Part 1: Growing renewable generation
On this page
Chapter 2: Accelerating supply of renewables
Approximately 50 submissions were received on issues discussed in Chapter 2. Some issues discussed in relation Chapter 2 also crossed over with competition-related matters discussed in more detail in Chapter 6 (workably competitive electricity markets).
Submitters agreed additional measures may be needed to accelerate renewable supply
Submitters generally agreed that significant investment in renewable generation is needed, or is expected, and that such investment needs to be enabled or supported by electricity market settings and by the broader policy and regulatory environment measures. However, submissions differed on the reasons why additional measures were needed, and the nature of measures needed.
Some submitters suggested measures need to improve investment uncertainty
Some submissions focused on a perceived lack of policy and market certainty to support investment decisions for new renewables. For example, several submitters claimed a lack of stable government strategy on macro-market drivers (including carbon pricing and gas exploration settings) has contributed to generation investment uncertainty, particularly from the offshore investor market. Some submissions suggested these uncertainties have also constrained investment in “firm” resources that could support new intermittent renewables (discussed in more detail the Chapter 3 summary below).
To address this, some submissions proposed generic forms of government support, including development of a vision and a pathway to a fully renewable system. Others called more specifically for greater certainty regarding gas exploration and a transition plan, the NZ Battery Project, emission trading scheme (ETS)/carbon pricing, and renewable energy targets to ensure an attractive investment climate.
Submitters had mixed views about whether competition-related measures were important
A key tension between submitters was whether analysis should focus on the sufficiency of the pipeline of renewables alone, or also ensuring low barriers to entry for non-incumbent generators to build new renewables. Many submitters said the current market gives incumbent and vertically integrated generator-retailers (known as “gentailers”) too much market power, and that generation investment by new entry developers is challenging without additional measures to reduce the entry costs. However, many submitters also noted that plenty of generation is being investigated and planned without such measures – and that further measures could therefore be distortionary and should only be considered if there is evidence insufficient generation is forthcoming.
Those concerned with incumbent generators’ market power suggested that, without extra measures, new generation development could largely remain the domain of existing incumbents who have access to renewable based dispatchable generation - and in particular, those participants that own and operate hydro generation with storage. Some also said the existing generation market structure incentivised incumbents to perpetuate only incremental growth in capacity to keep prices high by maintaining a perpetual state of near shortage. These submitters suggested measures were needed to disrupt this model by enabling entry from independent developers, which could lead to a step change in the scale of generation development that could reduce wholesale prices.
Submitters suggested measures could focus on overcoming new entrant developers’ need for commercial offtake agreements and/or a retail customer base to underwrite generation investments – these being advantages which incumbent gentailers possess and use to leverage their own investments. Measures could be developed to stabilise new entrant developers’ revenue, or otherwise reduce investment risk and support access to debt finance.
Submitters said there was a lack of suitable risk management tools to support new renewables
Related to the above discussion, many submitters also discussed the difficulty of non-gentailers accessing suitable risk management arrangements – such as standardised financial hedging contracts, including shaped or flexible hedge contracts – to secure offtake agreements needed for intermittent renewable projects.
Some suggested the government could underwrite such arrangements to enable new entrants to invest. One submitter suggested gentailers could be required to provide peak demand and price cap products. However, others thought this issue could be addressed through introduction of a capacity market, or other measures to reward firm or flexible capacity that could support further investment in intermittent renewables.
Many submitters were concerned with network capacity and planning processes
Many submitters agreed that planning regulation adds unwarranted time and cost to generation and network development, and is a barrier to investment. Many also thought unwarranted delays, uncertain timing, and high costs of transmission and distribution network investment were a barrier to renewable generation investment.
Many submissions referred to the need for more streamlined and more supportive planning processes under the Resource Management Act 1991 and Conservation Act 1987, both for generation projects and for the associated transmission and distribution infrastructure. Some also extended this to roads and the port infrastructure that will be needed for offshore wind farm development.
Some submitters suggested that, because of the slow pace of transmission investment, there was a high probability that new renewable generation projects will be consented and built before there will be is sufficient transmission capacity available to service 100% of the generation output. To avoid this, some submitters favoured “renewable energy zones” (REZs), or other measures for the government to ensure grid capacity.
Chapter 3: Ensuring sufficient firm capacity during transition
Approximately 45 submissions were received on issues discussed in Chapter 3.
Submitters agree firming is needed, but there is disagreement about how to support this
Submitters all supported the need for more firming generation, but were divided over whether the energy only market will provide this or whether additional capacity incentives or schemes are needed – either now, or in the future. Submitters were also divided over whether, if support is needed, that support should be only for renewable technologies, should support thermal generation, or should be technology agnostic.
A range of submitters supported an ongoing role for thermal firming during the transition
A range of submitters, including developers of renewable generation, argued that there was a role for thermal firming to help support the energy transition, although specific views on that role varied. Some submitters noted a range of renewable generation coming to build stage, but a paucity of new firming to replace soon to be retired thermal generation plant.
One submitter suggested that both gas and a diverse set of other supply and demand-side options would be an important enabler of the transition, to get to a more renewable energy supply while maintaining system reliability and affordability, including reducing the need for extra grid capacity just for peaks.
Several submitters considered gas fired or thermal generation may need (financial) support in future to manage security of supply and to support renewable generation, but argued that this support was not yet needed. One submitter, however, argued against any form of government intervention in future unless there was clear evidence of market failure, but if intervention was to happen then government could support investment by removing the risk of future government policy or regulatory changes materially negatively impacting the economics and overall viability of such investments.
If support was needed, potential options cited by submitters could include some form of capacity market or mechanism, while others pointed to the UK model to incentivise thermals during the transition, while using CfDs to promote renewables and batteries. One submitter argued that the costs of running a capacity market are unlikely to outweigh its benefits. In contrast, another submitter acknowledged that while capacity payments may bring unintended consequences they argued that these consequences are less than the counterfactual of doing nothing as hoping the market will deliver is a high risk strategy. Another submitter suggested that if government did intervene, the model should be structured to prevent future changes in policy affecting the economic viability of investments made in reliance on this.
Separately, one submitter argued that the current pricing mechanism that pays all generators the marginal price should be reviewed despite the disruption that would result to the current market mechanisms as it pushes up prices to consumers. It also commented that payment for firming generation and demand side load reduction should be considered.
Many submitters supported firming from renewable only sources (with no role for thermal)
Many submitters supported the need for new firming, and for this support to be provided by government but only if it was provided via renewable options. Submitters made a range of points in support of or relevant to this position, examples being that:
- there are no compelling reasons to support existing or new fossil fuel gas fired generation (baseload or peak), and support on the basis of affordability is short-term and misguided
- use of hydro generation should be changed so that it is used for firming renewable generation, rather than as baseload generation – and that this approach may require a “rationalisation” of hydro assets
- continuing policies supporting gas fired or thermal generation keep market prices high
- interventions should consider both firming and peaking, and longer term storage – and that Battery Electric Storage Systems (BESS), unlike a pumped hydro scheme, will not address longer term storage issues
- interventions would also need to be carefully designed (e.g., support for long term storage could significantly shift the balance in terms of utility scale versus household solar).
Some submitters supported both renewable and thermal firming or were technology neutral
A number of submitters supported measures to enhance firming but were either neutral on its form, or supported both fossil fuelled and renewable options. For example:
- One offshore wind developer argued government-facilitated price stabilisation measures could support firming / storage assets in the same way as for new renewable generation, and that measures to support both BESS and green-molecule based storage are warranted.
- One gentailer saw existing and new gas fired peaking as the least cost, most emissions friendly option for support the renewable transition, but considered regulatory certainty about the role of gas was the only support needed.
- Another gentailer supported an ongoing role for some fast start peaking generation in the foreseeable future but not a capacity market. It argued that future demand response will eventually displace gas peakers as emissions prices increase and large-scale demand response becomes more economic.
- One electricity distribution network (EDB) suggested demand response will need to be carefully managed when thermal peaking starts to phase out. It also argued that consumer energy resources or CER (e.g., rooftop solar, batteries, electric vehicles (EVs) and smart devices) should be optimised to play a role in short term firming, and that this will require CER owners to be incentivised to participate, including through appropriate pricing and retailer incentives for storage.
Chapter 4: Managing slow-start thermal capacity during the transition
Approximately 30 submissions were received on issues discussed in Chapter 4.
Submitters had mixed views about support for slow-start thermals to manage an orderly transition
There was no clear agreement between submitters on whether further measures are needed to support slow-start thermal as we transition to a more highly renewable system, to avoid the risk of an unmanaged exit of thermal generation. However, some submitters who argued against further measures also indicated limited support for an obligation for thermal generators to notify in advance where they intend to retire plant.
Submitters in favour of extra measures focused on security of supply risks
Submitters speaking in favour of, or supporting, intervention polices generally noted the need to support system security over the transition. Comments across different submitters included that:
- arguments for measures will carry more weight if it becomes apparent that thermal plant is necessary to ensure ongoing security of supply
- the size of thermal plant creates significant risks, as there could be an unplanned material reduction in system resources to balance energy capacity, voltage and frequency – and so a standby ancillary service will become critical to provide additional flexible resources and reduce operational capacity risks in a more intermittent system
- there are conflicting objectives with thermal plant – on the one hand there is an expressed requirement to “phase down” existing thermal plants, and on the other measures may be needed to retain thermal plants to avoid risks to security of supply
- retirement of some thermal will see more concentration in the remaining thermal plant, and the ability to set the price, which also flows through to the value for hydro
- notice periods will help manage phase down
- however, notice periods could also have a direct value impact for market participants, including for staff retention and maintenance expenditure
- there may be a need to place thermal plant into a strategic reserve in the future, which could include models such as “Thermalco” proposed earlier by Contact Energy, to support the transition.
Submitters against further measures thought these were unneeded and could impose costs
A few submitters rejected the need to support thermal retirement. Comments included that:
- the evidence for further measures is mixed – this would impose a collective “insurance” cost on the market and Genesis, which owns the bulk of slow start thermal not due for retirement, will need this to meet its customers’ demand and compete with hydro during peaks
- this could be used as ploy to retain thermal longer than needed and to keep spot prices high – whereas massive investment in rooftop solar could be the best option to avoid supply shortages
- a capacity market or strategic reserves creates risks of higher prices and oversupply.
Chapter 5: the role of large-scale flexibility
Approximately 35 submissions were received on issues discussed in Chapter 5.
Submitters agree industrial demand response will be an important part of the energy system
All submitters emphasised the value of demand response in helping to balance supply and demand and its increasing value as the percentage of renewable electricity increases and thermal generation declines. Submitters indicated the importance of the Electricity Authority’s real time pricing work to facilitate greater use of demand response.
The value of avoided business production is a key issue for participation in demand response
Submitters generally agreed that a key issue for whether businesses participate in demand response was the impact of reducing, or delaying, production of their goods versus the benefits of lowering electrical demand. However, submitters varied considerably over what was a sufficient incentive to deliver the value from demand response – and in particular, whether the benefit of lowering demand should simply be the avoided electricity cost, or whether some additional incentive was required.
There are mixed views on additional measures to incentivise greater demand response
Submitters expressed mixed views on whether the market by itself provides sufficient incentives for large-scale demand response. In general, larger industrial submitters argued for additional payments, especially for longer-term demand-response over weeks or months.
Some submitters argued that market or contractual arrangements between suppliers and consumers were sufficient to enable significant demand response, such that no further incentives were needed. One gentailer, for example, argued that bilateral contracts are fully capable of meeting the specific requirements of any large consumer to provide demand response, while another submitter expressed a similar view.
A contrary view was presented by many submitters, arguing that additional incentives were needed to bring forward material volumes of demand response. Some for example argued that:
- participants that bid demand response into the market should be paid the final price for that trading period on the volume of demand response dispatched
- the ancillary market needs to be considered, and that load reduction should be remunerated as for generation as it has the same value to the system.
Various points were made by different submitters about market dynamics, including that:
- the dispatchable demand model (e.g., avoided purchase cost) is not attractive to large industrial users because it does not provide a material benefit sufficient to balance lost production
- aside from some long-term energy arrangements with flexibility included, there is very little demand response developing in the commercial and industrial space outside of large individual bespoke contracts
- it is unclear whether demand response solely through market developments under real time pricing would be sufficient.
Relationship with distributed flexibility
Other submitters noted the synergy between demand response and distributed generation and storage (batteries), and argued that these CER-enabled responses should have access to similar mechanisms and incentives in the market.