Part 3: Networks for the future
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Chapter 7: A transmission system for growth
Approximately 35 submissions were received on issues discussed in Chapter 7.
Submitters noted that the risks of early versus later transmission investment have changed
Almost all submitters agreed that the balance of risk between investing too early and investing too late has shifted in recent years. Reasons for this included the need for sufficient grid capacity to support electrification for net zero by 2050, and the divergence between the time needed to build new transmission (which has gotten longer) compared to new generation. Submissions suggested Transpower will likely need to strengthen the core grid to respond to the changing mix of generation sources and location of new renewable resources, as well as changing demand centres.
Submissions emphasised the importance of transmission not ending up an impediment to investment in renewables generation. Historically, in an environment of low demand growth, new generation was primarily added to the system as large hydro or thermal assets. There were few actors in the generation space, and transmission upgrades were largely planned and developed in parallel with these generation assets. The risks of underinvestment previously were mainly security and reliability.
These risks remain – but in addition there are now also the risks that delayed transmission build out creates a barrier to us meeting emissions reductions targets and/or connecting new renewable generation (which should put downward pressure on wholesale prices). From a global perspective, there are also supply chain risks, as international demand for transformers and other grid equipment increases to support global decarbonisation.
Submissions agreed that planning laws needed to be more enabling
To support more timely build out of the national grid, submitters agreed on the importance of an enabling environment for resource management consenting – to try shave time off the end-to-end process and align with generation investment timeframes.
Timely access to the grid is critical for some generations sources (such as offshore wind)
Specifically for offshore wind developers, submissions suggested that guaranteed and timely grid access is critical. Developers require certainty regarding transmission and grid connection to achieve final investment decision. This point was also echoed by others, for an independent solar developer.
Submitters acknowledged possible overbuild, but some queried whether this was a timing issue
There was recognition that ‘overbuild’ is still a real and significant costs to consumers and therefore scrutiny and robust regulatory processes remain necessary. However, some argued that stranded asset risk, in this current environment, is likely to be a timing issue, that is, that this may result in underutilised capacity for a period, rather than complete redundancy.
In support of this, some supported development of new financing mechanisms that recognise future demand is a matter of “when” rather than “if”. Related to this, a few submitters commented that first-mover disadvantage or FMD (i.e., high upfront costs when Transpower builds above the actual needs of the connecting party, on the basis of anticipated future demand) was still an issue that is slowing down electrification.
Submitters expressed mixed views on the need for regulatory change and Transpower’s processes
Submitters expressed mixed views on whether changes are required to the Commerce Commission’s regulatory framework under Part 4 of the Commerce Act 1986, or whether it is sufficiently flexible.
Likewise, submitters varied in their views on the state of Transpower’s connection queue. Some submitters said that recently implemented changes were good and sensible, while others said the waiting time remained too long and more needed to be done to get rid of ‘opportunistic applications’. Other comments suggested the large number of connection queries make it difficult for developers to understand where future capacity needs to be built, or where existing capacity exists.
Some groups challenged the traditional one-way power system supported by transmission
A small number of consumer groups suggested that the traditional centralised model (big power stations with lots of transmission) is outdated and that focus should be on more distributed generation – particularly rooftop solar. This would allow more generation to occur where electricity is consumed, avoiding losses and expensive transmission.
Chapter 8: distribution networks for growth
Approximately 40 submissions were received on issues discussed in Chapter 8.
Submitters agreed that existing regulation was a barrier to efficient network investment
Submissions indicated a widespread concern that the existing regulatory settings will not support the scale of investment electricity distribution businesses (EDBs) need to make in the next regulatory period (2025 – 2030). This concern was expressed strongly from EDBs themselves, but also a range of other submitters – with very few submitters suggesting only incremental change is needed.
Concerns ranged across both the suitability of the statutory framework regulating the return EDBs can make as monopoly providers (Part 4 of the Commerce Act 1986), and the Commerce Commission’s regulatory processes to implement this framework, to meet accelerated investment needed for rapid electrification of homes and businesses, and for increased resilience in the face of a changing climate.
Common concerns included that:
- there is a lack of flexibility to change EDBs’ recoverable revenue during their five-year regulated period
- the Commission’s approach is too focused on historical data rather than less certain future growth
- the regulatory model disincentivises opex solutions as against capex investment
- regulatory decisions do not adequately take account of sustainability objectives
- “whole of system” thinking is not integrated into decisions around network investment under the current framework.
Some EDBs also raised concerns with Commission’s recent draft, and forthcoming, decisions on the next five-year regulatory period starting in 2025 – highlighting, for example, how back-ending cashflow may reduce funding for network investments, and a lack of adequate funding for innovation.
Non-EDBs saw issues with the cost of connections and first-mover disadvantage, while EDBs did not
A large number of non-EDBs expressed concerns with the high costs of connecting to networks, and how this could be a barrier to electrification or new generation – especially where new connections involve anticipatory build, the costs of which a new connector could have to bear (leading to first-mover disadvantage or FMD). This included electric vehicle (EV) charge point operators (CPOs), who cited this and variability between EDBs as a key barrier to electrification of light transport. Non-EDB submitters also cited wide variations in the extent to which EDBs pass on connection costs: (a) all or largely upfront or over a longer period via lines charges, and/or (b) solely to the connecting customer or also to others (cross-subsidising).
However, most EDB submitters suggested both that FMD was not a significant issue and that their costs of connection were reasonable – suggesting that significant network connections can be expensive by their nature and the “costs are the costs”. At least one EDB did, however, concede that the regulatory framework is not geared to reward anticipatory network build.
EDBs submitted against the idea of regulating costs of connection, arguing they needed discretion to apply connection policies meeting the unique circumstances of their network (e.g., given their particular financing needs, customer types, and geographical spread) and that this would undermine the idea of more efficient cost-reflective pricing. At least one EDB argued for transparency first (e.g., of costs), before more direct interventions.
EDBs also argued against applying pricing principles similar to those in Part 6 of the Electricity Industry Participation Code 2010 (Code) – saying this would add complexity and would not address FMD or costs issues – as EDBs would still be entitled to charge reasonable costs. There were mixed views for a Part 6 approach from non-EDBs. A number supported this idea or something similar, with particularly strong support from the representative body for CPOs, but others thought this might give the appearance of a solution without actually addressing key concerns.
A good number of non-EDBs and EDBs supported some form of government-backed financing to help support anticipatory build of network capacity, potentially for national or regionally significant connections, to overcome high upfront costs and/or FMD. A large range of other options were also suggested to address these issues, such as creating renewable energy zones, exploring capped-costs for different connection types, better transparency of connection costs, competition for network upgrade work, or adoption of a FMD approach similar to that in the Transmission Pricing Methodology.
Submitters agreed that non-price considerations could be barriers to connection of new demand
Submissions indicated a high degree of consensus that non-price barriers – in particular, limited availability of information regarding capacity and inconsistency of processes – are affecting the speed and difficulty of new connections.
Several submitters pointed to a lack of lack of transparency around capacity constraints and utilisation affecting connection decisions and cost. Submitters suggested this should be clearer and more accessible – for example, via information disclosure on the worst performing feeders and/or GIS data on network load and asset utilisation.
Some submitters also raised more general concerns that connection processes are often opaque and/or can involve unnecessary delays.
Submitters agreed that Code processes for connecting distributed generation need reviewing
Few submissions suggest there is a fundamental problem with processes for connection of distributed generation, but there are a range of “niggles” with Part 6 of the Code (governing distributed generation connections) and support for its review. Key themes are that Part 6 has remained largely static, despite the nature of connections growing from smaller scale distributed generation to significant utility scale that may not have originally been envisaged.
EDBs did not necessarily have any concerns technically with connections, but did generally support a review of Part 6 of the Code, some noting challenges with:
- the thresholds for different connection processes in Part 6 (including timelines and requirements), given differences between smaller and larger scale connections
- charging for larger-scale connections (e.g., that it can be difficult to apportion recovery of network cost for distributed generation export to these customers).
Some non-EDBs suggested possible concerns with the cost of connecting, although EDBs suggested these connections can simply be expensive by nature. Non-EDBs also pointed to possible delays affecting investments, and a lack of clear guides or standards for large distributed generation and EDB published constraint management policies.
EDBs oppose more regulated distribution pricing, while many non-EDBs support this
EDBs oppose prescriptive distribution pricing, saying that the Electricity Authority’s scorecards are working, and that differences between networks means EDBs should retain discretion to adopt pricing appropriate to them. They also raise concerns that this could undermine cost-reflective pricing.
However, there is support for more prescriptive pricing from a number of non-EDBs, with a smaller number concerned that this will not be effective. Non-EDBs also point to a lack of transparency across EDBs as to how distribution pricing is established and costs allocated across customers.
Although other factors affect cost reflective pricing (e.g., the LFC phase out), EDB submitters were concerned that retailers are failing to pass through price signals and point out many retailers are failing to use actual time-of-use consumption data. However, retailers submitted that they should have wide discretion in how they respond to pass on distribution tariffs, and suggested that consumers are not yet ready for highly price-reflective tariffs.
Most submitters thought there was insufficient regulatory coordination and alignment
Most submitters that responded suggested there is a lack of coordination and/or transparency across regulatory actors. Only a small number suggested there was adequate coordination. A number of submitters also specifically noted an unhelpful regulatory overlap between the jurisdiction of the Electricity Authority and the Commerce Commission.
Submitters suggested a variety of options for better regulatory alignment, such as:
- better transparency and coordination from the Council of Energy Regulators
- the development of an energy strategy with industry
- more focus on “whole of system” planning
- amendments to the regulators’ objectives
- proposals for a single energy regulator and/or new energy-specific ministry.
Chapter 9: is the government’s sustainability objective adequately reflected for market regulators?
Approximately 30 submissions were received on issues discussed in Chapter 9.
Most submitters thought sustainability objectives should be reflected in regulators’ decision-making
The majority of submitters on this question did not think existing regulator objectives were sufficient in relation to the energy transition, or that it was sufficiently clear that they would be sufficiently taken into account.
A few submissions from EDBs acknowledged the Commerce Commission’s position with respect to the permissive consideration in section 5ZN of the Climate Change Response Act 2002 (CCRA). But, they further commented that this consideration was too subjective in terms of how much weighting should be given to climate change and emissions reduction objectives in section 5ZN of the CCRA.
Of those who supported strengthening direction, some of the reasoning included that:
- emissions reduction is consistent with the long-term benefits for consumers
- climate change is a long-term challenge that New Zealand (and the world) will grapple with, making it appropriate to reflect this in regulatory objectives
- the 2050 net zero target is legislated
- if the Electricity Authority and Commerce Commission are expected to support decarbonisation and emissions reduction in line with net zero 2050, then that mandate should be explicit.
Of those who supported strengthening climate change objectives of regulators, there was not a consensus on whether a government policy statement (GPS) or legislative change would the most appropriate vehicle. One submitter suggested that a GPS could be issued, monitored for effectiveness, with consideration of legislative change following that.
There were submitters who thought the status quo was sufficient and appropriate for market regulators. A few submissions pointed towards the 2018-2019 Electricity Price Review which considered this question, but which ultimately concluded that the addition of a climate focused objective could pull the regulator in too many directions.