TPM Development Project questions & answers

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We're here to answer your questions throughout the development of our TPM proposal. Feel free to send questions to or read our existing answers here.  

Questions and responses are listed by reverse chronology - the most recent questions and answers appear first. Where more than one question is asked in a single email, questions are numbered within each date entry.

01 Dec 20 (Contact Energy) - TPM audit query - download [ pdf 100.28 KB ]
23 Nov 20 (MEUG) - TPM Options Consultation - download [ pdf 117.63 KB ]
17 Nov 20 (Trustpower) - TPM Options Consultation - download [ pdf 274.52 KB ]
29 Oct 20 (Mercury) - First Mover Disadvantage Consultation - download [ pdf 116.21 KB ]
21 Oct 20 (Refining NZ) - Connection Charges, focus area 7 - download [ pdf 63.14 KB ]
23 Sep 20 (Trustpower) - Forthcoming workshops on TPM congestion charge - download [ pdf 99.77 KB ]
07 Sep 20 (MEUG) - Breakdown of costs by individual GXP and GIP download [ pdf 136.86 KB ]
07 Sep 20 (MEUG) – Questions addressing the Connection Charges Consultation - download [ pdf 141.52 KB ]
18 Aug 2020 (IEGA NZ) - Transitional peak charge in project timeline - download [ pdf 73.63 KB ]


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.

In addition:

  • 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 [205]. 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 [51] 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 [82]. 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 [137] Transpower notes: ‘the Authority gave support to using capacity (for load) … as proxies for net private benefit.’ However in the table below [143] 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 [98] 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 [136]. 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:

  1. adopt proposed option 1: recovery through the residual charge; or
  2. adopt option 2: allocate connection asset decommissioning costs to all customers connected to the asset, regardless of the reason for decommissioning; or
  3. 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.