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University of New South Wales Law Journal Student Series |
GEORGIA HALL
In July 2021, the Australian Energy Market Operator (‘AEMO’) set a goal of being able to handle 100% renewable energy on the National Electricity Market (‘NEM’) by 2025.[1] To do so, and to allow for an orderly and cost-effective energy transition, around A$23 billion of transmission infrastructure investment will be needed to accommodate the 50 gigawatts (‘GW’) of new large-scale wind and solar photovoltaic (‘PV’) generation (‘VRE’) expected to come online by 2040, as 16 GW of coal power capacity (61% of the coal fleet of the NEM) goes offline.[2] For the benefits of the transmission projects identified by AEMO to be realised in full, market reform will be necessary to ensure market participants are adequately incentivised to make timely and efficient investment.[3] In particular, new and augmented electricity interconnectors are key assets the NEM will increasingly rely on as the underlying energy mix changes.[4] The planning and building of new transmission infrastructure involves long lead times, regulatory scrutiny, and stakeholder engagement, which makes timely investment critical to facilitating the energy transition.[5] A failure to expand and modernise electricity networks to match VRE uptake “would almost certainly make the energy transition for net‐zero emissions impossible”.[6]
Most scholarship has focused on the role of law in Australia in incentivising renewable energy uptake by analysing instruments such as the Renewable Energy Target[7]. Limited research has been directed at understanding how the laws and regulations governing transmission in the NEM influence VRE penetration.[8] An underinvestment in greenfield transmission in Australia over the past decade is now emerging as a stumbling block for the energy transition, primarily due to market uncertainty owing to a lack of policy direction on energy and climate change and disparate transmission planning between state and federal governments.[9] Other residual factors – such as challenges with financeability, outdated approaches to cost allocation, and protracted regulatory approval processes – are also creating bottlenecks for investment.[10] The regulatory framework governing transmission in the NEM is struggling to respond in a timely manner[11] to the extent that the network configuration and investment signals no longer correspond with the underlying energy system conditions.[12]
This paper explores two barriers to timely and efficient investment in transmission infrastructure in the NEM; namely, the challenges of financing the scale and complexity of the projects identified by the AEMO Integrated System Plan (‘ISP’),[13] and, secondly, the need to allocate costs for interconnectors in a way that reflects the beneficiaries across the NEM. This paper proposes that the current regulatory framework governing financeability and cost allocation for transmission infrastructure must be revised as it is no longer fit-for-purpose for the NEM. Firstly, this paper highlights how timely transmission infrastructure investment is critical to the successful uptake of VRE. Secondly, the emerging issue of financeability for actionable ISP projects is discussed by using Project EnergyConnect – an interconnector being constructed between South Australia (‘SA’) and New South Wales (‘NSW’) – as an example of how the current regulatory approach to revenue recovery is creating challenges in the delivery of these capital-intensive projects for Transmission Network Service Providers (‘TNSPs’). Thirdly, this paper dissects the emerging challenges associated with the current transmission pricing approach to cost allocation for interconnector projects by using as a case study the Marinus Link Project – a proposed undersea and underground interconnector between Tasmania and Victoria. Examples of solutions implemented or being explored in other jurisdictions facing similar challenges with transmission investment are considered.
Despite suggestions that the 2016 blackouts in SA were caused by high levels of VRE penetration,[15] limited inter-regional transmission capacity and poor grid planning were critical drivers of the shutdown of the state’s electricity network.[16] On 28 September 2016, a major storm caused damage to transmission and distribution lines that led to multiple system faults and voltage disturbances and forced most of the state’s wind farms to shut down.[17] Operating thermal generators were unable to make up this shortfall quickly enough, leading to a rapid increase in power flow from Victoria into SA through the Heywood Interconnector to fill the void.[18] SA was only connected to Victoria via two interconnectors which could provide approximately 25% of the state’s peak load at the time.[19] This surge in power activated the automatic loss of the synchronism protection system and tripped the Heywood Interconnector, “islanding” SA from the rest of the NEM.[20] The state grid’s inability to meet demand combined with low inertia ultimately caused the remaining online generators to trip, leading to a state-wide blackout. [21]
The NEM is one of the most disperse and thinnest grids in the world, meaning there is a much lower density of alternative pathways when there is a failure event on a transmission line.[22] The Heywood Interconnector, commissioned in 1988, was one of the last major transmission projects commissioned in the NEM.[23] The process of developing a second point of connection between SA and NSW – which formally began three months after the SA blackout – has been protracted[24] with construction only starting in June 2021. The interconnector – known as Project EnergyConnect (‘EnergyConnect’) – was close to not proceeding due to challenges with financeability.
According to the International Energy Agency (‘IEA’), to reach net zero emissions by 2050, global investment in network infrastructure will need to increase from approximately US$260 billion today to US$820 billion (+215%) by 2030.[25] The need to augment and expand transmission and interconnector infrastructure – to accommodate VRE and improve network resilience and reliability – has been identified as a key challenge and priority over the coming decades.[26] Around A$23 billion will need to be invested in transmission over the next 20 years to accommodate a changing NEM.[27] Renewable energy support mechanisms have accelerated VRE uptake in Australia over the past decade, namely through the Large-Scale Renewable Energy Target,[28] supportive state laws and regulations,[29] and a declining Levelised Cost of Energy (LCOE) for VRE.[30] With the pace of the change running ahead of the AEMO’s fastest change scenario,[31] transmission hosting capacity is forecast to fall short of the amount of VRE expected to come online by 2030.[32]
The long lead times associated with the deployment of new infrastructure makes timely investment essential. If decisions are delayed or abandoned, NEM consumers will face increased costs and risks[33] and VRE will struggle to connect – potentially leading to under-investment in the generation capacity needed to fill the void left by exiting generators.[34] As more VRE is connected, inter-regional transmission will play an increasingly important role in allowing bidirectional flow between loads, providing trade and reliability across states while limiting the need to curtail VRE and invest in large amounts of peaking capacity.[35] Importantly, large generator trips would not be as catastrophic for one region because of their increased ability to import load from other regions,[36] as was needed in the SA blackout. Improved interconnection also allows different regions to benefit from one another’s diversity of VRE resources[37] – particularly renewable energy zones.[38]
AEMO’s “actionable” ISP projects[39] are forecast to cost between A$8.1 and A$15.1 billion over 2022-32 – an order of magnitude relative to current transmission regulatory asset bases (‘RAB’) in the NEM, which total A$21.4 billion.[40] The economic regulatory framework is creating new challenges for the timely and efficient delivery of ISP projects due to their unprecedented size and complexity combined with a lack of regulatory precedent.[41] Under the current framework, the Australian Energy Regulator (‘AER’) determines a maximum allowed revenue for TNSPs over a regulatory period[42] and adjusts the revenue allowance and therefore the Regulated Asset Base (‘RAB’) to account for inflation to ensure the target return remains constant in real terms (“indexation”).[43] TNSPs can then recover depreciation once an asset is commissioned and customers receive the benefits of the services, but not when capital expenditure is incurred.
EnergyConnect, a double-circuit interconnector being built between SA and NSW, offers a case study for whether the current economic regulatory framework is fit-for-purpose with regards to financeability[44]. As the first of the actionable ISP projects to be commissioned, the interconnector will increase transfer capacity between both states, deliver fuel cost savings, unlock already stranded renewable investments,[45] and reduce the risk of the SA grid being “islanded” from the NEM.[46] Both TransGrid and ElectraNet – the joint TNSPs for EnergyConnect – have flagged financeability as a stumbling block for the timely delivery of the project owing to both the indexation of the RAB[47] and the delay in revenue for depreciation to when an asset is commissioned.[48] These two aspects of the regulatory framework create a mismatch between when costs are incurred and revenue can be recouped.[49] According to TransGrid, its cashflows were insufficient to provide for the 60% debt funding at a BBB+ or investment grade credit rating over an extended period of time, whereby a A$2 billion project beginning in 2020 would not achieve benchmark credit rating under the existing regulatory framework until 2050.[50] Equally, analysis undertaken by Electranet shows a A$500 million project would not do so until 2055.[51] This means that the returns for EnergyConnect would be less than what the AER deems will attract investment in a benchmark efficient entity under the rate of return and revenue determination methodology for TNSPs.[52] The regulatory framework has not created financeability problems to date as a typical portfolio of assets would provide adequate revenue to support a benchmark credit rating[53] with inadequate cashflows from new projects counteracted by cashflows from existing assets.[54] However, both TNSPs believe this is no longer possible due to the size of ISP projects relative to their RAB alongside their already stretched capital expenditure programs.[55] Importantly, other TNSPs believe financeability will create investment bottlenecks for other ISP projects going forward.[56]
In May 2021, the Clean Energy Finance Corporation (‘CEFC’) “kick started” EnergyConnect with a A$295 million subordinated note instrument – on behalf of the Australian Government – to supplement private sector debt.[57] The note is the single largest investment made by the CEFC to date and comes six months after a A$125 million investment in the Snowy 2.0 grid.[58] The CEFC believes it will need to support other ISP projects in the future due to financeability challenges.[59] The governance framework of the NEM has been designed to support a liberalised electricity market of “privatization, deregulation... and a diminished public sphere”,[60] where the private sector is guided by market signals and incentive regulation.[61] The reality that EnergyConnect was only financially viable with support from the Government[62] undermines the premise of the NEM’s market-based governance framework where the public sphere acts “at a distance”[63] and is not involved in service delivery.[64] The emerging trend of government intervention to support the delivery of the ISP projects – through mechanisms such as the CEFC Grid Reliability Fund[65] – may seem like a logical solution, however, this brings into question whether the economic regulatory model is fit-for-purpose and regulatory adjustments are needed. For Rick Francis, CEO of Spark Infrastructure,[66] “the CEFC stepping in is a clear indication that the regulatory system and framework are not working”.[67]
Solutions to minimise financeability bottlenecks should be considered to ensure the security and reliability of the NEM, deliver consumer benefits, and support the energy transition. One possible approach would be, firstly, to remove the indexation of the RAB and, secondly, to change the deferral of revenue recovery for depreciation from when the investment is commissioned to the point of capital expenditure (on an “as incurred” basis).[68] Analysis undertaken by TransGrid shows that while a A$2 billion notional project with these adjusted features and 60% gearing would be unlikely to meet the benchmark credit rating (of BBB+) until around 2050, it would attain investment grade status much earlier than under existing rules and help secure the necessary capital to proceed in a timely manner.[69] Removing the aforementioned features would help overcome financeability barriers without increasing (i) the transmission costs recouped over a project’s life in present-value terms, (ii) the overall regulated return as allowed by the AER,[70] or (iii) the total costs borne by customers.[71]
For EnergyConnect, the total allowable revenue would be lower in absolute terms with these regulatory adjustments compared to the existing regime.[72] TransGrid estimates that NSW customers would pay an additional A$3 per household per year for the remaining years of its regulatory period if such a rule change went ahead for EnergyConnect,[73] however, this would be offset by the project’s estimated benefits of A$60 per annum.[74] Equally, SA customers would face an average A$5 increase in their annual electricity bill, but this would be outweighed by the estimated A$100 net price reductions from the project.[75] These changes would help align the revenue profile with customer benefits whilst improving inter-generational equity by reducing bill pressure on future generations.[77] Such changes would need to be made to the National Electricity Rules (‘NER’)[78] by the AEMC with the AER adjusting the roll-forward model and post-tax revenue model[79] to give effect to all ISP projects.
Similar adjustments have been made in other jurisdictions such as Transpower in New Zealand (‘NZ’), which experienced challenges with financing NZ$3 billion worth of transmission investments and thereby doubling its RAB.[80] In response, the NZ Commerce Commission endorsed a nominal return model for Transpower so the value of its assets could be brought forward without indexation.[81] Challenges associated with the financeability of large transmission projects in the US – particularly inter-regional infrastructure – have also been identified as an investment barrier for regional transmission organisations (‘RTOs’) across the country by the Multi-Sector Coalition Transmission (‘Coalition’). Various RTOs and renewable energy developers in the US believe an investment tax credit (‘ITC’) should be included in the draft 2021 Budget Reconciliation Legislation for regionally significant transmission.[82] The Coalition believes this “would give private capital the certainty it needs now to invest in the national, high-priority lines that will serve as the backbone for America’s clean energy grid”.[83] The use of ITCs to support transmission investment is well established in the US. For example, the Federal Energy Regulatory Commission (‘FERC’) is mandated to incentivise transmission investment to benefit customers.[84]
Formalising a tax credit program for ISP projects in Australia could offer a more standardised – as opposed to ad hoc and discretionary – platform to kick start projects whilst sharing the cost burden between customers and taxpayers. However, this approach would still undermine the NEM’s design for which the regulatory framework should, in principle, provide the right incentives to guide investment decisions without tax payer intervention. As the IEA points out, “some claim that market failures are inherent across the value chain in electricity markets requiring government intervention. But, upon closer scrutiny, many alleged failures turn out rather to be the result of regulatory failures.”[85]
While the NEL does not employ the term “financeability”, issues relating to financeability could impinge upon the ability of a TNSP to achieve the National Electricity Objective (‘NEO’)[86] – for example with the timely delivery of projects and/or the relevant revenue and pricing principles.[87] “Financeability” is recognised in other jurisdictions. In the UK,[88] the Office of Gas and Electricity Markets must carry out its functions having regard to “the need to secure that licence holders are able to finance the activities which are the subject of obligations imposed” to deliver on its principle objective to “protect the interests of existing and future customers”.[89] In the US, the Energy Policy Act (2005) requires FERC to “provide a return on equity that attracts new investment in transmission facilities (including related transmission technologies)”.[90] In the case of Australia, recognising “financeability” under the National Electricity Law (‘NEL’)[91] would help establish the concept in overarching law and shape the approach taken by the AEMC and AER along with the associated rules and guidance on revenue setting arrangements under the NER.[92]
Given the last greenfield interconnector in the NEM was built two decades ago,[93] it is worth considering whether the current pricing rules governing cost allocation are fit-for-purpose for ISP interconnector projects .[94] In November 2019, the Council of Australian Governments (‘COAG’) Energy Council asked the Energy Security Board (‘ESB’) to consider the charging arrangements for interconnectors, requesting “advice on a fair cost allocation methodology as part of its work to action the ISP”.[95] As such, this is now an area of reform being considered by the ESB post-2025 Market Design Project and the AEMC.[96] Indeed, the ISP process has “opened up an inevitable, and rather unedifying, fight between the states over how to divide the cost pie: each wanting the smallest slice”.[97]
There are two key aspects to cost allocation under the existing framework. Firstly, there is an initial cost allocation dictated by physical location of the interconnector[98] as part of the AER’s Aggregate Annual Revenue Requirement (‘AARR’) assessment undertaken in TNSPs’ revenue determinations.[99] Secondly, interconnectors employ a recharging mechanism between neighbouring regions – known as a Modified Load Export Charge (‘MLEC’) – to allocate costs according to inter-regional flows.[100] The MELC has been designed by the AEMC to allocate costs according to the ‘regional beneficiaries pay’ principle[101] by reflecting “the benefit derived by customers from costs incurred in a neighbouring transmission region”.[102] The aggregate effects of the MLEC tend to be minimal, however, because the MLEC reflects the proportionate use of the interconnector at periods of peak utilisation[103] and only 50% of each region’s shared network costs are subject to the MLEC.[104] This means that although interconnectors provide NEM-wide benefits, the question of “who pays?” is confined to two adjoining regions, thereby giving rise to questions of fairness and cost-effectiveness.[105]
The Marinus Link Project (‘Marinus Link’) – a proposed A$3.5 billion electricity connection between Tasmania and Victoria – offers a case study for how a mismatch between the allocation of costs and beneficiaries can occur.[106] Marinus Link is anticipated to improve grid stability, reduce wholesale electricity prices, and provide the NEM mainland with access to Tasmania’s lower cost, dispatchable renewable generation, and storage resources.[107] The interconnector is essential to achieving the Tasmanian Renewable Energy Target[108] while driving a A$3.2 billion reduction in wholesale electricity prices due to less reliance gas-fired generation.[109] Although Tasmanian customers would be minor beneficiaries (at around 6%) of Marinus Link through reduced wholesale prices (under the current rules) they would pay for a significant portion of the project alongside Victoria.[110] At the same time, NSW customers would not bear any costs for Marinus Link but would likely receive around 38% of the benefits through the current MELC mechanism.[111] If the initial cost allocation of the AARR does not mirror the beneficiaries, then it is unlikely the MELC will correct this mismatch because the mechanism only accounts for flows between two connecting regions and not to an interconnected NEM.[112] A similar mismatch can be seen in the case of EnergyConnect, where the costs of the interconnector will be borne by NSW and SA consumers despite Victorian consumers also receiving benefits.[113]
The initial feasibility study for Marinus Link[114] highlighted the need for timely, targeted, and proportionate reform of the regulatory framework governing cost allocation for interconnectors.[115] According to TasNetworks, the current pricing arrangements may lead to essential interconnector projects not proceeding, despite satisfying the Regulatory Investment Test for Transmission (‘RIT-T’).[116] Current arrangements would lead to outcomes that are not in customers’ best interests within a given region – as required by the NEO[117] – and would not give full effect to the ‘regional beneficiaries pay’ principle[118] as defined by the AEMC.[119] As an actionable ISP project subject to “decision rules”, progress with Marinus Link is now dependent on a pricing resolution as part of the work undertaken by the ESB and the AEMC.[120] At the time of writing, Marinus Link has reached an impasse, unable to finalise the RIT-T until a resolution is found,[121] while other TNSPs have indicated their support for cost allocation reform due to investment uncertainty.[122] Arguably, the current pricing framework fails to promote efficient and timely investment in interconnector ISP projects.[123]
A ‘beneficiaries pay’ principle is adopted in other jurisdictions. In its true sense, cost allocation arrangements have no regard for the location of an asset and are agreed ex ante rather than through network pricing arrangements such as long-run marginal cost pricing.[124] In 2011, FERC Order 1000 (‘Order 1000’) was enacted in the US to drive more efficient transmission investment. Order 1000 introduced a series of principles governing the cost allocation for new inter-regional transmission. The principles stipulate, inter alia, that (i) costs must only be allocated to those that benefit in a manner roughly commensurate with the estimated benefits (‘Beneficiaries Pay’);[125] (ii) those that receive no benefit, either at present or in a likely future scenario, must not be allocated any of those costs;[126] (iii) the cost allocation method and data for determining benefits and identifying beneficiaries must be transparent to inform stakeholders.[127]
Under Order 1000, the benefits of new transmission may relate to reliability, the sharing of reserves, cost savings, congestion relief and/or public policy requirements that drive transmission needs.[128] This position is less restrictive than Australia’s NEO – which is primarily concerned with economic efficiencies – and means that renewable energy and emissions reduction targets could, for example, be considered a benefit of inter-regional transmission.[129] The Beneficiaries Pay approach has been adopted across the US to allocate the costs of greenfield, higher value and/or voltage regulated transmission where the benefits are cost-related.[130] The costs for other types of benefits that are hard to quantify – such as reliability, congestion relief, and public policy benefits – are mostly subject to postage stamp-type methods such as total volume and peak demand.[131] The Beneficiaries Pay approach is well supported by economic theory[132] and offers one potential solution to the cost allocation conundrum for Marinus Link and future interconnectors subject to the RIT-T.[133]
In the case of Marinus Link, a Beneficiaries Pay approach in line with the principles of Order 1000 would allocate costs in a manner roughly commensurate with the estimated benefits irrespective of the interconnector’s location.[134] Taking a “roughly commensurate” approach is at odds with the NEM’s inter-regional pricing mechanisms, which attempt to allocate costs with precision between adjoining regions. Tasmanian customers who do not benefit from the project – at present or in the likely future – would not be allocated any costs while NSW and Queensland would not become “free riders”.[135] Under this model, the project proponent would be responsible for identifying the beneficiaries when evidencing the cost benefits through the RIT-T process. Importantly, engagement and dispute resolution provisions would be needed to ensure the cost benefit assessment is fair, reasonable, and efficient.[136] A key question, therefore, is how the regulated revenue allowance set by the AER should be recovered across regions, particularly as recovered costs only come from load customers and not all network beneficiaries.[137] As Hogan explains, “despite the common claim otherwise, the power flow model does not provide a good theoretical foundation for estimating benefits”.[138] In line with the NEO, customer benefits could also include estimated price reductions in ancillary services, wholesale generation price changes, and/or more reliable supply.[139]
The cost allocation approach set out by Order 1000 is not perfect. Its principles-based approach has allowed cost allocation methodologies to vary by project, thereby creating complexity.[140] Moreover, it provides no definition of transmission benefits and the associated minimum standards needed to support cost-benefit analysis.[141] These areas are currently being reviewed as part of a proposed rulemaking initiated in July 2021.[142] Nevertheless, Order 1000 has made headway in clarifying cost allocation issues since enactment.[143] Given the complexity of the US transmission network, the rule attempts to provide clarity to market participants while providing enough flexibility to develop cost allocation methodologies supported by stakeholders, reflective of regional circumstances, and specific to the benefits of a particular project.[144] Order 1000 was never intended to dictate how costs are to be allocated, but rather it leaves the details to transmission providers to determine in the planning processes.[145] Other jurisdictions, such as NZ, have replaced legacy inter-regional transmission charges[146] with benefit-based charges aligned to a Beneficiaries Pay model [147] in anticipation of the significant investment needed to support the energy transition and the need to better allocate costs according to benefit.[148] Unlike NZ, it would be more proportionate to apply such changes only to greenfield ISP projects while grandfathering existing pricing arrangements for brownfield assets in the NEM.[149]
The economic regulatory frameworks governing transmission infrastructure and pricing arrangements for interconnectors in the NEM are no longer fit-for-purpose. They are creating material barriers to the timely and efficient investment necessary to facilitate the energy transition, which is contributing to uncertainty amongst market participants. As the IEA explains, “appropriate market design is a key parameter in creating incentives for efficient transmission investment, particularly for interconnectors”, whereby “inappropriate regional pricing models ... can increase investment risks and create a potential barrier for investments”.[150] Liberalised electricity markets rely on effective price signals to market participants to incentivise and attract the requisite investment in infrastructure.[151] The issues encountered by EnergyConnect and Marinus Link reveal how features of the regulatory framework governing the NEM are contributing to uncertainty, delays, and risk that are hindering the successful delivery of these two critical projects. This delay is, in turn, undermining the NEO as customers are denied the estimated benefits of the projects in a timely manner. Equally, the current pricing arrangements for interconnector infrastructure means that some NEM customers could bear disproportionate costs relative to others who receive a higher proportion of the estimated benefits. The current regulatory framework takes an overly narrow and arbitrary view of an interconnected NEM that relies on infrastructure with benefits beyond load that extend beyond two adjoining regions.
Whilst financeability and cost allocation have not historically been investment impediments, it is worth noting that there has been a underinvestment in greenfield transmission over the past 20 years and these barriers have only become apparent recently. Transmission pricing reform and opportunities to provide better customer outcomes have frequently been “thwarted by an unrealistic ambition to implement ‘perfect’ solutions”.[152] With the AEMC reviewing transmission planning and investment frameworks and the ESB’s Post-2025 Market Design project underway, now is an appropriate time to review financeability and cost allocation for ISP projects. As a market-led liberalised electricity market, it is important to consider the role of the government in intervening with investment for actionable ISP projects – whether this is due to a failure of the regulatory framework or an appropriate long-term solution to financeability. Postponing regulatory change while waiting for evidence of a failure in the existing framework presents significant risks to the NEM, the realisation of the NEO, and the energy transition. The historical performance of the regulatory regime is no longer a marker of future success given the changing scale and complexity of transmission projects needed.
[1] AEMO oversees wholesale electricity market and transmission network planning in Australia as per National Electricity (South Australia) (National Electricity Law – Australian Energy Market Operator) Amendment Act 2009 (SA) pt 5 div 1 s 49(2); Australian Energy Market Operator (‘AEMO’), ‘AEMO CEO Daniel Westerman’s CEDA Keynote Address: ‘A View from the Control Room’’, AEMO Newsroom (Speech, July 2021) <https://aemo.com.au/en/newsroom/news-updates/the-view-from-the-control-room>.
[2] Australian Energy Regulator (‘AER’), ‘State of the Energy Market (2021)’, AER (Report, 2021) 6 <https://www.aer.gov.au/system/files/State%20of%20the%20energy%20market%202021%20-%20Full%20report.pdf>; FTI Consulting, ‘Assessing the Benefits of Interconnectors: A Report for TransGrid’, AER (Report, October 2020) 3 <https://www.aer.gov.au/system/files/TransGrid%20-%20A.11A%20-%20FTI%20PEC%20-%20Wider%20Benefits%20Report%20-%20September%202020.pdf>; cite AEMO ISP 2020.
[3] Australian Energy Market Operator (‘AEMO’), ‘2020 Integrated System Plan for a National Electricity Market’, AEMO (Report, July 2020) 8 <https://aemo.com.au/-/media/files/major-publications/isp/2020/final-2020-integrated-system-plan.pdf?la=en&hash=6BCC72F9535B8E5715216F8ECDB4451C>.
[4] FTI Consulting (n2) 7; Penelope Crossley, ‘Renewable Energy Law in the Context of a Transforming Australian Energy Market’ in Tina Hunter et al (eds), Routledge Handbook of Energy Law (Routledge, 2020) 481.
[5] Eric Larson et al, ‘Net-Zero America: Potential Pathways, Infrastructure, and Impacts’, Princeton University (Report, 15 December 2020) 269 <https://netzeroamerica.princeton.edu/img/Princeton_NZA_Interim_Report_15_Dec_2020_FINAL.pdf>.
[6] International Energy Agency (‘IEA’), ‘Net Zero by 2050: A Roadmap for the Global Energy Sector’, IEA (Report, May 2021) 180 <https://iea.blob.core.windows.net/assets/beceb956-0dcf-4d73-89fe-1310e3046d68/NetZeroby2050-ARoadmapfortheGlobalEnergySector_CORR.pdf>
[7] Legislated through the Renewable Energy (Electricity) Act 2000 (Cth).
[8] Anne Kallies, ‘A Barrier for Australia’s Climate Commitments? Law, the Electricity Market and Transitioning the Stationary Electricity Sector’ (2016) 39(4) University of New South Wales Law Journal 1550; Lee Godden and Anne Kallies, ‘Electricity Network Development: New Challenges for Australia’ in Martha Roggenkamp et al (eds) Energy Networks and the Law (Oxford University Press, 2012) 294.
[9] Anne Kallies, ‘The Australian Energy Transition as a Federalism Challenges: (Un)cooperative Energy Federalism?’ (2021) 10(2) Transnational Environmental Law 211.
[10] Energy Security Board (‘ESB’), ‘ESB Post 2025 Market Design Options – a Paper for Consultation (Part B)’, ESB (Paper, 30 April 2021) 88 <https://esb-post2025-market-design.aemc.gov.au/32572/1619564172-part-b-p2025-march-paper-appendices-esb-final-for-publication-30-april-2021.pdf>.
[11] Kallies (n9) 211.
[12] ESB (n12) 75.
[13] Note the AEMO ISP is not binding on network businesses as per National Electricity Amendment (Integrated System Planning) Rule 2020. See National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 5 r 22.1.
[14] Nick Aberle quoted in Mini Perkins, ‘'From Sunny North to Windy East': What are Victoria's Renewable Energy Zones?’, The Sydney Morning Herald (Article, 26 November 2020) <https://www.smh.com.au/national/victoria/from-sunny-north-to-windy-east-what-are-victoria-s-renewable-energy-zones-20201125-p56hsl.html>.
[15] Ketan Joshi, ‘ABC News Interview with Senator Nick Xenophon’ (YouTube, 26 September 2016) <https://www.youtube.com/watch?v=fy6c-PD6InA>; Michael Slezak, ‘South Australia's blackout explained (and no, renewables aren't to blame)’, The Guardian (Article, September 2016) <https://www.theguardian.com/australia-news/2016/sep/29/south-australia-blackout-explained-renewables-not-to-blame>; Andrew King et al, ‘What Caused South Australia’s State-wide Blackout?’, The Conversation (Article, September 2016) <https://theconversation.com/what-caused-south-australias-state-wide-blackout-66268>.
[16] Matthew Warren, Blackout (Affirm Press, 2019) 2; Slezak (n15); Australian Energy Regulator (‘AER’), ‘The Black System Event Compliance Report: Investigation into the Pre-event, System Restoration, and Market Suspension Aspects Surrounding the 28 September 2016 Event’, AER (Report, 2018) 13 <https://www.aer.gov.au/system/files/Black%20System%20Event%20Compliance%20Report%20-%20Investigation%20into%20the%20Pre-event%20System%20Restoration%20and%20Market%20Suspension%20aspects%20surrounding%20the%2028%20September%202016%20event.pdf>.
[17] AER (n16) 13.
[18] Ibid.
[19] Warren (n16) 78.
[20] AER (n16) 13.
[21] Australian Energy Regulator (‘AER’), ‘Investigation Report into South Australia's 2016 State-wide Blackout’, AER (Webpage, December 2018) <https://www.aer.gov.au/wholesale-markets/compliance-reporting/investigation-report-into-south-australias-2016-state-wide-blackout>.
[22] King et al (n15).
[23] Aside from the Queensland-NSW Interconnector, built in 2001.
[24] ElectraNet released a Project Specification Consultation Report in November 2016.
[25] IEA (n6) 21.
[26] AEMO (n3) 8; Infrastructure Victoria, ‘Victoria’s Infrastructure Strategy 2021-2051’, Government of Victoria (Report, August 2021) 18 <https://www.infrastructurevictoria.com.au/wp-content/uploads/2021/08/1.-Victorias-infrastructure-strategy-2021-2051-Vol-1.pdf>; New South Wales (‘NSW’) Department of Planning and Environment, ‘NSW Transmission Infrastructure Strategy’, Government of NSW (Overview, 2018) 1-20 <https://www.energy.nsw.gov.au/sites/default/files/2018-11/DPE8754%20NSW%20Transmission%20Infratructure%20Strategy_WEB.ACC_.PDF>/
[27] AEMO (n3) 8.
[28] Legislated through the Renewable Energy (Electricity) Act 2000 (Cth).
[29] Such as Renewable Energy (Jobs and Investment) Act 2017 (Vic), Energy Co-ordination and Planning Amendment (Tasmanian Renewable Energy Target) Act 2020 (Tas), Electricity Infrastructure Investment Act 2020 (NSW).
[30] Lazard, ‘Lazard’s Levelized Cost of Energy Analysis – Version 14.0’, Lazard (Report, October 2020) 9 <https://www.lazard.com/media/451419/lazards-levelized-cost-of-energy-version-140.pdf>.
[31] Angela MacDonald-Smith, ‘AEMO’s New challenge: 100pc Renewables by 2025’, The Australian Financial Review (Article, 13 July 2021) <https://www.afr.com/companies/energy/aemo-s-new-challenge-100pc-renewables-by-2025-20210712-p5891j#:~:text=The%20national%20power%20market%20operator,cost%20wind%20and%20solar%20generation>.
[32] Energy Security Board (‘ESB’), ‘Post 2025 Market Design Options – a Paper for Consultation (Part A)’, ESB (Paper, April 2021) 75 <https://esb-post2025-market-design.aemc.gov.au/32572/1619564199-part-a-p2025-march-paper-esb-final-for-publication-30-april-2021.pdf>.
[33] AEMO (n3) 26, 64.
[34] AEMO (n3) 13.
[35] Infrastructure Victoria (n26) 38; Tom Geisler, ‘Two Wrongs Don’t Make a REZ’, WattClarity (Article, July 2021) <https://wattclarity.com.au/articles/2021/07/two-wrongs-dont-make-a-rez>.
[36] Geisler (n35).
[37] TasNetworks, ‘Discussion Paper: “Beneficiaries Pay: Pricing Arrangements for New Interconnectors’, TasNetworks (Paper, December 2019) 5 <https://www.marinuslink.com.au/wp-content/uploads/2019/12/attachment-3-cost-allocation-discussion-paper.pdf>.
[38] IEA (n6) 179; Geisler (n35).
[39] Pursuant to National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 5 r 16A.
[40] Australian Energy Regulator (‘AER’), ‘AER Work Program to Support Efficient Delivery if Actionable ISP Projects – Stakeholder Views Sought’, AER (Letter, 17 November 2020) 1-2 <https://www.aer.gov.au/system/files/AER%20-%20Work%20program%20letter%20-%20Regulation%20of%20large%20transmission%20projects%20-%20November%202020.pdf>.
[41] AER (n40) 1-2; AER, ‘Guidance Note: Regulation of Actionable ISP Projects’, AER (Guidance, March 2021) 1 <https://www.aer.gov.au/system/files/AER%20-%20Final%20Guidance%20note%20-%20Regulation%20of%20actionable%20ISP%20projects%20-%20March%202021%20-%20FINAL%20FOR%20PUBLICATION%2812129318.1%29.pdf>.
[42] By using four “building blocks”. See National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 6A r 5.4. The rate of return instrument is set out under National Electricity (South Australia) Act 1996 (SA) pt 3 div 1B sub-div 2 s 18I(3)(5).
[43] Australian Energy Regulator (‘AER’), ‘Final Position: Regulatory Treatment of Inflation’, AER (Paper, December 2020) 9 <https://www.aer.gov.au/system/files/AER%20-%20Final%20position%20paper%20-%20Regulatory%20treatment%20of%20inflation%20-%20December%202020.pdf>.
[44] “Financeability” relates to the willingness of investors to extend equity or debt to a TNSP to finance its business activities.
[45] AEMO (n3) 61.
[46] Clean Energy Finance Corporation (‘CEFC’), ‘Historic CEFC investment to kickstart nation building Project EnergyConnect’, CEFC (Media Release, 31 May 2021) <https://www.cefc.com.au/media/media-release/historic-cefc-investment-to-kickstart-nation-building-project-energyconnect>; AEMO (n3) 61.
[47] Inflation is compensated for by deducting the forecast CPI indexation from the revenue determination. See National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 6A r 4.2(a)(4) and r 5.4(a)(1)(b)(1). TransGrid, ‘Rule Change Proposal – Making ISP Projects Financeable’, AEMC (Proposal, 30 September 2020) 5 <https://www.aemc.gov.au/sites/default/files/2020-10/New%20Rule%20Change%20Proposal%20-%20National%20Electricity%20Rules%20-%20TransGrid%20-%20Making%20ISP%20projects%20financeable%20-%2020200930.PDF>.
[48] TransGrid (n47) 1. “As-commissioned depreciation” is a result of the roll forward and post-tax revenue models adopted by the National Electricity Rules and determined by the AER as per National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 6A r 6.3. See ch 6A r 6.1(b)-(e) for roll forward model and ch 6A r 5 for post-tax revenue model.
[49] TransGrid (n47) 3.
[50] TransGrid (n47) 1.
[51] ElectraNet, ‘Participant Derogations: Financeability of ISP Projects – ElectraNet Submission’, AEMC (Submission, 3 December 2020) 9-10 <https://www.aemc.gov.au/sites/default/files/documents/rule_change_submission_-_erc0320_-_electranet_-_20201203.pdf>.
[52] TransGrid (n47) 1.
[53] ElectraNet (n51) 9-10; TransGrid (n47) 6.
[54] ElectraNet (n51) 2.
[55] For example, excluding Project EnergyConnect, the average size of ElectraNet’s projects was approximately A$25 million with few projects exceeding A$50 million over the 2019/20 period. Project EnergyConnect is A$471 million (2017-18); the Eyre Peninsula Reinforcement is A$283 million (2017-18); and the Main Grid System Strength project is A$183 million ($2017-18). TransGrid estimates the total investment required to deliver its share of ISP projects to be between A$9 to 10 billion over the next ten years. See TransGrid (n47) 9 and ElectraNet (n51) 2, 8-10.
[56] TasNetworks, ‘Financeability of Integrated System Plan Projects’, AEMC (Submission, 3 December 2020) 2 <https://www.aemc.gov.au/sites/default/files/2020-12/Rule%20change%20submission%20-%20ERC0320%20-%20TasNetworks%20-%2020201203_0.PDF>.
[57] Clean Energy Finance Corporation (‘CEFC’), ‘Historic CEFC investment to Kickstart Nation Building Project EnergyConnect’, CEFC (Media Release, 31 May 2021) <https://www.cefc.com.au/media/media-release/historic-cefc-investment-to-kickstart-nation-building-project-energyconnect>.
[58] CEFC (n57); CEFC, ‘CEFC and TransGrid Services in Landmark Investment to Support Snowy 2.0 Grid Development’, CEFC (Media Release, 27 November 2020) <https://www.cefc.com.au/media/media-release/cefc-and-transgrid-services-in-landmark-investment-to-support-snowy-2-0-grid-development>.
[59] Chanticleer, ‘TransGrid’s $2.28b Plan to Keep Flawed NEM Alive’, The Australian Financial Review (Article, 1 June 2021) <https://www.afr.com/chanticleer/transgrid-s-2-28b-plan-keeps-flawed-nem-alive-20210531-p57wkz>.
[60] John Braithwaite, Regulatory Capitalism: How it Works, Ideas for Making it Work Better (Edward Elgar, 2008) 5.
[61] Rather than rate of return or cost of service regulation. See Kallies (n8) 1563; Australian Government Productivity Commission, ‘Electricity Network Regulatory Framework: Productivity Commission Inquiry Report Vol 1)’, Australian Government Productivity Commission (Report, 9 April 2013) 93, 129 <https://www.pc.gov.au/inquiries/completed/electricity/report/electricity-volume1.pdf>.
[62] TransGrid, ‘Submission to the Energy Security Board’s Post 2025 Market Design Options Paper’, TransGrid (Submission, 9 June 2021) 4 <https://energyministers.gov.au/sites/prod.energycouncil/files/publications/documents/92.%20TransGrid%20Response%20to%20P2025%20Market%20Design%20Consultation%20Paper_0.pdf>.
[63] See Kallies (n8) 1563 and (n9) 224-225; David Osborne and Ted Gaebler, Reinventing Government: How the Entrepreneurial Spirit is Transforming the Private Sector (Plume, 1993) 25.
[64] Kallies (n8) 1563.
[65] Such as the A$1 billion Grid Reliability Fund. See Department for Industry, Science, Energy and Resources, ‘Grid Reliability Fund’, Australian Government (Article, 30 October 2019) <https://www.energy.gov.au/government-priorities/energy-programs/grid-reliability-fund>; Department for Industry, Science, Energy and Resources, ‘Technology Investment Roadmap: First Low Emissions Technology Statement – 2020’, Australian Government (Statement, 2020) 32 <https://www.industry.gov.au/sites/default/files/September%202020/document/first-low-emissions-technology-statement-2020.pdf>.
[66] Spark Infrastructure owns approximately 15% of TransGrid as at 30 June 2021.
[67] Chanticleer (n59).
[68] TransGrid (n47) 4.
[69] TransGrid (n47) 5.
[70] Ibid.
[71] TransGrid (n47) 7.
[72] ElectraNet (n51) 2.
[73] As at September 2020.
[74] FTI Consulting (n2) 13.
[75] ElectraNet (n51) 14.
76 As at September 2020.
[77] ElectraNet (n51) 1-2, 14; TransGrid (n47) 1; Gareth Davies, ‘Climate Change and Reversed Intergenerational Equity: the Problem of Costs Now, for Benefits Later’ (2020) 10(3-4) Climate Law 266-281.
[78] For example under National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 6A r 4.1, 6.3
[79] As is allowable under National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 6A r 6.1(c), 5.2(b).
[80] New Zealand Commerce Commission (‘NZCC’), ‘Input Methodologies (Transpower): Reasons Paper’, New Zealand Commerce Commission (Paper, December 2010) 30 <https://comcom.govt.nz/__data/assets/pdf_file/0026/63890/Transpower-Input-Methodologies-Reasons-Paper-Dec-2010.pdf>.
[81] NZCC (n79) 30-31; TransGrid (n47) 7; ElectraNet (n51) 12.
[82] Multi-Sector Coalition Transmission, ‘Investment Tax Credit Letter to House Ways and Means Committee’, Americans for a Clean Energy Grid (Letter, 11 August 2021) <https://cleanenergygrid.org/wp-content/uploads/2019/04/Multi-Sector-Coalition-Transmission-ITC-Letter-to-WM-Commmittee-8-11-21.pdf>.
[83] Multi-Sector Coalition Transmission (n81).
[84] Energy Policy Act of 2005 42 USC §13201 et seq. s 219(b)(1), (c) (2005)
[85] International Energy Agency (‘IEA’), ‘Lessons from Liberalised Electricity Markets’, IEA (Report, 2005) 16 <https://www.iea.org/reports/lessons-from-liberalised-electricity-markets>.
[86] National Electricity (South Australia) Act 1996 (SA) s 7. See Kallies (n8) 1564.
[87] National Electricity (South Australia) Act 1996 (SA) s 7.
[88] Excluding Northern Ireland pursuant to Utilities Act 2000 (UK) c 27 s 4.
[89] Electricity Act 1989 (UK) pt 1 s 3A(1-2). See Office of Gas and Electricity Markets (‘OFGEM’), ‘Financeability Assessment for RIIO-2: Further Information’, OFGEM (Report, 26 March 2019) 5 <https://www.ofgem.gov.uk/publications/financeability-assessment-riio-2-further-information>.
[90] Energy Policy Act of 2005 42 USC §13201 et seq. s 219(b)(2) (2005).
[91] National Electricity (South Australia) Act 1996 (SA).
[92] National Electricity Rules (Cth) (Version 171, 1 September 2021).
[93] The Queensland-NSW Interconnector was built in 2001.
[94] AEMC, ‘Final Report on the Coordination of Generation and Transmission Investment’ AEMC (Report, 21 December 2018) para 40 <https://www.aemc.gov.au/sites/default/files/2018-12/Final%20report_0.pdf>.
[95] COAG Energy Council, ‘Meeting Communique: Twenty-second Energy Council Meeting’, COAG Energy Council (Communique, 22 November 2019) 2 <https://energyministers.gov.au/sites/prod.energycouncil/files/publications/documents/EC%20-%20Final%20Communique.pdf>.
[96] ESB (n12) 75-76, 78-79; COAG Energy Council (n94) 2.
[97] Ben Skinner, ‘Which State Pays for Interconnectors?’, Australian Energy Council (Article, 1 October 2020) <https://www.energycouncil.com.au/analysis/which-state-pays-for-interconnectors/#:~:text=Beneficiaries%20pay&text=The%20Tasmanian%20Government's%20view%20is,pay%20much%20less%20than%20half>.
[98] See National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 6A r 23.3.
[99] Ibid ch 6A r 22.1.
[100] As per (n97) ch J r 6A.29A; Australian Energy Regulator (‘AER’), ‘Transmission Network Services Providers: Pricing Methodology Guidelines’, AER (Guidelines, July 2014) <https://www.aer.gov.au/system/files/AER%20-%20Transmission%20pricing%20methodology%20guidelines%20-%2017%20July%202014_4.pdf>; Skinner (n96); TasNetworks (n37) 7.
[101] Australian Energy Market Commission (‘AEMC’), ‘Rule Determination: National Electricity Amendment (Inter-regional Transmission Charging) Rule 2013’, AEMC (Rule Determination, 28 February 2013) ch 6 s 2 <https://www.aemc.gov.au/sites/default/files/content/e262eb5c-1572-4154-b14d-6afcb83f1d1f/Final-determination.pdf>; AEMC (n93) ch 7 paras 6 3.3-4.
[102] Ibid.
[103] This can lead to modest net charges between regions if both have similar peak import volumes at different points in the day. See National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 6A r 29A.2.
[104] National Electricity Rules (Cth) (Version 171, 1 September 2021) ch 6A r 29A.2(a)(1).
[105] Skinner (n96).
[106] Blake Matich, ‘Marinus Link Bolstered by New Reports Attesting its Potential Benefit Across NEM, But Who Should Pay?’, PV Magazine (Article, 29 June 2021) <https://www.pv-magazine-australia.com/2021/06/29/marinus-link-bolstered-by-new-reports-attesting-its-potential-benefit-across-nem-but-who-should-pay/>; Marinus Link, ‘Marinus Link a Priority Project According to AEMO’s Integrated System Plan 2020’, Marinus Link (Media Release, 30 July 2020) < https://www.marinuslink.com.au/2020/07/media-release-marinus-link-a-priority-project-according-to-aemos-integrated-system-plan-2020/>.
[107] FTI Consulting and TasNetworks, ‘Wholesale Pricing Report: How do customers benefit from Project Marinus?’, TasNetworks (Report, June 2021) 3-7 <https://www.marinuslink.com.au/wp-content/uploads/2021/06/Wholesale-Pricing-Report-How-do-customers-benefit-from-Project-Marinus.pdf>; EY and TasNetworks, ‘RIT-T Project Assessment Conclusions Report’, Marinus Link (Report, June 2021) 18-20 <https://www.marinuslink.com.au/wp-content/uploads/2021/06/Project-Marinus-RIT-T-PACR.pdf>.
[108] AEMO (n3) 62; see Energy Co-ordination and Planning Amendment (Tasmanian Renewable Energy Target) Act 2020 (Tas).
[109] As modeled over a 2020 to 2040 time period. FTI Consulting and TasNetworks (n106) 13.
[110] FTI Consulting and TasNetworks (n106) 6.
[111] Ibid.
[112] TasNetworks (n37) 11.
[113] TransGrid, ‘Submission to the Energy Security Bord’s Post 2025 Market Design Options Paper’, TransGrid (Submission, 9 June 2021) 6 <https://energyministers.gov.au/sites/prod.energycouncil/files/publications/documents/92.%20TransGrid%20Response%20to%20P2025%20Market%20Design%20Consultation%20Paper_0.pdf>.
[114] TasNetworks, ‘Project Marinus Link: Initial Feasibility Study’, TasNetworks (Study, February 2019) <https://www.marinuslink.com.au/wp-content/uploads/2019/02/Initial-Feasibility-Report-Project-Marinus-Feb-2019.pdf>.
[115] TasNetworks (n37) 4.
[116] Ibid.
[117] National Electricity (South Australia) Act 1996 (SA) s 7.
[118] TasNetworks (n37) 14.
[119] AEMC (n100) ch 6 s 2.
[120] FTI Consulting and TasNetworks (n106) 13, 16-17.
[121] At the time of writing, the National Cabinet Energy Reform Committee has not initiated a rule change.
[122] TransGrid (n12) 6.
[123] TasNetworks (n37) 7.
[124] See William W. Hogan, ‘A Primer for Transmission Benefits and Cost Allocation’ (2018) 7(1) Economics of Energy & Environmental Policy 25-45.
[125] FERC Order No. 1000 ‘Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities’, 136 FERC § 61,051, para 587(1) (21 July 2011).
[126] Ibid para 587(2).
[127] Ibid para 587(5).
[128] Ibid para 587(1).
[129] Kallies (n8) 1561.
[130] For example, the New York ISO, Midcontinent ISO, and JPM Interconnection. Electricity Authority of New Zealand, ‘Beneficiaries-pay in USA: Discussions on Implementation of Beneficiaries-pay Cost Allocation for Transmission Investment’, Government of New Zealand (Report, 20 June 2018) iii <https://www.ea.govt.nz/assets/dms-assets/25/25122Beneficiaries-pay-in-USA-joint-report.pdf>.
[131] ‘Postage stamp’ is a method of cost allocation that disregards location, for example, the allocation could be based on a measure of each region’s size such as total volume and peak demand over a defined period.
[132] Hogan (n123) 25-45.
[133] TasNetworks (n37) 21-29.
[134] FERC Order No. 1000 (n124) para 587(1).
[135] FERC Order No. 1000 (n124) para 587(2).
[136] TasNetworks (n37) 24.
[137] Revenue recovery is undertaken with respect to each TNSP’s pricing methodology, which is conditional on the AER’s approval in the respective revenue determination.
[138] Hogan (n123) 26.
[139] As defined by the Values of Customer Reliability set by the AER. See AER, ‘Values of Customer Reliability: Final Report on VCR’, AER (Final Report, December 2020) <https://www.aer.gov.au/communication/values-of-customer-reliability-adjusted-for-2020>.
[140] Rob Gramlich and Jay Caspary, ‘Planning for the Future: FERC’s Opportunity to Spur More Cost-Effective Transmission Infrastructure’, Americans for a Clean Energy Grid (Paper, January 2021) 58 <https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf>.
[141] Ibid 58-59.
[142] Federal Energy Regulatory Commission (‘FERC’), ‘Joint Statement from Chairman Glick & Commissioner Clements on Building Transmission for the Future’, FERC (Statement, 15 July 2021) <https://www.ferc.gov/news-events/news/joint-statement-chairman-glick-commissioner-clements-building-transmission-future>.
[143] Gramlich and Caspary (n139) 58.
[144] Ibid.
[145] South Carolina Public Service Authority v Federal Energy Regulatory Commission, 12-1232 68, V. (DC Cir, 2014) <https://www.cadc.uscourts.gov/internet/opinions.nsf/9642B5B52A1B402785257D350052548A/%24file/12-1232-1507702.pdf>.
[146] The Regional Coincident Peak Demand and the High Voltage Direct Current charges.
[147] Electricity Authority of New Zealand, ‘Transmission Pricing Methodology (‘TPM’) 2020 Guidelines and Process for Development of a Proposed TPM’, Electricity Authority of New Zealand (Decision, 10 June 2020) i, v <https://www.ea.govt.nz/assets/dms-assets/26/26851TPM-Decision-paper-10-June-2020.pdf>.
[148] Ibid.
[149] RNZ, ‘Power Price Shuffle Means Fairer Prices, Lower Emissions - Electricity Authority’, RNZ (Article, 10 June 2020) <https://www.rnz.co.nz/news/business/418693/power-price-shuffle-means-fairer-prices-lower-emissions-electricity-authority>; TasNetworks (n37) 19-21.
[150] IEA (n84) 146.
[151] Ibid.
[152] TasNetworks (n37) 4.
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