVAC availability. The purpose of AP2 is to incentivise Transpower to ensure the Grid is available as much as possible, minimising losses and constraints on the electricity market. Within this context the crucial issue identified by stakeholders is that AP2 does not within itself incentivise efficiency and optimisation of scheduling planned outages on network equipment. In considering the alternatives to AP2, it is evident that many mechanisms are susceptible to significant influence from behaviour that is outside our control. Accordingly, we are currently undertaking an outage planning review to further improve the process including how we communicate and work with stakeholders to determine the trade-offs, timing and efficiency that occurs within the planning horizon. In addition, we consider there are some potential refinements to the measure. These include reviewing the circuits on which the availability measure is applied, and considering the target setting mechanism e. Rationalize PMD 4 and 8, as they relate to outage planning into a new asset performance measure AP3, stick to the plan. The new measure will supplement the current asset performance measures and ensure that we are incentivised to deliver the outage plan as described. The new measure would be biased towards penalising the late return of assets to service and rewarding the early return. f. Time on n-security is a function of grid configuration and maintenance cycles, and while it is interesting information, it is not a primary driver of our behaviour. Unplanned outages due SERVICE ENGAGEMENT PAPER 2: APRIL

10 to customers being on n-security are captured through the reliability measures. We propose to discontinue reporting PMD 5 for RCP3. g. Evolve the remaining PMD measures to be more valuable for customers and stakeholders. It is proposed that the communication related PMD measures (PMD 1, 2, and 3) are combined into the existing post-event survey mechanism that can assess the customer experience after the event in a timely (~one-week) fashion. Reporting on PMD 7, energy not supplied, could be published on our website if that would provide value to stakeholders, and that those PMD measures that appear to be interesting but can be or are reported elsewhere be ceased (PMD 6 and 9). Together we consider these proposed refinements provide a more focused and effective combination of measures than what we operate under in RCP2. Further details on each of the proposed changes are set out in the following sections of this paper. The proposed refinements and the transition from the RCP2 measures to the proposed RCP3 measures is illustrated in Figure 1 below. SERVICE ENGAGEMENT PAPER 2: APRIL

11 Category Performance measure RCP2 code Propose as a measure for RCP3? Reliability Number of unplanned interruptions each year by customer category GP1 Average duration of unplanned interruptions by customer category (min/yr) GP2 Duration of 90 th percentile unplanned interruption by customer category (min/yr) GP3 Availability % availability of HVDC AP1 % availability of selected HVAC circuits AP2 Category Development measure RCP2 code Customer Service/ Event Communications Customer Service/ Event Communications Customer Service/ Event Communications Availability Availability Reliability Reliability Availability Reliability Current RCP2 Measures Time to provide initial information following an unplanned interruption Time to provide updated information following an unplanned interruption (greater than 30 minutes) Accuracy of notified restoration times following unplanned interruptions Extent that Transpower meets planned outage restoration times Extent that Transpower places customers on N security Number of unplanned momentary (of less than one minute) interruptions Energy not supplied for each point of service for each unplanned interruption Extent that Transpower meets planned outage start times for critical circuits and equipment Extent that Transpower provides its reports to affected parties on unplanned interruptions within 15 working days of the interruption. Transpower will report any expectations on the number of times it did not meet the timeframe PMD1 PMD2 PMD3 PMD4 PMD5 PMD6 PMD7 PMD8 PMD9 Propose as a measure for RCP3? Category Performance measure RCP3 code Reliability Number of unplanned interruptions each year by customer category GP1 Availability Average duration of unplanned interruptions by customer category (min/yr) % availability of HVDC % availability of selected HVAC circuits Sticking to the outage plan Extent that Transpower keeps to planned outage times Customer Service/ Event Communications Proposed RCP3 Measures Existing post event survey. Focuses on timely information provision and communications. GP2 AP1 AP2 AP3 CS1 Proposed Refinement Categorisation to be aligned with VoLL Categorisation to be aligned with VoLL Refined to include equipment that determines reserve limits Circuits included and target setting mechanism to be reviewed Refined to target late restoration times only [Method to be developed] Incorporates PMD1, 2 and 3 including qualitative information on the quality of the communications Other reporting: finalisation of post event reports, online updates for energy not supplied for each POS, voltage disturbance working group Figure 1: Transition from the RCP2 performance measures to RCP3 SERVICE ENGAGEMENT PAPER 2: APRIL

12 Consultation Question Do you agree with the proposal outlined above to transition from the RCP2 performance measures to RCP3? Proposed refinements to the Grid Performance measures GP1 to GP3 In RCP2 POS were allocated into five categories that reflected the relative economic impact of supply interruption. The categories were: High Priority Important Standard N-security Generator The economic impact of an interruption was considered higher for loads that contained either one (for the Important priority category), or two (High priority category) of the following criteria: 1. A Main City 2. Key Loads 3. More than 25,000 Individual Connection Points (ICPs) This allocation approach proved useful as an initial indication of the categorisation as it simplified the representation of economic impact of an interruption within the categories and it invited further engagement with our stakeholders on the loads that were being supported within their respective regions. However, experience has shown that the allocation process required a high level of judgement, particularly in assessing the definition of a Key load (criteria 2). In addition, the method does not explicitly consider the volume of energy being supplied at a POS. This has meant that POS supplying a relatively high level of energy, but not meeting some of the criteria above, were classified lower than POS supplying much less energy. Therefore, the application of the approach is subjective, not easily repeatable, and may lead to inconsistent classifications of POS. Consequently, we are proposing to refine the approach for the categorisation of POS by assessing the cost of an interruption utilising VoLL, the level of load supplied at the POS, and the type or makeup of the load. After some initial testing of the proposed mechanism our view is that the result is likely to be very similar to that developed for RCP2. However, the approach will be more robust and consistent over time. SERVICE ENGAGEMENT PAPER 2: APRIL

13 Refinement Proposal The proposed approach ranks POS based on estimates of the economic consequence of an interruption at each POS. This draws on information about both the customer mix supplied at each POS and VoLL. There are three steps in applying the proposed methodology: 1. Determine the energy and sector composition supplied at each POS. We propose to determine the composition of the energy supplied at each POS using a variety of data sources such as: a) Installation connection point (ICP) numbers by POS, ANZSIC code, and Meter Category data drawing on data from the Electricity Authority (EA) 4 b) Regional residential average demand also from the EA 5 c) Sector aggregate consumption data published by MBIE 6 d) Transpower s own Grid Exit Point (GXP) metered data. For example, residential demand at each POS can be approximated by using a) to determine the number of residential customers and b) to determine their average usage. We are also considering if there is any value in further breaking down residential demand into urban versus rural demand, demand by income distribution, and demand by daytime status (e.g. younger at home, younger away etc). Business demand by sector can be approximated using the remaining data. For example, a) provides the number of businesses by ANZSIC code and by making assumptions about the amount of energy used by different meter categories as estimate of business demand by ANZSIC code can be estimated. This can further be moderated using information about sector totals provided by c) and metered data provided by d). 2. Application of the VoLL The second step involves applying a sector specific VoLL to the breakdown of demand at each POS. We have trialled an approach to deriving VoLL for different customers in the Upper South Island and plan to extend this study to other parts of the country. The aim of the VoLL study would be to determine distinctive VoLL values for each composition of demand found in step 1 above. 4 ANZSIC codes and meter categories are assigned in the ICP registry by traders (retailers) and metering equipment providers respectively. This information has been collated and provided by the Electricity Authority SERVICE ENGAGEMENT PAPER 2: APRIL

14 The product of the average demand identified in step 1 and the composition specific VoLL found in this step provides an estimate of the average cost of an interruption at each POS. 3. Categorisation based on the value of an interruption After calculating the total value of an interruption, each POS will then be ranked and ordered. At this stage we are considering if we should retain the 3 existing N-1 categories (e.g. High, Important, Standard) or should reduce the number of N-1 categories to 2 categories. This will depend to some extent on the differentiation in the total value of interruptions across POS. If there is relatively little variance across the majority of POS then reducing to 2 N-1 categories may make more sense. Changes to the POS categorisation We have done some initial analysis to test the likely effects of these proposed changes. Our results to date indicate that should we retain the existing categorisations the majority of POS are likely to remain in the same categories as assigned through the more subjective RCP2 process. However, some minor movements will likely occur. For example, from our results to date it is possible Stoke 33kV and Ashburton 66kV may move up a category, but we still have further work to do to confirm this result. We will consult on the final methodology and classification of POS later in the year. Consultation Question: Do you agree with the proposed change in the categorisation methodology for POS categorisation? Please explain your rationale for you answer. N-security sites For RCP2 we classified all N sites in a single category. We could use this approach again in RCP3 but are interested to receive feedback on if it would make sense to divide this category into two categories. Our understanding is that some N sites are more important than others from our customers perspective, as at some N sites lines companies have the ability to back feed load from other POS and generation, whereas at other sites this is not possible. The ability to back feed load and supply load from other generation, would be an important consideration if we did look to subdivide this category. In theory a similar approach as taken for other POS, as per above, could be used to inform the categorisation along with information about the ability to back feed. Consultation Question: Do you think we should classify all N sites in the same category? If not what alternative methodology would you suggest? Please explain your rationale for you answer. SERVICE ENGAGEMENT PAPER 2: APRIL

15 Generator categorisation to remain the same While it has been suggested that major generation be separated into a separate category there are several factors that do not support such a move. These factors include the lack of data to support meaningful targets and the lack of consistent distinguishing features which might be used as an objective basis for the categorisation. Furthermore as tracking the performance of the entire generation category, we still observe and report interruptions at individual generator sites which allows us to highlight any poor performing generator POS. Consultation Question: Do you agree with retaining the same categorisation methodology for Generation sites? If not what alternative methodology would you suggest? Please explain your rationale for you answer. Proposed refinements to the Asset Performance measures AP1 and AP2 There are two asset performance measures for RCP2, HVDC availability (AP1) and HVAC availability (AP2). We refer to these as availability measures throughout this paper. It is proposed to retain the HVDC availability measure and evolve the HVAC circuit availability measure for RCP3, as discussed further below. AP1 HVDC Availability Due to the configuration of the HVDC, the availability measure as utilised in RCP2 excludes the impact that some of the secondary HVDC plant has on the transfer capability between the Islands. This means that currently the measure does not fully reflect the availability of the HVDC within a market context. The cause of this issue is that the unplanned loss of some HVDC components can cause the HVDC system to overload. In order to keep post-event HVDC transfer within the capability of the remaining HVDC components, we need to limit the overload of the HVDC system following an HVDC asset failure. This is called the overload capability of the HVDC. Due to the calculation methodology utilised for AP1, this effect does not result in a reduction in the % availability that is reported, however, it does have a real effect on the market. In technical terms, the overload capability of the HVDC is represented in the market system by a factor called the risk subtractor. Currently, the HVDC s overload capability is 650 MW. It reduces during planned outages to the HVDC s harmonic filters to as low as 140 MW. This 140 MW limit is set by the filtering requirements of the HVDC with both poles in service, following the unplanned loss of an additional filter. However, for reasons that are beyond the simple measurement of the HVDC availability, we are currently investigating a control system change for the HVDC. This change would automatically block Pole 2 following the unplanned loss of an additional filter during a planned filter outage, leaving just Pole 3 in service. This reduces the filtering requirements of the HVDC, and increases the HVDC s overload capability during planned filter outages. Hence, we expect the HVDC risk subtractor to SERVICE ENGAGEMENT PAPER 2: APRIL

16 remain at 650 MW during all planned filter outages following this change. We expect the change in the control system to be implemented before When the change to the control system is made, the current calculation methodology for the HVDC availability measure will capture all the outcomes intended without a change to the methodology. Accordingly, we are proposing to retain the current methodology for AP1 for RCP3. Should the HVDC control system change not be implemented by RCP3 we would then reconsider the calculation of AP1. Consultation Question Do you agree with retaining AP1: HVDC availability for RCP3? If not, what are your reasons, and what alternative would you recommend? AP2 HVAC Availability As described in the 2016 paper there are possible alternatives to AP2 that could be considered and explored. Having considered a range of potential alternatives for the HVAC availability measure, we believe there is benefit in retaining the core measure but evolving some aspects of it for RCP3. As these measures are relatively new it is also important that we have some stability in them, while ensuring the incentives they create are appropriate. This measure was implemented in response to the RCP2 engagement process. Since being implemented we have been working to update our processes to deliver more effectively the service. In considering alternatives to the availability measures we are also concerned that market based mechanisms are susceptible to being significantly influenced by market behaviours which are entirely outside our control. Mechanisms that are subject to these characteristics shouldn t be utilised as a performance mechanism for us in RCP3. Accordingly, we are proposing that the current measure, which is almost entirely within our control, be retained but refined to ensure that the measure reflects the outcomes sought by stakeholders. As noted previously, this involves refining four relevant aspects: The efficiency and optimisation of planned outages The circuits that are covered by the measure The target setting mechanism The degree by which we deliver on our outage plan. Each of these is discussed below: 1. Efficient and timely management of planned outages The crucial issue identified by stakeholders on our current asset performance measures is that there is nothing to incentivise efficiency and optimisation of scheduling planned outages on network equipment. Whilst considerable effort is made by us to be both efficient and to optimise outages, we acknowledge that this isn t necessarily visible to market participants. We are currently reviewing the end-to-end outage planning process. This entails reviewing the existing process and technology, and identifying opportunities to increase efficiency. We will SERVICE ENGAGEMENT PAPER 2: APRIL

17 look for opportunities to address how we can enhance our communication and work with stakeholders to determine the trade-offs of timing and efficiency that goes into our outage planning. Reviewing and communicating the activities and analysis that is undertaken to ensure the optimal timing of outages within the planning horizon is a key consideration of our outage planning. An important consideration is also the timeframe in which this optimisation occurs. Specifically, the service measures are related to the longer term asset planning rather than the system security assessment time horizon (within 4 months) that is governed by the provisions in the Code 7. For the efficiency and optimisation of outages to occur the trade-offs can only occur within the planning horizon and not in real-time. As substantial resources are involved, and the extent of the outage programme across the year (we co-ordinate over 7000 outages a year), the moving of outages within a short time horizon is both expensive and has significant impact on the timing of subsequent planned outages. This also negates the work that has been undertaken to optimise the timing and efficiency of those outages. Consultation Question Do you agree with our proposal to improve our communication around how we undertake efficiency and optimisation of outages within the planning horizon? 2. The circuits covered by AP2 The AP2 measure is the average availability of a selected group of HVAC circuits. Currently the availability is based on a selection of 27 circuits, upon which it was estimated that an outage would impact market security constraints and system losses. The circuits are listed in Appendix B and can be seen graphically on a map in Appendix C. On consideration of these circuits, our view is that the intent of the measure is more associated with the key high voltage circuits on the transmission backbone rather than a selected few, i.e. the current circuits are South Island dominated and, as demonstrated by the map in Appendix C, there are backbone gaps with no circuits being monitored going up the country. Accordingly, we propose that the circuits utilised for the measure be reviewed with the aim of potentially increasing the number of circuits. Consultation Question Do you agree with our proposal to review the circuits with the intent of incorporating more circuits within the measure? If not please explain your rationale and which circuits should be included. 3. Target setting mechanism Both AP1 and AP2 each have the constant availability target applied in each year over the fiveyear regulatory period. Given the regulatory proposal is submitted 2 years in advance of the 7 Electricity Industry Participation Code (2010) SERVICE ENGAGEMENT PAPER 2: APRIL

18 commencement of the regulatory period, this requires us to set a single availability target for each circuit involved up to 7 years in advance. In practical terms this is unrealistic and does not achieve the intended outcomes from the measure. By way of example, maintenance on circuits isn t always cyclical in nature, and the outage requirements and therefore optimisation opportunities aren t always clear in these longer timeframes. Furthermore, efficiency and optimisation of our work and outage plan closer to the time will affect availability. As such we are interested in looking at alternative mechanisms for setting availability targets from year-toyear. Our initial view is that the targets should be set annually, with a fixed mechanism for determining the cap and collar. We are interested in any suggestions on what you might consider appropriate here. Consultation Question Do you have any improvements on how our availability targets could be set? 4. Additional stick-to-the-plan asset performance measure Both feedback from stakeholders and our experience indicates that market impacts are less likely where outages stay within their scheduled timeframes. Sticking to an outage plan, allows the market to have confidence to arrange and execute appropriate risk management mechanisms and for traders to set up book positions in advance, leading to better long term outcomes for end-consumers (relative to uncertainty and volatility being induced by transmission outages unexpectedly shifting and running late). It also means customers can plan to minimise inconvenience and disruption. Therefore, we propose to introduce a third asset performance measure around sticking to the plan. Feedback we have received is that this should be biased against late restoration only. There should be no punishment for early restoration as this is almost always a positive impact for consumers. This stick to the plan measure would replace two less effective PMD measures, namely PMD4 and PMD8. Consultation Question Do you support the addition of this new stick-to-the-plan asset performance measure and the dropping of PMD4 and PMD8? Proposed refinements to the PMD measures The purpose of the PMD initiatives were to develop and report on additional measures that stakeholders indicated were important to them during the RCP2 consultation. While the effectiveness of the PMD measures was uncertain, the aim of these measures is to provide an indication of our performance regarding outage planning, the financial impact of outages and customer service. The PMD initiative has been valuable, however our experience with these measures has demonstrated that there is value in evolving the PMD measures further to: SERVICE ENGAGEMENT PAPER 2: APRIL

19 Link the outage planning related PMDs to the asset performance measures, as discussed previously Provide more effective information by including the communication related PMDs within our customer service surveys Improve the timeliness of the energy not supplied information by reporting nearer to real time on our website, which will also improve the accessibility of the information to stakeholders Cease reporting on those PMDs that, through practice, have shown to not add the value that was initially envisaged or are already being reported elsewhere. More specifically, on each of the measures: a. PMD 4 and 8 provide information on the extent to which we meet out pre-planned timeframes for planned outages. As discussed in section 4 above, the proposal is to combine these development measures into a third stick to the plan asset performance measure. b. PMD1 captures the time taken to provide initial information following an unplanned outage. While the time taken is simple to record it does not capture whether the information provided was useful or accurate. This same issue has arisen with PMD2, PMD3 and PMD5, where the binary nature of a measure doesn t represent the real quality or value of the information. Recognising this issue we have sought to introduce a better means to assess our performance in this area. Since October 2015 we have taken the initiative to incorporate information on both the timeliness and the quality of communications within post-event surveys undertaken with our customers. Feedback received to date, is that the surveys are an effective and positive step. Accordingly, it is proposed that reporting on PMDs 1, 2, and 3 is ceased as the information is captured within the customer post-survey process. c. The frequency that a site is placed on N security, as measured by PMD 5, is a function of the grid configuration and the maintenance cycles required for good asset management. Hence while the information reported through PMD 5 is interesting it isn t, and shouldn t be, a driver of our behaviour. The calculation of PMD 5 is highly resource intensive. When an unplanned outage occurs the impact from a customer being on n-security also is captured through the reliability measures. We therefore do not believe PMD 5 is a useful performance measure and are proposing to discontinue reporting PMD 5 for RCP3. This is not to say that we will not provide the information to customers as required. We are interested in working with customers to establish how we can provide better information of this type in more efficient and targeted ways. d. We do not believe that PMD 6 is an appropriate performance measure as most unplanned momentary interruptions are outside of Transpower s control. However, like PMD 5 this information may be of interest for customers. Hence, we propose to continue collecting this data and communicate this information openly to those who want it through various industry working groups, i.e. voltage disturbance working group. e. Stakeholders have indicated that the time lag in reporting on PMD 7, energy not supplied for each unplanned outage, devalues the usefulness of the measure. Therefore, we propose to SERVICE ENGAGEMENT PAPER 2: APRIL

20 move the reporting of PMD 7 closer to real time, potentially via our website, and cease to report it as part of the PMD measure suite. f. PMD 9 is already reported on as we are obligated to provide post-event reporting under connection contracts with our customers. Therefore, it is proposed to cease reporting on PMD 9 separately. Consultation Question Do you agree with the proposed changes to the PDM measures? If not, what do you propose? (Please provide your rationale for your position). Customer Service Effective communication with our customers is important to us. As such we were interested in developing a better understanding of how we were performing in the management of unplanned interruptions as part of an ongoing exercise of better meeting our customer needs for communication. Feedback received from customers stated that surveys were an appropriate mechanism to gather this information, as they can also be done anonymously if a customer chooses to do so. These surveys were implemented in October 2015 and feedback on them to date has been particularly positive. Customers feel included and involved in giving feedback (both positive and negative) in a timely fashion about process, people and our communication. We have found this to be particularly useful in understanding where we are meeting expectations and where we can improve. Accordingly, as discussed above, it is proposed that reporting on PMDs 1,2, and 3 is ceased as the information is captured within the customer post-survey process, and feedback suggests it is working well for all parties. Consultation Question Do you agree that the existing post-event customer survey process allows for effective two-way information gathering on where things are working well and where improvement can be focused? SERVICE ENGAGEMENT PAPER 2: APRIL

21 Appendix A - Summary of consultation questions 1. Do you agree with the proposal outlined above to transition from the RCP2 performance measures to RCP3? 2. Do you agree with the proposed change in the categorisation methodology for POS categorisation? Please explain your rationale for you answer. 3. Do you think we should classify all N sites in the same category? If not what alternative methodology would you suggest? Please explain your rationale for you answer. 4. Do you agree with retaining the same categorisation methodology for Generation sites? If not what alternative methodology would you suggest? Please explain your rationale for you answer. 5. Do you agree with retaining AP1: HVDC availability for RCP3? If not, what are your reasons, and what alternative would you recommend? 6. Do you agree with our proposal to improve our communication around how we undertake efficiency and optimisation of outages within the planning horizon? 7. Do you agree with our proposal to review the circuits with the intent of incorporating more circuits within the measure? If not please explain your rationale and which circuits should be included. 8. Do you have any improvements on how our availability targets could be set? 9. Do you support the addition of this new stick-to-the-plan asset performance measure and the dropping of PMD4 and PMD8? 10. Do you agree with the proposed changes to the PDM measures? If not, what do you propose? (Please provide your rationale for your position). SERVICE ENGAGEMENT PAPER 2: APRIL

22 11. Do you agree that the existing post-event customer survey process allows for effective twoway information gathering on where things are working well and where improvement can be focused? SERVICE ENGAGEMENT PAPER 2: APRIL

23 Appendix B - Definition of the existing measures The revenue linked annual measures of grid performance for RCP2 are defined as 8 : Total number of unplanned interruptions across all points of service in a category during a disclosure year (where each of the five categories has a separate measure of grid performance as identified in table A1 as GP1A to GP1E; Average duration (minutes) of unplanned interruptions at points of service in a category during a disclosure year, where each of the five categories has a separate measure of grid performance as identified in table A1 as GP2A to GP2E; Duration (minutes) of the unplanned interruption that is at the 90th percentile during a disclosure year, where each of the five categories has a separate measure of grid performance as identified in table A1 as GP3A to GP3E. The revenue linked annual asset performance measures are defined as: HVDC energy availability of the HVDC poles 2 and 3 as a percentage of annual capacity during a disclosure year, as identified in table A1 as AP1; The average percentage of time that the selected HVAC circuits (listed in Table A3) are available during a disclosure year, as identified in table A1 as AP2. 8 Sourced from Transpower Individual Price-Quality Path Determination, 2015, [2014] NZCC 35, 28 November SERVICE ENGAGEMENT PAPER 2: APRIL

24 Table A1 Category / Grid output Description: grid Circuits / output measure Measure reference Grid output target rate ($000) Cap Collar incentive Disclosure year Measures of grid performance Number of unplanned interruptions High Priority GP1A Important GP1B Standard GP1C Generator GP1D N-security GP1E Average duration (minutes) of unplanned interruptions High Priority GP2A Important GP2B Standard GP2C Generator GP2D N-security GP2E Duration (minutes) of P90 High Priority GP3A unplanned interruption Important GP3B Standard GP3C Generator GP3D N-security GP3E Asset performance measures HVDC availability (%) AP HVAC availability (%) Selected circuits AP SERVICE ENGAGEMENT PAPER 2: APRIL

25 Table A2 RCP2 code PMD1 Performance Development Measure Time to provide initial information following an unplanned interruption PMD2 PMD3 Time to provide updated information following an unplanned interruption (greater than 30 minutes) Accuracy of notified restoration times following unplanned interruptions PMD4 Extent that Transpower meets planned outage restoration times PMD5 Extent that Transpower places customers on N security PMD6 Number of unplanned momentary (of less than one minute) interruptions PMD7 Energy not supplied for each point of service for each unplanned interruption PMD8 PMD9 Extent that Transpower meets planned outage start times for critical circuits and equipment Extent that Transpower provides its reports to affected parties on unplanned interruptions within 15 working days of the interruption. Transpower will report any expectations on the number of times it did not meet the timeframe SERVICE ENGAGEMENT PAPER 2: APRIL

26 Table A3 Selected circuits for AP2 HVAC availability measure in RCP2 South Island North Island Clyde-Cromwell-Twizel 1 and 2 Ohakuri-Wairakei 1 Manapouri-North Makarewa 1,2 and 3 Te Mihi-Whakamaru 1 North Makarewa-Tiwai 1 and 2 Bunnythorpe-Tokaanu 1 and 2 Clyde-Roxburgh 1 and 2 Rangipo-Tangiwai 1 Ashburton-Timaru-Twizel 1 and 2 Atiamuri-Whakamaru 1 Invercargill- Manapouri 2 Te Mihi-Wairakei 1 Tekapo B-Twizel 1 Pakuranga-Whakamaru 1 and 2 Islington-Tekapo B 1 Ohau B-Twizel 3 Ohau C-Twizel 4 Ashburton-Islington 1 Islington-Livingstone 1 SERVICE ENGAGEMENT PAPER 2: APRIL

27 Appendix C Map of RCP2 points of service and critical circuits SERVICE ENGAGEMENT PAPER 2: APRIL