Grid Pricing Q&As

Here, you'll find answers to some commonly asked questions and helpful insights on key topics relating to Grid Pricing. If you don't see your question here, please feel free to reach out to the Grid Pricing team at [email protected].

General TPM

• Asset Classification

• New Customers

• Embedded Connections

Connection Charges

Benefit-Based Charges (BBCs)

• Assumption Book

• Adjustments

Residual Charges

Prudent Discounts

General TPM

Where can I find a high-level overview of the Transmission Pricing Methodology (TPM)?

We have plenty of resources to help our customers understand the TPM.  

• A short guide and in-depth information sheets on various aspects 
• Subscribe to our newsletter alerting you when new information is published and other TPM-related updates 

Over time, we intend to develop and share more information. 

Where can I find information to estimate TPM charges? 

See our Indicative Pricing page for guidance for new customers. If you have a connection request with Transpower and require further assistance, please get in touch with your Relationship Manager. 

Asset Classification

How do I work out whether an asset is classified as connection or interconnection? 

The TPM adopts a ‘deep connection’ approach to classifying grid assets as connection assets. Connection assets are grid assets that exist specifically to connect a customer to the grid, even if the customer’s assets are not directly physically connected to those assets. Connection (and interconnection) assets are defined in Part B of the TPM based on the physical configuration of the grid.  

The key distinguishing feature of connection assets is that they are configured such that there are no ‘loop flow’ effects on the assets, making it possible to identify the specific customer(s) without whom the assets would not exist. These customers are referred to as customers connected to the assets, even though they may not be connected directly. The costs of a connection asset are recovered from the customers connected to it through connection charges. If there are multiple connected customers, the costs and charges are shared between them and the connection asset is referred to as a shared connection asset. 

A grid asset that is not a connection asset is an interconnection asset. 

If you need assistance, please contact the grid pricing team. 

The new TPM says connection asset replacement costs must be updated. How does this align with Transpower’s Depreciated Historical Cost (DHC) regulation where the Weighted Average Cost of Capital (WACC) allowance is based on original asset costs? Will this update in lead to a higher level of connection charges and a lower residual charge? 

The role of the connection asset replacement costs in the calculation of connection charges is more fully explained in our connection charges information sheet, which includes a worked example (see sections 4 and 5). We updated the connection asset replacement costs before for the first year of the new TPM because they were well overdue for updating, having not been reviewed for many years. 

The changes we made to our connection asset replacement costs do not impact on either:

(i) Transpower’s total revenue allowance set by the Commerce Commission (which, includes a WACC return on the DHC of our regulatory asset base), or  

(ii) the total cost of connection assets allocated under the TPM through connection charges (i.e. the total amount of connection charges). 

The connection asset replacement costs are only relevant to how capital and some maintenance costs of connection assets are allocated amongst our customers through their connection charges. The impact of the changes on a particular customer depends on the mix of connection assets to which it is connected.  

We are required to review the replacement costs at intervals at least once every 5 years. We will consult with customers before the replacement costs are next updated, unless the update is technical and non-controversial or there is widespread support among customers.  

New Customers

I’m a new customer wanting to connect to the transmission grid. What charges will apply to me?

We have published an information sheet which sets out the charges that apply to new customers. You can also see our indicative pricing page for information to help you estimate these. 

How does Transpower determine the intra-regional allocator (IRA) value at a connection point with both injection and offtake allocations for Appendix A benefit-based investments (BBIs)? Is this value used in selecting the comparator customer?

The process is covered in clause 83 of the TPM. New customer allocations for the Appendix A BBIs are based on Transpower’s estimate of their estimated average annual offtake or injection, multiplied by the average benefit factors for comparator Appendix A customers. If there are same-type (generation or load) Appendix A customer(s) at the new customer’s connection location, those Appendix A customer(s) will be the comparator customer(s).  If not, the electrically closest Appendix A comparator customer connection location is determined based on circuit length. The IRA value is not used in determining the electrically closest Appendix A comparator customer connection location. 

Why are generators choosing to build new generation further away from load when it must be more economic from a whole-of-system perspective for generation plant to be built closer to load. 

Over time, generation located further away from load will likely receive higher benefit-based charges (BBCs) than generation located close to load.  

However, yhere are a number of other locational factors that generation investors consider, including the capacity factors achievable at different locations, the ease of consenting, land prices, access to site, and the existing capacity of the grid to connect new generation. It is possible these factors will outweigh the higher BBCs.  

When do benefit-based charges apply following commissioning of large generation plant?

Clause 85 of the TPM applies to the connection of large plant (grid-connected or with a capacity ≥ 10 MW). This will be treated as the connection to the grid of a new notional customer under clause 83.  

Under clause 83(10), Transpower must start the benefit-based charges for the new notional customer as soon as reasonably practicable. Normally this will be the month after the connection, and the first invoice will include an additional back-dated charge to cover the period from connection to the start of that month. 

Embedded Connections

Do embedded customers pay transmission charges under the TPM, and if so, how are these calculated?

Under the TPM, Transpower allocates costs to its transmission customers – grid-connected generators, distributors and directly-connected load customers. Distributors continue to determine how transmission charges are passed through to their customers, including embedded generators connected within distribution networks.  
The Electricity Authority has published  Distribution Pricing: Practice Note, which contains high level guidance for how distributors should pass on transmission charges to their customers. 

Although embedded parties do not pay transmission charges directly, the connection of large (≥ 10 MW) embedded plant can increase the benefit-based charges paid by the host customer, and that increase may be passed through to the embedded party.

How will Transpower know when large plant connects to a distribution network in order for the benefit-based charge (BBC) adjustment provisions to be triggered? Is there anything in the TPM that compels distributors to inform Transpower?

There is nothing yet in the TPM or elsewhere in the Electricity Industry Participation Code requiring distributors (or plant owners) to tell Transpower when large embedded plant is connected to their distribution networks. However, there are a number of ways Transpower may become aware this has happened or will happen: 

•  The distributor may volunteer information about the connection to Transpower, which Transpower encourages distributors to do.  
• The distributor may need to tell Transpower about the connection because the distributor needs part of the grid upgraded to facilitate it.  
• The distributor may notify Transpower of the connection under clause 2.4 of the connection code in schedule 8 of the distributor’s transmission agreement.  
• Another customer may tell Transpower about the connection, particularly if the resulting adjustment is likely to reduce that customer’s transmission charges.  
• The information may be publicly available, including via NZX, news articles or regulatory disclosures.  
• Particularly for large generating plant, the system operator may have been notified of the connection, in which case the system operator is able to disclose that information to Transpower under clause 12.102A of the Code. 

Once Transpower knows about a large embedded plant connection it can require the distributor to provide further information about it through clause 30.2 of the distributor’s transmission agreement. 

Can Transpower reallocate residual charges when new embedded load on a local distributor network is connected?

There is no immediate change to residual charge allocations when large (or any) embedded load connects to a distributor’s network. The new load will have an impact on residual charge allocations later when it comes through the lagged residual charge adjustment factor (RCAF) for the distributor. The impact of the new load on the distributor’s allocation factor (AMDR) will ramp up over the period between 5 and 8 years after the new load is connected. This mechanism is in Part E of the TPM, and Transpower has no discretion to depart from it.

If a new embedded generator reduces the load in a distribution network, is there a chance that the transmission charges will reduce for that network? 

If a new embedded generating station connects to a distribution network, that will not reduce the distributor’s benefit-based charges (BBCs) for existing benefit-based investments (BBIs). It may increase the distributor’s BBCs for existing BBIs if the station is large (≥ 10MW) because the new large plant adjustment mechanism in Part F of the TPM will attribute to the distributor any BBCs the station would have incurred if it had connected directly to the grid. The presence of embedded generation in a distribution network will tend to decrease the distributor’s BBCs for future BBIs because the distributor’s grid offtake will be lower. This will be reflected in the starting allocations for those BBIs. 

The distributor’s residual charge will not decrease as a result of a new embedded generating station because the residual charge is allocated on the basis of gross load. The distributor’s residual charge may increase slightly over time due to the station’s auxiliary load. 

Are there any savings created because of embedded generation that could be paid out to an embedded generator as Avoided Cost of Transmission (ACOT)?

Transpower and the TPM have no role in determining or advising on how a distributor should pass transmission charges through in its pricing or other commercial arrangements with load and generation customers on its network. 

Considering each major component of the TPM:  

• Where connection assets are shared between multiple connected customers, the connection charges for them are allocated in proportion to the customers’ anytime maximum demand (AMD) and anytime maximum injection (AMI). Embedded generation can help to reduce a distributor’s share but by how much is not easily predictable, including because the distributor’s allocation is also a function also of the other customers’ AMD/AMI. 
• Residual charges are allocated on the basis of historic gross load parameters. Gross load means all load on a distributor’s network, whether it is supplied from the grid or embedded generation, and regardless of time-of-use or seasonality. Therefore, embedded generation does not reduce the distributor’s residual charge. 
• Existing embedded generation can reduce a distributor’s benefit-based charges (BBCs) for future benefit-based investments (BBIs) by reducing the values of the distributor’s grid offtake intra-regional allocators (IRAs) in the 5 years ahead of the investment being made. But existing embedded generation could also impact total regional benefits, or give rise to higher BBC allocations if the embedded generation causes the distributor’s point of connection to change to a grid injection point. The implications of embedded generation for the distributor’s BBCs for future BBIs are therefore not predictable and may be different for different BBIs.  
• For existing BBIs, any new large (≥ 10 MW) embedded generation is treated as grid connected and will trigger a large plant adjustment event, which could result in an increase in the distributor’s BBCs (it cannot result in a decrease). 

If a distributor’s offtake at a connection location exceeds injection and a new generator over 10 MW connects within the distributor's network, will the distributor’s Appendix A benefit-based investment (BBI) allocations be calculated at the electrically closest connection location or the actual connection location?

If a large embedded generator connects to a distributor, the new Appendix A BBI allocations will be calculated as if the generator connected directly to the grid at the distributor's connection location. Comparator customers will be other grid-connected generators that are Appendix A customers, and their benefit factors will determine the new allocations. If there are generation Appendix A customer(s) at the distributor’s connection location, those Appendix A customer(s) will be the comparator customer(s).  If not, the electrically closest Appendix A comparator customer connection location is determined based on circuit length. The new allocations will be attributed to the distributor, who will likely pass the charges to the embedded generator

Is there a future HVDC charge in the TPM? How would any net injection at a GXP be treated and what would be the cost impact to the relevant distributor? Is there any additional cost that the distributor would need to pass through to the embedded generator(s)?

The HVDC charge ended on 1 April 2023 when the new TPM came into effect (although there is an Appendix A benefit-based investment (BBI) relating to historic HVDC investments, for which there are benefit-based charges (BBCs)).  Future investments in the HVDC link will be captured in new BBIs, and their costs in new BBCs. Some intra-regional allocator (IRA) values are calculated based on net injection and offtake. A customer’s IRA value over an historic period (capacity measurement periods (CMP) B and C under the new TPM) is an input into the calculation of the customer’s non-Appendix A BBI allocations. Distributed generation will tend to decrease a distributor’s IRA value for the regional demand group it is a member of, and therefore its share of positive regional net private benefit for that group (if any). However, if there is significant net injection at a connection location, the distributor may become a member of a regional supply group and take a share of the positive regional net private benefit for that group (if any). Absent an adjustment event under Part F of the new TPM, IRA values are calculated once based on activity during CMP B (standard method) or CMP C (simple method) and are not updated during the life of a BBI. Therefore, in most cases, changes in net injection and offtake at a connection location will not impact on the distributor’s BBCs for existing BBIs. 

Transpower does not advise how distributors (or other customers) should pass on their transmission charges to their customers. That is up to each individual distributor, subject to present (and potentially future) Electricity Authority regulation and guidance. 

Connection Charges

What is a connection charge?

The costs of a connection asset are recovered from the customers connected to it through connection charges. Connection charges are calculated for each pricing year and per customer, connection asset and connection location. See our information sheet for further information. 

Are peak demand and peak injection onto the grid the measures being used under the new TPM to work out the customer allocation at a grid connection?

Yes, the connection charge allocators, anytime maximum demand (AMD) and anytime maximum injection (AMI), are based on peak offtake and injection, using the 12 highest trading periods over the previous capacity year (CMP A). Offtake and injection are kWh values, and they are multiplied by 2 to produce kW values (the 2x multiplier reflecting the fact that a trading period is half an hour). This is the same as under the old TPM. 

Benefit-Based Charges (BBCs)

What is a benefit-based charge? 

The costs of new and some historic interconnection investments (benefit-based investments or BBIs) are allocated to the expected customer beneficiaries of those investments through benefit- based charges (BBCs). 

The cost recovered through the BBCs for a BBI is referred to as the BBI’s “covered cost”. A BBI’s covered cost includes capital components (return on and of investment) and an allocation of Transpower’s total operating costs (including overheads). Covered cost is calculated annually, for each BBI. 

Our Assumptions Book sets out the assumptions and detailed methodologies we apply to allocate and adjust BBCs. 

How does Transpower determine benefit-based charge (BBC) allocations for large plant connected by a customer who is already a member of a regional customer group if the plant is commissioned after the CMP B period  but before Transpower sets the allocations?

In this scenario the large plant needs to be included in the regional customer group but will not contribute to the calculation of the intra-regional allocator (IRA) value because the plant was commissioned after the end of CMP B.  
New large plant joining post-CMP B will be treated as being connected by a new notional customer under clause 85(2) and its IRA value will be estimated under clause 83(3)(a).

How would costs be allocated if Transpower invests more money into the BHL-PAK circuit? 
Would the accelerated depreciation cost be borne by the current beneficiaries of the circuit? If so, who are those parties, and to what extent would each contribute?

Accelerated depreciation (which has a particular definition in the TPM) is excluded from the calculation of covered cost under clause 39 of the TPM. The effect of this is accelerated depreciation of a benefit-based investment (BBI) is recovered from load customers through residual charges rather than from the beneficiaries of the BBI (which in this case is the North Island Grid Upgrade (NIGU) Appendix A BBI).  Residual charges are allocated in proportion to gross load – see our residual charge information sheet for further information.  

If Transpower invests more money into the BHL-PAK circuit as part of a new project, the expenditure must be treated as a separate post-2019 BBI rather than as part of NIGU (clause 37(2)). This means Transpower will have to calculate new allocations under either a standard method or the simple method, depending on the value of the investment, rather than using the existing allocations for NIGU.

Where can I find customer allocations for the simple method benefit-based investments (BBIs)? 

You can find the current customer allocations for BBIs under the simple method in Appendix D of the Assumptions Book.

Where can I find the starting intra-regional allocator (IRA) values, simple method factors & Customer Allocations for the first simple method period?

You can find this information in Appendix C of the Assumptions Book. 

What HVDC regulated asset base (RAB) should customers rely on? The 2021/22 or 2022/23 model?

In calculating annual covered costs for benefit-based investments (BBIs), we use asset values from the last complete financial year (1 July to 31 June) preceding the relevant pricing year. As such, the relevant RAB is dependent on the pricing year. For example, for PY2023/24 we used the FY2021/22 RAB. 

Assumptions Book

Does Transpower carry out an analysis of the sensitivity of the new TPM charges to perturbations in key assumptions. (e.g. fuel price, deficit generation prices, carbon prices, build cost curves, build time frames)? If Transpower has already conducted a sensitivity analysis, can the results of the sensitivity analysis be provided to stakeholders?  

The standard methods involve a bespoke analysis for each benefit-based investment (BBI). The assumptions that are most influential on the individual customer allocations will vary from BBI to BBI. Therefore, we are unable to undertake a sensitivity analysis that would reliably indicate the most important assumptions across all (or even a small number of) BBIs. Furthermore, there are a large number of input assumptions, and the process of producing allocations is multi-staged and time-consuming. In general, a traditional sensitivity analysis that varies each assumption independently of the others is not practicable. 

That said, given we assess benefits over a range of market scenarios which vary key inputs including demand, new generation, and hydrology, we expect it will usually be possible to understand how sensitive the results are to these key assumptions. Furthermore, we expect to be able to qualitatively indicate the assumptions that are most influential on the results. 

Can Transpower clarify the assumptions in the Assumptions Book that are specified in the Code and those at Transpower’s discretion? 

The purpose of the Assumptions Book is to record assumptions and detailed methodologies that are not specifically referred to in the TPM (or wider Code). Therefore, most of the content of the draft assumptions book is not “TPM-mandated”, so to speak. However, the Assumptions Book is, in our view, consistent with the higher-level methodologies contained in the TPM. In chapter 2 of the Assumptions Book, the only piece that might be described as TPM-mandated is the maximum 20-year duration of the standard method calculation period (section 2.2.3). 

We note that the “Background” sections in chapter 2 of the Assumptions Book discuss the bases for the various assumptions contained in it. Chapter 3 of the Assumptions Book is concerned with process and methodologies, so does not contain assumptions as such. Chapter 3 breaks down the higher-level methodologies in the TPM into the specific steps we intend to apply. We note we have chosen T=100 in section 3.3.7.2 (the number of peak trading periods for the intra-regional allocator for peak BBIs) which is TPM-mandated in so far as that is the maximum number of peak trading periods we could have chosen. 

Chapter 4 of the Assumptions Book is the outcome of our application of the simple method processes and methodologies in section 3.5 for the current simple method period. The regions and factors in chapter 4 are not TPM-mandated, but the high-level methodologies we have used to determine and calculate them are. The benefit factors in chapter 5 of the Assumptions Book are calculated based largely on the BBI customer allocations in Schedule 1 of the TPM, and in that sense are TPM-mandated.  

Is the output from Transpower's OptGen generation expansion model available - specifically the assumed new generation plant by location and technology over time? What happens to benefit-based charge (BBC) allocations if new generation is not built in the regions in the quantum or within the timeframes that Transpower models? 

OptGen is generally run for each benefit-based investment (BBI), as a BBI can influence when and where generation is connected to the grid. Therefore, the generation location and technology assumptions are provided as part of the consultation on the starting allocations for the BBI (e.g. see Appendix B of the CUWLP starting BBI customer allocations – Record of application of the BBC standard method). 

Once we’ve made our decision (following consultation) starting allocations are fixed unless one of the BBC adjustment events listed in clause 81(1) of the TPM occurs (apart from the events in (a) and (k), which are “scaling” adjustments and do not affect allocations). Allocations are not regularly revisited to see if our original modelling assumptions were correct (a deliberate policy choice by the Electricity Authority). 

How is generation embedded in a local network modelled in the TPM?

The two most important aspects of the TPM where embedded generation is modelled or data about embedded generation is used are as follows:  

• Residual charges: Transpower is required to use meter data for embedded generation in order to determine residual charges on the basis of gross load. The residual charge is payable on all load whether it is supplied by the grid or embedded generation. It is not a charge on generation itself (except to the extent the generator has load embedded behind it or consumes load when it is on outage perhaps). Any part of embedded generation injected into the grid does not count towards gross load.  
• Benefit-based charges: The cost of benefit-based investments (BBIs) made by Transpower in the interconnected grid since July 2019 is allocated on a basis intended to reflect benefits derived from the grid as augmented by the BBI. For the simple method, net metering at points of connection to the grid is used (embedded generation is not explicitly modelled). For the standard methods, modelling typically follows the approach Transpower takes to modelling the grid for grid planning and investment decisions. In many cases that includes explicitly modelling embedded generation as grid connected because it does impact the grid. The benefits or disbenefits accruing to the modelled embedded generation are attributed to the host customers, which may result in distributors receiving benefit-based charges for embedded generation that injects to the grid via the distribution network. Conversely, embedded generation will tend to reduce the benefit-based charges of distribution customers as their offtake will be lower. 

Adjustments

What would trigger a benefit-based charge (BBC) allocation change? 

BBC allocations change when BBC adjustment events occur (clause 81(1) of the TPM lists the types of BBC adjustment event). BBC adjustment events affecting BBC allocations can be divided into two groups - those that are, or are treated as analogous to, customer entry or exit and those that are not. The BBC adjustment events related to large plant connections and disconnections, as well as large upgrades and de-ratings, are triggered when the connection/disconnection is to/from the grid or, for embedded plant, when the plant capacity or change in capacity is at least 10 MW. 

The adjustment event of substantial sustained increase in consumption is triggered when there is an increase of at least 25% in large (grid-connected or at least 10 MW) plant consumption or generation since the last time the relevant BBC allocations were calculated that is expected to persist for at least five years. 

For more information on the BBC adjustment events please check the TPM information sheet on benefit-based charges - adjustment events 

Residual Charges

An embedded load customer currently pays 85% of the total GXP Transpower charges, the load has a finite life (approx. 10 years), and the distributor does not have a current contract with the customer to pay the residual charges for the following 4 years from termination. Will the distributor’s residual charge and benefit-based charges (BBCs) be adjusted down immediately from the termination date of this load?

Residual charge allocations do not respond immediately to either new or exiting load. In this example, all other things constant, the reduction in load will be reflected in a reduction (ramping down) of the distributor’s residual charge allocation between years n+5 and n+8, where n is the year of the load reduction. This is because the numerator of the residual charge adjustment factor (RCAF) is lagged (clause 71 of the TPM).  

Depending on why the load reduction has occurred, it may be a BBC adjustment event, specifically, the disconnection of large (≥ 10 MW) embedded plant or a large de-rating of embedded plant (clause 81(1)(e)). This may immediately reduce the distributor’s allocation for any given BBI depending on whether the embedded plant would have been a beneficiary of the BBI had it been connected directly to the grid at the relevant connection location. This is covered in clause 85 of the TPM. 

Prudent Discounts

The prudent discount manual requires an application to be ‘verified’. Who should be the verifier for a prudent discount application?

The verifier needs to confirm the accuracy and sufficiency of the information and analysis contained in the application, and in particular whether the TPM requirements for the type of prudent discount being applied for are satisfied objectively. This will include assessing the engineering scope of the alternative project, the alternative project costs (cost of capital, materials, fuel, construction etc.) and how the alternative project would impact the relevant customers’ transmission charges.  

The breadth of expertise required for this task may require the independent verification to be carried out by more than one person or firm, which the TPM allows for. A “big 4” firm may have the necessary expertise to verify the application without involving anyone else. Other options might include an engineering firm or an economic/ financial consulting firm. Experience with developing or advising on business cases for investments of the same type as the alternative project would be desirable. The verifier(s) must be approved by Transpower, and we may ask for evidence of the verifier(s’) experience and qualifications as part of that. 

How will a prudent discount recipient’s avoided transmission charges be reallocated and recovered by Transpower?

Part I of the TPM contains the prudent discount policy. The calculation of prudent discount recovery charges is covered in clause 138(3).

Can't find an answer to your question? Reach out to our Grid Pricing team at [email protected].