Review of Part 6 distributed generation pricing principles
Authority decision on the review of DGPPs and ACOT
6 Dec 2016
The Authority proposed in May this year to remove the distributed generation pricing principles (DGPPs) from the Electricity Industry Participation Code 2010 (Code), and to shift responsibility for determining avoided cost of transmission (ACOT) payments from distributors to Transpower. The Authority has decided not to remove the DGPPs from the Code. Instead, we are amending the Code so that distributed generation that does not efficiently defer or avoid transmission costs will no longer receive ACOT payments under the regulated terms.
Transpower will assess which existing distributed generators in each region are required for Transpower to meet the grid reliability standards, and advise the Authority of its findings. The Authority will decide, based on Transpower’s advice, which existing distributed generation should receive ACOT payments under the regulated terms. Transpower can contract with new distributed generation where this would provide additional grid support, and it should only do so when it is the lowest cost option for meeting grid reliability standards. Distributors will no longer make ACOT payments to new distributed generation.
Over the long-term, this change will save consumers between $25m and $35m per year. The current rules mean consumers are paying for distributed generation that doesn’t reduce costs for them. Over the last eight years, the rate of ACOT payments has increased by 79%. Effectively, New Zealand consumers are subsidising the owners of distributed generation. Perversely, under the current ACOT rules the more transmission capability we have the higher the rate of the ACOT subsidy. Another perverse feature of the current rules is that they encourage distributed generation to be built in locations that increase future transmission costs (rather than reducing transmission costs).
The Code amendment is expected to create substantial long-term net benefits to consumers. It will largely end the subsidy aspect of the current ACOT arrangements, remove inefficient incentives on the investment in, and operation of, distributed generation, and will enhance competition.
Following feedback from consultation the Authority has decided not to proceed with its proposal to remove a regulated price ceiling for what distributors can charge distributed generators to connect to their networks. This issue may be revisited in the future after final decisions are made about how the costs of the transmission grid are allocated, and distributors have made more progress with setting cost-reflective charges.
We have also published a summary of the submissions we received in response to the consultation paper we released in May 2016.
Last updated: 6th December 2016
Last updated: 6th December 2016
High Court declines Trustpower application for judicial review
2 Dec 2016
On Friday 2 December 2016 the High Court issued its decision declining Trustpower's application for judicial review of the Authority’s decision not to extend the consultation period for the reviews of DGPP and TPM. The Court found no fault with the Authority’s consultation process.
Distributed generation pricing principles (DGPP) date change
18 Oct 2016
We are considering submissions in relation to our DGPPs proposal, and have not made final decisions. However, we are advising parties that the implementation date for any Electricity Industry Participation Code 2010 (Code) amendment relating to the first phase of the DGPP review will not now occur until April 2018 at the earliest.
Further update on review timing
12 Apr 2016
The Authority Board has confirmed the release date for the Transmission Pricing Methodology (TPM) second issues paper and the consultation paper on a review of Part 6 distributed generation pricing principles.
Both papers will be released on Tuesday, 17 May 2016. Consultation will run for eight weeks.
We will hold a stakeholder briefing, covering both papers, on the morning of Tuesday, 17 May 2016. During the consultation period, we will hold workshops in Auckland, Wellington, Christchurch and Invercargill on the TPM second issues paper. We will confirm the timing of the stakeholder briefing and the workshops closer to the release date. We will also meet with stakeholders on a one-to-one basis if they would like to discuss either paper.
Update on review timing
15 Mar 2016
The Authority Board considered a suite of Transmission Pricing Methodology (TPM) papers and has requested adjustments to the modelling to ensure the implications for the sector are clearer and can be better understood.
The Board expects to decide on a firm date for the release of these papers at its meeting on 7 April. At the latest, the Board expects to have the papers released by mid-May 2016.
The review of Part 6 distributed generation pricing principles will be released at the same time as the TPM papers.
Request for information sent to distributors and answers to distributors' questions
25 Aug 2015
The Authority wrote to all distributors on 25 August 2015 requesting information to inform the Authority’s review of distributed generation pricing principles.
The Authority has received a number of questions from distributors seeking guidance on providing the information requested. The questions and the Authority responses are set out below for the benefit of all distributors.
The Authority acknowledges that the information request is generic to all distributors, but that distributed generation arrangements may vary across and within various distribution networks. In compiling information in response to the Authority’s request, distributors are invited to provide assumptions and comments that explain the information they have provided.
- The identity of DG owners, net importers, and nameplate capacity
- What do connection assets and connection costs refer to?
- Annual or monthly payments
- MW during RCPD periods
- Other information sources
1. One distributor advised that it did not always know the identity of the DG owner, and that the distributor was concerned about providing potentially sensitive customer data to the Authority. The distributor asked the Authority what the information would be used for.
Distributors should provide the names of all DG owners that they know, identifying any information that they consider commercially sensitive. The Authority will use the information provided to cross check installation identities. Some of the larger ones DGs will already be known. The Authority understands the sensitivity around customer information that has been provided to distributors by retailers.
2. A distributor has asked whether “nameplate generation capacity” means the total for each connection where, for example, some connections have more than one generator.
The Authority is seeking the capacities of individual plants. The reference to “… each distributed generation plant” should have read “…individual generation units”. If that information is not available, the total of all of the unit nameplates for an installation will be sufficient.
3. A distributor has advised that it has a large number of sites with DG > 10kW, but only a subset export (inject) and not all of those receive export (ACOD and / or ACOT) payments. The distributor presumed that since the request is about the pricing principles, the Authority is only interested in the subset for which the distributor makes payments.
The Authority wishes to obtain information for each DG. If a particular DG never injects energy into the local network due to local (behind the meter) load, that is still an important piece of information. If a DG injects energy into the local network (even if only in some periods due to behind the meter load) but is not paid, this is useful information in understanding a distributor’s pricing methodology.
4. A distributor noted that there were a number of DG’s that are exactly 10 kW on its network and sought guidance as to whether a detailed breakdown of information is required (Question 1).
Detailed information should be provided for any DG that is equal to or above 10 kW.
5. Questions 2(b) and 2(e) – “Number of connected parties using the connection assets”. A distributor has asked how deep into the distribution network the “connection assets” it should look in answering this question. For example, in the case of PV panels on a house, whether the distributor should include the connection assets comprised the LV cable along the street and the distribution transformer supplying that street. In the case of a dedicated connection directly to a zone substation for a large embedded generator, should the distributor include the dedicated 11kV circuit breaker as a connection asset or the entire 11kV switchboard?
Distributors should include all assets that are necessary to connect a distributed generator to the network. Please use a “but for” test to determine whether distribution assets are a DG’s connection assets, for example, whether a distributed generator would be able to connect to the distribution network without the asset in question.
6. Question 3(d) – “Connection charges”. A distributor noted that Question 7(c) acknowledges that connection costs can be recovered through capital contributions at the start or via periodic (monthly or annual) connection charges. The distributor asked whether, in the context of Question 3(d), capital contributions are considered as connection charges.
Capital contributions should be included as a connection cost.
7. The Authority has received a number of questions about how connection charges should be defined, and whether these are the one-off charges to pay for assets required to inject into the network (for example, transformer upgrades), or are annual charges for which the net incremental cost can be calculated (ie, net of the annual distribution and transmission costs) as referred to in schedule 6.4(2)(a).
When assessing whether assets are connection assets, please include all assets that are necessary to connect a distributed generator to the distribution network, even where other parties share these assets. Please use a “but-for” test to determine whether assets are connection assets. For example, whether a distributed generator would be able to connect to the distribution network without the asset in question.
8. A distributor asked whether the “initial connection cost” is what the distributor charged the connecting party, rather than what it might have cost the distributor.
Please include both the cost charged and the cost incurred if they are different and if the distributor knows the incremental cost.
9. A distributor advised that it does not know the number of “connected parties” using the “connection assets” either at the commissioning date or as at 31 March 2015 (ref 2(d) and (e)). If this includes all parties (ie, not just DG), the distributor asked how far up the network to go in determining connection assets. The distributor asked whether, when referring to connection assets, it should include assets that were charged for under clause 2(c).
The relevant reference is Schedule 6.4 2(i), which deals with multiple DGs that might share an investment in connection assets that a distributor has commissioned. In most cases, there is probably just one. Schedule 6.4 2(i) only relates to DG, not to other connected parties. Connection assets are those that would not be required but for the connection of the DG. The Authority is aware of a case where connection assets included a new transformer that was installed at a nearby zone substation. The transformer would not have been required if the (quite large) DG had not requested connection.
10. Question 3(a) – “Total ACOT payments per generation plant per pricing year” A distributor asked whether the Authority would prefer monthly amounts despite the spreadsheet being configured for yearly amounts. The distributor advised that the monthly payments are identical for each of the 12 months of each financial year.
If payments do not differ from month to month, annual payments are sufficient.
11. Question 3(c) – “Metered injection in MW during RCPD trading periods”.A distributor advised that it has that information available for the larger DG plants, but since the RCPD comprises twelve trading periods each year (and 100 in some other areas) asked whether the Authority requires the MW for each of those trading periods or just the average across all the periods. In asking this question the distributor noted that Question 3(c) requests the net metered injection in MW during RCPD trading periods, rather than requesting the average MW across the RCPD trading periods. The TPM uses the average MW across all the RCPD trading periods to assess Interconnection charges for Transpower payments, so the distributor said it would expect that the Authority would only wish to see the average injection across the RCPD periods – otherwise the spreadsheet is going to get very large, especially for areas that use 100 periods for RCPD.
The average across all periods will suffice.
12. The Authority has received questions from distributors about information requested under 3(a) “Net metered injection (in MW) during RCPD trading periods for year ended 31 March 20xx”. In particular, some distributors have advised that Transpower’s Capacity Measurement Period (which is used to calculate transmission prices) runs from 1 September to 31 August. For example, transmission prices for the year ending 31 March 2015 are calculated using data from 1 September 2012 to 31 August 2013.
Please a provide Net Metered Injection information for the relevant Capacity Measurement Period. To avoid confusion, for the year ending 31 March 2015, please provide net metered injection for the period from 1 September 2012 to 31 August 2013 (the relevant capacity measurement period).
13. A distributor asked whether, when referring to net metered injection during RCPD periods, the Authority means average metered injection (ref 3(c)). The distributor advised that it only has access to data that records ICP import and export as measured at the meter and does not know if this is net of anything.
The Authority confirms that the average is required.
14. A distributor advised that it has a large amount of publicly available documentation on our approach, and it intend to provide links to this in its responses rather than copy and paste it all.
This will be sufficient if it covers the questions. If the existing documentation also contains other pricing information not related to DG pricing, please include a cross-reference so the Authority knows exactly where to look amongst the provided information.