Australia’s ENERGY FUTURE: 55 BY 35

Executive Overview The AEC has proposed an economy-wide interim emissions target of 55 per cent
reduction on 2005 levels by 2035 as a milestone on the way to net zero. This paper is one in a series of papers exploring the implications of the 55 by 35 target. This paper looks at the implications of this target and the transition to net zero for Australia’s electricity transmission networks.

Introduction Electricity transmission systems are the high voltage wires that link large scale generators such as coal and gas plants, wind farms, and hydro systems to the low voltage distribution systems that bring electricity to homes and businesses (a few of the largest users are directly connected to the transmission network). Australia has two main transmission networks: the National Energy Market (NEM) that covers eastern and southern states and the Southwest Integrated System (SWIS) that covers Perth and the south-western corner of Western Australia. While the SWIS has a single transmission network service provider (TNSP) in the form of state-owned Western Power, the NEM has five large TNSPs, one for each state covered by the NEM and three smaller TNSPs who operate interconnectors (transmission systems connecting two states). In the NEM, the market operator AEMO has an important role to play in national planning and is also the state planner for Victoria.

Policy and regulatory issues Transmission networks are natural monopolies and accordingly are heavily regulated. The risks associated with investing in new transmission should lie with the party best able to manage them. The key issue is that different parties disagree where risks should lie. The current framework imposes most of the risks of overbuilding, inefficient costs or excess congestion on consumers, even though they are not best placed to manage the relevant risks. However, they are the beneficiaries of an optimised transmission network that minimises the combined cost of generation and transmission whilst meeting reliability standards. The main activity of the networks – operating, maintaining and, where necessary, augmenting – the shared network is subject to a revenue cap that is set every five years. Because their revenue is fixed, the network businesses have a strong incentive to keep their costs down, although the rules require them to return a portion of any savings to customers through lower future prices. A set of standards (with penalties for non-compliance) and other incentives act as a safeguard against cost-cutting to the point that the quality of service degrades.

process is about trying to predict the future costs of the business there are risks in extending the period out longer. Until recently, the final determination could be appealed, but that right has now been removed. Importantly, given the need for additional transmission to support the energy transition, there are separate processes for large projects, so that the TNSP does not have to wait until the next five-year period to see if it can get these projects funded. These include a test to determine if a large project is worthwhile and the best option to solve the identified need, and a process for the regulator to review a robust estimate of the costs and determine an additional revenue allowance if required. Capital expenditure is added to the Regulatory Asset Base (RAB). Once in the RAB, it can earn a return of capital (depreciation, typically over 50-60 years for a major project) and a return on capital (to cover a blend of debt and equity financing for the expenditure). This guaranteed return helps the TNSP to obtain finance for its capital expenditure. The unusually high level of capital investment required for the transition is challenging this underlying assumption of financeability. Transgrid, the NSW TNSP, is particularly impacted as NSW’s position in the middle of the NEM means that most projects to strengthen the overall system pass through NSW. If all the relevant projects in the ISP went ahead in the timeframes suggested by AEMO, Transgrid would double its RAB in under a decade. Transgrid has already argued that it needs more flexibility than the rules currently allow to finance its share of Project EnergyConnect, the NSW-South Australia interconnector. The AEMC did not accept its arguments, and Transgrid eventually secured financing from the Clean Energy Finance Corporation (CEFC), the Federal Government’s “green bank”. The CEFC has a broader transmission funding program available for other projects.

Transmission for the transition Concerns about how to deliver a transmission system to support a low carbon electricity system have been around for some time. To address these concerns, Dr Alan Finkel’s Independent Review into the Future Security of the NEM recommended a “long-term integrated plan for the grid that establishes the optimal transmission network design to enable connection of renewable energy resources, including through inter-regional connections”. This proposal became the Integrated System Plan (ISP), first published by AEMO in 2018. The South West interconnected System (SWIS), the network that serves south-west Western Australia has its own Whole of System Plan (WoSP).

The Integrated System Plan The ISP focuses on proposing where major transmission investments should be made to strengthen the grid and enable new large-scale renewable investment. It does so by considering the optimal combination of generation and transmission capacity to meet a range of demand scenarios over a 20 year horizon. It models least cost systems but does not use market modelling to confirm that its proposed generation capacity will actually be commercially viable. The ISP is updated every two years. Figure 2 below shows AEMO’s latest view of how the NEM’s transmission grid should be upgraded to help the system transition to net zero emissions.

Transmission operators can use the ISP as a basis for proposing new investments to the AER, but each project must pass its own cost-benefit test. Energy market bodies have collaborated to streamline the transmission investment approval process in light of the many transmission projects emerging from the ISP. Critics still claim that the process takes too long: as Figure 2 above shows, the streamlined process still takes 18 months after publication of the ISP to gain regulatory approval for the project. Only at that point will the TNSP make its investment decision, and then the design, consultation and construction of the new asset can take several more years. Consumer advocates point out that consumers underwrite these projects, and the approval processes are there as an important check. They are broadly consistent with the recommendations of Infrastructure Australia for infrastructure development generally, including the need for detailed analysis of different options and independent review of the proposed project and its costs. Governments have tried to accelerate the process. The previous Federal Government funded early works that the TNSP would not otherwise be prepared to carry out as it waited on full approval. The rules have also been tweaked to allow TNSPs to stage projects and apply for early works separately. The current Federal Government has identified this as a priority issue and committed $20bn via its Rewiring the Nation policy to fund an accelerated rollout of transmission. Given that financing a project once it has been approved does not appear to be the major hurdle (see below for further discussions on financing) – and since the project will earn a guaranteed regulated return – it is not clear whether this policy will significantly accelerate the rollout.

prices overall). Interconnectors are only applicable to the NEM in Australia, as the SWIS lies entirely within Western Australia’s borders and does not have multiple regions. Interconnectors are paid for according to the same rules as the rest of the transmission network – customers in the state where the asset is built pay for it over several decades. But this allocation of costs depends on the geographical split of the assets and may not relate to how much each set of customers benefits through lower prices in their region. This is mitigated somewhat by interregional transmission use of system charges (IR-TUOS). AEMO looks at the net flows of each interconnector annually and allows the net exporting TNSP to charge the net importing TNSP (with flow on impacts for the consumers in each region). But this is only an approximation of the benefits as it relates only to the volume of the energy flows, not the value of the energy at the time of import/export or the price difference between regions. Because interconnectors have two-way flows and are ‘netted-off’, the IR-TUOS charges tend to be also very small compared to the true costs and benefits of interconnection.

In May 2021, the AER confirmed it would approve the build cost at $2.275bn. The TNSPs had already confirmed they would go ahead if approved and funding was obtained. Transgrid confirmed it had secured financing, thanks to the CEFC. Large amounts of change occurred in the five years from initial proposal to final sign-off. There is a lot of uncertainty about whether AEMO will continue to require two gas generators to run in South Australia with or without the interconnector. The South Australia system services that EnergyConnect was designed to support may be largely supplied by new synchronous condensers (built by ElectraNet) and various big batteries that have been installed on the South Australia grid. The energy plan for NSW looks designed to ensure NSW builds plenty of its own renewables and back-up capacity, which could impact the interconnector’s utilisation. Herein lies the challenge of building large new pieces of infrastructure in the NEM. There is a constantly moving target to chase when assessing the value of the investment.


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