The Authority welcomes questions on the Transmission Pricing Methodology 2019 Issues Paper.

We’re keen to ensure submitters are well informed about the proposal, including by publishing questions we receive from interested parties, and our responses to those questions. We will update our website regularly with new questions and answers. When publishing a question, we intend to publish the name of the company asking the question but to withhold the name of the individual asking the question. Similarly for questions from individuals, we do not intend to publish the individual’s name.

If you have a question and don’t want us to publish it (or the answer), or if you want us to withhold your company name, please let us know when you lodge your question. We will then consider your request and we will use the grounds under the Official Information Act 1982 to help us make that decision.

Question - Private consultant, name withheld for privacy considerations

Can you please explain the logic behind only considering peak demand charges on the basis of transmission costs while ignoring the cost of peak demand costs shouldered by generators and lines companies? This is a cost that the consumers pay and do not have any opportunity to manage.

The cost of one kW of after diversity maximum demand must be at least $3000. Therefore, peak demand charges should be something like $300/kW.

Answer

The Authority’s recent paper “Peak charges under proposed TPM guidelines information paper and next steps March 2020” is about whether there is a place for some transmission charge that is based on peak demand under its proposed new transmission pricing methodology guidelines.  

In this the Authority did not ignore the cost of peak demand costs shouldered by generators and lines companies. Generators’ costs of supplying peak demand are, and will continue to be, reflected in wholesale price offers. Lines companies reflect the cost of supplying local network services (at peak and other times) in their distribution pricing.

As our recent paper explains, wholesale nodal prices also cover short-run transmission costs. That is, they include generators’ costs of supplying electricity plus the costs of losses in transporting electricity and from transmission constraints, given current grid capacity.

As such, he Authority’s current thinking is that this means an additional permanent transmission peak demand charge would not be needed under its proposed transmission pricing methodology guidelines. However, to respond to uncertainty and potential risks (as our recent paper explains), the Authority’s current proposal includes the option of a transitional congestion charge, as an additional component of the proposed guidelines.

The Authority is keen to ensure that stakeholders are well informed about the TPM proposal. For that reason, we intend to publish your question and our answer on our website. We will publish the name of your company but withhold the names of individuals. If you believe there are grounds for the Authority not to publish your question, our answer, or your company name, please advise the Authority within 5 working days from the date of this email, including the grounds upon which you believe the Authority should not publish your question, our answer, or your company name. We will then decide whether there are grounds not to publish. If this timeframe is too short, please contact us within the 5 working days to request additional time to respond.

Response to answer

Thank you for your question. 

The Authority’s recent paper “Peak charges under proposed TPM guidelines information paper and next steps March 2020” is about whether there is a place for some transmission charge that is based on peak demand under its proposed new transmission pricing methodology guidelines.  

but my letter is about the whole system, not just transmission.

In this the Authority did not ignore the cost of peak demand costs shouldered by generators and lines companies. Generators’ costs of supplying peak demand are, and will continue to be, reflected in wholesale price offers. Lines companies reflect the cost of supplying local network services (at peak and other times) in their distribution pricing.

Can you tell me where peak demand features in the wildly fluctuating prices below?  Also note the flat demand profile of the upper South Island arising from the lines companies collectively managing peak demand by controlling consumers water heaters. An activity that is a loss maker for the lines companies who do it only because they happen to recognise that it brings a great benefit for their consumers. In a power system optimised to provide a reliable and economical supply lines companies would be rewarded for controlling water heaters and consumers would directly benefit from allowing their water heater to be controlled. The present system penalises lines companies and consumers do not directly see any benefit from having their water heater controlled.  They only see the cost the next time the retailer hikes their prices.

Can you see any sign of peak demand control in this picture for 10 June 2017? Yet, before the electricity “reforms” system demand on a peak demand day would be similar to the USI curve for 2 July 2009. The cost to the system and the consumer of meeting this extra and unnecessary peak demand is enormous. But maybe you never realised that, before it was destroyed by the reforms, New Zealand had the best demand-side management system in the world.

As our recent paper explains, wholesale nodal prices also cover short-run transmission costs. That is, they include generators’ costs of supplying electricity plus the costs of losses in transporting electricity and from transmission constraints, given current grid capacity.

Nodal prices make no difference to anyone’s long-term behaviour because they are ephemeral. Do you have any evidence at all of an instantaneous demand response to price spikes? If there is not, does it not destroy the economic theory underlying the market?

As such, he Authority’s current thinking is that this means an additional permanent transmission peak demand charge would not be needed under its proposed transmission pricing methodology guidelines. However, to respond to uncertainty and potential risks (as our recent paper explains), the Authority’s current proposal includes the option of a transitional congestion charge, as an additional component of the proposed guidelines.

If you want to change behaviour, you have to offer signals that are consistent in the long-term. Perhaps you didn’t realise that  no one will spend money trying to manage peak demand unless they have long-term certainty. Why should they?

The Authority is keen to ensure that stakeholders are well informed about the TPM proposal. For that reason, we intend to publish your question and our answer on our website. We will publish the name of your company but withhold the names of individuals. If you believe there are grounds for the Authority not to publish your question, our answer, or your company name, please advise the Authority within 5 working days from the date of this email, including the grounds upon which you believe the Authority should not publish your question, our answer, or your company name. We will then decide whether there are grounds not to publish. If this timeframe is too short, please contact us within the 5 working days to request additional time to respond.

I would be pleased if you published my question, your answer and this response.

For most of my life the power system development studies I carried out concentrated on what was called “least cost system development”. This ensures that every new increment of generating capacity contributed to minimising the long term cost. If New Zealand had a market that recognised this basic principle, electricity supply would be more reliable and lower in cost. Peak demands would be lower, there would be more geothermal stations and less wind and solar power generation and Huntly would have a coal stockpile of about 1 million tons available every April.

I would also point out that with most commodities new production facilities are more efficient and produce cheaper goods than old factories. Paying all producers the price bid in by the most expensive production unit encourages new efficient production and works well. If there is a shortage some older more expensive production units start producing and the price goes up a bit and further induces the construction of new units.  Alternatively, buyers choose an alternative good and stabilise demand. A balanced and stable system.

With the electricity industry in New Zealand the lowest cost production comes from depreciated hydro and geothermal stations. No new production can compete with them. So when the spot price rises to the level that will justify new generation the incumbent generators make huge windfall profits and the unfortunate consumers pay much more just to justify a few percent of new generation. As there is no alternative good there is a strong inducement on the generators to keep us at the edge of a shortage because, during a shortage, “Price is a trade-off between greed and guilt”.

Everyone does seem to have lost sight of the fact that the objective of a power system is to provide a reliable and economic supply. Electricity is an essential service like roads, sewage and water supply. And we don’t have a market in them.

Question - Contact Energy Ltd

Contact Energy requested a breakdown of maximum allowable demand.

More detailed information is available on EMI under TPM supporting information and analysis.

Here is the breakdown you were interested in:

Breakdown of maximum allowable revenue

Question - Horizon Energy Group

The question was how the impact of Aniwhenua generation would impact the calculation of the proposed TPM numbers supplied to date for Horizon particularly under the proposed pricing re benefit based and residual charges

Attached is a metering diagram that should assist your team understand the connection. In addition are two data files that will provide a quantum of generation data.

Supplementary question

X has reminded me that we should have also sent you the additional generation that commenced circa Sept 2018

For the embedded Kawerau TeAhiOMaui KA22 which we note is included in the new distributed generation adjust module. Can this be also modelled if possible?

Answer

From the diagram supplied, it appears that Aniwhenua has a connection into Horizon Energy’s distribution network, but Trustpower’s generation at Matahina does not. Based on the draft netting business rules set out in the Authority’s proposal, on the basis of the new information you have provided, we would recognise Aniwhenua as distributed generation and net this generation off Horizon Energy’s load.  This would have the effect of reducing Horizon Energy’s benefit-based charge. There would be no impact on the residual charge (which is proposed to be based on load measured ‘gross’ of distributed generation).

It has also come to our attention that there is significant load at Matahina, which has been assigned to Southern Generation and Trustpower (because the reconciliation data shows these to be the relevant customers for this load). Under the indicative modelling of our proposal, Southern Generation receives a residual charge for load at Matahina of $626,660 and Trustpower receives a residual charge of $39,753, taking the total residual charges on load at Matahina to $666,419. Could you please confirm in your submission whether some or all of the load at Matahina is, in fact, Horizon Energy’s load? (If only some of the load at Matahina is Horizon’s load, please confirm the proportion.) Pending confirmation on this matter, we are minded to assign this load to Horizon Energy rather than to Southern Generation and Trustpower.

The modelling below illustrates indicatively the impact on charges if both of the following changes were made:

1) Aniwhenua were treated as distributed generation and the Trustpower generator at Matahina were not, and

2) the load at Matahina were allocated to Horizon.

Note, however, that this is an indicative calculation and we will revisit it following consideration of submissions.

Table showing benefit-based charge under the proposal

We will look at these matters in more detail following receipt of submissions and come back to you for further information should this be required. Lastly, please note that our proposal has not been confirmed and our netting business rules are still draft and may be revised following consideration of submissions.

Kawerau TeAhiOMaui KA22

We recognised this as a new distributed generator in our modelling of the draft proposal and manually added its injection to KAW0111, which is a Horizon point of connection. It follows that the netting benefit from this new generator has already been included in the modelling of estimated charges for Horizon that was published with the proposal. The adjustment was 20MW running in every trading period at 90% capacity. 

Question - Pioneer Energy

Can the EA please confirm that the transmission charge associated with adding distributed generation on to load under the gross AMD calculation is intended to be passed on by distribution companies to load on the network and not to DG?

Answer

Under the proposal, the residual charge would be allocated based on load measured gross of distributed generation. It follows that injection by distributed generation on a network would have no impact (either positive or negative) on the allocation of the residual charge. Under a gross load approach, a distributor with distributed generation pays the same residual charge as an otherwise identical distributor without distributed generation. To be clear: under the proposal, the presence of distributed generation on a network does not increase the distributor’s residual charge. However, it is the distributor’s responsibility to determine how it takes account of transmission charges in setting its own distribution charges (guided by the distribution pricing principles). The TPM proposal does not specify how transmission charges are intended to be passed on by distributors.

Question - Pioneer Energy

Definition of GROSS AMD: Could you please confirm the calculation of Gross AMD for distributors and direct connects using an example for these two transmission customers. Some examples are given below (which may or may not be correct).

Answer

We have used Horizon and Southern Generation as examples.

Distributor: Horizon Energy. Our calculation uses gross demand data as provided by the reconciliation manager in the 010 file and which has been uploaded onto the EMI website for stakeholders’ reference. The calculation is provided in the table below.

Direct connect: Southern Generation. In the indicative modelling of the proposal, Southern Generation receives a residual charge of $626,660 (based on 11.12MW Gross AMD for MATT1101_BOPD / Total Gross AMD of 8766MW x total residual pool of $493,939,704, as set out below). However, if all of the Matahina load belongs to Horizon Energy (which we would need to confirm) then neither Southern Generation nor Trustpower would be allocated a residual charge for this load. Instead, Horizon would be allocated additional residual charges to the value of $666,412 (as indicated in the following table). However, Southern Generation may receive a residual charge to the extent that it is responsible for a portion of the offtake at Matahina. Please provide all relevant information in your submission.

The calculation in the following table is based on the reconciliation data 010 files which have been uploaded onto the EMI website for your reference.

Table: Calculation of residual charge for Horizon

Maximum gross demand in MW and residual charge as modelled in the proposal

Question - Pioneer Energy

As discussed in person, could the EA please check the load and the Gross AMD numbers assigned to Southern Generation at the MAT1101_BOPD POC Network connection. The reconciliation arrangements for Aniwhenua power station are complex and we have provided an information paper by the EA that could assist with your understanding.

Answer

The load does appear high for a generator and we are making further inquiries as to the relevant customer for this load. We need to understand how much of this load should be allocated to the Aniwhenua power station. It may be the case that we should assign most if not all load at this POC to Horizon Energy rather than to Southern Generation and Trustpower. Please provide the information paper, and any other information you consider relevant, in your submission, and we will investigate this as part of our consideration of submissions. Also, it is important to note that the modelling of the residual charge is indicative only. Should the Authority confirm its proposal, Transpower has the role of proposing the detailed methodology for the residual charge.

Question - New Zealand Steel Limited

AMD has been used as the allocator for the residual. This has been applied at the customer level. This creates an anomaly in that large consumers, particularly direct connects, are being allocated based on their AMD, but for consumers supplied through an EDB the allocation is an after diversity maximum demand (ADMD). What is the logic for this inconsistent treatment?

Answer

A potential disadvantage of using AMD as the residual allocator is that a load customer might (depending on how transmission charges are passed through in distribution charges) pay less if it were embedded than it might pay if it were grid-connected, as a result of the diversity issue to which you refer in your question. This potential artificial advantage could distort load customers' decisions on location and connection.

This issue could be addressed by using an alternative residual allocator. In determining our proposed default residual allocator, we are consulting on various options for the residual allocator, each of which has pros and cons (these are discussed in Appendix B of the 2019 issues paper). 

We would also note that the proposed guidelines require the TPM to avoid creating inefficient incentives for a large consumer or generator to shift its point of connection from or to Transpower and/or a designated transmission customer.  In its submission on the second issues paper, NZ Steel made the point that it might have an inefficient incentive to change its GXPs to allow for consolidation with Counties Power. This proposal is intended to address this issue. It may also help to address the issue to which your question refers.

We encourage NZ Steel to include its views on these issues in its written submission to inform the Authority’s thinking on the respective options for the default residual allocator.

Question - Contact Energy Ltd

Contact Energy Limited requested clarification of Anytime Maximum Demand (AMD) calculation

It’d be great if you could provide another clarification please.

I’ve pasted an excerpt from the draft guidelines below – is the intent of clause (ii) below to take the average of a customer’s gross  AMD’s for each of the past two years?  i.e. (Gross AMDyear1 + Gross AMDyear2)/2  ??

I’m just checking as the way it’s described it’s not exactly clear.

Answer

The intent is to take the average of a customer’s gross AMDs for each of at least two past years. Note that the two past years don’t have to be the last two years (2017 to 2019): they could be earlier.  (Or, they could be later, in the case of the residual charge allocation being revised at some future date more than 10 years in the future.)

Question - Contact Energy Limited

Contact Energy Limited asked if the Authority could help them understand the “AMD Summary” tab in the “Gross AMD Calculation” sheet:

  • What are the units of the values in this worksheet?
  • What is the data in this tab used for?
  • The other data (even apparently ‘raw’ half hourly data) in this workbook for each year (i.e. tabs 2014-2017) appears to be in “MW” (not MWh), is this correct?

Answer 

In the file titled 'Gross AMD Calculation', sheet titled 'AMD Summary', row 303 provides the total AMD amounts in MW. Namely, cell G303 returns a total gross AMD of 8,778 MW for 2017/18. This compares to a total Gross AMD of 8,727.85 in the 2016 TPM proposal indicative modelling.

To indicatively model the TPM proposal, the residual is calculated as follows:

  1. Gross AMD
  2. Data from 1 July 2014 to 30 June 2018 (4 years) - to be broadly representative of a 'typical' year
  3. Gross AMD is calculated annually over 4 years, from 1 July to 30 June

The gross AMD is an average of 4 annual AMDs 

The flow data is from the reconciliation manager (010 files), so it is actual volumes. The flow data is used to calculate the residual, and also to calculate the $/MWh impacts of the proposal, i.e., if you divide a customer's proposed 'indicative' TPM charge by their total offtake over a year, you arrive at a $/MWh charge.

While we provide AMDs in MW in row 303 as described above, it is the portion of the total that is relevant, rather than the unit being measured.

Question - Buller Electricity Limited 

In relation to Table 12 on page 61 are you able to provide the AMD value which was used to determine the residual charge for Buller Electricity?

While our total estimated charges are not large in absolute terms, in relative terms the change from the status quo is the most significant as well as the received relief via the cap.

Due to our small size and somewhat unique characteristics the calculations can sometimes be incorrect – this was our experience in 2016 so I would just like to verify the background numbers.

Answer

In response, please note that the indicative estimate of the residual charge is based on an average of four 12-month periods, starting on 1 July 2014 and ending on 30 June 2018. Please see attached spreadsheet with two sheets:

  1. The first sheet shows the breakdown of the calculation of the indicative estimate of the residual charge using gross AMD.
  2. The second sheet shows the alternative residual that we modelled, being based on kWh pa.

For the gross AMD calculation, the spreadsheet provides the separate AMD calculations of each of Buller Electricity's three Points of Connection (POCs). A separate peak is calculated for each POC and a 4-year average is taken. Note, we also provide date/trading period for each peak for Buller's reference in columns G to I. The calculation shows that Buller's AMD (in MW) reduced from 25.9MW to 19.48MW between the 2015-16 and 2016-17 years (see cells E6 and E7). Buller's average gross AMD over the 4 years is 23MW.

On the kWh pa calculation, Buller's load reduced from 95m kWh to 54.9m kWh between the 2015-16 and 2016-17 years, with an average over 4 years of 77.8m kWh (cell K6).

Also note that the proposed TPM guidelines set out a principle (at clause 41) that in allocating the residual charge, Transpower should adjust the allocation where a customer has experienced a substantial change to demand due to factors over which they have no control. This principle is intended to allow, for example, a downward adjustment to the AMD of a distributor where a large industrial customer that was previously connected to the distribution network has closed down. This is discussed at B.218 on page 155 of the issues paper. We have not made any adjustments of this nature in calculating the residual charges set out in the issues paper (which are only indicative charges – not actual proposed charges). However, Transpower would be required to apply this principle, if the proposed guidelines were adopted.
 
Note also that the Authority is consulting on whether the data or modelling outputs used in the impacts modelling (in particular, demand and generation volumes) should be adjusted (see Q.69 on page 276 of the issues paper). If submitters do seek adjustments, they are asked to provide detailed reasoning/quantitative calculations with their submissions.

Questions - Rio Tinto

1. Was any statistical analysis done to determine that the years 2015 to 2018 were representative?

No extensive statistical analysis was undertaken. The determination that the years 2015 to 2018 were representative was based on comparison of the flows across the HVDC in various periods.
1 July 2014 to 30 June 2018 is considered to be broadly consistent with the 10 year trend for northward versus southward flows across the HVDC. 
Please refer to the technical workshop presentation  (slide 56) 

Why was a four-year modelling period chosen as opposed to, say, a ten-year or another period of modelling? As the four-year modelling period was chosen based on matching a decade long hydrological profile, why was a ten-year period not used?

The Authority chose the four-year timeframe as it averages out variances from annual and seasonal patterns, without being too outdated as market conditions and other relevant factors change over time. The four-year period has a reasonable match with the decade-long hydrological profile, compared to an alternative two-year period that was also considered.
The Authority’s view is that the four-year period it selected represents an appropriate balance between these competing considerations and is likely to produce results indicative of a ‘typical year’.

2. Given the influence of 2017-2018 on the results was any sensitivity done on adding another year to the analysis (i.e. a 1:5 ratio for 2017-2018 rather than 1:4)?

No. The Authority considered two options for defining the modelling period: (a) a two-year modelling period ending 30 June 2018 and (b) a four-year modelling period ending 30 June 2018 (currently the Authority’s preferred option for the reasons above).

3. Under the Factual Simulation sections (H.81 to H.118) there is no description of the No Pole 2/Pole 3 upgrade factual simulation. Please provide the factual description for the No Pole2/Pole 3 upgrade?

Both poles are in place in the HVDC factual scenario whereas under the counterfactual scenario there is no HVDC link. This means that under the counterfactual, essentially all HVDC assets are removed. This differs from previous modelling of the HVDC in which Pole 2 and Pole 3 were assessed separately (and in the counterfactual scenario for Pole 3, Pole 2 was in place). In assessing the requirements for modelling the HVDC in vSPD, we noted that submissions to the 2016 Second issues paper argued that there was too much complexity with respect to the vSPD modelling. As Poles 2 and 3 combine to provide a unified transmission service across the HVDC link, it was considered that the modelling of the HVDC link should treat Poles 2 and 3 as a single, combined investment. The approach might need to have been different if we had been calculating benefits for a prospective or new investment.

In the “no HVDC” counterfactual scenario, the following branches were taken out: “BEN_HAY1.1, BEN_HAY2.1, HAY_BEN1.1, HAY_BEN2.1”.  In the “no HVDC” counterfactual scenario, we assumed a virtual price offer (VPO) with unlimited quantity, priced at 1.2 times the factual price, located at Otahuhu. We did not assume a VPO elsewhere, so a VPO was not available in the South Island in the “no HVDC” counterfactual scenario. Counterfactual prices above $10,000/MWh were considered infeasible and removed.

4. Paragraph H.85 states that “In case of HVDC (sic), only the energy market is modelled.” We take this to mean the ‘with reserve results’ are not used in the No Pole 2/Pole 3 upgrade case. Please explain why the Authority considers this a credible factual scenario?

The National Market for Instantaneous Reserve (NMIR) was activated in October 2015, part way through the analysis period. While we modelled HVDC both ‘with reserve’ and ‘reserves-off’ (ie, energy-only), the energy-only scenario was used for our proposal.
We consider reserves-off is a better solution for existing investments. The decision to turn the reserves market off was a pragmatic judgement which we consider makes the modelling more tractable.
Both the ‘with reserve’ and ‘reserves-off’ cases can be viewed on EMI under TPM 2019 Issues paper vSPD Excel Files 

We welcome submissions with alternative views and evidence for the Authority to consider.

5. HOB_PEN_1 had to be removed from the No NIGU factual simulation (H.89(c)). Does this mean that there are partial beneficiaries of NAAN?

The removal of HOB_PEN_1 in the “No NIGU” counterfactual configuration was a pragmatic judgement. It reflects the view that, in a scenario in which the NIGU investment had not proceeded, it is unlikely that HOB_PEN_1 would have been constructed, as – without NIGU – this infrastructure would not have been useful.. Based on vSPD modelling, HOB_PEN_1 does not have material benefits for any transmission customers.

6. Under H.67 “(North Auckland and Northland (NAaN), Otahuhu Substation Diversity and Upper South Island Reactive Support) the vSPD modelling was not able to identify material benefits for transmission customers commensurate with the costs of these investments. This comment implies that modelling was done, but no modelling was released. Is this modelling available?

No vSPD modelling has been completed for NAaN. It was not necessary to do so, as it was clear that removing the grid assets that from the NAaN investment would not result in material differences in energy flows, demand volumes or energy prices. This is because during the modelling period there would have been sufficient capacity to handle the required energy flow on the relevant grid assets without the NAaN investment. Capacity on the relevant grid assets without the NAaN investment would be slightly over 1000MW. Northward flow across the relevant grid assets was below 1000MW during the data analysis period of 1 July 2014 to 30 June 2018 (see chart below). Given these facts, it was clear that vSPD modelling would not be able to identify material benefits from NAaN during the modelling period.


 
No vSPD modelling has been completed for the Otahuhu Substation Diversity project. As with NAaN, it was not necessary to do so, as it was clear that removing the grid assets that form the Otahuhu Substation Diversity investment would not result in material differences in energy flows, demand volumes or energy prices.

Similarly, removing the grid assets that form the Upper South Island Reactive support investment would not result in material differences in energy flows, demand volumes or energy prices within the analysis period. No vSPD modelling has been completed for this project.

7. Arguably the vSPD method for assessing the large projects is equivalent to an “Economic Test”. How are reliability benefits captured in the modelling? Given that preference was given to undergrounding in Auckland, significantly increasing costs, how were aesthetic and other benefits identified?

We have not separately quantified reliability or other (such as aesthetic) benefits in allocating the costs of the seven historical investments subject to the benefit-based charge.  

Our view is that the vSPD method, which calculates consumer and supplier surplus, produces results that are a reasonable proxy for the total benefits from the seven historical investments subject to the benefit-based charge (including reliability benefits and other benefits).
With respect to allocating the costs of historical investments, our view is that promoting durability (and efficiency) does not require a highly precise allocation of the costs of historical investments. Accordingly, our view is that it is reasonable to use a proxy for total benefits in allocating historical investment costs, and it is reasonable to not separately quantify reliability and other benefits in allocating the costs of the seven historical investments.

That said, we note that the vSPD modelling approach places a value on unserved energy where that outcome appears in the modelled counterfactual scenario. It does this using the variable VPO approach. Our view is this approach assists in establishing a reasonable proxy for the higher costs to consumers in the scenario without the investment – including the costs of reduced reliability. Further, we have given some explicit consideration to reliability benefits. For example, in the case of the Otahuhu duplicate substation investment (for which reliability was the overwhelming consideration) we considered whether the expected benefits from the investment that might stem from avoiding high-impact, low-probability events would be likely to outweigh the costs of the investment. Our view is that such expected benefits for this investment would not outweigh its costs.

While the above discussion relates to historical investments, we would also note that for future investments we have not been prescriptive about the types of benefits that can be taken into account in allocating charges, or the methods that could be used to estimate these. It follows that where Transpower considers the reliability or other benefits of an investment to be material, it should take these into account in allocating costs. Further analysis may show that a more detailed approach, or different approaches (ie, different models for different types of investments), are justified.

8. Some results, in terms of the beneficiaries identified, are completely different to the beneficiaries identified in the investment references in Table 15 (e.g. Lower South Island renewables). Has this difference been reconciled?

The allocation of benefits in Schedule 1 of the proposed TPM guidelines is based on vSPD modelling of benefits for the four-year modelling period. Our modelled benefits (and beneficiaries) may or may not be similar to the benefits (and beneficiaries) identified in the original investment proposal and Electricity Commission decision.

For example, our analysis of the benefits of Lower South Island Renewables, found that the investment:

  • improves access to load for LSI generation during times of northward flow across the HVDC, although this is generally more than offset by disbenefits at times of southward flow across the HVDC
  • relieves constraint on import of energy into LSI in dry years, reducing dry year prices for LSI load, while it relieves constraint on import of energy into USI in normal years, reducing prices for USI load.

9. Why does the counterfactual case have no demand growth assumed while the factual case has increasing consumption of 1% per annum? What is the basis for this difference in assumptions?

The factual case does not assume increasing consumption of 1%. Demand is the same in both the factual and the counterfactual scenarios (ie, actual demand in the four-year modelling period).
However, an assumption of 1% demand growth is applied in other aspects of the modelling of indicative charges; in particular, for:

  1. calculating the $/MWh estimate of the indicative charges for 2021/22 and
  2. the application of the price cap.

We have seen relatively flat demand for the last 10 years, what is the basis for 1% load growth, and why would this apply to industrial customers?
MBIE’s EDGS 2016 “Mixed renewables” scenario, which is the basis for our CBA, assumes an average of 1% annual electricity demand growth. Our view is that 1% load growth is a reasonable assumption in general.

We have sought to avoid making bespoke adjustments (e.g. for industrial customers).

Is it reasonable to assume no demand elasticity in the counterfactual?

We have not adjusted prices in the counterfactual to take account of potential demand response to the higher prices resulting from the absence of the grid investment. The Authority’s view is that this approach results in reasonable estimates of benefit, as we have made various adjustments to address the prospect of unreasonably high prices, including:

  • the VPO assumption (both variable and fixed) essentially caps higher prices where there is unserved energy in the counterfactual, providing an effect not dissimilar to demand response
  • in circumstances where VPO does not apply, we dealt with prices we considered infeasible by removing them in post processing
  • we reduced the effect of outliers in the modelling through separately calculating benefits over four years and then averaging those benefits. For example, in a dry year South Island load benefits substantially from the HVDC (prices in the counterfactual are high), but this only occurred in one year of the four years in the modelling period.

10. Reductions in losses changes the relativity of prices across the grid where power flow is predominantly from South to North. We consider that these changes would not be distributed evenly as there are winners and losers across the grid, generally, from reduced locational price separation. Could you explain the basis for the comment: “Loss benefits are typically distributed fairly evenly across the grid” (H.34)?

The basis for the comment is that the differences in wholesale prices between different locations due to losses – compared to the price differences between different locations due to constraints – are both:

  • smaller in magnitude and
  • more evenly distributed across the country.

For both these reasons, the benefits estimated using the vSPD method are likely to be influenced more by constraints than by losses.


Excel modelling files
1. Why is it that “a net negative benefit cannot be carried over from one 12 month period to the next 12 month period”?

The proposal is not to compensate parties who experience dis-benefits from an investment, for the reasons set out in paragraph B.113 of the issues paper. Accordingly, net negative benefits are ignored (treated as zero) for the purposes of benefit allocation.
We treat each of the four years in the analysis as a scenario. That is, our estimate is an average of the results in four separate one-year modelling periods (as opposed to a single continuous four-year modelling period). When we use the terminology “four-year modelling period”, this is a short-hand for taking an average of the results in four separate one-year modelling periods. For each of the separate one-year modelling periods, net negative benefits are treated as zero (consistent with the policy set out at paragraph B.113).

2. Under “HVDC_no_reserve_FlexiNZD_node_period_data.xls” there is no change in smelter load or SI load under increased SI prices (assume HVDC south flow). Is this a credible scenario since, without Pole 2/Pole 3 upgrade, high SI load could often be infeasible?

We have not taken account of potential demand response to the higher prices resulting from the absence of the grid investment. The Authority’s view is that this approach results in reasonable estimates of benefit, as we have made various adjustments to address the prospect of prices that would likely result in material demand response, including:

  • we dealt with prices we considered infeasible by removing them in post processing (our pragmatic assumption is to remove trading periods where prices increase to 10,000/MWh or above on the basis that prices above $10,000/MWh are infeasible)
  • we reduced the effect of outliers in the modelling through separately calculating benefits over four years and then averaging those benefits. For example, in a dry year South Island load benefits substantially from the HVDC (prices in the counterfactual are high), but this only occurred in one year of the four years in the modelling period.

3. Could more clarity and guidance be provided on how to interpret the deltas on the consumer and supplier surplus in the results files, and how these flow through to the percentage allocations?

Please refer to the technical workshop presentation (slide 62).

An example of the calculation of consumer and producer surplus is provided. Given each 12-month period in the 4-year analysis is treated as a sensitivity, a point of connection’s (POC) benefits will accumulate over each 12-month period and disbenefits will net off against benefits during each 12-month period. The accumulated benefits at the end of each 12 month period is the POC’s total benefit for that 12-month period.

4. Under the preferred HVDC case, why are prices at TWI2201 sometimes significantly lower in the counterfactual than the factual in peak periods (for example, 27 July 2017 - 16:30 to 20:00 inclusive)? i.e. why would peak prices go down at TWI2201 under southward transfer with the deprival of Pole 3?

The 27/07/2017 was a day of southward flows in the factual case, so without the HVDC the prices at TWI2201 were higher (in the counterfactual) leading to benefits from the HVDC. However, between 5pm and 7pm the flows switched to northward, causing prices at TWI2201 to be lower in the counterfactual than the factual, and causing TWI2201 to disbenefit from the HVDC.

Question - Refining New Zealand

The intention of this email is to follow up from our conversation last Monday 2nd September at the EA workshop in Whangarei.

We discussed the possibility of having an estimate of the impact of the proposed TPM guidelines vs current TPM to Refining NZ’s transmission charges.
This would be the same information on point 5.15 of the issues paper for each transmission customer.
Refining NZ is not a direct connect but we currently get charged by Northpower on the same way as if we were direct connects.

Answer

As requested we have provided a broad estimate of the indicative transmission charge component of Refining NZ’s distribution charges at year one of implementation of the TPM guidelines proposals we are currently consulting on, on the basis that Refining NZ states it is charged by Northpower as if it were a direct connect.

Please note that ultimately the shape and level of distribution charges (including transmission charges) are a matter for Northpower to work through with Refining NZ. We are therefore hesitant to make an estimate like this, as we would not normally do so. But we have done so in this instance, given the ‘as if’ basis you describe, the relative size of Refining NZ, and that it may also act as a case study that other large electricity users could draw on.

Please note these caveats and those in the attached spreadsheet.

Question - Contact Energy Limited

This is just a heads-up that we think there may be an error worth exploring in the tab “Reconciliation maps 15042019” of the “Proposal Impacts Modelling” spreadsheet.

Our peaker generation seems to have been located to the UNI in Auckland (OTA), rather than being located in Taranaki (Stratford).

If this is also modelled in the vSPD runs, this could have a material impact on our charges.  It may be material, even if vSPD has the generation modelled correctly.

It may be worth us having a meeting later in the week to discuss some of this – we’ll have a better understanding of the material by then.

Answer

Just following up on your e-mail from yesterday about the peaker generation.

As discussed, my understanding is that the injection at Otahuhu that you are referring to in the spreadsheet is injection from Otahuhu B, rather than the peaker generation. The volumes at Otahuhu only occur in 2014-15 and part of 2015-16 - coinciding with the last operation of Otahuhu B. The information is from the reconciliation manager. 

As you’re aware, there is only one line item for injection at Stratford for Contact. However, my understanding is that the CCGT and the peaker are in adjacent physical locations and are connected to the same substation, so it seems that the injection from both are likely combined into a single line item at Stratford.

At this stage we aren't aware of any anomaly whereby Taranaki volumes are recorded at Otahuhu. However, thanks for letting us know about your concerns on this. If there were any errors or anomalies in the data, we’d be keen to identify them. So if you do identify anything further, we’d be grateful if you could provide us with further information so that we could investigate (either directly or in submissions).

Note also that the Otahuhu B closure is a particular example of a broader category of entries/exits. In the consultation paper we invite submissions on how such situations should be treated, and also about which years of historical data should be used to determine benefits and the indicative allocation of the residual charge. Also, we have avoided making bespoke adjustments, but we will consider submissions on whether any adjustments would be appropriate.

Question - Orion New Zealand Limited

Are you able to provide the basis of the “Status quo $m” in table 12 of the issues paper? For example in Orion’s case this is $46.9m.


Answer 

The basis for the calculation and the various caveats are explained in Appendix H to the issues paper (para H11-H15 specifically).

The calculations are provided in a spreadsheet called 2019 proposal impacts modelling.xlsx”, in the folder 2019_Proposal_Impacts_Modelling

See sheet “Current TP charges.”

The 2019-20 disclosed charges from Transpower by customer are scaled pro-rata to 2022, to get from current total charges to those indicated in the draft price path determination for 2022. That is, see cell h35 in that sheet.

Question - Pioneer Energy

I am looking at the worksheet on the EMI site titles 2019 Proposal impacts modelling. Column L in the Results sheet has this title. Can you please tell me what this refers to, thanks.

 4 year average gross (MWh)

Answer

This is the average gross load over 4 separate years of reconciliation load data (1 July 2014 to 30 June 2018), provided in the sheet titled ‘Reconciliation maps 15042019’, cell AP65, with 6 years of 1% pa compounded annual growth to broadly represent the 2021/22 year (being the estimated initial year of a revised TPM).  Refer cell AR67 of the sheet titled ‘Reconciliation maps 15042019’.

Question - Mercury NZ Limited

In terms of the modelled financial impacts to Mercury – does this include the any equity weighted contributions from our investments in our geothermal joint ventures (the impacts to whom are produced separately in the analysis) or is it just calculated based on Mercury’s overall generation fleet -  i.e. meaning we’ve been allocated 100% of the charges of our geothermal stations in the $6.6m?

Answer

We did not attempt to calculate indicative charges based on equity shares of JVs.  The indicative charges are allocated to designated transmission customers, using Transpower information on customers for each points of connection.  

The mapping we used can be found in the TPM spreadsheets available on EMI.  While we checked our mapping with Transpower, there may be some data issues and other nuances to consider, and we encourage you to identify any suggestions or issues in writing as part of your submission.

Specific details that informed the benefit based charge allocations can be found in the sheet titled "Final Net.vSPD" which maps Node.Gen and Node to customer.

The table shows the points of connection which are included in Mercury's and affiliate entities’ vSPD charge allocation. You can check other point of connection mappings on this sheet.

The basis for indicative residual charges for offtake can also be found in the spreadsheet titled "2019 Proposal Impacts modelling" at the same EMI web location. See the sheet titled "Reconciliation maps 15042019". If you filter on column F (customer), you will see the list of Points of connection where the residual is allocated to Mercury and affiliates. 

Question - MainPower

I also wonder whether there will be more details for the simulations released at some stage?  I’m interested to look at a more detailed breakdown of MainPower’s transmission charges under status quo and the proposal.  This will help us understand which component movement is causing the increase of annual transmission charge anticipated for 2022 from $9.5 million to $10.4 million.

I’m at this stage looking for the breakdown of component charges, and list of connection assets for MainPower under the simulation scenarios.

Answer

Detailed information on the modelling behind the proposal is accessible on various folders on the EMI website. 

For information on the modelled indicative transmission charges, you could begin with the 2019 Proposal impacts modelling spreadsheet.

Question - Top Energy Ltd

I note that on page 275 H.76, that Ngawha has been treated as grid connected. Are you able to share the impact of this on the additional $1.2m that has been signalled for the Far North? It refers to a spreadsheet, not sure if that will just show the data flows or also the $value impact of the adjustment.

Answer

You asked about the share of the impact of treating Ngawha as grid-connected as per page 275 para H. 76.

Under the proposal, that treatment would account for most of the impact. If Ngawha expansion was instead treated as distributed generation, the indicative benefit-based charge would reduce from approx. $1m to approx. $0.15m.

This would be the indicative charge in the first year. Charges would adjust as historic assets depreciate (and for any future movements in, for example, the cost of capital).

The residual charge is not affected. That is proposed to be based on gross load.

There are specific consultation questions on whether any adjustments should be made, and the net vs gross load measures. Please set out Top Energy’s views on this, or any other part of the TPM proposal, in your written submission.

Question - New Zealand Steel Limited

Please talk us through the process and strength of pricing signal when grid congestion is encountered, including the settlement process and cash flows.  

As an example, please talk to the situation for a scenario where there is high demand on an area of the grid during a winter peak. There is adequate energy and reserves ie modest energy prices. How does SPD arrive at the market price? What congestion price can we expect? How will this compare with the ~$2200 / MWh pricing currently coming through the RCPD signal with regard to expected demand response? How does this high congestion price flow into the settlement process and LCE distribution?

Answer

Here is a response to your Question 1, on nodal pricing signalling congestion. This is the question that you were originally intending be discussed at the technical workshop on the 10th September, however, as it turned out there was not enough time to discuss then, so we have responded in writing instead.

First, you’ve asked about how SPD arrives at the market price when grid congestion is encountered.

Grid congestion is represented in the market schedules as a result of power flows breaching one or more of the system operator’s N-1 security transmission constraints. The prices at either end of the constrained transmission line will separate, with the highest price end representing the inability of the system to supply the demand at that GXP.

Note that if there is no local generation or price-responsive load, then a constraint may cause a supply shortfall. Under the current system this results in instructed load shedding (artificially suppressed demand) and typically means an artificially suppressed price. In future under real-time pricing, scarcity prices will be triggered in real-time whenever load shedding is needed, at any node. This will ensure all demand without an explicit bid has a default price in real-time and give retailers and direct purchasers a stronger incentive to contract to avoid paying scarcity prices. This will stimulate efficient demand response.

The explanation for how transport costs (grid congestion and losses) are incorporated into the CBA (the grid use model) is explained in pages 48 - 51 of the CBA technical paper that is available on our website.

Second, you’ve asked what congestion price can be expected and how it might compare to the RCPD signal.

The actual price that can be expected will be different in every location, depending on (amongst other things) what local generation or price-responsive load exists in the area. The Authority’s grid use model forecasts changes in annual average peak nodal prices in a simplified 14-node grid. In broad terms this modelling finds that peak nodal prices will be higher under the proposal than under the status quo, but that the overall signal (the nodal price including transmission costs) at peak times is expected to be lower under the proposal compared to the status quo.

Based on our discussion on 10 September, I understand that you are interested in the Authority’s forecasts of wholesale market prices under the proposal: in particular, the levels to which peak nodal prices are forecast to rise, and the timing and location of such price movements.

As part of our modelling of the CBA of the proposal, we have modelled wholesale market price movements under the proposal (and under the status quo) at each of the 14 backbone nodes in the model. These are average annual figures, for peak, off-peak and shoulder periods. The peak period forecasts, for example, provide a value at each node for a given year that is an average across the 1600 peak periods for that year. Given that this is an average, prices can be expected to be higher than the average in some of those periods and lower in others. However, we do not have forecast prices at this more granular level.

The attached HTML file “PeakPrices.html” presents forecast peak energy prices in the central scenario of the CBA (from the ‘grid use model’). The model calculates average annual costs per MWh (prices) for:

  • Interconnection costs
  • Transport costs (loss and constraint excess)
  • Energy prices, excluding transport costs.

Peak Prices

Last updated: 27th September 2019

The charts entitled “Peak wholesale prices including interconnection charges” provide a comparison of such prices under the status quo and the proposal, which could allow a comparison of prices across the 1600 peak periods with and without the RCPD signal. Note these are annual averages. The RCPD charge of $2,180 per MWh for 100 periods in the 2019/20 pricing year is assumed to translate to a price signal of $136/MWh across 1,600 peak periods (on the basis that the coincident peak is not known in advance and consumers respond to the RCPD signal – as well as to peak wholesale prices – across 1,600 periods; see discussion from para 4.36 in the 2019 Issues paper).

Third, you’ve asked how congestion prices flow into the settlement process and LCE distribution?

The market generates a surplus (as payments by load exceed generation revenue) known as the loss and constraint excess (LCE). Loss and constraint rentals are collected by the market clearing manager, applied to fund FTRs, with any excess distributed by Transpower to transmission customers in proportion to their transmission charges. The 2019 TPM issues paper also discusses (in appendix F) a potential adjustment to this distribution, under which LCE would be first distributed in proportion to the LCE generated by each grid investment, and then amongst customers in proportion to the transmission charges they pay in that year in respect of that investment.

Question - Energy Link Ltd

Energy Link Ltd asked how nodal prices were envisaged to be used in calculating the new benefit- based charge. 

Answer

The benefit-based charge for a grid investment is to be allocated in proportion to each customer’s share of net private benefits from the investment. Investments can produce a range of benefits, including changes to nodal prices.

The Authority is proposing to estimate each customer’s share of the benefits from each of the seven recent major investments in clause 13(b) of the proposed guidelines using vSPD (the Authority's version of the Scheduling, Pricing and Dispatch model). We estimated the historical investments’ benefits based on changes in the price and quantity of energy at various nodes occurring as a result of each grid investment, calculated by running the vSPD model.

Question - Contact Energy Limited

The cogen discussion is partly about the dynamic nature of plant entry and exit, and what the deminimus change to circumstances is to get a change to charges (for the generator).
It's also about decarbonisation incentives in relation to the proposal.

It’d also be good to talk a bit about the vSPD modelling, and what’s driving the change in charges whereby benefits are deemed higher for generators and less for load, compared to the earlier proposal. We are trying to understand how much inherent variability in outcomes can arise within the guidelines due to the embedded assumptions and choices of method.  Did the Authority do the vSPD modelling, or was it contracted out?

Answer

Thanks for coming in for the meeting. Hopefully it assisted your understanding of the Authority's TPM proposal. I just wanted to reiterate that if Contact Energy has views on the TPM proposal, we would ask that these are made in writing in your submission.
However, if you have any further requests for information, please put them into an email and we’d be happy to assist if possible. (We may publish any non-confidential information relevant to requests.)

The price charts you were asking about can be found at the “price charts” tab in the “Price indices and grid use model cost benefit components” spreadsheet

You said you hadn’t managed to locate Contact’s Te Rapa plant.

Our records show Te Rapa to be partially embedded. However (as per para H.63), in our modelling partially embedded generation is treated as distributed generation. Here are some details:
• POC_Network: TWH0331_WAIK
• Te Kowhai
• Rolls up into WEL Networks

For net vSPD we 'provisionally' manually net TWH0331 and HAM0111 against TWH0331 TRC1. This reduces charges to WEL Networks.

Question - Contact Energy Limited

As I work through the TPM there are inevitably more questions that arise.  A couple relate to the depreciation method used and I’d appreciate your confirmation that my understanding is correct.

Risk of over recovery from not treating revaluations as income and using a nominal WACC

There are three ways to ensure that no over recovery occurs.  These are:

  1. Index Transpower’s regulatory asset base (RAB) for inflation, with these revaluations treated as income (that is, negative depreciation) and apply a nominal WACC.  This is the approach adopted by the Commerce Commission with regard to Transpower;
  2. Index the RAB for inflation and apply a real WACC (with revaluations not treated as income); and
  3. Not indexing the RAB and applying a nominal WACC.

As drafted, the Authority appears to be proposing that for post-2019 investments, the benefits-based charge be based on indexing the RAB for inflation, applying a nominal WACC, and without treating revaluations as income.  All other things being equal, this will lead to over-recovery.  Please confirm.

Use of the residual charge as a balancing mechanism between depreciated historic cost and indexed historic cost for future investments

Under the Authority’s proposal, Transpower will receive revenues in accordance with its independent price path which uses a depreciated historic cost approach, while it will only be able to allocate out charges using an indexed historic cost method for future investments. 

Depreciated historic cost recovers most of the cost of an investment in the early years of an asset’s life, whereas indexed historic cost recovers more relatively later in its life.

Paragraph B.93 indicates that the Authority expects the residual charge to adjust over time to allow for the difference between the DHC charges (which are the same as Transpower’s recoverable revenue attributable to the investment) and the actual charges.  As the Authority explains, the effect of using IHC on the residual charge is positive in the early years of an investment’s life and negative in later years. 

This will reduce the benefits-based charge to generation customers in the early years of an investment and increase them in later years. 

Doesn’t using the residual the residual charge as a balancing mechanism undermine the Authority’s objective of beneficiaries pay?

Answer

Risk of over recovery from not treating revaluations as income and using a nominal WACC

We don’t consider that our proposed approach to the benefits-based charge for post-2019 investments will lead to over-recovery. This is because:

  • the proposed TPM guidelines only apply to the allocation of the total MAR for each year between transmission customers. The total MAR for each year is set by the Commerce Commission and is unaffected by the TPM. (This is reinforced by Clause 9 of the proposed guidelines, which requires that the total recovered by Transpower from the main transmission charges may not exceed Transpower’s forecast MAR.) When the TPM guidelines refer to changes to the recovery profile, they refer to the recovery profile for the benefit-based investment only – not to the recovery profile for Transpower’s overall MAR
  • our intention under the proposed guidelines is not to index Transpower’s RAB for inflation. Rather, the intention is to adjust the profile of benefit-based charges for inflation. In other words, the annual benefit-based charge for the investment would change over time in line with a price index. To be clear, the adjustment for inflation is not intended to be purely an upward adjustment: rather, charges would be lower in the early years, and higher in the later years (assuming a price index that increases over time), compared to simply dividing the expected benefit-based charge into equal annual amounts over the benefit-based investment’s expected life. The profile is intended to be set in order that the cost of the investment would be exactly recovered (not over- or under-recovered) over the benefit-based investment’s expected life, on an expected NPV basis.

If in your view the Guidelines are not sufficiently clear on this point, please include in Contact’s submission any suggested changes to the Guidelines that you consider would improve their clarity.

Use of the residual charge as a balancing mechanism between depreciated historic cost and indexed historic cost for future investments

We don’t consider that using the residual charge as a balancing mechanism would undermine the objective of a benefit-based approach.

It is correct that – as your question notes – our IHC approach would reduce the benefits-based charge in the early years of an investment and increase it in later years, relative to an approach in which the recovery profile for the benefit-based charges was based on DHC throughout the asset’s life. However, the reduction in the early years and the increase in the later years are expected to balance out, so that transmission customers who benefit from a transmission investment would collectively pay for its costs over the investment’s life. The charges would be in proportion to the benefits received by the customers from the investment. In the Authority’s view, this would have a number of advantages, including for example that it would:

  • bring implications for grid-related costs into proper consideration when businesses make location and other investment decisions
  • encourage customers to participate in the scrutiny of investment proposals and reveal their best information about benefits and costs of those proposals.

Supplementary question - Contact Energy Limited

Thank you for this detailed response.  On the first point, is it correct to surmise that the residual charge will need to be used as a balancing mechanism?  If you keep within MAR but index the benefit-based charge for inflation without treating these revaluations as incomes and use a nominal WACC, then this must lead to an over recovery of the benefit-based component of the transmission charge.  In order to keep within MAR, the residual charge would need to reduce correspondingly.  Please advise if you agree with this assessment.

Answer

Yes, under the proposal the residual charge is the balancing mechanism. The Commerce Commission approves a different recovery profile than what we have in mind for future investments, so that means unders/overs on the benefit-based charges, with the difference mopped up by the residual charge.

Question - Horizon Energy Group

You may recall we raised the issue of our notionally embedded generation that is equally direct connected to the grid, and is subject to a PDA.
 
We are looking to explore what will be the treatment under the proposed TPM approach. How do we best achieve this?

Answer

Thank you for your question on the treatment of the notionally embedded generation at Aniwhenua and Matahina under the proposed TPM.

We have treated both Aniwhenua and Matahina as grid-connected generation, based on our understanding that neither generator is physically connected to the distribution network. This is consistent with our treatment of all notionally embedded generation that does not meet the definition of distributed generation in the Code (see Appendix H of the 2019 issues paper, paragraph H.63).

On this basis, under the proposed TPM, injection from generation at Aniwhenua and Matahina has not been “netted off” against Horizon Energy’s load in the calculation of Horizon Energy’s allocation of benefit-based charges in respect of the seven historical investments in Schedule 1 of the proposed guidelines. (Conversely, had the generation been considered to be distributed generation, its injection would have been netted off, and Horizon’s allocation of benefit-based charges would be lower.) The generation would have no effect on Horizon’s residual charges (regardless of whether or not it is classified as distributed generation), as under the proposal, residual charges would be calculated on a “gross load” basis (see Appendix B, discussion from paragraph B.210).

Please inform us in your submission if the assumptions we are working from are incorrect (for example, if either Aniwhenua and Matahina were in fact physically connected to the distribution network). If there was evidence that the generation is physically connected to a distribution network, the Authority would modify its modelling to allow netting of that generator against load (which would reduce Horizon’s benefit-based charge but not its residual charge).

With respect to the existing PDA, we would note that our proposed changes to the TPM Guidelines do not override existing contractual commitments. We would also note that the prudent discount policy continues to exist in the proposed TPM Guidelines (with some modifications). It is possible that some or all aspects of the rationale for a prudent discount agreement would continue to apply under the proposed TPM guidelines as applies under the current guidelines (which would be a matter for consideration by Transpower and other potential parties to such an agreement).

Question - Independent Electricity Generators Association

In the file named 'Investment efficiencies model' from the CBA EMI files and in the 'Generation capacity' sheet. The Model results in the "All major capex" scenario  columns S to AJ has an average of 65% of generation MW 'export constrained'  from BEN, ROX, TWI and WKM (eg in 2020 total MW is 7,732 of which 5,027MW export constrained and 2.705MW not export constrained). What is the impact of this constraint situation on the modelled wholesale electricity price? Does this result in a 'scarcity situation' price of $20,000 to trigger generation or transmission investment?

Answer

The 'investment efficiencies model' estimates benefits from improved generation investment location decisions based on expected percentage changes in generation investment in areas where exports may strike constraints (on a fraction of output) that are sufficient to justify transmission investment. The term "constraint" is used here to reflect congestion costs and not necessarily an absolute constraint on exports. No assessment has been made of the effects of this constraint situation on wholesale electricity prices. The investment efficiencies model is assessing long-run effects on investment decisions. The implicit assumption in this sort of long-run analysis is that scarcity will be resolved by transmission investment or generation investment. 

Question - Independent Electricity Generators Association

In the Forecast peak demand sheet there is a sum of output from different locations (don't know where these numbers come from) and an UNCHANGED Diversity Factor of 1.28 is applied to total demand to get Peak demand. This diversity factor is unchanged over all the years in the analysis. How is this consistent with the EA assumption that demand will be more responsive to nodal price and might increase demand at 'peak' times because that is when consumers value electricity the most?

Answer

The assumption of an unchanged diversity factor is consistent with the assumption used throughout the CBA that peak demand can be measured as demand during the top 1600 trading periods - that on average consumers do not distinguish between the very highest peak periods and other trading periods when making consumption and investment decisions.

Question - Independent Electricity Generators Association

The following two graphs come from the presentation slides for the TPM CBA workshop in Wellington (page 22 and 18 respectively). Looking at these alongside each other the CBA includes a benefit of avoiding ~$40m per annum average spend on batteries between 2026 and 2040 due to the proposed TPM at the same time investment of $500 - 800m per annum in actual transmission infrastructure from 2030 occurs. Is the investment in actual transmission infrastructure more efficient because of the resulting increase in the capacity of the transmission grid? Also wondering what the increase in transmission revenue from non-load transmission customers is over this time - the graph only shows the impact on load customers? The difference in the percentage increase for load customers under the proposal compared with the status quo also looks small given the quantity of assumed transmission investment?

Answer

The assumption underpinning the CBA results shown in the charts is that the transmission investment is efficient. The amount of transmission investment in the long-run level of transmission investment (other than overheads) is assumed to be proportional to peak MW demand. The average of the annual change in grid investment over the modelled period is $53m (and $75m pa for the period between 2030 and 2049 that you reference). In effect the increase in peak demand brings forward grid investment. Note that the comparison should be to total wholesale cost, that is also consider the impact on wholesale energy prices, not just investment in batteries vs investment in grid. The CBA models the net effect being a reduction in total costs and an increase in consumer surplus.

In the CBA modelling, transmission revenue recovered from generation customers falls as a share and in total under the proposal compared to what it would have been under the baseline, by an average of 33% per year over the modelled period. It is, for example, 42% lower in 2040 under the proposal than in the baseline. 

Graph showing transmission investment rises under the proposal
Graph showing battery investment

Question - Northpower

TPM Consultation – Official Information Act Request

Following the review of the TPM consultation material released by the Electricity Authority, we request that the Authority provide us with the following information:

  1. Can you please advise who prepared the cost benefit analysis (CBA) that form the basis of the 2019 Issues Paper?
  2. If the CBA was prepared by an external firm, could we please have a copy of the terms of reference (excluding financial matters)?
  3. Can you please confirm whether you had the CBA work peer reviewed? If so, can you please provide the document that form that review.

For the avoidance of doubt, this request for information is made under the Official Information Act.

Answer

The Authority’s response to Northpower’s Official Information Act request has been published on the Authority’s website here.

Question - Major Energy Users Group

Loss and constraint excess

I asked for clarification at the TPM workshop on Tuesday about LCE treatment but don’t agree with the answer given –  they said the treatment was consistent, but my understanding is that they have used a different treatment when comparing the impact on grid customers for the current and proposed methodologies.

According to my understanding of the EMI spreadsheet:

  • The EA’s status quo cost estimates in 2021/22 are based on the TP interconnection rate for 2019/20 scaled down to account for the lower WACC in RCP#3 times the RCPD for the 2019/20.  The estimate does not allow for the LCE rebate that xx receive (share of around $xxm attributed to HVDC and IC assets)
  • The estimates for the TPM proposal calculate the residual charge based on residual MAR after LCE revenue (xxm) is deducted

Consequently the BAU charges are overstated (about xx% for xx) compared to charges under the proposal.  This is misleading and will have a secondary impact on the cap calculations

The Authority discussed this directly with MEUG - after which MEUG sent the following response and additional question

Thank you for discussion last Friday on the topic of LCE per emails below.

Have discussed with xx slide 33 used at the regional workshops (similar to slide 45 at TPM CBA technical workshop) that noted LCE is netted off.  This is the summary you drew on the whiteboard.  Also confirmed approach consistent with cells top LHS of spreadsheet “2019 Proposal impacts modelling.xls”, tab “Forecast TPM Revenue.”

On this basis can advise we are ok with treatment of LCE per prior emails. 

Please provide string of annual data for each year 2022 to 2049 for Demand Model output follows

Baseline expected case

NZ total electricity demand

GWh pa

2022 to 2049

A

Transmission costs

$m pa

ditto

B

Generation costs

$m pa

ditto

C

Proposal expected case

NZ total electricity demand

GWh pa

ditto

D

Transmission costs

$m pa

ditto

E

Generation costs

$m pa

ditto

F

 

Grid use efficiency benefits

$m pa

ditto

G

Where (NPV(E)+NPV(F)) – (NPV(B)+NPV(C)) + NPV(G)= $2,579m, i.e. the NPV of the gross benefit of more efficient grid use (expected case).

Am interested in the volume data (GWh pa) because will be able to compare average annual unit costs over time as a proxy for relative prices of transmission and wholesale energy between the baseline and proposal.

If available can you provide NZ maximum demand (MW) yearly 

Happy to discuss how the above question could be improved to reflect the granular annual flows we want.  Hope you can help with providing the above data.

Answer

Here is a spreadsheet with the series you asked for:

Note that the final CBA summary reported (grid use bens of $2.6b) takes half of one scenario and half of another scenario, that is with and without energy price effects, as explained in chapter 4.

You will see just one scenario (the higher number, with energy price effects) here.

For the final consumer surplus calculations please see the “Summary costs and benefits” excel workbook that was released in July (eg in the “Summary grid use model” sheet there is an adjustment to the net benefit number in column M.)

Question - Contact Energy Ltd

I listened with interest to John Stephenson’s presentation yesterday.  He made the point that it is widely accepted that the efficiency cost of a tax is approximately proportional to the square of the tax rate (i.e. small taxes have relatively small efficiency costs while large taxes have relatively large efficiency costs).  This leads you to the conclusion that it is more efficient to spread taxes across a broad base to keep tax rates low.

The Authority has applied this principle when deciding to gross-up a load customer’s demand by adding injection by distributed generation and/or behind the meter generation for the residual charge.  This will have the effect of spreading the incidence of transmission charges over a significantly broader base.

As the slide below illustrates, Authority’s proposal will reduce the efficiency cost (referred to below as the cost of raising revenue) during peak periods but increase it in off-peak periods.

My question is as follows:  how much of the grid-use benefits of the Authority’s proposal can be attributed to the “grossing-up” element of the proposal?  How does this compare to the aspect of the Authority’s proposal to flatten the interconnection charge across peak and off-peak periods?

Answer

Thanks for your question on the residual allocator.

In response to your question, the choice between a gross load approach to measuring the default residual allocator and a net load approach does not make a material difference to the quantified grid-use benefits of the Authority’s proposal. The Authority has proposed a gross load approach to the default residual allocator on the basis of the qualitative analysis set out at page 154 of the 2019 issues paper, including that:
• gross load is a better proxy for customers’ size (and so their willingness and ability to pay) than net load
• use of gross load avoids creating an artificial incentive for investment in distributed generation over time.

Note that the slide “Time of use energy prices and consumer welfare” (to which your question refers) does not relate to the choice between a gross and net load approach to measuring the default residual allocator. Rather, it relates to the proposed removal of the RCPD charge (and spreading of interconnection charges across peak and off-peak periods).

Supplementary question

Thanks for this.  I was aware of that the slide related to the proposal to remove the RCPD.  Hence my question.  What has more of an impact in the CBA – removing RCPD or the proposal to gross-up the residual charge?  I agree with the qualitative assessment described below but am a little surprised that the impact is so small.  So if you were to gross up the existing RCPD charge would you still get a materially better result under the Authority’s proposal of grossing up AMD?


Supplementary answer

In response to your question, removing RCPD has more of an impact in the CBA than the proposal to gross up the residual charge. It does not make a material difference to quantified CBA results whether a gross or net measure of demand is used to allocate the residual charge. The main quantified benefits come from removing the RCPD charge (which sends a very strong price signal that often does not reflect the economic cost of using the grid) and replacing it with a less distorting alternative. 

We have not assessed the impact of grossing up the existing RCPD charge as an alternative to the proposal. However, we do not expect that such an alternative would have benefits as high as those of the proposal. That is because an important source of benefits from removal of the RCPD charge stems from the resulting significantly lower effective price for consumption during times of peak demand, when consumers value electricity most highly. Simply grossing up the existing RCPD charge as an alternative to the proposal would not capture this source of benefits (as it would not result in a significantly lower effective price for consumption during times of peak demand).

Further supplementary question

One final point, paragraph 2.32 makes the point that “an efficient, cost-reflective charge would rise when the grid gets congested, and drop when there is spare capacity.”  The point is made that the current RCPD does not do this.  It generally increases after Transpower has invested in the grid to increase its capacity.  How does the Authority’s proposal do anything different?  The Authority’s proposals will not see charges rise when the grid gets congested, and drop when there is spare capacity.  Rather, like the current RCPD charge, they will rise once Transpower has invested in the grid to increase its capacity.

Further supplementary answer

Thanks for your question.

Some context for our response: sometimes stakeholders make the argument that the RCPD charge should be retained because – as it applies at times of peak demand – it provides an effective signal of the economic cost of using the grid.

The Authority does not agree with this argument. Our view on the RCPD charge, as set out in paragraph 2.32, is that it is a not a good signal of economic costs, so the function of signalling economic costs is not a good justification for the retention of the RCPD charge.

However, the point of paragraph 2.32 is not to suggest that the main transmission charges under our proposal (the benefit-based charge and the residual charge) are a better signal of grid congestion than the RCPD charge. That is not our view. Under our proposal, grid congestion would not be signalled primarily through transmission charges. Instead, it would be signalled through nodal electricity prices determined in the wholesale market. The Authority’s view is that nodal prices provide a timely and efficient signal of the actual cost of grid congestion at specific locations. (If Transpower considers that grid demand would not be adequately controlled by nodal pricing, then it could propose a transitional peak charge as part of its TPM.)

The cost of transmission investments would still be recovered, including when those costs increase, but through fixed-like charges that least distort grid use and investment decisions.

Question - Mercury NZ Limited

Thanks for making yourselves available at the CBA conference.  Overall it was really useful hearing how you went about approaching the CBA.  We had a few questions on it which would be useful for us to clarify before we make our submission.  At this stage we intend getting into the technical aspects of the CBA in our cross submission. 

  •  From an analytical review perspective we’re struggling a bit coming to terms with how the CBA could provide a net benefit of a multiple of total current transmission charges.  The best case scenario seems implausibly high.  Putting aside the technical CBA model, are you satisfied the expected net benefit represents a reasonable outcome based on current market dynamics?  
  • I recall seeing in one of the files (which I can no longer find sorry) that the future generation model lists Mercury’s Turitea windfarm as operational in the 2040s, yet we are commencing construction in late 2019.  While we acknowledge the precise date of future generation plant is difficult to predict, what is the effect in the model of potentially wide differences between the assumed generation investment and other dates?  In other words, how sensitive is the CBA to assumed generation investments?
  •  Comparing the “alternative” with the proposal, where the alternative is essentially retaining the existing TPM but increasing the RCPD periods such that it becomes a sort of energy tax, do you have an explanation for how there can be a $1 billion net benefit difference?  Or how can the proposal be 30% better than what looks like the same outcome?

Answer

Thanks for your email. Here is a response to your three questions.
  •  From an analytical review perspective we’re struggling a bit coming to terms with how the CBA could provide a net benefit of a multiple of total current transmission charges.  The best case scenario seems implausibly high.  Putting aside the technical CBA model, are you satisfied the expected net benefit represents a reasonable outcome based on current market dynamics?  
The $2.7b net benefit is over 27 years. As a rough indicator, the net benefits are around 12% of transmission charges on an annualised basis (based on $2.7b / 27 years and compared to $850m per annum transmission charges in the initial years. The net benefits are estimated as 4.4% of baseline wholesale market costs (including  interconnection costs), in net present value terms. See table 6 in the 2019 issues paper.  This is the relevant comparator, as many of the benefits come from the benefits consumers get from reduced wholesale + interconnection charges at peak times and reduced off-peak prices and reduced investment in batteries. See slides 24-28 of the slidepack from the technical workshop available on our website. The Authority is satisfied this is a realistic outcome, based on an analysis of long term market dynamics
  •  I recall seeing in one of the files (which I can no longer find sorry) that the future generation model lists Mercury’s Turitea windfarm as operational in the 2040s, yet we are commencing construction in late 2019.  While we acknowledge the precise date of future generation plant is difficult to predict, what is the effect in the model of potentially wide differences between the assumed generation investment and other dates?  In other words, how sensitive is the CBA to assumed generation investments
The Turitea windfarm is listed in the file ‘possible_gen.csv’ as available from 2020. See link: https://www.emi.ea.govt.nz/Wholesale/Datasets/_AdditionalInformation/SupportingInformationAndAnalysis/2019/20190723_TPM_2019_IssuesPaper/2019_Cost_Benefit_Analysis%20(including%20additional%20files)/Grid%20use%20model/Data
Whether and when the model calls on this possible generation investment depends on assumptions about how tight supply conditions are at the start of the assessment period and the assumptions being made as to how many generation investments can be made in any one year.  The CBA Technical paper explains this around para 2.63. The CBA is very sensitive to assumptions about generation. See para 4.210 in the 2019 issues paper on generation investment. This sensitivity is one of the key reasons that we adopt a conservative approach in the CBA by presenting a 50/50 average of the ‘with and without’ price effects result.
  • Comparing the “alternative” with the proposal, where the alternative is essentially retaining the existing TPM but increasing the RCPD periods such that it becomes a sort of energy tax, do you have an explanation for how there can be a $1 billion net benefit difference?  Or how can the proposal be 30% better than what looks like the same outcome?
The “alternative” is an option that could in principle be implemented under the current TPM; that means that the RCPD charge could be amended, but the HVDC charge would be retained. The dominant reason for the difference in benefits between the proposal and the alternative is that, relative to the proposal, generation investment is delayed during the first half of the assessment period. The reason for the delay is the higher cost that South Island generation faces under the alternative from the retention of the HVDC charge compared with the proposal.
A second, less material reason is that the investment efficiency benefits estimated under the proposal as being the result of benefit-based charges do not arise under the alternative.
We trust this answers your questions sufficiently. Please let us know if you have further questions.

Question - New Zealand Steel Limited

Modelling is stated to have been carried out based on market prices for the 12 months to August 2018 and $109/MWh for 2050. These prices are significantly different to what has been the market prices in the past 12 months.

What work has been done on changed market situation? what impact does this have on the conclusions in the report.

Answer

We have not carried out any analysis to consider the effects of changes in market prices over the past 12 months on either the CBA or the charges modelling.

We do not consider it is necessary or appropriate to carry out such analysis with respect to the CBA as:
  • the CBA only considers the effects of proposed changes to the TPM from 2021
  • the CBA analyses the long-term effects of changing the TPM (out to 2049), assuming that certain underlying market conditions are not affected by the TPM (e.g. fuel costs and population growth)
  • shifts in market conditions will have an impact on the size of costs and benefits associated with TPM options, however, the CBA analysis is not expected to accurately predict the path of market conditions over the long term (this would not be a reasonable expectation)
  • we have conducted sensitivity analysis on assumptions on the scale and speed of generation investment response to higher electricity prices, as a way of investigating the sensitivity of CBA results to alternative market conditions.
With respect to the charges modelling, we are satisfied that the period we have used for the modelling is a representative period and thus reflects the expected distribution of benefits. The modelling uses electricity data for July 2014 to June 2018, which includes both wet and dry years.

Question - Transpower

We have consultants Axiom and Farriersweir reviewing the TPM CBA modelling.  They have struck information availability problems so have asked us to request the Authority make further information available.  Material they have identified they need to complete their review is a range of data, spreadsheets and computer code they understand was used to run the analysis presented in the issues paper and technical paper.  This is set out below. 
 
The absence of this information makes it difficult for us (and other stakeholders) to fully understand the model including whether it is reasonable.  A key concern is that we receive this information with enough time to review and consider it before submissions are due.
 
I’m assuming you’re busy this afternoon with TPM workshops so won’t pick up the phone right now.  Please give me a call when you are available. 
 
The information we request be made available is as follows:

  • Demand modelling – the input data, computer code (e.g. R and Python), other methods and outputs of the EA’s modelling of demand (used to generate elasticity estimates), referred to as ‘Model 1’, which is set out on pp. 30-46 of the CBA technical paper

  • Prices and costs modelling – the input data, computer code (e.g. R and Python), other methods and outputs of the Authority’s modelling used to generate the generation prices, transport costs, transmission charges and price expectations, which is set out on pp. 47-53 of the CBA technical paper

  • Generation investment modelling – the input data, computer code (e.g. R and Python), other methods and outputs of the generation investment model, referred to as ‘Model 2’, which is set out on p. 54 of the CBA technical paper

  • DER (i.e. battery) investment modelling – the input data, computer code (e.g. R and Python), other methods and outputs of the battery investment model, referred to as ‘Model 3’, which is set out on pp. 55-50 of the CBA technical paper

  • Monte Carlo analysis – the Monte Carlo analysis, including any input data, computer code (e.g. R and Python), and other methods used to support benefits for ‘more efficient investment in generation and load’ and ‘durability: increased certainty for investors’, including for each:
     
     - a description of the input variables and the distribution from which each is assumed to be drawn

     - an explanation of the relationship that is modelled between these variables that gives rise to the benefit that is being estimated and 

            - documentation of the outputs of the Monte Carlo analysis, including the results of each                     random trial used.

 
We recognise that some information on the above components is included already on the Authority’s EMI website.  However, it does not pick up all of the information above and is otherwise insufficient to fully understand the Authority’s cost-benefit analysis.


Answer

The information you requested, and related files, can now be accessed on the EMI website.

For convenience, the spreadsheet ‘list of files.xlsx’ provides a map to the files at that web address. See rows 4-104 in the ‘list of files.xlsx’ to direct you to the information you requested, namely the input data, computer code (e.g. R and Python), other methods, and outputs for:

  • Demand modelling (Model 1 on pages 30-46 of the CBA technical paper)
  • the prices and cost modelling (as described on pages 47-53 of the CBA technical paper)
  • the generation investment modelling (Model 2 of the CBA technical paper)
  • the distributed Energy Resources (Batteries) investment modelling (Model 3 set out on pp 55-60 of the CBA technical paper).

The central scenario for the grid use model (row 21 of that spreadsheet) may be the best starting point for the components listed above.

In relation to the Monte Carlo analysis for investment efficiencies and increased certainty for investors, you also asked for:

  • input variables and assumed distributions – these are set out in the CBA Technical Appendix (Tables 25, 26, 28, 29) and in the excel file ‘Investment efficiencies model.xlsx’
  • an explanation of the relationship modelled between the variables – these are described in the CBA Technical appendix
  • documentation of the outputs of the Monte Carlo analysis, including results of each random trial used – see rows 123-129 in the “list of files.xlsx’ for computer code.

Question - Trustpower

As I mentioned last week, we have now finished pulling together a list of additional information we need from the Authority in order to complete our review of the CBA for the Authority’s latest transmission pricing proposal.

Attached is a letter containing the details of the additional information we need from the Authority.

Answer

Thank you for your request, dated 14 August 2019, for additional information related to the cost benefit assessment for the 2019 TPM proposal.

The information you requested, and related files, can now be accessed on the EMI website.

Question - Farriersweir

Thanks for your time earlier.

As promised, the two files referenced in the ‘List of files’ spreadsheet that I could not find on the EMI website were:

(Apologies if I missed them somehow).

Also, as discussed, I look forward to seeing the R / Python code used to run the grid use model once this is available.  (I have subsequently spoken to others that also indicated a desire to see this).

Answer

Thank you for your emails of 12 and 13 August 2019 in which you asked for the computer code and files with parameter estimates for battery investment and econometric models.

The informaton you requested is available on our EMI website.

The spreadsheet ‘list of files.xlsx’ provides a map to the files that contain this information. The central scenario for the grid use model (row 21 of that spreadsheet) may be your best starting point. The parameter estimates you asked for are in the folder ‘Parameter estimates’ in the folder ‘Grid use model’.

Question - Farrierswier

It appears that your grid use model predicts that total consumption (over peak, shoulder, off-peak and EG periods) would be lower under your proposal than the status quo (the baseline scenario). Can you confirm that is the case and, if it is, can you explain why a reduction in peak prices would result in lower consumption, overall?

Answer

Modelled total consumption, in MWh, is lower under the proposal than under the baseline. Demand at peak increases as a result of the reduction in peak prices inclusive of interconnection charges. But energy consumption outside peak periods is, on average, 0.7% lower under the proposal compared to the baseline.

There are two main drivers of this effect.

First, under the proposal interconnection charges are modelled as a per MWh charge. This is the same approach used in the modelling for the 2019 CBA (see paragraph 2.10 of the 2019 CBA Technical Paper). This causes an increase in the cost of consuming electricity outside peak periods. This approach to modelling what would be fixed charges is conservative, as it will tend to overstate the demand reduction under the proposal (and thereby understate the proposal’s benefit), to the extent that consumers respond to marginal electricity costs and not average costs.

Second, a small share (5-10%) of the lower demand under the proposal arises because the baseline includes more energy demand related to meeting energy lost during the charging and discharging of utility-scale batteries.

Question

The net benefit of $1.335b combines benefits and costs that output from the grid use modelling. However, those benefits and costs come from different sensitivities applied to the central scenario (as the median value was selected from the range of sensitivity results in each case). For instance, the sensitivity scenario (s_1.0_1.05_0.01_0.9) used for the more efficient grid use benefit ($1.131b) has different benefit values from more efficient investment in batteries and bringing forward transmission investment than those adopted by the EA. Does this introduce inconsistency into the net benefit estimate given the modelled interrelationships between these costs and benefits?

Answer

We have reported the median values when summarising the model results in a way that is consistent with the reporting of results in the 2019 CBA.  The summary takes the typical model results, and this approach is not inconsistent.

We note that adopting instead the values for batteries and transmission investments at sensitivity scenario (s_1.0_1.05_0.01_0.9) for the proposal does not materially affect results (net benefits would increase somewhat). 

Question - Axiom Economics

There’s said to be no transfers counted benefits in the CBA. It’s instead claimed that any reduction in existing suppliers’ profits arising from the forecast reductions in wholesale prices are efficiency gains arising from cost changes. What is the grid use model’s estimate of the amount by which the total cost of generation would fall if the proposal was implemented?

Answer

The total cost of generation to consumers declines by $1.18 billion or 1.8% of the baseline value (present value, on average across model simulations).

Question

The Authority states that it has based its estimates of the benefits from “improved scrutiny” of grid investments on its observations from “the Commerce Commission’s regulation of Transpower’s expenditure over the past 10-15 years and the administrative settlement between Transpower and the Commission in May 2008”. Throughout this period there has been no benefits-based (BB) charge in place – the TPM has instead reflected largely the approach that the Authority is now seeking to amend, i.e., scrutiny of new investments was taking place in the absence of a BB charge. How does looking at outcomes from this window – when there was no BB charging – provide an indication of the incremental effect that introducing a BB charge would have (if any) on the Commission’s existing oversight role, given that there wasn't such a charge in place throughout this entire period?

Answer

The purpose of using observations from the Commerce Commission’s regulation of Transpower over the past 10-15 years was to infer the likely scale of gains from increased scrutiny of transmission investments.

We cannot draw directly from prior experience about the specific effects of the proposal because it has not been implemented. The Authority considers it is reasonable to draw from the prior experience of Commerce Commission regulation. The trigger for scrutiny need not be identical to the trigger under our proposal; it is more important to identify a reasonable estimate of the magnitude of gains that may be expected from scrutiny of investment proposals.

Question - Pioneer Energy

In the table and chart you had on one slide the Table lists MWs of new generation projects and the graph shows cumulative increase in peak MWs. What assumption is made about the contribution of the new wind projects to peak MWs?

Answer: The assumption is that peak output from wind generation is 83% of off-peak output. This is based on observed ratios of peak to off-peak output from wind generation in the past decade.

 

Question - HRL Morrison

Why are some committed wind farms not included?

Answer

Recently committed wind farms were not included in the modelling because they were not committed at the time the CBA database for possible and probable projects was finalised. See also our explanation at para 2.29-2.31 of the CBA Revisions paper, where we acknowledge revisions did not aim at updating all data or assumptions, and that the sensitivity analysis provides a sufficient range of possible circumstances to cover the potential effects of changes  in assumptions.

Question 

(Question clarified after the webinar)Follow up on generation. There appears to be significant imperfections and uncertainties in modelling the indirect impacts of the small change in demand (only ± 1-2% overall GWh and higher at peak relative to shoulder and off-peak and less distributed batteries) arising from the proposal on wholesale market supply, new investment and pricing.

Other than the location of plant between islands arising from the changes to HVDC cost recovery, can you explain why these small changes should not be as efficiently met by adjustments in the dispatch of existing wholesale generation plant and the building and timing of an appropriate mix of new plant, as any other change in the demand structure that might arise from other factors (e.g. population growth, changing patterns of consumption, changing fuel and new investment costs etc).  Can you be confident that the modelling approach used is adequate to identify and quantify these small changes in the structure of demand.

Answer

The CBA's modelling of interactions between demand and supply is of course simplified. For example, the modelling accounts for adjustments in the dispatch of existing generation plant due to changes in operating costs, demand and new generation investment. But the modelling does not consider changes in generator offer strategies.

To the extent that simplifications exist in the modelling, they exist in the analysis of both the TPM proposal and the baseline against which the proposal is assessed. This equality of treatment between the proposal and the baseline helps to ensure the CBA modelling focuses on key effects arising from the proposed policy change.

We are confident the approach used in the CBA modelling appropriately identifies and quantifies the key economic effects of the proposed changes to the structure of transmission prices.

The CBA is not modelling the effect of other initiatives or changes, such as adjustments in dispatch or building an appropriate mix of new plant (although the Authority currently considers its proposal would improve incentives to support, for example, investment in an appropriate mix of new plant).

Question 

(Question clarified after the webinar)Can you confirm that if both the positive and negative indirect impacts  on wholesale pricing and costs were excluded (as has been done in regard the indirect impacts on the distribution sector) the quantified net benefit  of the proposal would be reduced by $1.17b.

Answer

The CBA’s net benefit number might be reduced by an amount in the order of $1.17 billion, if we deducted (arithmetically) the quantified effect of changes in wholesale prices and costs on consumer welfare. This is not a calculation considered in any detail in the CBA.

It would be inappropriate to exclude one component of the CBA’s modelled results (such as the effect of changes in wholesale prices and costs) without reconsidering other components (such as the effect of changes in the amount and timing of electricity demand). This is because the CBA modelling considers demand and supply jointly.

As such, it does not follow that the TPM proposal’s net benefit would be reduced by $1.17 billion if we excluded the effect of changes in wholesale prices and costs on consumer welfare.  Doing so would result in a different model of the effects of changes in the structure of transmission prices on the functioning of the wholesale electricity market. A CBA on this alternative basis would require a fully elaborated alternative model.

Question - Department of Engineering Science, Auckland University

Please can you break down the $1.13B consumer surplus gains (Figure 1) into gains from productive efficiency and allocative efficiency (as per Figure 7).

Answer: We have not done this as it was not necessary for the overall CBA assessment and would be quite involved given the interaction of price and demand changes across different times of use and over time. The diagram in Figure 7 was presented to illustrate our response to a conceptual point raised in submissions, rather than presenting the basis upon which benefits were broken down in our calculations.

Follow on question: Thanks for getting back to me. Let me try and elaborate on my question. Allocative efficiency in consumer welfare comes from changes in consumption with different charging regimes.

Consider an industrial plant shifting 1 MWh out of a single peak period t  when it is consuming q_t to a single offpeak period u when it is consuming q_u.

This will have a shifting cost $C = per MWh, but plant will save money from arbitrage from spot price difference = p(t)-p(u). The cost/MWh will be C-p(t)+p(u). If the plant has utility functions U_t and U_u at t and u,  then we get a loss in marginal utility U'_t(q_t) - U'_u(q_u). The cost per MWh is then

C - p(t) + p(u) + U'_t(q_t) - U'_u(q_u)         

If, for simplicity, we assume no capacities on plant, we get prices p(t) = U'_t(q_t),  p(u) = U'_u(q_u). Then the loss in marginal welfare from shifting is C.

Suppose RCPD charge is $r/MWh, and plant shifts with RCPD but does not if r=0. Then we have:

r >  C  (plant shifts with r>0)

C > 0  (plant does not shift with r=0)

If we made the plant shift when r=0 then it would lose C per MW, where 0 < C < r. Welfare loss amounts to estimating C.

If the plant is at capacity in the peak period t then p(t) < U'_t(q_t) and p(u) = U'_u(q_u), then we get a loss in welfare at the margin of
C - p(t) + U'_t(q_t). In this case the analysis comes down to estimating   C and  U'_t(q_t) - p(t).

If the plant is at capacity in period u then we cannot shift load and so there is no increase in welfare from removing RCPD.

The loss in welfare from unnecessarily moving out of period t depends on assumptions about C and U'_t(q_t).
Without knowing these, we can only assume this welfare gain is anywhere from 0 to r per MWh.
I was curious to know what assumptions on C and U'_t(q_t) were used in the CBA.

Answer: The CBA did not make any explicit assumptions about the operational or capital costs to industrial users from shifting load.

The approach we took to measuring changes in consumer welfare is documented in the technical documentation.

For example, modelled changes in consumption at time of use and between time of use as a result of changes in wholesale prices inclusive of transmission charges at different times of use are based on empirical estimates discussed in chapter 2 of the CBA technical documentation:

https://www.ea.govt.nz/development/work-programme/pricing-cost-allocation/transmission-pricing-review/consultations/#c18138

 

Question - Transpower

(clarified version provided after the webinar)

I’m trying to be clear on the high-level story the CBA is telling - how the pieces fit together towards long term benefits to consumers including as a sense check (does it survive the sniff test?).  Is it something like this?

  • peak demand goes up (because interconnection charges are fixed, not charged on peak),
  • spot energy prices go up / become more volatile – bringing forward investment in new peaking/firm generation and batteries,
  • transmission investment comes forward (to meet higher peak demand/generation – and batteries to the extent they are ‘seen’ at grid level),
  • consumption (volume) grows mainly through factors extraneous to TPM reform including electrification and population growth offset by energy efficiency measures (how fast relative to peak demand growth?), and
  • delivered electricity prices to consumers go down (how given transmission, generation and battery investment needs to be paid for?), noting that
  • distribution investment to enable peak demand to grow is not modelled on the assumption that the cost of making that investment is always less than the economic benefit of investing.

What have I missed or misinterpreted?

Answer

The pieces would come together as follows:

  • Peak demand goes up by 1% in the near term compared to the baseline, following the removal of the transmission charge at peak.
  • Wholesale electricity prices (excluding interconnection costs) rise at peak. This brings forward generation investment. The modelled commissioning of generation (hydro, wind, etc) is summarised at table 5 of the CBA revisions paper.

Note that prices are not expected to be materially more volatile under the proposal and this is reflected in the modelling results. The main effect we expect is that peak prices will rise earlier under the proposal (but not as high) compared to the baseline. This stimulates new investment, after which prices will fall (and will fall sooner) than under the baseline.

  • Higher peak demand is modelled to bring forward transmission investment. This would also bring forward benefits from new transmission investment.  
  • The baseline assumes 0.5% demand growth per year on average. This is based on underlying demand growth rates (gross national income and population) consistent with the updated mixed renewables scenario from EDGS (see p10 CBA technical paper released with the 2019 Issues Paper) and the effect of changes in prices and income on electricity demand. 
  • On average, wholesale electricity prices inclusive of interconnection costs reduce relative to the baseline as a result of generation investment brought forward.

This average takes an aggregate consumer perspective. It reflects the bundle of wholesale electricity services purchased by backbone node and by time of use. The wholesale price indices show the changes in prices weighted by consumer expenditure shares by backbone node and time of use in 2017. 

  • Changes to distribution investment costs are not modelled explicitly. It is expected that any such changes in costs would be offset by uncounted benefits. The reasoning is set out in the CBA revisions paper at p26.

See also the chart pack in the summary folder on EMI. 

Question - Top Energy 

Do you a have waterfall graph / table showing the individual drivers of the reduction in More efficient grid use from CBE 19 to CBA 20. (2,579M-1,131M). Given time happy to be sent rather than discuss on call.

Answer

We have not broken down the change in the ‘more efficient grid use’ benefit in a way that allows us to prepare a waterfall chart of the individual components. ‘More efficient grid use’ relates to the combined and interdependent effects over time of investment in and operation of utility scale batteries, of wholesale electricity price formation, and of investment in generation investment.

 

Question - Contact Energy Limited

This next question may be more for whoever did the vSPD analysis:

Is the producer surplus calculated for a particular trading period (and factual or counterfactual scenario) calculated using the clearing price (and volumes) alone, or the clearing price and the offer price (along with volume)?  A worked example would be useful -  Figure 20 in the full report doesn’t quite answer this for us.


Answer

On EMI  there is an excel file entitled 'Illustrative benefit calculation' which provides the formulas for the calculation of producer surplus using worked examples from actual data. For the factual and counterfactual producer surplus, the formula is 'generator revenue' less 'generator cost', for each trading period/point of connection.  Generator revenue is the cleared price multiplied by the volume dispatched. Generator cost is the generator's offers multiplied by the volume. There may be more than one generator offer in a generator's offer tranche, so 'Generator cost' for a generator/trading period/POC will may include a number of volumes with differing offer prices.

Question - MainPower New Zealand Limited

I have a question with regards to reclassifying interconnection assets that provide essentially connection services as connection assets.  This is Additional Component B for the proposed TPM (paragraphs B.294 to B.301, page 172 of the consultation document).
 
I have a suspicion that there are interconnection assets with circuits around MainPower NSPs that would be affected by the proposal.  Transpower has advised that the SBK-WPR A line including switchgear are interconnection assets under the current TPM.  Are you able to advise in your study whether they would be reclassified as connection assets?

Source: Transpower

Also, will there be any other Transpower assets in relation to MainPower NSPs that will be reclassified?

Answer

Thanks for your question on additional component B. Unfortunately we can’t give a definitive answer to your question, as much depends on the specifics of each asset.

Additional component B seeks to address the issue that the existing TPM may provide an incentive for a customer to have a connection asset reclassified as an interconnection asset for the purpose of avoiding or reducing charges. This could lead to inefficient investment.

In the view of Authority staff, additional component B should be applied to connection assets that in future might be reclassified as interconnection assets. In our view it should not be applied to assets that have already been reclassified. The implementation costs of doing so could be significant and could outweigh any benefits. We would welcome submissions on this point (i.e., whether additional component B should be restricted to future reclassifications of assets) – and on any other point.

Note that as this is an additional component, it might not become part of the TPM. Transpower is only required to include an additional component if, in Transpower’s reasonable opinion, including it would better meet the Authority’s statutory objective than not including that additional component.

Finally, if it does become part of the TPM, its application would depend on Transpower’s design of the TPM and on the specifics of each asset.

Question - Contact Energy Limited

We’re trying to understand how the proposed TPM guidelines would apply for a hypothetical new generation asset (e.g. a geothermal plant in the central North Island) and a hypothetical thermal asset.  Clauses 26 and 42 of the Guidelines provide very little insight, and neither does the discussion in Appendix B.  Are you able to provide some guidance on what the cost implications for Contact are under both scenarios (the entry of a new geothermal asset and the exit of a thermal asset)?

Answer

Thanks for your question on entries and exits.

Unfortunately we can’t give a definitive answer regarding the cost implications for Contact, as that would depend both on Transpower’s design of the relevant parts of the TPM and on the specifics of each case (as well as on any amendments made to the proposed Guidelines after consultation). However, we can provide some indication of how we currently think things could work out in various scenarios.

Entry of a new grid-connected geothermal generation asset

  • The proposed Guidelines would require Transpower to include in the TPM a process for allocating charges to new large consumers or generators (or to existing large consumers or generators who establish a new plant or generating unit).
  • So the new generation asset would be allocated a share of the benefit-based charges for any investments that it would benefit from (and that are subject to the benefit-based charge)
  • The shares of all other parties paying the benefit-based charge in respect of those investments would be reduced accordingly (to prevent over-recovery)
  • The way in which the share of the new generation asset would be calculated has yet to be determined (that would be a matter for Transpower to design in the TPM)
  • The Authority’s current view is that the new generating unit should be charged (going forward) in a similar way to a hypothetical existing generating unit that was otherwise identical, but was connected to the grid from the outset (i.e. from the date of publication of the 2019 issues paper). If that is the case, then you may be able to gain some insight into likely cost implications by starting with charges / allocations that have been calculated for similar generation plant located in a similar area of the grid (to the extent that there are any comparable generators)
  • We think it likely that the charge would not be based directly on the generator’s capacity or injection, but would instead have to be based on a proxy measure (determined by Transpower as part of designing the TPM).

Exit of a grid-connected thermal generation asset:
There are a number of possible scenarios:

1. Reassignment (see clauses 33 – 38 of the guidelines):

  • If the specified criteria are met (e.g. a 20% drop in value of a transmission investment), the relevant transmission charges can be reassigned.
  • If the exit of the generation asset triggered reassignment of the benefit-based charge for an investment, the charges of the owner of the plant would be reduced commensurate with the reduction in benefit from the relevant transmission assets and residual charges for all parties who pay the residual charge would rise to ensure Transpower can recover its costs in respect of the relevant investment.

2. Substantial and sustained change in grid use (clause 26):

  • The proposed Guidelines would require Transpower to include in the TPM a method for determining whether there has been a substantial and sustained change in grid use and a method for adjusting allocations in the event that there has been.
  • We would expect Transpower may establish some sort of materiality threshold that must be met before a substantial change of this nature was invoked. We don’t at this stage have a view on exactly what that threshold would be, however the Authority’s view is that a substantial and sustained change in grid use would be a rare event. There is also likely to be some judgement involved in determining whether or not the exit of the thermal generation asset you have in mind would be considered a substantial change in grid use or not. The Authority is not in a position to provide a view at this stage.

3. Assuming the exit did not trigger either Reassignment or a Substantial and sustained change in grid use:

  • If the owner of the generation asset was ceasing to be a transmission customer, then our expectation is that it would stop paying transmission charges and all other parties’ charges would rise proportionally so that Transpower was able to recover its costs in respect of the investments in question. There are a number of exceptions to this, which would apply in particular circumstances including:
  • if the party was selling part of its business: (clause 42b): Transpower may allocate charges between the old and new owners
  • if the party was shifting its point of connection: (clause 42c): the TPM must avoid creating inefficient incentives for this to occur
  • if the situation would be an inefficient bypass of the grid (perhaps involving connecting the generator to a distribution network): (clauses 46 - 48): a prudent discount may be payable.
  • If the owner of the generation asset was continuing to be a transmission customer, then closing down one of its generation assets wouldn’t generally lead to a change in charges. The owner would continue to be liable for the same level of charges for which it was previously liable. The reason for this is to avoid distorting the owner’s incentives: the intention is that the owner should not have an incentive to shut down a generation asset arising due to the avoidance of the benefit-based charge or the residual charge. These are intended to be fixed charges that do not vary based on a party’s use of the grid.

Hopefully the above points provide some assistance. Thanks for the question, it’s been useful for us to work through these examples. 

If Contact has views on potential improvements to the proposed guidelines on entry and exit – or any other aspect of the TPM proposal – please set these out in your submission.

Question - Mainpower New Zealand Limited

I have a question regarding Customer Investment Contract (CIC) charges in relation to the current Transmission Pricing Methodology (TPM) proposal consultation.  There is no direct reference in the consultation about CIC related New Investment Charges.  I’m taking that since the CIC sits outside the TPM that it will go on as is the case currently, especially as paragraph D.33 points out that it is unregulated commercial contract. And since it not set out in Electricity Authority’s statutory power to regulate unregulated commercial contracts, that it sits outside and will not be affected by the proposed changes to the TPM.
 
There are very little references to CICs in the previous TPM consultations either.  Are you able to confirm that my take is correct, and also the best source (such as the Code, or Electricity Industry Act) indicating that CIC is outside the TPM’s scope and/or it stays the same after the TPM changes?

Answer

Your understanding is correct: investment contracts sit outside the TPM and will not be affected by the proposed changes to the TPM guidelines.
This is confirmed in clause 1 of Schedule 12.4 of the Code: “The transmission pricing methodology is used to recover the full economic costs of Transpower’s services, with the exception of investment contracts entered into under clauses 12.70 and 12.71 of this Code, existing new investment contracts and other contracts of the kind referred to in clause 12.95 of this Code.”

Questions and answers - Pioneer Energy

Our understanding is that the EA‘s calculation of the allocation of the Benefit-based charge for the seven historic transmission investments for grid generators, network companies and direct connects is based on net generation or load (at a GIP or GXP respectively). For network companies, this means Gross AMD minus the anytime maximum output of the distributed generation connected to that network.

The Authority‘s calculation of the allocation of the benefit-based charge for the seven historical transmission investments is based on load measured net of distributed generation (a net load approach). The allocation is determined using the vectorised Scheduling, Pricing and Dispatch (vSPD) model. To clarify: the allocation is not based on AMD. Rather, the model calculates half-hourly benefits for all trading periods from 1/7/2014 to 30/06/2018.

a. Is it the EA’s intention that the allocation of Benefit-based charges for new transmission investments will be on the same basis?

The proposed approach for applying the benefit-based charge to new investments is flexible: we consider a net load approach is likely to be best in most circumstances, as it better reflects the benefits customers receive from the grid, but there may be situations for which a gross load approach may be better. See paragraphs B.114 – B.119 in the 2019 Issues paper.

b. What is the proposed treatment at a node if from time to time it is importing electricity from the transmission grid (a GXP) and from time to time it is injecting electricity on to the transmission grid (a GIP)?

This is set out at paragraph B.120 of the 2019 Issues paper. The proposal is that Transpower would need to estimate the share of a transmission customer’s charges associated with benefiting as an importer or as an exporter. Generation benefits would be calculated for a net exporting node while load benefits would be calculated for a net importing node. If a node switches between being a net importer to a net exporter from one trading period to the next, it may have load benefits in the first trading period and generation benefits in the next trading period.

Question - Pioneer Energy

Could you please confirm if the generation output of Aniwhenua will be treated as grid connected or embedded for the Benefit-based charge and the Residual charge?

Answer

You have indicated to us that Aniwhenua is physically connected to the Horizon distribution network. On that basis, according to the proposed netting policy set out in the 2019 issues paper, Aniwhenua would be treated as embedded and would net off against Horizon’s load for the purposes of allocating the costs of the seven historical investments subject to the benefit-based charge. However, please provide the information you have confirming Aniwhenua’s connection to Horizon’s distribution network in your submission, so that we may consider this matter alongside other similar matters when we consider submissions. We will ask Horizon to provide similar information.


Question - Network Waitaki

I would appreciate if you could confirm whether our understanding of the presentation was correct that the relatively high contribution of the South Island loads to the cost of the HVDC investment is based on the counter-factual situation on the South Island for a scenario without the HVDC system in place. The proxy prices (virtual price offer) on the South Island during drought conditions was allowed to rise much higher than for most other counter-factual simulations due to the judgement that, had no HVDC system been built, no other back up generation on the South Island would be likely since the hydro generators are already much bigger than required. Instead of having non-factual generation cost at 20% above the normal market prices, these cost were instead allowed to rise to multiples of the normal energy price. Is this a correct summary of the reasoning behind the choices you made?

Answer

Yes, your summary of the approach we took in the modelling is right.

Please note that the assumption on price – the virtual price offer – is only one of the assumptions that matter; the other important one is the time period of the analysis, as benefits are highly correlated to the direction of the flow across the HVDC. The analysis takes each of four recent years (including one year with net southerly electricity flows), with each year having a 25% weighting toward total benefits.

In the modelling it is assumed that, in the counterfactual (i.e. the case without the investment being assessed), there is unlimited energy available at Otahuhu at 1.2 times the factual price (or as an alternative a fixed price of $500/MWh). But VPO will not be available at a node in a counterfactual case if a constraint causes VPO volumes to be unavailable at that node. In particular, if the HVDC is taken out, VPO will not be available in the South Island as it cannot access the assumed virtual generator.

This can cause higher counterfactual prices than 1.2 times the factual price or the alternative $500/MWh price. The counterfactual price is constrained by a rule in the modelling whereby if prices reach $10,000/MWh or above, those trading periods are removed. Some high prices at around $1,000/MWh are reached during southward flows across the HVDC in the fourth 12 month assessment period (2017-18) - (slide 63 of the technical workshop slides), 2017-18 has just a 25% weighting in estimating the total benefits.

We recognise that, if the Authority had positioned the virtual generator in the South Island or had a virtual generator with unlimited capacity in both the North and South Islands, this would likely reduce the allocation of the benefit-based charge on South Island load. However, we have not modelled that.

Our modelling assumptions, including the VPO assumption, weighed up several considerations, including the surplus in wet years and shortage in dry years in the South Island. These considerations included: 1) that demand response is not modelled 2) there are no changes to generator offers in the counterfactual 3) vSPD calculates economic benefits and arguably underestimates reliability benefits, and 4) the investments in the benefit-based charge are historical investments, and compared to prospective investments, they are already utilised and even for the reliability investments in the benefit-based charge – their benefits exceed their cost.

We look forward to any suggestions and supporting materials in submissions on the assumptions we applied or that you or other submitters consider we should apply to estimate benefit-based charge investments.

Question - Network Waitaki

Can you also provide information on how you adjusted the water levels in the reservoirs on the South Island due to lower generation levels for the counter-factual scenario and how that lead to a generation shortfall during the winter of 2017 where the very high proxy prices up to $1,000 per MWH was calculated (slide 63).

Answer

The model does not measure or recalculate lake levels, and generator offers are not revised in the counterfactual case to reflect changing grid configuration, for example, in the absence of the HVDC. Where constraints are reached, higher prices are dispatched from generator offer stacks or VPO is applied. Infeasibly high prices are removed. While some high prices at around $1,000/MWh are reached during southward flows across the HVDC in the fourth 12 month assessment period (2017-18), 2017-18 has a limited (25%) weighting on total benefits.

Question - New Zealand Institute of Economic Research Inc. (for New Zealand Steel)

At our meeting last Wednesday, I think you showed me some files for the benefit charges that had NZ Steel loads separated out for Alinta and NZ Steel. Are you able to send those files to X at NZ Steel?

Answer

Please see attached, NZ Steel benefits before and after draft cogeneration netting, and a summary sheet.

Question - New Zealand Steel Limited

X has been in touch with you re some of the numbers you attached for the benefits charge.
Now that we know how to access the information I have had someone look at the gross numbers used for the residual. His conclusion is that the GLN0332 numbers are not correct, by a noticeable, but not out-of-the-ball park difference. Seems this relates to the complexities at the Glenbrook substation and switching. How do we get to the bottom of this? There are probably few people who understand the detail and I am not one of them.

Answer

We have relied on the reconciliation data (file 010) to inform our allocations of load to Transpower customers, but recognise there could be instances this data may not fully or properly reflect the true situation (eg when there are multiple customers behind a point of connection), and that we may need to make adjustments.
From your question it appears you have already done this, but the best way to check the load we used for calculations is to view the ‘Reconciliation maps 15042019’ sheet in the EMI file titled “2019 Proposal impacts modelling”. Filter on POC (GLN0332) in column B. Gross load is provided in columns H to K.
In general, if parties consider the reconciliation data may not be correct, then we would encourage parties to provide the relevant information and supporting evidence in submissions or earlier. This can then inform our consideration of whether an adjustment is justified. For example, if NZ Steel considers that it is allocated a charge that related to some of Counties’ load, it would be ideal if Counties Power and NZ Steel agreed on the appropriate allocation and thus the proposed adjustment, and to let us know.

(Ultimately the reconciliation manager needs to be informed if load is not allocated to the correct networks. There is a formal process for this, which we can talk to later if it becomes necessary.)

Please let us know if you need further information on the relevant datasheets or the process. We would be happy to assist.

Question - Trustpower

How would the allocation of charges work under a reliability-based investment where modelled net private benefits in aggregate are less than the covered cost of the asset? Is there a worked example of this one that you could direct us to?

Answer

In response to your question about the allocation of charges for a reliability-based investment where the modelled benefits are less than the covered cost:

• Historical investments with estimated total benefits less than total costs are not covered by the benefit-based charge; instead, it is proposed these are recovered through the residual charge. We consider that the vSPD approach (which is based on price and quantity differences) produces results that are a reasonable proxy for the distribution of total benefits from an investment (including reliability benefits).


• For future investments, if total benefits are less than total costs, that would not affect the initial allocation of investment costs under the proposed guidelines (costs would be allocated in proportion to net private benefit). That said, one of the effects of the proposal is that additional scrutiny by stakeholders would reduce the likelihood that such an investment would go ahead (and for example instead more efficient non-grid alternatives could be identified).


• Under the proposed guidelines, reliability-based investments are not treated differently from other investments. Reliability benefits are, however, amongst the categories of benefit that Transpower may take into account in allocating the costs of investments.

Question - Top Energy Limited

At the workshop last week I asked if the EA had done the projections of what the BB charge would mean for transmission customers in Northland at the end of modelled period.  The outcome of the discussion was that the answer would be sent to me. Do you have an eta on this?

A split by Top Energy and Northpower would be appreciated.

What we wanted to know was what the BB charge for Top Energy and Northpower at the end of modelling period e.g. equivalent of the $1.2m for TE and $2m for Northpower in year 1. In real and nominal terms would be great

Answer

Thanks for the question you posed on 10 September: you wanted to know was what the benefit based charge for Top Energy and Northpower would be at the end of modelling period.

As we discussed on the phone last Wednesday, we have not explicitly modelled the indicative charges for transmission customers beside the starting values at implementation. The reason for that is that future charges are dependent on future grid investments relevant to Top Energy and Northpower, and the benefit-based share of charges that Top Energy and Northpower would attract. These are unknown.

I also mentioned that the modelling undertaken for the cost benefit analysis does make projections of transmission revenues by 14 ‘backbone’ nodes (see figure 3 in chapter 4 of the 2019 Issues paper). These results are best interpreted with reference to the methods and assumptions as set out in the technical CBA document that came with the 2019 Issues paper.

One of the backbone nodes is Marsden. We discussed the modelled quantities  would provide you one indication of the order of magnitude of effects at that backbone node, at least in how that has been modelled in the cost benefit analysis. The relevant information is available in the results files on www.emi.ea.govt.nz released at the time of the Issues paper.

Attached is a spreadsheet with the modelled transmission revenue under the status quo and proposal and benefit-based charges at the Marsden node. By way of context, I have also extracted the data on load and average prices (wholesale and interconnection), and total $, and charted these too. Table 6 in chapter 4 of the issues paper reports the long term consumer benefits.  The spreadsheet also has some notes on the specific sources used, to allow you to extract similar information for other nodes if that were helpful to you.

Question - Federated Farmers of New Zealand

I was wondering if there was a breakdown of consequences / adjustments for consumers by region for the proposed shift from IHC to DHC approach to benefit-based charging. 3.22 mentions that Vector consumers in the Waikato and Upper North Island would see higher immediate benefit-based charges, with that lessening over time, but no mention is made of what the proposal means for consumers in other regions / under other lines companies.

Answer

The proposed shift from IHC to DHC would apply to post-2019 investments. As these investments or their benefit-based allocations are not determined, we were not able to provide a meaningful quantification of the full consequences over an extended period, nor provide a regional breakdown. The example was therefore provided as an illustration of the type of effects on benefit-based charges.

Recovery under DHC would also avoid having to adjust the residual charge (which is paid for by all customers), by an equal total amount but of opposite sign. So under the revised proposal load customers would pay lower residual charges in the early years of the investment (but this effect would reverse in the later years of the investment, that is, it is a timing effect).  In this way the proposal also affects customers in other regions that are not beneficiaries of the WUNI voltage management investment.

Question - P2P Energy Services

I have some urgent follow up questions that I would appreciate clarification on:

  1. As I understand the consultation paper and your answers to my original Q1&2 below: if a directly connected load customer was to completely shut down and disconnect, they would continue to pay the residual charge for effectively nine years (7 + the 4-year ramp down).  Is that correct?

  2. As I understand footnote 5 on Page 9 of the consultation paper: if a directly connected load customer was to completely shut down and disconnect, the benefit based charge would cease in the next pricing year.  Is that correct?

  3. As I understand the consultation paper: if a directly connected load customer was to substantially reduce load by (say) shutting down a process train or one of the site plants (even if this was most of the site load), both charges on the customer would continue with the standard adjustment provisions described in the paper.  Is that correct?

  4. Under the amended proposal the EA are proposing a 7 year lag on the residual charge adjustment mechanism, apparently because you are concerned about inefficient avoidance behaviour.  Could you please give an example of the avoidance behaviour that you envisage could be possible, and provide a comparison of the potential level of avoidance for both the proposal as described compared to the proposal without the 7 year lag?   

Answer

Here are our answers to your questions.

  1. No, that is not correct. If a directly connected load customer were to completely disconnect from the grid (for whatever reason), it would cease to be a transmission customer and so its liability for transmission charges (including the residual charge) would cease.  

  2. The Authority’s proposed TPM guidelines do not specify detailed requirements such as precisely when the benefit based charge would cease (eg whether it would cease during or at the end of a pricing year). This would be a matter for Transpower to design as part of the development and implementation of the actual transmission pricing methodology.

  3. The revision to the proposal discussed at section 4 of the supplementary consultation paper (Adjusting benefit-based charges when a plant closes) applies when a plant closes, but generally does not apply when a plant remains open with reduced load. This is because it is intended to create a limited exception to the general rule that liability for benefit-based charges remains fixed. However, the revision does apply where the customer has closed down plant representing the bulk of the site’s energy needs and there is still some remaining energy use, but that use is negligible compared to the prior energy use: see footnote 4 on page 8. So in the scenario you describe, the directly connected load customer’s benefit-based charge would not reduce unless the site’s remaining energy use was negligible compared to the prior energy use.

    In the scenario you describe, the directly connected load customer’s residual charge would eventually reduce through the provisions for updates to the residual charge: either through a Transpower operational review (as proposed in the 2019 Issues paper) or instead through a regular annual update (as proposed in section 5 of the supplementary consultation paper).

    It's also possible that other provisions in the proposal, such as the reassignment provisions and substantial and sustained change in grid use provisions, might apply.

  4. If there was no meaningful lag, it can provide customers with incentives to take actions for the main purpose of avoiding their residual charges. Such actions could involve making investments or changing processes to reduce electricity use. Such actions are not costless nor do they reduce the cost of transmission investments that are in place (but just shifts the costs to other parties).   A lag, such as one of seven years, mutes the avoidance incentive while still providing for an adjustment over time, as illustrated by the example in the supplementary consultation paper and the spreadsheet example.  

(Load customers still have appropriate incentives to take actions to increase their energy efficiency and reduce their bills related to electricity consumption.)

Follow-up question

Thank you for answering the additional questions.

In summary, based on your answers, I would appreciate it if you could confirm my understanding of the effect of the revised proposal on a directly connected load customer with a year to year relatively steady load profile would be as follows:

  • The customer’s benefit-based percentage (%) share of the costs for each post-2019 transmission asset would be predetermined and fixed; and would not change unless the customer shut down one of the “plants” on a site, in which case it would be reset to a commensurate level at a time 10 years after the associated transmission asset came into service.
  • The customer’s residual percentage (%) share would be predetermined based on their AMD averaged over the 4-year 2014-2018 period, and it would be adjusted annually from 2025 with a 7-year lag based on changes in energy (kWh/y) used reference to the same 2014-2018 period.  This adjustment mechanism would continue to apply even if the customer’s energy use was substantially reduced.  In this step reduction scenario, the customer’s residual % share would not reduce for 7 years after the step reduction in load and it would then take a further 4 years to reduce to a commensurate level.
  • Both charges would cease within a relatively short period if the customer disconnected from the grid.


Follow-up answer

That is largely correct (see minor edits to your statement below). We note the reassignment provision (clause 41 of the guidelines) to accommodate a designated transmission customer’s substantial change in demand due to factors beyond their control or influence.

  • The customer’s benefit-based percentage (%) share of the costs for each post-2019 transmission asset would be predetermined and fixed; and would not change unless the customer permanently ceased to operate the plant that previously consumed the bulk of its energy needs at one of its sites (such that any residual energy use at the site is negligible compared to the prior energy use) and is not intending to replace it shut down one of the “plants” on a site, in which case it would be reset to a commensurate level at a time 10 years after the associated transmission asset came into service.
  • The customer’s residual percentage (%) share would be predetermined based on their gross AMD averaged over the 4-year 2014-2018 period, and it would be adjusted annually from April 2025 with a 7-year lag based on changes in gross energy (kWh/y) used reference to the same 2014-2018 period.  This adjustment mechanism would continue to apply even if the customer’s energy use was substantially reduced.  In this step reduction scenario, the customer’s residual % share would not reduce for 7 years after the step reduction in load and it would then take a further three 4years to reduce to a commensurate level.
  • Both charges would cease within a relatively short period if the customer disconnected from the grid.

Question - Major Energy Users Group

Is it fair to say that in a WCM the situation leading to Q6 (reference Q6 from P2P) would not arise? i.e. in WCM no business would over the long-term be able to sustain prices to recover costs that could not be reasonably allocated to the provision of a service of product? 

Answer

Thanks for the question.

The proposed methodology would better match transmission charges to beneficiaries (that is, match costs to the production of a product or service) and allocate common overheads across all transmission customers.

The remaining part of the residual charge is in essence a transitional component to recover costs for historical investments that in the 2019 Issues paper are not proposed to be allocated via the benefit-based charge.

In this way, the proposal would move charging for transmission services far closer to arrangements that might arise in a workably competitive market (e.g. long-term contracts or other risk-sharing arrangements). Under the current methodology most costs are allocated to regions on a postage stamp basis.

Questions - Network Waitaki Limited

Question

In order for us to meaningfully comment to your proposal, I have to get clarity on a few issues regarding your modelling of batteries to reduce demand. I would be happy if you could provide a short answer in the text next to each question.
 
You mentioned in your presentation on batteries that only one of the battery transactions (either charging the battery, or discharging the battery) should be used to prevent double accounting for the kWh volume transacted. Please correct me if I am incorrect in understanding what was said.

Answer

The presentation mentioned that different objectives/purposes require different methods of accounting for energy flows related to batteries.

For example, when the focus is on energy balance across a system, it is appropriate to count the amount of energy used to charge batteries. We have used this approach in our CBA in circumstances where the focus is on the energy balance. The question is how the energy use is accounted for in the calculation of demand/generation by time of use; that is, whether we include battery charging as e.g. off-peak demand or peak demand. It can't be both, if we want generation and load across times of use to add up to total energy. We count the demand in the period that the battery is charged. On the one hand, it is demand for use at peak, so from a consumer's perspective it would be peak demand. But from a generation perspective it is off-peak demand.

However, another method may be appropriate in other circumstances. For example, where the focus is on volumes traded in wholesale energy markets, it would be appropriate to count the energy used to charge the batteries and the energy discharged by the batteries.

Question
 
Please confirm whether I understood correctly that you recommend recording only charging of the battery (or alternatively only the discharging of the battery) when modelling a battery strategy to reduce demand during peak periods.

Answer

Both charge and discharge need to be considered when modelling a battery strategy. This is the approach we have adopted when modelling a battery strategy in our CBA. By contrast, our decision to measure battery 'use' using only charging volumes related to how battery use was counted in aggregate, as opposed to how strategies were modelled for charging / discharging to reduce exposure to RCPD charges. Note that the analysis of battery investment strategies is done separately to the grid use model and used to construct parameters that are then plugged into the (more aggregated) grid use model.

Question
 
A second issue with the battery model is the cycle period of the battery in the model. It showed a battery going through multiple charge/discharge cycles during a single peak period, with a 2 hour cycle period shown for the morning and a 1 hour cycle period in the afternoon. Again please correct me if my understanding of your presentation is incorrect.

Answer

The model assumes a hybrid of two strategies: (1) for 6 months of the year the battery is used to reduce exposure to regional coincident peaks. During those 6 months the battery has an average of 5.4 charge/discharge cycles per day at an average discharge of 0.5 of maximum. (2) for the other 6 months of the year the battery is used to arbitrage energy prices using an average of 2 cycles per day and an average discharge of 0.8 of maximum. 

Question 

From the table you indicate to use full power (1 MW for a 1 MW battery for both charging and discharging of the battery).  From the table: Discharge/Charge (h), constant power … 1
That would mean when charging, the 1 MW battery would be like a load 1 MW on the system, and when discharging it would be like a 1 MW generator on the system.  Is my understanding of the meaning of the table correct?

Answer

Yes
 

Question

When you specify a battery capacity as 1 MW, do you mean it can produce power at 1 MW sustained for one hour only?  Do you mean the energy stored in the battery would be 1 MWh?
Are you thus considering all batteries to have a power rating high enough to fully charge or discharge the battery in one hour? Have you considered battery usage cycles where the discharge period is longer than one hour?
Is this a correct understanding of your assumptions about batteries and your modelling proposal?

Answer

The model assumes that the battery can produce 1 MW for 1.29 hours - at most. In practice, the state of charge of the batteries is modelled as staying within (a) 0.8 and 0.2 of maximum, when cycling more frequently to avoid regional coincident demand peaks (b) between 1 and 0.2 of maximum when arbitraging energy prices. We have considered long(er) discharge periods but our assessment was that these are likely to be less profitable as (a) arbitrage strategies will be most profitable by maximising the amount of discharge when prices are high(est) and (b) the profitability of avoiding regional coincident peaks hinges on being able to charge and discharge in short cycles to maximise the number of coincident peak periods in which the battery is discharging. 

Question - Solar City

The question related to the basis for the $733/kW assumption for grid scale batteries

Answer

At the technical workshop last week you asked the basis for the $733/kW assumption for grid scale batteries. We referred you to page 55 onward of the CBA technical paper.

The $733 per kW capital is based on media reports on the cost of a 100MW Tesla battery. See footnote 1 to table 18 in the technical report.

The assumed $NZ 73.3m for 100 MW translates to $733/kW.  We recognise a range of costs are being reported in the media. In terms of the modelling, the assumed battery use strategy and assumptions about the annual decline in capital cost are also relevant, and these were subject to a sensitivity analysis (eg see page 72 of the CBA technical document).

We welcome your submission on this and any other topic.

We trust this answers your questions sufficiently. Please let us know if you have further questions.

Question - P2P Energy Services

Regarding the calculation sheet for the cap:

It appears that the EA’s cap calculations for load are based on a comparison of the 2019/20 interconnection costs (before LCE rebates) and the estimated 2021/22 BBC + RC (after assumed LCE rebate). Is this what is intended and reflected in the draft guidelines?

Answer

The draft TPM guidelines do not specify whether or how to adjust transmission charges to take account of the LCE rebate, in the calculation of the price cap (they are silent on this matter). Clause 50 of the guidelines refers to “transmission charges subject to the price cap” and “transmission charges minus connection charges in the 2019/20 pricing year”.

As you correctly observe in your e-mail, the Authority’s indicative calculations on the effects of the proposed price cap are based on a comparison of 2019/20 transmission charges other than connection charges (before LCE rebate) and estimated 2021/22 transmission charges subject to the price cap (after assumed LCE rebate).

An alternative approach would be to carry out indicative calculations on the price cap on a post-LCE-rebate basis for both 2019/20 charges and future charges. If the calculations were carried out on this basis, the amount redistributed by the price cap would be $16.1m (rather than $15.4m), and estimated customer charges under the proposal would be slightly different to those published in the 2019 issues paper. See the attached table, in which the column headed:

  • “Capped proposal - as published” sets out the indicative charges from the 2019 issues paper
  • “Capped proposal - post-LCE rebate” sets out indicative charges with the price cap calculated on a post-LCE-rebate basis for both 2019/20 charges and future charges
  • “Difference” shows the change, compared to the published indicative charges, if the cap were calculated on a post-LCE-rebate basis for both 2019/20 charges and future charges.

Question - Refining NZ

As per the estimates provided, the indicative increase in Refining NZ’s transmission charges would be of around 40% compared to status quo.

I would appreciate if you could provide some clarification on whether the price cap (as per the proposed TPM guidelines) would apply to Refining NZ only if we were direct-connects?

If that was the case, do you consider that this would be incentivising large consumers to become direct-connects in odds to paragraph B.238 requiring the “TPM to avoid creating inefficient incentives for a large consumer or generator to shift its point of connection from or to Transpower and/or a designated transmission customer”?

Answer

Thanks for your question on the price cap.

Given that Refining NZ is not a direct connect and does not pay transmission charges directly, the proposed price cap would not apply to Refining NZ. The proposed price cap is applied at the distributor level and would be calculated based on the total electricity bill for all consumers the distributor supplies. (See clause 50 in the draft guidelines for the details of the proposed cap and the basis for its calculation.) This means that for consumers, electricity bills would not need to increase by more than 3.5% as a result of the changes. The precise impact will depend on the distributors’ own pricing.

The indicative increase of “around 40%” you mention relates to the transmission charges, which is only one of the components that make up a total electricity bill (which would also include lines charges, wholesale energy prices and so forth). The cap for distributors is 3.5% of their estimated total bill.

Where in the spreadsheet we supplied to you it states, at row 24, “no cap is applied”, a better terminology would have been “before any cap is applied”. In the case of Northpower, which is the relevant distributor, the indicative transmission charges do not increase by an amount that exceeds the capped amount. Instead, under the proposed approach, Northpower would be contributing to funding the cap, which increases its proposed transmission charges (see row 26). 

However, as you suggest in your e-mail, if (hypothetically) Refining NZ had been a direct connect and assuming that the estimate of charges provided in our earlier e-mail applied, it appears likely that in that scenario the price cap would have applied to reduce Refining NZ’s charges. (Note that for grid-connected consumers, after five years the cap lifts by 2% every year.)

We are aware of the risk that boundary issues like this could create incentives for large customers to change their point of connection (for example, a change from network-connected to grid-connected in order to qualify for the price cap and so potentially reduce transmission charges). For this reason, we have included clause 42(c) in the guidelines, which requires the TPM to avoid creating inefficient incentives for a large consumer or generator to shift its point of connection (this clause is discussed at paragraph B.238 of the issues paper – as you note in your e-mail). To be clear, we don’t agree that the risk of creating incentives to change a point of connection is at odds with clause 42(c); rather, we have included clause 42(c) in order to mitigate that risk. 

For this reason, our view is that the proposed price cap will not incentivise large network-connected consumers to become grid-connected. We expect that the TPM will be designed in such a way that such an incentive is not created. This could be achieved in various ways (for example, the price cap could be restricted to those customers that were grid-connected at the date of release of the 2019 issues paper). The proposed guidelines do not prescribe how Transpower is to achieve this objective, as it was considered that a prescriptive approach on this issue would not be effective.

 

 

 

Question - P2P Energy services

I would appreciate it if you could answer the following questions about the proposed amendments to the TPM proposal:

  1. Calculating the residual charge adjustment.  While the proposed methodology is described in outline, it is not clear in the detail.  I am presuming it will be the initial AMD % allocation to the grid customer that will be adjusted each year (after the 7 year lag)?  I am presuming that the annual residual charge with be the adjusted AMD % allocation to the grid user times the total residue to be recovered (that will also be reducing slowly)?  I am presuming the average MWh/y over the 2014-2018 period will be the base for adjusting the AMD%?  It would be most helpful if you could provide a spreadsheet example to clarify the overall adjustment calculation
  2. Adjusting residual charge when a plant closes. You have described what happens to a customers benefit based charge when a plant closes, but not what happens to the residual charge. Could you clarify that please?   

Answer

On calculating the residual charge adjustment:

The proposal is that the initial AMD allocator – set based on 2014-2018 – is adjusted each year based on the annual change in the 4-year average annual gross electricity usage, with a 7-year lag.  Thus the first change would occur from 2025-26.  The adjusted % allocation for each customer for that year is applied to the total residual charge for that year. We expect the total residual charge will reduce over time. Attached (see below for copy of attachment) is a step-by-step spreadsheet example that corresponds to the box “Stylised example for Boomtown” on p.15 of the supplementary consultation paper.

On adjusting the residual charge when a plant closes:

Liability for the residual charge would not adjust in the way proposed for the benefit-based charge. That is because the proposal provides separately for updates to the residual charge: through a Transpower operational review (as proposed in the 2019 Issues paper) or instead through a regular annual update (as proposed in the supplementary consultation paper). The customer’s liability for the residual charge would continue until it is updated via one of those mechanisms. 

Attachment (click to expand)