Government support for renewables financing: the future for VRET, LTESAs, CISAs, the FERM, RETAs and the proposed ESEM

This article addresses two central questions: how effective are existing government support programs for renewables financing – CISAs and LTESAs – in achieving their intended purpose, and will the proposed Electricity Services Entry Market help address ongoing financing challenges.

It begins by examining the current landscape of government underwriting of renewables, outlining why and how government support has been provided, how these programs were intended to operate, and how they have worked in practice. The discussion then turns to efforts by the Commonwealth and the States to harmonise and streamline their respective schemes, before concluding with an analysis of the proposed Electricity Services Entry Mechanism and its potential role in the next phase of market reform.

Why do Governments provide support for renewables financing?

Australia’s renewable energy transition is constrained not by a shortage of sun, wind or capital, but by the multiple market and economic obstacles which make getting projects to financial close hard.

Australia's energy-only National Electricity Market (NEM) was not designed to support investment in new, capital-intensive renewables. It was conceived in the 1990s to optimise dispatch and competition among existing coal and gas generators, a goal it largely achieved in an era of abundant thermal capacity and relatively modest new-build investment needs.

Volatile spot prices leave lenders unable to predict future cashflows over the long term with confidence. Long-term power purchase agreements (PPAs), the traditional solution, have become hard for developers to secure. Retailers and corporates now favour short-term flexibility and resist locking in long-term prices high enough to recover capital and returns for renewable developers and investors.

The result is that even projects with a low levelised cost of energy (LCOE) often struggle to secure finance. In an energy-only market as volatile as the NEM, revenue uncertainty can render otherwise competitive projects effectively unbankable.

In response, the Victorian, NSW and Commonwealth Governments introduced a series of targeted market corrections to restore investment confidence:

• In 2017, Victoria established the Victorian Renewable Energy Target (VRET) support agreements.
  
  

• In 2020, NSW created Long-Term Energy Service Agreements (LTESAs) under its Electricity Infrastructure Roadmap.

• In 2022, the Commonwealth launched the Capacity Investment Scheme (CIS) and Capacity Investment Scheme Agreements (CISAs).

These mechanisms were designed as limited, market-based interventions to stabilise project revenues and unlock private capital. Rather than offering outright subsidies, they function as revenue insurance instruments structured somewhat like contracts for difference (CfDs): developers nominate an eligible share of project output and bid both a floor and a ceiling. When wholesale prices fall below the floor, the government makes up the shortfall; when prices exceed the ceiling, the project pays the excess to the government. This two-way design aims to keep the schemes fiscally neutral and politically sustainable.

How were the VRET, LTESAs, and CISAs intended to work?

While differing in tenor, governance and design, all three instruments have some similarities to CfDs:

• VRET Support Agreements offered 15-year terms under VRET 1 in 2017 and 10-year terms under the 2021–22 VRET 2 auctions. They applied only to new large-scale generation (not storage) and have now been effectively superseded by CISAs.

• LTESAs are option contracts of up to 20 years for projects in (or dispatching into) NSW. They allow projects to call on government support when market revenues fall below a strike price. LTESAs are awarded through competitive tenders run by the Consumer Trustee (AusEnergy Services Ltd, formerly AEMO Services) and target generation, long-duration storage and firming.

• CISAs provide a continuous floor-and-ceiling arrangement for up to 10 years, covering generation or storage capacity, with cost-sharing between federal and state governments. The Commonwealth Department of Climate Change, Energy, the Environment and Water administers all CISAs, with AEMO conducting auctions on its behalf, typically in coordination with the relevant state authority.

Both LTESAs and CISAs were conceived as revenue-neutral mechanisms, designed to provide downside protection when market prices fall below a floor and to return value to the public when prices exceed a ceiling. For many projects, an LTESA or CISA has become the preferred route to financial close, as traditional PPAs have grown scarce.

How have LTESAs and CISAs worked in practice?

Outcomes have been mixed.

The first LTESA tenders were heavily oversubscribed, signalling strong market appetite but driving strike prices to unsustainably low levels. Some floor prices were assessed by lenders as insufficient to support debt sizing, and in several cases the LTESA offered limited credit enhancement value, functioning more as a signalling tool than effective revenue protection.

As project costs rose beyond bid assumptions and financing tightened, financial close was delayed across many projects. In response, the Consumer Trustee shifted its evaluation focus from headline price to deliverability, recognising that excessive competition meant some successful CISA bids may prove unbankable under prevailing cost and revenue conditions.

The CIS has scaled rapidly, targeting about 40 GW of new renewable generation and storage by 2030. Yet progress from award to financial close has been slow. By late 2025, only part of CIS Tender 1 had achieved financial close, though later rounds show stronger progression. Oversubscription again prompted aggressive bidding, with some proponents offering minimal floor prices in anticipation of future cost reductions or refinancing. The Commonwealth’s reserve-list mechanism, allowing second-ranked projects to proceed if initial awardees stall, reflects awareness that some winning bids may not be commercially viable.

Despite this, the CIS has generated substantial momentum, especially in storage. BESS projects have advanced more quickly than generation-only assets, and solar-plus-storage hybrids dominated Tender 4 (about 6.6 GW of awards announced on 9 October 2025). This highlights a clear investor preference for firming-capable capacity aligned with system needs.

However, if wholesale electricity prices remain below or only marginally above the levelised cost of energy (as estimated in the CSIRO and AEMO GenCost 2025-26 report) many proposed projects would generate revenues insufficient to achieve bankable returns or recover capital and financing costs. In these conditions, payments flow predominantly from government to generators, with limited clawbacks, risking a shift from temporary support toward a de facto subsidy sustaining an energy-only market that undervalues reliability and capacity.

This imbalance may ease later in the decade as coal retirements tighten supply and lift average wholesale electricity prices above new-build LCOEs. Until then, the assumption of fiscal neutrality remains uncertain, underscoring the need to move toward market-based mechanisms such as the proposed Electricity Services Entry Mechanism.

A broader concern remains that reliance on government-backed contracts may crowd out private PPAs, dampen commercial risk pricing, and entrench dependence on government support rather than fostering a self-sustaining, market-driven offtake environment.

How well have LTESAs and CISAs co-existed?

In principle, these schemes were meant to integrate, with the CISA extending the LTESA model nationally and avoiding duplication.

In practice, their co-existence in NSW produced legal, financial and administrative complexity. The state found itself running parallel auctions, one under its Roadmap, another under the national CIS, each with distinct indexation, curtailment and eligibility rules. Developers faced high bid costs and uncertainty about contract precedence. Lenders, dealing with two government counterparties under different laws, priced the ambiguity as risk.

Without a harmonised contract or clear hierarchy of claims, projects required bespoke legal opinions on enforceability, priority, security and tax, driving longer diligence periods, higher transaction costs and slower investment.

What is South Australia's FERM?

The Firming Energy Reliability Mechanism (FERM) establishes a capacity-style procurement framework for firming services to complement renewables, effectively operating as a state-level reliability insurance scheme. It would contract with dispatchable resources such as batteries, gas-peakers and demand response providers to ensure availability during periods of system stress.

A FERM agreement is a CfD-like contract designed to stabilise revenues for firming projects. Each specifies a strike price reflecting the level of market revenue needed for bankability: when a project’s actual market revenues fall below this level, the South Australian government provides a top-up payment; when revenues exceed it, the surplus is returned to government. The structure is intended to be revenue-neutral over time, balancing payments and clawbacks while providing investors with predictable returns and maintaining exposure to market outcomes.

The FERM is intended to align with the CIS, with South Australia seeking its recognition as an eligible pathway under the national framework to enable shared funding and harmonised reliability metrics. The timetable remains fluid, with the first tender round for up to 700 MW commencing in late 2025, with successful bidders announced in March or April 2026.

If executed well, the FERM could serve as a pilot for a unified national reliability framework. If poorly executed, it risks adding another layer of complexity.

What are Renewable Energy Transformation Agreements?

Recognising the potential inefficiency of overlapping state and Commonwealth schemes, Canberra and the states struck a series of accords, beginning with NSW in June 2023 and followed by others through 2024 and 2025, to coordinate tenders and codify cost-sharing through the Renewable Energy Transformation Agreements (RETAs), effectively a national framework for cooperative procurement.

RETAs set out capacity targets, cost-sharing arrangements and governance under the CIS framework. They form the structural bridge between Commonwealth support and state-based renewable policies. Under these arrangements, states may retain certain jurisdiction-specific instruments (such as NSW’s LTESAs for long-duration storage), while generation rounds are progressively integrated with CIS tenders:

• The NSW RETA, signed 26 March 2025, integrates the CIS with the LTESA framework, aligning procurement schedules, eligibility and cost-recovery arrangements while retaining the option-style design for long-duration storage. It allocates up to 7.1 GW of renewables and 1.78 GW (7 GWh) of dispatchable capacity, supported by A$1.4bn in Rewiring the Nation funding.
  
  

• The Victorian RETA, signed 6 December 2024, replaces VRET auctions as the delivery mechanism for meeting the state’s legislated renewable and storage targets. While the VRET remains the statutory framework, new capacity will be procured through CIS tenders administered jointly by AEMO and Victoria's Department of Energy, Environment and Climate Action. The agreement provides for 11 TWh of renewables, 1.7 GW (6.8 GWh) of dispatchable capacity and A$1bn in Rewiring the Nation investment.
  
  

• The South Australian RETA, agreed 10 July 2024, commits to 3 TWh of renewables and 0.9 GW (3.6 GWh) of dispatchable capacity, complementing the state’s proposed FERM.
  
  

• The Western Australian RETA, announced 22 July 2024, provides for 6.5 TWh of renewables and 1.1 GW (4.4 GWh) of dispatchable capacity, within WA's own reliability and capacity framework outside the NEM.
  
  

• The Tasmanian RETA, signed 12 December 2024, commits to 4 TWh of additional renewable generation and supports transmission upgrades under Rewiring the Nation to enable export of surplus hydro and wind capacity.
  
  

• The ACT RETA, announced 12 September 2024, focuses on demand-side measures: accelerating electrification, improving building efficiency and supporting vehicle-to-grid and distributed energy trials rather than new large-scale generation.
  
  

• Queensland and the Northern Territory have not yet finalised RETAs.

Taken together, the RETAs are the contractual architecture of a federated clean-energy framework, binding states to a coordinated national reliability plan while allowing for jurisdiction-specific instruments and transition pathways.

Yet key details remain unresolved for LTESAs and CISAs, including curtailment allocation, indexation formulas, claim waterfalls, and whether a unified contract will adopt the LTESA’s option-style model or the CISA’s two-way collar. Until those issues are settled, the dual-track structure continues to deter financiers and slow capital deployment.

There also remains a risk that the Commonwealth and individual states may be unable to reach agreement on key implementation details. Disagreement over cost-sharing was a key factor behind the Victorian Government’s September 2025 decision to defer its proposed auction for offshore wind CfDs.

What is the proposed Electricity Services Entry Mechanism?

With LTESAs and CISAs addressing the immediate investment coordination challenge, policymakers have turned their attention to the next phase: sustaining new generation investment once these contractual supports reach the end of their terms.

The Electricity Services Entry Mechanism (ESEM), as recommended in the Nelson Review (formally, the NEM Wholesale Market Settings Review, released 16 December 2025), represents the next evolution of Australia’s renewable investment framework. It is conceived as a centralised marketplace for long-term electricity contracting, designed to facilitate the transition from government support to market-based offtake.

The ESEM seeks to address what the Nelson Review terms the tenor gap, the mismatch between short-term contract horizons in the wholesale and corporate PPA markets and the long-term financing needs of capital-intensive renewable projects. The report identifies this gap as a key barrier to sustained new investment. Whether the ESEM will effectively close this gap, and whether this is indeed the principal constraint on financing, remains the subject of active debate.

The ESEM would operate as a government-facilitated offtake clearing house, with a Central Buyer procuring and administering standardised long-term offtake contracts for defined electricity services including bulk energy, shaping and firming, through competitive auctions. Projects could bid to provide one or multiple services, allowing efficient integration of generation, storage and demand-response technologies within a single coordinated framework.

The ESEM would effectively extend the forward curve for wholesale electricity prices into longer horizons, functioning much like a futures market for long-term contracts. Rather than displacing the ASX Energy Futures or OTC derivatives markets, it would complement them by providing liquidity once those markets thin out, typically beyond three years.

Key design features include:

• Standardised 8–15-year contracts, typically covering the middle years of a project’s operating life.

• Settlement against a reference generation profile rather than actual generation, shifting resource and congestion risk allocation away from the generator.

• Optional secondary contracts for essential system services such as inertia or grid-forming functionality to diversify project revenue streams.

• Central clearing and credit enhancement, managed by AEMO or a designated intermediary, with optional government participation as buyer of last resort to anchor liquidity.

• Contract recycling, enabling the Central Buyer to on-sell contracts back into the market to foster liquidity and limit long-term fiscal exposure.

The ESEM is intended to build on existing regulatory architecture rather than reinvent it, thereby limiting disruption and leveraging frameworks familiar to market participants under the CIS and LTESA regimes. Its detailed operation would be codified within the National Electricity Rules, providing legal durability while allowing states limited flexibility to tailor participation, for example to reflect differing system needs, eligible technologies or firming requirements.

Importantly, the ESEM represents a shift beyond the NEM’s traditional energy-only market design. The existing market relies on short-term spot prices to signal investment, but this model has struggled to finance capital-intensive renewable and storage projects that depend on predictable long-term revenues. By introducing a Central Buyer to procure long-term service contracts, the ESEM effectively adds a capacity-style layer to the market, internalising the value of reliability, flexibility and investment timing that energy prices alone cannot reflect.

In this sense, the ESEM functions as a hybrid mechanism, combining competitive short-term energy dispatch with a rule-based market for long-term services. It would procure not only energy, but also shaping, firming and essential system services, embedding these attributes into the contracting framework rather than relying on scarcity pricing. While it retains market competition and price discovery, it extends the NEM’s design to support system reliability in a decarbonising grid.

Conceptually, the ESEM represents evolution, not revolution. It is an effort to transition from direct government support toward a market-based framework that still coordinates investment timing. Its success will depend on whether it meaningfully addresses the true constraints on capital formation, not only the tenor gap, but also broader structural challenges such as transmission build-out, social licence and supply-chain risk.

Several critical design issues remain to be determined. These include how bulk energy profiles will be set, how multi-service projects will be contracted, how commissioning delays and curtailment risks will be treated, and how the Central Buyer’s governance, credit standing and loss-recovery mechanisms will operate. Financiers will pay close attention to these questions, particularly the creditworthiness of the Central Buyer (expected to be AEMO Services Ltd, which already conducts tenders for CIS Agreements and LTESAs), which will influence the bankability of ESEM contracts.

Implementation of the ESEM would require legislative amendments to the National Electricity Law to be agreed and enacted by all jurisdictions participating in the NEM. At this stage, Queensland has withheld in-principle support for the Nelson Review’s recommendations, although it has not formally opposed them. The Nelson Review’s Implementation Roadmap proposes an ambitious end-2026 target for passage of a single legislative package giving effect to the proposed reforms, including (but not limited to) the ESEM.