Here's how to get Australian renewables into the zone | RenewEconomy

Here’s how to get Australian renewables into the zone

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Rather than a hedge, regulators should encourage wind and solar generators to connect early through lower access charges to help unlock the lack of investment in network infrastructure.

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Wind and solar at Coober Pedy. Photo credit: Christian Sprogoe
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People want reliable and affordable energy, and most also want it to be renewable. Meeting these demands requires delivering new, renewable generation quickly and at lowest cost.

Renewable Energy Zones (REZ) are one way of doing this. A REZ is a cluster of generators either sharing connection assets or sharing both connection and some transmission assets.

Through the sharing of assets, REZs provide a lower cost and faster way of delivering new generation to the system – helping to accelerate the process of decarbonisation and deliver affordable and reliable power. They are needed to meet not just the generation projects that are currently committed but those that are reasonably expected in coming years.

Despite the obvious benefits of using REZs, historically they haven’t been delivered. One reason for this is the current regulations aren’t designed for building transmission infrastructure ahead of generation.

The Australian Energy Market Commission (AEMC) has been grappling with the issue of how to coordinate transmission and generation investment so that the required new generation can be delivered quickly and at lowest cost through its COGATI process.

As part of this, it published two discussion papers last week – one on coordinating investments more generally and one on REZs in particular. The papers put forward a plan for encouraging transmission investment in advance of generation by overcoming some barriers in the existing regulatory framework.

To overcome the barriers to coordination of transmission and generation the AEMC proposes to change the way wholesale electricity is priced by introducing dynamic regional pricing and improve financial risk management for generators.

These measures are a welcome attempt to address pressing issues but they will likely be insufficient to address the barriers to investment that exist under the current system.

The AEMC’s proposed model hinges on generators committing money to transmission projects early, rewarding them for doing so by delivering the transmission investment and financially guaranteeing their level of access through contractual arrangements called hedges.

This model assumes generators have the ability to commit funds early in the project. However, it’s not clear that they do. Under the current system there is nothing stopping generators from committing funds early. If generators had funds available, more REZs or similarly coordinated generator connections would likely already exist. They do not.

Even if generators could commit funds early, they may not want to. By design, a REZ should minimise congestion to an efficient level so the risk of a generator being constrained is low. Without this risk there is little value in a hedge.

PIAC has proposed an alternative model for funding REZs that the AEMC considers in its discussion paper. Core to the PIAC model is sharing the risks and costs of developing REZs between generators and consumers, rather than just consumers. It does this by splitting transmission investment into guaranteed and speculative, rather than just guaranteed.

The guaranteed portion is the amount of capacity required to meet some minimum need and is recovered by TNSPs through regulated revenue. The speculative portion covers any capacity above guaranteed, is funded by a speculative investor, and is recovered through generator access charges.

Both the guaranteed and speculative portions are determined by the regulator or some other administrative body and are based on a variety of different factors.

The process for planning, delivering and connecting a REZ is summarised in the diagram below.

Under the PIAC model, rather than ask generators to commit funding early to projects for a guarantee of access, generators are encouraged to connect early through lower access charges. In doing so they are protected from the risk of REZ underutilisation as their access charges depend on their decision to develop and connect early, not on the overall utilisation of the transmission asset.

Instead, a speculative investor bears the risk of underutilisation and the generator pays a commensurate premium. However, by receiving lower access charges for connecting early, generators are incentivised to take on some of this risk.

Regulated transmission businesses do not take on any more risk than they face under the existing regulatory framework. They are guaranteed cost recovery from consumers via the usual regulated transmission charges, and retain the design and operation responsibilities for the transmission assets that make up the REZ.

The speculative transmission investor takes on some underutilisation risk via the portion of investment costs that are not underwritten by either government or consumers and receive a commensurate return through access charges. By linking revenues to utilisation, speculative investors are encouraged to forecast utilisation accurately and support regulators to accurately determine guaranteed and speculative capacities.

Under the model, the risk that consumers will have to pay for underutilised transmission infrastructure is capped. This limits consumers’ liability under all scenarios, including the worst case where utilisation is very low.

At the same time, consumers share some risk with the transmission investor by underwriting a portion of the transmission investment through regulated revenue. Consumers still benefit because it helps to reduce uncertainty that deters transmission investment, increases competition in the wholesale market and facilitates the transition to decarbonisation.

Under the PIAC model, government can have a role in taking on some underutilisation risk by underwriting some portion of the cost. Government may do so to support infrastructure investment, broader social, economic and planning goals, or to reduce risk to consumers. Government may also wish to underwrite to earn a return if utilisation exceeds the underwritten level.

Developing a framework that fairly and effectively shares the risks and benefits of a REZ is a wicked problem. It requires rethinking how we plan, invest and pay for network assets. It’s an important problem to solve and there are solutions. But it’s essential that we do in fact solve it and deliver the decarbonisation the industry needs.

Miyuru Ediriweera is senior policy officer for Energy and Water at the Public Interest Advocacy Centre.

 

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1 Comment
  1. Malcolm McCaskill 5 months ago

    Need some examples of how this proposal could be any better than the current system for key projects in the ISP such as
    – the new SA-NSW interconnector
    – HumeLink
    – KerangLink
    In each case the investment has multiple benefits that go well beyond connecting another wind or solar farm to a captial city market. For example benefits of the SA-NSW connector include
    – less gas required for stability in SA (SA consumers benefit)
    – increases capacity on the Heywood interconnector from 500 to 750 MW, so the total export from SA rises to 1500 MW (current + new SA generators benefit)
    – greater stability in the Sunraysia area where current solar farms have been unexpectedly curtailed to 50% (Vic generators benefit)
    – less curtailment of wind and solar in SA (SA generators benefit)
    – more efficient market (SA and NSW consumers benefit)
    Much of the curtailment at present was for reasons not forseen just a few years ago. For example on 13 November 2016 SA operated for several hours on wind and solar with only a single gas unit providing inertia. The inertia requirements came later. Most of the beneficiaries of the proposed SA-NSW link listed above would not have envisaged these issues as even being a problem when investment decisions were made 3 years ago. How would it work for a speculative investor in the SA-NSW link who expects they are buying into a 1500 MW export capacity from SA, if new requirements come in that reduce it to (say) 1000 MW? As an example, the Heywood interconnector upgrade was meant to allow 650 MW to be exported from SA to Vic, but this has been constrained to 500 MW. If an SA solar farm had contibuted to the upgrade expecting to get say 150 MW of the upgraded capacity, but this was not delivered because of grid issues that could not be modelled at the time of the investment decision, where would they stand? Likewise the SA-NSW connector only goes as far as Wagga, with the HumeLink scheduled for completion several years later, so the 750 MW export capacity SA to NSW may well be constrained by capacity between Wagga and Sydney. This all becomes a murky area for investment that would only attract high-risk capital justifiable only by high returns.

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