Questions and answers are listed by reverse chronology - the most recent questions and answers appear first. When more than one question is asked in a single email, questions are numbered within each date entry.
23 September 2021 (EA Networks) - Export to the Transpower Grid (where to look in the proposed TPM)
Questions: We are getting questions from a prospective solar farm developer about the cost implications of total connected generation exceeding total load on the EA Networks system. This generation excess would cause an export of energy to the Transpower network. We are aware that you currently cannot give us any guidance on the proposed TPM, but we wish to examine the proposed TPM to discover this for ourselves. Our hope is that you can suggest the relevant section(s) of the TPM that we need to interpret.
Response: We have recently published the second part of our response to the Authority’s comments on the proposed TPM we submitted on 30 June. Our response is here and includes some changes to the proposed TPM.
In clause 5 of the resubmitted proposed TPM we have introduced netting off of coincident grid injection for the purposes of calculating embedded electricity, and therefore total gross energy, for transmission customers. So, in a situation where the embedded generation on EA Networks’ network exceeded load and the excess was injected into the grid during the same trading period, the grid-injected quantity would not count towards EA Networks’ total gross energy (assuming our proposal is accepted by the Authority). This would reduce EA Networks’ allocation of the residual charge versus our previous proposal under which the excess embedded generation would count EA Networks’ total gross energy (as required by the Guidelines).
We note that the indicative pricing provided with our 30 June proposal reflects the netting off of coincident grid injection for the purposes of calculating embedded electricity, and therefore total gross energy (the update we proposed on 15 September was to the TPM drafting and has no impact for indicative pricing).
It is possible some of the excess embedded generation would go to charging a battery. The resubmitted proposed TPM does not include any special treatment for batteries. As you may know, the question of what special treatment the new TPM should give to batteries (if any) has not been resolved by the Authority. The Guidelines don’t contemplate any special treatment, but we understand the Authority intends to consult on this issue as part of its consultation on the proposed TPM later in the year.
20 September 2021 (Buller Electricity) - TPM Indicative Charge Modelling
Question: Buller Electricity is of the view that our Residual Charges are significantly overstated in the indicative charge modelling.
This is because the charge modelling does not take into account that at the end of June 2016 our load almost halved following the loss of a major industrial customer (Holcim Cement at Cape Foulwind) which resulted in the closure of the WPT GXP.
The historic AMD used in the Residual Charge calculation was 19MW whereas a more appropriate value would be 11MW.
This oversight was also made in the Electricity Authority’s previous charge modelling.
We are also of the view that the Connection Charges (stated as being $0.5M) are incorrect as they are current near zero (2021/22) following a recent Connection Asset reclassification.
Response: Thank you for your email and comments. The indicative pricing submitted to the Electricity Authority on 30 June 2021 is consistent with the TPM Guidelines requirements and the proposed TPM Transpower submitted to the Authority at that time:
- The indicative residual charge is based on Buller’s metered gross AMD for the period July 2014 to June 2018, then adjusted against metered gross energy. For the expected first pricing year (23/24) the gross energy adjustment would be calculated from meter data for July 2015 to June 2019, and then roll forward each subsequent year.
- It may be that the loss of Holcim cement is relevant under the reduction event mechanism, which is in clause 73 and the definition of “reduction event” of the proposed TPM we resubmitted to the Authority on 15 September.
- We are aware of the recent reclassification of grid assets in the Buller region from connection to interconnection. The indicative prices have been produced on the assumption clause 25 of the proposed TPM will be applied to return the classification of those assets to connection given the nature of the transmission services they provide.
The Authority will be consulting fully on the TPM approved by the Authority for consultation later this year. Buller may wish to make a submission on these or other parts of the proposed TPM in response to that consultation.
15 September 2021 (Northpower) - Indicative pricing for high value BBIs
Question: We’re just working through the documents recently published by Transpower relating to the TPM recently submitted to the EA. Specifically, we’re trying to trace back our allocation of the high value BBI investments into their 4 components (market/ancillary/reliability/other) and identify the allocator (and our actual allocator value) that has been used to allocate it, so we can in turn determine how much that allocator was driven by each of our VLI consumers (Refinery, Fonterra, GBC, etc) so that we can pass-through the portion of the transmission cost that they drive.
The allocation of the high value BBI investments appear to be loaded into the input tab of ‘Supporting information for APP B Indicative Pricing Model 2’ and link back to an internal TP spreadsheet.
Is the calculation of how the covered cost of the high value BBI investments is allocated to connection IDs contained somewhere in the models and I just can’t find it (and if so can you please point me in the right direction?), or has this not been released? If it has not been released, is it possible to provide it to us?
Response: Thanks for your email. The indicative pricing for high value BBIs you are looking at all relates to the 7 historic investments listed in Schedule 1 to the Guidelines. The allocations for these were determined by the Electricity Authority as part of their decision to issue new TPM Guidelines (10 June 2020). As noted in Appendix B to our 30 June TPM Reasons paper (footnote 6):
Adjustments have been made in Schedule 1 allocations provide for new customer connections and disconnections, and to correct for errors immaterial to indicative prices. These changes are captured in the allocations provided in Appendix A to the proposed TPM drafting.
Note that for the year our indicative pricing year covers (pricing year 2020/21) there were no post-2019 high-value BBIs. So, the proposed new standard methods are not relevant to your question.
The Electricity Authority may be able to provide you with more information. We were provided with a breakdown of the Schedule 1 allocations by customer and node but did not publish it with our proposal because that information is the Authority’s rather than Transpower’s.
09 September 2021 (SGLP) - Indicative transmission prices published on 9 August 2021
Question: The Southern Generation Limited Partnership (SGLP) acknowledges the transparency Transpower has provided as it works to convert the 2020 Transmission Pricing Guidelines into a transmission pricing methodology and, ultimately, transmission charges for industry participants.
We are working through the information provided to the Electricity Authority (Authority) on 30 June 2021 and published by Transpower in early August 2021 and fully understand this information is still under review / development.
However, SGLP is writing to bring to your attention issues with the indicative charges calculated for the Aniwhenua hydro power station. The connection configuration of Aniwhenua is complicated and Transpower’s approach appears to replicate errors made by the Authority in its modelling of indicative charges in 2019. My email includes a copy of our letter sent to the Authority at that time (see PDF above). Also attached is a copy of an Information Paper prepared by the Electricity Commission in 2008 to assist with understanding reconciliation (also see PDF above).
The Authority acknowledged their modelling was incorrect in 2019. You will see that [personal information removed] was copied in on our letter to the Authority as he has detailed knowledge of the connection of Aniwhenua – [personal information removed] would be a good resource for Transpower as you work to correct your model. The letter to the Authority has all the details I think you need to revise the modelling of the Aniwhenua power station for allocation of the residual charge (and please ignore the content that is obviously not relevant) so I have not repeated it in this letter. Please contact me if you require further clarification [note: see above for attachments].
Answer: Thank you for your letter in relation to the indicative residual charge pricing at Aniwhenua, which was included with our TPM proposal to the Electricity Authority on 30 June. We have reviewed both our proposed TPM drafting and our indicative pricing model and have concluded: - Our model incorrectly attributed gross load served by Aniwhenua injection into the Horizon network and/or Galatea embedded network to SGLP: this should have been treated as gross load for Horizon behind EDG0331. - Our proposed TPM drafting correctly treats this as gross load for Horizon behind EDG0331, as required by the Guidelines. Thank you for bringing this to our attention. Our expectation is the next iteration of indicative pricing will be released to support the Authority’s consultation later this calendar year. We will ensure this error is fixed in that release. For transparency, we have copied this response to Horizon, and will publish your letter and this response to it on our TPM webpage
09 April 2021 (Nova Energy) - Battery storage consultation
Question: As you might expect, the treatment of the residual charge for grid-connected batteries has a lot of overlap with Nova’s concern over charges on industrial load with embedded cogen. As such we want to be sure we capture the key issues in Nova’s submission. Would it therefore be possible to get an extension of time on Monday’s deadline, say a couple of days? (Still giving time for parties to respond in cross-submissions.)
Answer: Thanks for your email. Unfortunately, our timelines don’t allow us to extend the due date for submissions (or cross-submissions). Any submissions we receive late will be published (and marked as late), as has been our practice to date.
11 March 2021 (Rio Tinto) - Prudent Discount Policy
Question: How soon can we start to prepare an application for a Prudent Discount for NZAS? I am aware of the published timetable and that you will currently be in the process of preparing your Code submission to the EA by the end of June, with the likelihood the EA will take some months before approving it. That gives us the draft Code from the PDP consultation paper as reference material to date. However, I also note that Transpower intends to develop a Prudent Discount Practice Manual, and imagine this will be critical to prepare an application. Are you able to give me any insight as to when you expect to publish the Practice Manual and whether a draft will be circulated beforehand?
Answer: The form of the expanded Prudent Discount Policy (PDP) under the new TPM will not be certain until the Electricity Authority (the Authority) makes its final decision to incorporate the new TPM into the Code. This will follow its review of Transpower’s proposal and consultation with stakeholders. Our preliminary proposal for the PDP is now progressing through the Checkpoint 2 process, where we will receive the Authority’s feedback on our current approach. The Authority has said the checkpoints “will ensure Transpower’s proposal is well-aligned with the 2020 guidelines and so is more likely to elicit the Authority’s approval.” (Letter to Transpower, 10 June 2020). The Prudent Discount Practice Manual concept, which we introduced in our PDP consultation paper, would not be a part of the TPM. We are yet to consider if, or when, the manual would be produced. It would not be until after a new TPM is in place.
11 March 2021 (Vector) - Benefit-Based Charge and standalone cost prudent discount applications
Question: Vector asked for a response to a point they made as part of their 'TPM Options Consultation, Part B - Benefit-Based Charge' submission: “The most significant deficiency with the development of the TPM is the internal inconsistency between Transpower’s approach for assessing a standalone cost prudent discount application and the assignment of private benefits for assessing beneficiaries for BBC”.
We understand this submission point is linked to a recommendation made by Axiom Economics in its report to Vector and Northpower, included as part of Vector’s submission to our TPM Options Consultation process.
Axiom’s recommendation was as follows:
As Transpower goes about finalising the new PDP it should strive to ensure there is internal consistency with the methodology used to identify beneficiaries and allocate BBCs. This would mean accounting for factors such as impacts on energy prices when assessing hypothetical 'standalone' costs - not just transmission infrastructure costs.
Northpower’s submission also supported Axiom’s recommendation, and ENA made a similar comment:
“The ENA sees a significant in-principle shortcoming with the BBC analytical assessment being completely different to the methodology used to determine whether a Beneficiary Customer qualifies for a Standalone Cost Prudent Discount (SACPD)”.
Answer: The difference in analytical assessment reflects that the TPM Guidelines require the Benefit-Based Charge Method (BBCM) to be benefit-based, while the SACPD is cost-based. We recognise consideration may be needed of energy cost impacts in the SACPD assessment including, for example, if the SACPD provides for transmission alternatives that include non-network solutions.
02 March 2021 (Energy Link) - ACOT regime and the proposed new TPM
Question: We received a phone call via reception from Energy Link on Friday 26 February, 2021. He wanted to know if the proposed TPM would include any changes to the ACOT regime.
Answer: The ACOT regime is set by the Electricity Authority and is separate from the TPM. The Authority’s June 2020 TPM decision paper says it plans to consider and consult on Code amendments on related matters, including ACOT, alongside consulting on the proposed TPM (see below extract). We note the new TPM may impact ACOT payments Distributed Generation receives, as transmission charges will be more fixed and less avoidable e.g. particularly with removal of the RCPD peak-usage charges.
The Electricity Authority
Note: Potential Code amendments
17.37 The 2019 Issues Paper discussed (in Appendix F) some potential Code amendments on related matters including allocation of loss and constraint excess (LCE), the avoided cost of transmission (ACOT) provisions in Part 6 of the Code and an amendment to ensure workability of the TPM.
17.38 The Authority is not yet proposing to make these Code amendments and they are not considered further in this paper. Subject to consideration of submissions received on these topics, we expect to consult on whether to adopt the Code changes (if the Authority considers them necessary) alongside the proposed TPM to be developed by Transpower.
19 February 2021 (NZ Steel) - TPM Transitional Congestion Charge decision
We are responding to the Transpower decision not to include a TCC in the TPM proposal to the Electricity Authority.
NZ Steel does not consider this decision to be in the best interests of consumers or New Zealand. However, this email is not to relitigate the matter, but to seek clarification as we plan plant maintenance work and coordinate with Alinta Energy regarding cogeneration at our Glenbrook site.
Please confirm our understanding is correct:
- RCPD measurement will cease at midnight 31 August 2021.
- Transmission charges for the 1 Sept 2020 to 31 August 2021 measurement period will be applied as an interconnection charge from April 2022 to March 2023 as per the current TPM.
- From 1 September 2021 there will be no Transmission charges based on real-time demand ie whatever the Glenbrook gross or net demand, it will not impact Transpower charges to NZ Steel or Alinta other than through the anytime gross charge proposed in the new TPM to allocate the Residual, and only then if a rolling average is adopted to the historic average anytime gross demand which the Electricity Authority has already set.
- On whatever basis Transpower plans to recover revenue from April 2023 to March 2024 it will not involve demand measurement after midnight 31 August 2021.
Plant maintenance shuts are, currently, being planned for September/October 2021 which involves the Alinta kilns cogeneration plant.
As you are aware we have been managing load carefully during upper North Island peak periods consistent with the pricing signals contained in the current TPM hence we would previously not have planned shuts during the May to September period.
In an extreme situation a change in our shut management processes could see a short-term additional 150MW of net demand.
It is important we have an early response to confirm our understandings outlined above.
Answer: Thank you for your email below regarding the implications of Transpower conclusion it will not include a transitional congestion charge in our new TPM proposal required to be submitted to the Electricity Authority by 30 June 2020. Your questions relate to the end of the RCPD price signal in the context of NZ Steel / Alinta planning towards plant outages in coming years. Because the timeline for the new TPM taking effect is a matter for the Electricity Authority to decide under Part 12 of the Code I am forwarding this question to Rob Bernau at the Authority. We will publish this question (email below) and our response (this email) on our webpage as is our practice for questions we receive in relation to TPM development.
15 February 2021 (Counties Power) - TPM Options Consultation re: regionalised charges
Question: Consistent with its submission to the TPM Options Consultation, Counties Power expressed concern to our Customer Services Team: “Transpower is recommending regionalised TPM charges without stating the regions. If Counties Power is included into the Upper North Island Region, then we would face a significant increase in transmission charges while not receiving any of the transmission benefits. This is contrary to the EA advice on the TPM impact to Counties Power and the EA TPM guidelines.” Counties Power asked for this feedback to be provided to our TPM development team.
Answer: We received your feedback on regionalised TPM charges via our Customer Services Team. We’re currently drafting our Summary & Response document to feedback received during the TPM Options Consultation, and we’ll be sure to address your concerns in it. Our aim is to make this available by the end of February. Thanks for your continued interest.
10 December 2020 (ENR) - TPM Options Consultation submissions deadline and project timeline
Question: From Electricity Networks Association via email - 09 December 2020. I have just come off a call with my brains trust members group where we reviewed the ENA TPM Options submission draft 1. There was a bit of a discussion on timing for subs and X subs on this wrt Xmas period and, while I told them that TP were on a fixed and tight timeline with TPM development, I undertook to contact you regarding flexibility to receive input on this submission after the 14th. There was also the unanswered question about whether we would have another opportunity to provide feedback closer to the finishing line in 2021 (after EA have responded to you on your full TPM package). Your thoughts?
Answer: Transpower response via email – 10 December 2020 Thanks for your question. You are correct in your assumption that the timeline and other process constraints for TPM development mean that we are unable to offer an extension to our 14 December (submission) and 18 January (cross-submission) closing dates for the TPM Options consultation. We do appreciate the challenge that presents for our customers and other stakeholders. With respect to planning beyond the current consultation process, please refer to our project timeline on our webpage where we have noted “We consider it unlikely that there will be sufficient time following Checkpoint 2 to engage meaningfully with stakeholders on the draft proposed TPM. However, we continue to explore what options are available to hear your feedback ahead of submitting our proposed TPM to the EA next June.” Please note that your question below, and our response above will be published on our webpage for the benefit of our other stakeholders. Thanks to you and your members, including the ‘brains trust’ for engaging in our process – we do really value the feedback.
08 December 2020 (NZIER) - TPM Options Consultation Part C
On 1 December 2020, we received questions related to the TPM Options Consultation Part C from the New Zealand Institute of Economic Research (NZIER). These questions were responded to in our online drop-in session that day. You can view the transcript and video recordings of that session on our website. We also provided the NZIER written responses to each question within their original memo:
From NZIER: Purpose - The questions in this note are focused on TPM Options Development Part C (referred to as ‘Part C’ in this note). Unless otherwise stated paragraph numbers in this note refer ‘Part C’.
Question: Residual charge reallocation. Paragraphs 29, 34 and 37. Could Transpower provide examples of: What criteria Transpower will use to determine whether a reduction in demand is ‘substantial’ (paragraph 29 of the Guidelines)? How the step change adjustment is expected to be calculated for new customers as opposed to an increase in offtake by existing customers and how the RCAF will be set?
Answer: We have not yet considered what the threshold should be for “substantial” in clause 29 of the Guidelines. One option is to use the “substantial” threshold we are proposing for the increase in load or injection adjustment trigger, which would mean a reduction in maximum gross demand of more than 20% and at least 5MW post-2014 would be required (section 4.7 of Part C). Transpower already has to estimate various metrics for new customers (clause 34(6) of the current TPM) and we expect to use the same broad methods to estimate baseline AMDR for new customers under the new TPM. We expect inputs to the estimate will include the capacity of the new customer’s plant, information we have about how similar plant has ramped up, information provided by the customer about its intentions (being wary of incentives the customer may have to under-estimate its demand), and any information we have about the customer’s actual demand post-2018. Our initial thinking is that we should have the ability to re-open our estimate of baseline AMDR if it transpires we have materially over or under-estimated the new customer’s maximum gross demand. Our initial thinking is that RCAF will be set at 1 for a new customer until the customer has been a customer for at least 8 financial years. This is the period required to provide a value for Ut in clause 30 of the Guidelines. The customer’s AMDR would not change from its baseline during that period (unless we re-opened it due to a material over or underestimate)
Question: Residual charge reallocation. Paragraph 35. Has Transpower’s interpretation of paragraph 33(c) of the Guidelines expressed in paragraph 35 of Part C been tested with the Electricity Authority (EA)?
Answer: Formal feedback from the Authority Board on our interpretation and application (or not) of clause 33(c) of the Guidelines will come after the “checkpoint 2” process next year.
Question: Residual charge reallocation. (Paragraph 33(c) refers to what a new entrants share of the residual would be if the new entrant had been fully operational from 1 July 2014 – the start date for the measurement of historical anytime maximum demand (AMD) for existing load customers when the TPM was designed.)
What does Transpower regard as the key criteria it would use as a guide to forming the ‘reasonable opinion’ sought by the EA in paragraph 33(c) of the Guidelines.
Answer: As noted in paragraph 35 of Part C, our initial thinking is that in most cases treating a new customer (or new or upgraded grid-connected plant) as fully operational from the start would be inconsistent with the Authority’s statutory objective and could unfairly disadvantage new customers relative to existing ones. Our initial thinking is therefore that we should depart from clause 33(c) of the Guidelines. As noted in our response to question 1 above, we think we should take into account matters in addition to capacity when estimating baseline AMDR (and other metrics) for new customers.
Question: Residual charge reallocation. (Paragraphs 28 and 30 of the Guidelines emphasise the use of historical AMD as the core allocator of the residual for existing customers while changes in share of gross usage are used as a lagged modifier of the core allocator.) Schedule 1 Re-allocation Is Transpower able to provide an estimate of the level of the benefit based charges for the Schedule 1 assets over the period 2025 to 2030 to assist submitters to gauge the future materiality of this charge?
Answer: We cannot provide an estimate at this time as we have not finished designing the method for calculating the covered cost of a benefit-based investment, or calculated covered costs for the Schedule 1 investments. The proposed TPM we submit to the Authority next year must be accompanied by indicative transmission charges, so at least by that point indicative benefit-based charges for the Schedule 1 investments will be available.
Question: Adjustment triggers. Damage and other non-capex change in covered cost - Paragraph 57.3 Can Transpower: Outline the criteria it would use in exercising its discretion to assess materiality for the adjustment trigger? Indicate a likely range for the quantitative trigger (‘an X% increase or decrease’)? (As the threshold refers to the whole annual BBC it would seem that either X would have a very small magnitude or Transpower does not envisage that this adjustment will be common or significant.
Answer: As noted in paragraph 57.3 of Part C, our initial thinking is that materiality in the case of this adjustment trigger should be at our discretion. This is because of the relatively wide range of events and changes in circumstance that could activate this adjustment trigger. For the same reason, we have not developed criteria for exercising our discretion. We are interested in hearing any stakeholder views on what the appropriate criteria might be, including any appropriate quantitative threshold. We agree that if there is a quantitative threshold based on the percentage increase or decrease in covered cost (X%), the value of X would be small.
Question: Capex on existing BBI - Paragraph 66 Can Transpower indicate what criteria it would use to assess ‘materiality’ of the change in distribution benefits and how the threshold for materiality might vary for within region as opposed to inter region benefits?
Answers: Our assessment of the materiality and intra versus inter-regional impact of capex on an existing BBI would depend on the nature of the capex. For example, a tower painting project is very unlikely to change the distribution of benefits so would almost certainly not result in a reallocation adjustment of any sort. On the other hand, adding an additional circuit to a transmission line may well result in a change to the distribution of benefits from the BBI, possibly beyond a single region. In general, our base capex projects (which are mostly maintenance driven) are less likely than our major capex projects to result in a change to the distribution of benefits from a BBI. We note that when an existing BBI is upgraded the Guidelines allow us to treat the upgrade as a new BBI (clause 26(a)). In that case we would not change the allocation of the underlying BBI at all. This may turn out to be the way most upgrades are handled, as we will likely have considered the incremental benefits of the upgrade as part of the investment test.
Question: New customer - Paragraph 74 Paragraph 15 of the Guidelines refers to the ‘present value’ of the covered cost of the BBI which implies discounting of future costs. The example in paragraph 74 refers to covered cost over a very short asset life. Can Transpower provide an example of the type of allocation discussed in paragraph 74 which includes the effect of calculating present value and a longer asset life?
Answer: The table in paragraph 74 of Part C is only intended to illustrate the total benefits approach required for new customers under clause 33(b) of the Guidelines. In the hypothetical example, it can be assumed that the $50 covered cost of the benefit-based investment has been calculated on a present value basis and otherwise in accordance with clause 15 of the Guidelines.
Question: Exiting customer - Paragraph 79 Can Transpower: Clarify how the ‘relevant BBI’ is defined for the exiting customer and if the BBC threshold for the customer ($100k) applies to the sum of BBC over all relevant BBI? Describe the rationale for nominating a threshold of $100,000 in this case and how this aligns with the rationale for other materiality tests.
Answer: A “relevant BBI” would be any benefit-based investment for which the exiting customer formerly paid part of the benefit-based charge. The $100,000 threshold would apply per relevant BBI, not across all of them. There is no underlying rationale for the $100,000 threshold, other than our view that there should be some materiality threshold that needs to be crossed before moving away from the simplest type of reallocation adjustment (pro rata). We are interested in hearing any stakeholder views on what the materiality threshold (if any) should be for moving to a more complicated form of reallocation adjustment.
Question: New plant or upgrade - Paragraph 89 and Plant de-connection or de-rating Paragraph 100 Can Transpower describe the rationale for adopting a physical capacity increase as the criterion for reallocating BBC for new or upgraded generation plant and this aligns with the financial and other physical thresholds suggested in Part C.
Answer: The Guidelines require the new plant or upgrade to be “large” before this adjustment trigger applies. In our view, the adjective “large” is describing the plant or upgrade itself, not the magnitude of its injection or load. We consider capacity is the best metric for measuring the magnitude of new plant or an upgrade. As noted in paragraph 89 of Part C, our initial thinking is that a capacity threshold of 10MW is appropriate, as this aligns with the thresholds for generator offers in the Code.
Question: Increase in load or injection - Paragraph 95 Can Transpower describe: The rationale for adopting a change in peak load/generation as a criterion for reallocating BBC? How long the change in peak needs to be sustained for (is this a single trading period measure like AMD or an average over several trading periods like RCPD)? How Transpower would form a view that it would be sustained over five years? How criterion aligns with the financial and other physical thresholds suggested in Part C?
Answer: Our interpretation is that this adjustment trigger is aimed at capturing substantial increases in load or injection by existing, non-upgraded plant (new plant and upgrades being captured by the previous adjustment trigger). In that case, it is appropriate to consider metrics related to the use of the relevant plant. In our view, an increase in peak load or injection is the best indicator of increased plant use, at least for the purposes of activating the adjustment trigger (not necessarily for the reallocation itself). We are interested in hearing from any stakeholders who disagree. We are considering a “substantial” threshold of a more than 20% and at least 5MW increase in peak load or injection. This adjustment trigger is different in nature to most of the others because it does not require a physical change to the grid or anything connected to it, or a change to Transpower’s customer base. Accordingly, we do not consider there is any obvious basis for aligning the materiality threshold for this adjustment trigger with those that may apply under other adjustment triggers. Our initial thinking is that a substantial increase in peak load or injection would be sustained if it is reasonably likely to persist for 5 years. That would ultimately be a matter for Transpower’s judgement, based on available information about the reasons for the increase. A temporary increase caused by matters outside the customer’s control would not be treated as sustained.
01 December 2020 (Contact Energy) - TPM audit query
Question: Quick query for you. Under the existing TPM, is there any scope for third-party oversight or audit process available of Transpower's annual charges? The EA is the guardian of the Code and the TPM falls within the Code but I'm unclear if the EA or anyone else has any reserve powers to review or audit Transpower's annual charges? The reason for the question is that it strikes me that implementation of new TPM is likely to become a bit of a black box to everyone not directly involved within Transpower for setting the charges. Having some kind of independent third-party oversight/audit, even if only on a by-exception basis might provide a degree of comfort that the charges are as they ought to be.
Answer: Subpart 4 of Part 12 of the Code does provide for auditing of Transmission Prices (cl. 12.97-12.102). The current provisions provide that the Authority can appoint an auditor to confirm that prices have been calculated in accordance with the TPM. Any such EA appointed audit would be after we’d completed our annual pricing process. Our operational approach each year is to provide the Transpower Board with an external audit opinion to help support their approval of prices. This provides our directors with comfort that any audit that the EA could commission is unlikely to pick up anything new that might unwind the decision. Our Board’s certification of prices is confirmed annually to the Electricity Authority.
23 November 2020 (MEUG) - TPM Options Consultation
Question one: Referring to Table 2 in Appendix 1 (p51):
a) How is this table to be interpreted when applying BBC? For example, does it mean:
~ The Investment Test is met if the capex to increase capacity of the line from 50 MW to 200 MW is less than or equal to $7,800 (the change with the investment leading to lower total system generator costs).
Answer one a1: Yes, correct
~ If say the capex was exactly $7,800, the BBC would be applied 100% to the generator at Node A because they are the only party that had a net positive change in their net private benefit.
Answer one a2: In this simplified example, the only beneficiary is the generator at Node A because they are the only party that receives a positive net private benefit from the investment. They would pay 100% of the investment regardless of the project cost. However, note this example shows a snapshot of benefits for a single hour for a single scenario. In reality, load and generation varies throughout the year and over the life of the investment under different potential future scenarios which would likely result in the load at Node B also receiving private benefits. For example, if load at Node B fell to between 70MW and 180 MW, then the price with the investment at Node B would fall to $40/MWh and Node B load would be deemed a beneficiary (all else remaining equal).
~ There is nothing the consumer at node A can do to stop or modify the proposed capex of $7,800 even though they a decrease in their net private benefit of $1,200.
Answer one a3: The TPM is not changing how stakeholders can engage with or inform our investment decisions– the consumer at Node A would be able to submit on the proposed investment through the usual consultation processes required by the Capex IM.
b) Not sure why there is a transmission rental in the scenario before the transmission investment. Doesn’t the generator at node A benefit from selling 20MW at cost ($40/MWh) to load at node A and just up to or equal to $100/MWh to load at node B and hence they capture the transmission rental?
Answer one b1: Our modelling assumes generation offers and dispatch based on operational costs. In the counterfactual without investment, this results in price separation and transmission rentals between A->B due to a lack of transmission capacity. With investment, the generator at Node A can maximise its output and prices level out in the market, so there are no transmission rentals.
Question two: Can Transpower provide an indication of amount of the MAR (annual capital cost, depreciation and operating expense that would be recovered through benefit based charges) for MCP, E&D (not included in MCP) and R&R projects over RCP3?
Answer two: This is a matter that will be addressed as we calculate indicative prices, which we must include with our proposal to the Authority in June 2021.
Question three: Can Transpower comment on how the BBI projects will be grouped for cost allocation modelling purposes as the benefits for some may be interdependent or contingent on other projects?
Answer three: Our current thinking is to use a market dispatch model with the grid representation based on constraints associated with the investment being assessed and simplifying constraints outside the region of the investment. We refer to this in the consultation paper as the investment grid. The price signals created from the market dispatch model with the investment grid approach would be used to help identify the regions that benefit from the investment. Note as per the TPM Guidelines we are only required to consider positive net private benefits. Where the benefits of an investment are largely dependent on other investments proceeding, then such investments could be considered as a portfolio when the investment decision is made for this portfolio. We have considered this in thinking about the investment grid approach and consider that such portfolio of investments could be accommodated with the investment grid approach with constraints changing as modelled investments change [see paragraph 95]. The resulting changes in simulated prices would impact calculated benefits and reflect the change in impact on charges. Where a portfolio of investments is not being considered as part of the investment decision, there could still be a dependency between the private benefits and beneficiaries of an investment and a future transmission investment occurring. However, if these future changes to private benefits and beneficiaries are not necessary for the first investment to have a positive net-benefit, then the option, cost, and timing of the second transmission investment may not be well understood, which would add discretion and complexity to our assessment under the TPM. Therefore, in the interests of reducing discretion and the risk of false precision, we think the investment grid approach should err on the side of spreading the benefits over a wider region by assuming an unconstrained grid outside the investment region as opposed to considering them concentrated on local customers.
Question four: Can Transpower list:
a) Recent (say since the start of the just completed RCP3) approved MCP’s, listing for each the expected market benefits and reliability benefits if they were quantified in the final CC approval or if not indicating which MCP’s were primarily market benefit or reliability benefit driven?
Answer four a: In the past, we have not necessarily explicitly quantified the same counterfactual scenario as outlined in Part B in our proposals – for example, because the benefits would be very high so doing nothing is not a sensible option, or because the project was primarily driven under the deterministic arm of the grid reliability standards. However, below is a qualitative summary of the primary benefit of Listed Projects or MCPs approved by the ComCom in the last 5 years, and our current expectations of the primary benefit (market or reliability). Note, until we produce indicative pricing we cannot definitively comment on if secondary benefits are material. Furthermore, we note per the Guidelines only those investments commissioned after June 2019, or listed in Schedule 1, will have benefit-based charges.
- Oteranga Bay to Haywards (Listed Project) – primarily market.
- CPK-WIL B reconductoring (Listed Project) – a mix of reliability and market benefits (because the line connects to both Central Park and West Wind).
- Waikato and Upper North Island Voltage Management (MCP) – primarily reliability.
- We recently began construction of the Clutha Upper Waitaki Lines Project. We expect this investment to primarily deliver market benefits.
- The ComCom has recently issued its draft decision to approve the BOB-OTA MCP. If it is approved, this has a mix of market and reliability benefits.
b) An approximate view of which future (say next 10- years) possible MCP’s might be primarily justified by market benefits or reliability benefits or a mix of the two?
Answer four b: Below is a list of possible MCPs and listed projects occurring out to 2030, and our preliminary view of their primary benefits (noting detailed analysis on these projects has not yet occurred):
- Net Zero Grid Pathways (investments relating to a Tiwai exit) – primarily market benefits.
- BRK-SFD B reconductoring – primarily market benefits.
- Upper South Island voltage stability – primarily reliability benefits.
- Waikato Regional interconnection capacity – a mix of reliability and market benefits.
- OTA-WKM A and B reconductoring – a mix of reliability and market benefits.
- BPE-WIL A reconductoring – a mix of reliability and market benefits.
For questions 5 -12 Understanding the recent past and Transpower’s view of the trend for the medium-term future would assist us prioritise whether we need to focus on TPM for MCP driven by market benefits, or reliability benefits, or both:
Question five: Will the TPM specify the type of algorithm to be used to estimate aggregate benefits or the actual software package? Refer . If the TPM describes the type of algorithm, then what is the process for choosing the actual software package and will that process include consultation with interested parties?
Answer five: We recognise the TPM needs to set rules for how net benefits, including market benefits, will be determined so that there is broad consistency of approach between different benefit-based investments. However, there is a danger of over-prescription if those rules are specified at too low a level or in a technology-specific way. Our current thinking is not to specify the algorithm or software package that will be used to calculate market benefits. Instead, we anticipate the TPM will describe the key properties of the market dispatch model, such as (a) the approach used to inform the resource scheduling in the market dispatch model should take into consideration the valuation of water and operational requirements of the New Zealand power system, and (b) should be broadly consistent with the approach used in the assessment of investment benefits as part of the investment test. We mentioned the SDDP algorithm and software package in the consultation paper [see paragraph 205] as its currently being used as part of the investment test and could potentially be a candidate for the market dispatch model to inform the benefit-based charge (standard method).
Question six: Can Transpower provide examples of how the operational cost for wind and geothermal generators will be modelled and how the inputs from EDGS and MBIE generation expansion modelling would be included in the modelling of generation investments?
Answer six: The operational cost for wind and geothermal could be modelled using a $/MWh input into the market dispatch model reflecting the marginal operating costs e.g. due to operating and maintenance for wind generation and similar for the geothermal plus any associated carbon costs to account for carbon emissions from geothermal generation. This information is incorporated as part of the ‘generation stack’ recently reviewed by MBIE, and we understand the next EDGS update will incorporate the updated information. The Capex IM requires Transpower to use MBIE’s EDGS (or variation of the EDGS). The EDGS provides scenario stories on how different potential future system states could play out. These scenarios are used to provide an indication of future generation options and demand growth that might eventuate. Transpower uses these scenarios and any updates to help inform future generation and demand scenarios which are then used to assess the costs and benefits of an investment. Generation expansion software (such as OptGen) could be and has been used by Transpower in the past to help inform different potential generation scenarios that might prevail under the different EDGS scenarios. To be broadly consistent with the investment test, it would seem reasonable to utilise similar future generation and demand scenarios for the assessment of the benefit-based charges for that same investment.
Question seven: Can Transpower provide additional information on the calculation of consumer benefit  particularly with respect to how the maximum price a consumer is willing to pay is determined and how this estimate is varied for different types of customer (residential, commercial, EDB connected industrial and direct connect)?
Answer seven: Willingness to pay and VoLL are similar concepts. The term VoLL is commonly used to assess the cost of interruptions to supply, whereas willingness to pay is more commonly used when discussing the response of consumers to prices in the wholesale market. However, given a lack of transmission capacity can cause very high (scarcity) prices in the wholesale market and emergency load management, there is some overlap between the two concepts. We acknowledge willingness to pay and VoLL will vary between individual customers. However, both are difficult to objectively measure because very high (scarcity) prices in the wholesale market are rare, and because there is no market through which consumers can express their preference for reliability of supply. Therefore, as outlined in paragraph 243 of Part B, in the early years of an investment we currently think willingness to pay should be based on a VoLL/scarcity pricing value (set in the Code e.g. either the grid reliability standards in Part 12 or based on the upcoming default scarcity pricing blocks under RTP amendments to Part 131 ). In the later years of an analysis period, we currently think willingness to pay should be based on the long-run cost of self-supply e.g. using diesel generation or solar + battery storage. See also the responses to Question 8 below.
Question eight: Transpower’s initial view is load does not need to be aggregated into groups other than regional groups . For generation though different groups are being considered. MEUG is unsure why different groups for generation are being considered and not for load when there are similarities between base load generation and base load large industrial load versus intermittent wind generation and likely future unpredictable retail level SCDG/DSM. Can Transpower comment on the following two propositions:
a) For MCP that are primarily driven by reliability benefits, there could be very granular VoLL assumptions for different load groups including be-spoke assumptions for material load. Hence grouping loads will be feasible assuming granular VoLL assumptions are used.
Answer eight a: We acknowledge this point. However we are also conscious that VoLL is challenging to determine and not readily observable hence we typically rely on customer surveys (whereas for generation we can reference relative technology characteristics). We are wary of creating an incentive for customers to understate their VoLL for the purpose of avoiding transmission charges, at the expense of other customers. Furthermore, we are conscious that it is not possible for us to differentiate the level of reliability we provide on the interconnected network – i.e. it is a shared service. Hence – as outlined in Question 7 – we currently think a single value should be used for all customers based on a third-party source set in the Code. One possible exception to this is if customers can demonstrate they are willing to adopt a VoLL that has real-world consequences for customers (including by engaging in our investment decision processes under the Capex IM) – for example, a materially lower service level target than other customers under Transpower’s incentive framework with the Commerce Commission. We are interested in stakeholders’ feedback and alternative suggestions based on objective or third-party measures.
b) For MCP that are primarily driven by market benefits, the difference in the demand curve for delivered electricity between households and C&I customers could differ markedly. Therefore, the option of distinguishing between different groups needs to be an option depending on the MCP.
Answer eight b: For the same reasons as VoLL, we currently think there should be a single demand curve for all customers. One possible exception is where a customer can demonstrate a strong statistical relationship between their offtake and a transmission or wholesale market price signal. We are open to considering a more granular demand curve for a particular set of customers. We are interested in stakeholders’ feedback and alternative suggestions based on objective or third-party measures.
Question nine: In  Transpower notes: ‘the Authority gave support to using capacity (for load) … as proxies for net private benefit.’ However in the table below  the proxy for capacity is narrowed to transformer capacity. Can Transpower provide data on the current transformer capacity that would be covered by this proxy and indicate how the use of this benefit proxy would be compared to the other benefit proxies suggested in the table (historical and forecast net coincident peak demand)?
Answer nine: There are several options for using transformer capacity as a proxy, including:
- The sum of the nominal rating of all supply transformers to a customer
- The nominal N-1 rating (for sites with N-1 security)
- The maximum possible loading on the customer’s transformers before they reach operational capacity
- N-1 operational rating of all transformers (for sites with N-1 security)
As an example, consider a GXP with two transformers. Both have a nominal rating of 30 MVA. The first transformer has an operational rating of 35.5 MVA, and the second has an operational rating of 38 MVA. The transformers have the same impendence – i.e. each transformer has the same amount of power flowing through it when both are in-service. At this GXP:
- The sum of the nominal rating of all supply transformers is 60 MVA
- The nominal N-1 rating is 30 MVA
- The maximum possible loading on the transformers before they reach capacity is equal to 71 MVA (35.5 × 2). Note, it is not equal to the sum of the operational capacities because the first transformer would begin to overload as soon as its loading exceeds 35.5 MVA, despite there still being some spare capacity on the second transformer.
- The N-1 operational rating of the transformers is equal to 35.5 MVA – equal to the lowest operational rating of the two transformers.
Question ten: Can Transpower describe how the BBI project benefits will be allocated between ‘peak demand driven’ and ‘non-peak demand driven’ and provide an estimate of the proportions of RCP3 project cost recovery that is expected to be allocated using ‘peak demand driven’ and ‘non-peak demand driven’ benefit proxies?
Answer ten: The intent of the peak vs. non-peak distinction is to use a proxy that best matches when benefits occur under the standard method, as identified during the investigation and analysis of the project. Therefore, we cannot provide a forward-looking estimate of if a project is likely to use a peak or non-peak proxy under the standard method. For the simple method, we do not currently have a view on whether peak or non-peak proxies are better for use under the simple method, and are interested in stakeholders’ views.
Question eleven: The CUWLP case study schematic in  illustrates lower SI (region 1) generators are “injection beneficiaries” with a large increase in prices and load north of the CUWLP (region 2) are “offtake beneficiaries” as they benefit from lower prices. Questions:
a) Is the scale of the blue rectangles proportional to the NPV benefits? Or is the scale related to something else?
Answer eleven a: Not necessarily. The blue rectangles are the calculated PV of the average price difference with and without the investment under one possible future scenario. This example was used to provide an illustration of how the investment grid could be used to provide regional price signals which would be an input into the beneficiary identification (benefit proportion). If this was done as per the standard method discussed in the Part B consultation paper, several different scenarios (based on the EDGS or variants) would be used. The benefit impact would also need to consider the price at which generation and load would be willing to inject and consume, the quantity of injection and consumption and apply processing to translate the benefits to a proportion as outlined in Section 2.3 of the Part B consultation paper.
b) Not shown in the schematic is the decrease in net private benefit to customers in region 1. How is that disbenefit to load in region 1 because of CUWLP proceeding considered in calculating share of BBC? For example, to avoid load in region 1 being charged a share of CUWLP BBC.
Answer eleven b: The TPM Guidelines require allocation based on expected positive net private benefits. In the paper, we have outlined our current thinking on removing disbenefits (negative benefits). This involves removing negative benefits only after summing positive and negative benefits. This is discussed in Section 2.3.3. of the Part B consultation paper.
Question twelve: Transpower’s initial view of allocating regional benefits is to use physical metrics . Can Transpower give an example(s) of how this would work and for the following case. Assume a MCP is being considered to allow for expected demand growth in and north of the Auckland Isthmus. There are two demand groups: base load industrial and retail. Base load industrial is expected to decline over the next 20-years whereas retail is expected to grow and more so than the decline in industrial base load; hence the proposed MCP. There are likely to be two sets of beneficiaries: load in and north of the Auckland Isthmus and generation south. We are interested in how the share of load benefits are shared between base load and retail load. The benefits to load will grow over time but the proportion of charges will be set in the first year and will be unchanged over time (i.e. we assume consistent with the approach in Schedule 1 of the TPM Guidelines for the seven pre-2019 investments with prescribed allocation of BBC). How can we be sure that the industrial base load grouping in this case that pays its fair share of NPV benefits to load if the physical metrics proposed on p38 are used when the main benefit to that load group is in the near term but the aggregate benefit to all load groups will be highest at the end of the 20-year planning horizon?
Answer twelve: As required by the TPM Guidelines, the TPM will contain triggers for adjusting the allocation of benefit-based charges at some point after the initial allocation. These are discussed in section 4 of Part C of the consultation package. Some of the adjustment triggers may apply in circumstances where the balance between industrial and retail load has changed, depending on why it has changed. Specifically:
- Section 4.3 - New customer
- Section 4.4 - Exiting customer
- Section 4.5 - New plant or upgrade
- Section 4.6 - Increase in load
- Section 4.7 - Plant disconnection or de-rating
- Section 4.11 - Substantial and sustained change in grid use
Therefore, one option would be to assume within the initial allocation that base load industrial plant remains at its current offtake (while consumer load grows) and reallocate charges at the point in time the industrial plant permanently increases or decreases its offtake.
17 November 2020 (Trustpower) - TPM Options Consultation
Question: To help with understanding how the new BBC and reallocator arrangements will work in practice, would it be possible for Transpower to provide a case study for a more complex transmission investment project?
While a detailed case study could usefully be walked through during one of the scheduled drop in sessions, it would also be valuable to provide a written document containing the details to enable greater reflection and identification of any practical and/or philosophical issues that might emerge.
For example, it would be useful to apply the proposed new arrangements to an upcoming “deep” investment (i.e. HVDC capacity upgrade project etc) where the need for the investment is largely driven by forecasts of what is predicted to occur in the future. It would also be useful to consider how the methodology works on a retrospective basis for a deep investment.
We have made this suggestion previously in response to the case studies that Transpower provided as part of its submission to the Authority on the third TPM issues paper. Attached is the relevant expert report from Dave Smith on this matter in case this is of help (refer to section on GIT retrospective). [This is included in the download above for this question.]
Answer: At this stage in the TPM development process we are not able to provide a case study, particularly for a deep/complex interconnection investment. The current consultation is seeking views on options and concepts relevant to the key design decisions we need to make in order to develop case studies of the type you’re interested in. These design decisions will inform our preliminary proposal for the BBC component of the new TPM, which must be submitted to the EA for the Checkpoint 2 process. We are interested to hear the views of our stakeholders, which might include views about any practical difficulties of applying BBC options to different types of investment, including the ‘deep’ type your question relates to.
29 October (Mercury) – First Mover Disadvantage Consultation
Question: Could you clarify whether the word “not” is missing from this sentence? I assume that is the case but just wanted to make sure as it may change how we approach this issue/question.
[Page 9 of First Mover Disadvantage Consultation paper]
Answer: Thank you for your question. You are correct – the word “not” is missing from para 27. It should read “Our initial thinking is Nova’s suggestion should not be adopted because…”. We have updated the consultation document to rectify this.
21 October 2020 (Refining NZ) - Connection Charges Summary and response document, focus area 7
Question: I would like your clarification around the Transpower’s response on Area Focus 7: Connection assets decommission costs. I think the language use on the summary and response document on page 14 is confusing, as it states:
“Transpower response: We consider legitimate concerns have been raised about a “last man standing” problem and retrospective application of this proposal. Based on our consideration of submissions, our thinking is now that it would be better to continue to allocate connection asset decommissioning costs to all customers connected to the asset, regardless of the reason for decommissioning. This would mean that the cost recovery would default to the residual charge. We will make final decisions as part of the finalisation of our TPM proposal.”
Can you please clarify if Transpower is now thinking to:
- adopt proposed option 1: recovery through the residual charge; or
- adopt option 2: allocate connection asset decommissioning costs to all customers connected to the asset, regardless of the reason for decommissioning; or
- adopt a combination of these two options.
Answer: Thank you for your question, and for taking the time to provide your feedback on our consultation paper and summary and response. We agree that part of the summary is a bit confusing. What we mean to say is, based on the submissions we received, particularly relating to the “last man standing” problem, our thinking now is to retain the status quo approach of socialising decommissioning costs across all load customers, being currently via the interconnection charge (option 1). Under the new TPM that would mean decommissioning costs for connection assets would be socialised through the residual charge, unless we have an agreement outside the TPM (for example an investment contract) under which the relevant customer(s) have agreed to pay all or part of the costs. We will update the response paper soon to clarify this.
23 September 2020 (Trustpower) - forthcoming workshops on TPM congestion charge
Question: The proposed transmission congestion charge is a new charge. If adopted it will partially replace a charge that has been in place for many decades. Any congestion charge recommended by Transpower as part of the TPM will directly affect our business. For this reason our Board will expect us to participate fully in its design.
Trustpower is pleased I have been directly invited to participate in one of the two workshops on 6 October as a representative of embedded generators. However, a number of other members of our transmission pricing team are also keen to have real time access to the discussions in these workshops rather than wait for Transpower to upload the videos which, in any event, may not capture the full tenor of the meeting.
We note it is easy for the meeting host to mute any observer who attempts to ask questions so there is no risk to the efficient conduct of the meeting by allowing attendance in this manner.
In our view providing real time access will enhance the quality of our submission to you on this important topic. This is particularly the case given the unconventional process you have proposed and the limited time you have afforded (two weeks) for making what you have termed a ‘cross-submission’.
Could you please advise if it is possible for Trustpower and its advisers to attend the proposed online workshops on the transmission congestion charge as an observer.
We believe this will enhance the accessibility of the process.
Answer: Thank you for your letter dated 23 September. We appreciate Trustpower’s interest in Additional Component D: Transitional Congestion Charge and are very grateful you’ve made time to be available to participate in one of our two workshops on 6 October.
Transpower engaged John Hancock to facilitate these sessions including because he has built up considerable experience in running such forums using virtual tools. We are employing the virtual approach in part to de-risk our plans given the uncertainty of how COVID might next impact the country and/or parts of the country. But also this format makes it easier for the experts we have invited to participate to do so around their other commitments.
John’s experience is that he has tried and tested allowing observers, and learned it changes the dynamic of the session - it turns into a set of presentations rather than a full and open discussion. Further, if we brought in others from Trustpower, we would have to make the same oﬀer to all interested parties. We would then have to address the practicality of muting and managing everyone while still trying to focus on the 9 original invitees. It is a technical workshop with expert invitees so we have to focus on them for it to work. We are very mindful that the input of those experts we have invited will be invaluable in informing our own thinking, process and, if necessary, development going forward.
We will publish the unedited recordings from both sessions to our webpage the morning following the workshops – so on 7 October. The risk that the full tenor of the workshops is not captured is small.
We appreciate that two weeks is a short period for the ‘cross-submissions’ stage, however our timelines across the full TPM Development scope are tight in all areas and we are mindful of the subsequent process steps to come if our June proposal is to include a TCC proposal.
I’m sorry we cannot, on balance, accommodate your request. We will publish your letter and this response on our ‘TPM questions and answers’ webpage.
7 September 2020 (MEUG) - Breakdown of costs by individual GXP and GIP
Question: Most interesting would be the breakdown of costs by individual GXP and GIP. If this information is already disclosed please let me know where it can be found. If not disclosed at such a granular level, is there readily accessible data to fill in parts of the table below that would assist?
If the structure of the table doesn’t correctly capture how CIIC’s and Part 4 regulated assets are treated as part of connection assets, please call to discuss or modify the table below.
Note I’m assuming the acronym used is CIIC’s. I think it used to be New Investment Contracts (NIC’s).
Answer: Connection charge information you have requested is not disclosed publicly. Having discussed your question with you, we understand that the following information (at an aggregate level, in dollar amounts not percentages) will serve your purpose.
*Other includes assets created under investment contracts (TWA, CIC, NIA, AAGA) as well as customer owned assets (e.g. HTI_TMU) leased (e.g. KUM line) and prudent discount assets.
7 September 2020 (MEUG) – Questions addressing the Connection Charges Consultation
Regarding focus area 7: Connection asset decommissioning costs:
Question one: Can you outline scenarios and past examples where decommissioning costs have been involved (in addition to Pike River mentioned in the paper).
Answer one: Some examples where decommissioning costs have or will soon be incurred are: generation exit – Otahuhu and New Plymouth; industrial exit – Holcim. Another example where we may incur decommissioning costs is: industrial exit – Pike River. In addition, there have been distributor connection reconfigurations that have made some grid assets redundant. As things stand, the grid decommissioning costs arising from events of this type are recovered through the interconnection charge.
Question two: What is the definition of decommissioning costs? Does this include a credit for scrap/recovered assets? If the decommissioning costs are a credit, is it planned to share this on the same basis?
Answer two: This is defined in proposed clause 19A.2(a) of the benchmark agreement as “[Transpower’s] reasonably anticipated costs (including Transpower internal costs) for decommissioning (including removing) any part of the grid that is redundant as a direct result of the Termination Event”. This covers decommissioning opex, and it is an open question whether it should also cover the stranding cost of the decommissioned assets (accelerated depreciation). We would welcome stakeholder views on that point. The point about the scrap/reuse value of the assets is helpful and we suggest it be submitted formally.
Question three: What is the materiality of the components of the connection charge (capital/maintenance/overhead split)?
Answer three: The relativity changes each year depending on various factors. As a representative indication split for the current pricing year (April 2020 to March 2021) is:
Decommissioning opex costs are highly dependent on the extent of assets being decommissioned. Indicatively, to date the decommissioning opex cost for an entire connection location has been of the order $0.5M to $1.5M.
Question four: How does timing fit in? Where there is growth in demand expected, the assets would not be decommissioned without a lot of thought.
Answer four: Nothing in the proposal obliges Transpower to decommission an asset. If it is considered there would be value in retaining the asset for some future scenario then we will not decommission it and ongoing maintenance costs will be recovered through the residual charge until there is a connected customer. There may be a case for adding a time restriction to the clause (e.g. decommissioning costs are only recoverable through the agreement if decommissioning commences within X years of the Termination Event). We would welcome stakeholder views on that point.
Question five: Under option 2, would a party signing up for supply need to do due diligence on the other parties sharing the connection assets?
Answer five: That would be up to the connecting party. We think it would be very rare that a shared asset would be decommissioned if only one customer exited. It would probably only occur if some grid optimisation were sensible with the reduced number of connected parties, such that the shared asset is made redundant. We acknowledge there is a “last one to leave” risk.
Question six: It is likely EDBs will look at applying the same approach. Has the appropriateness of this been assessed?
Answer six: It is beyond the scope of the TPM development project to assess distributor pricing policies or what changes may be made to them in future.
Regarding focus area 8: First-mover disadvantage:
Question seven: Paragraph 102 rightly points out these proposals have parallels with the proposed Benefits Charge. Can we have some explanation and discussion around how all this may work?
Answer seven: Paragraph 102 is talking about Type 2 first mover disadvantage as investment contracts are very rarely used for interconnection investments. First mover disadvantage has potential implications for both connection and benefit-based investment assets. How the treatment may best interact is something we will need to turn our mind to as we develop proposals for the benefit-based charge. We would welcome any stakeholder feedback on this matter in the meantime.
Question eight: The Type 1 proposal (paragraphs 104 to 106) brings back memories of the old Electric Power Board’s minimum annual guarantee provisions which involved proportioning as more consumers connected. Has the dust been blown off these rules as to an appropriate allocation mechanism? Can we be talked through the example or before the meeting sent a table showing how charge components would be calculated and cashflows work over the 10 years for the 2 cases (C1 then C2, and second case C1, then C2 and then C3)?
Answer eight: The strawman proposal to address Type 1 first mover disadvantage was not informed by any pricing strategy the old Electric Power Board may have employed. It is a potential way to ensure subsequent customers contribute to the capital cost of the connection assets they connect to rather than getting a “free ride”. Extending the example in the consultation paper and assuming C1’s NIC payments end after 10 years, C2 enters at year 4 and C3 enters at year 8, the customers’ net payments (NIC + FAC) look like this:
Question nine: Type 2 (paragraphs 107 to 12) opens up much broader, but important design issues such as:
Q9.1: The shareholder funds additional investment for the future. Alternatively one would expect a risk-free rate of return.
A9.1: How investments are funded and the permitted returns on those investments is a Part 4 Commerce Act matter and outside of the scope of TPM development.
Q9.2: It would be useful to have a discussion on the incentives, and how those can be reflected in connection charges, on any discretion Transpower may have to over-build connection assets in anticipation of Transpower’s view further customers will connect in the future. We think this is an important factor that is not addressed in the consultation paper.
A9.2: The constraints on, and incentives affecting, Transpower’s grid investment decisions are matters for Transpower’s regulation under Part 4 of the Commerce Act and outside the scope of the TPM. If an investment is major capex, the investment needs to pass the grid investment test under Transpower’s Capex Input Methodology. For base capex, Transpower has a fixed allowance for its whole regulatory control period, and regulated incentives to prudently underspend (rather than overspend) relative to the allowance baseline. Many connection investments are carried out under investment contracts, which must be agreed with the funding customers.
Regarding additional components C and F
Question ten: Additional component C is charges for connection investments to use a method substantially the same as for benefit-based charges. Additional component F is allocation of opex. The paper says there is no compelling reason to adopt these (paragraph 9). It’s possible that in the details of the yet to be designed benefit-based charges regime there will be innovative approaches relevant to additional components C and F. Can the timeline be adjusted to allow reconsideration of these after we see the details of the for benefit-based charge regime?
Answer ten: We agree that there are various potential interrelationships and dependencies between the different parts of the new TPM. This includes tat the approach we develop for the benefit-based charges may impact how we should deal with additional components C and F. This is something we will consider as part of the benefit-based charge development, on which we plan to consult in November-December. We welcome further stakeholder feedback on any potential interactions such as those detailed in this question.
18 August 2020 (IEGA NZ) - Transitional peak charge in project timeline
Question: Thanks for your regular and thorough communications on this project. I read with interest the TPM Development project timeline. It is not clear to me how work on the transitional peak charge component of the TPM Guidelines is incorporated into the project timeline. Appreciate hearing from you on this.
Answer: Thanks for your question. We’re glad to hear our communications are welcome. We are yet to make a decision on how we will approach Additional Component D: transitional congestion charge and will update all stakeholders as soon as a decision has been made.