TPM questions & answers

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We're here to answer your questions throughout the development of the TPM. 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. Questions are numbered within each date entry.

7 September 2020 (MEUG) - Breakdown of costs by individual GXP and GIP  - download.

7 September 2020 (MEUG) – Questions addressing the Connection Charges Consultation - download.

18 August 2020 (IEGA NZ) - Transitional peak charge in project timeline - download.


7 September 2020 (MEUG) - Breakdown of costs by individual GXP and GIP


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).


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

Q1: Can you outline scenarios and past examples where decommissioning costs have been involved (in addition to Pike River mentioned in the paper).  

A1: 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.


Q2: 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?

A2: 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.


Q3: What is the materiality of the components of the connection charge (capital/maintenance/overhead split)?

A3: 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.

Q4: How does timing fit in? Where there is growth in demand expected, the assets would not be decommissioned without a lot of thought.

A4: 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.


Q5: Under option 2, would a party signing up for supply need to do due diligence on the other parties sharing the connection assets?

A5: 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.  


Q6: It is likely EDBs will look at applying the same approach. Has the appropriateness of this been assessed?  

A6: 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

Q7: 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?

A7: 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.


Q8: 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)?  

A8: 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:

Q9: 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

Q10: 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?  

A10: 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.