The ESEM’s contract co-design paradox – will financiers actually bank it?

The Electricity Services Entry Mechanism (ESEM) is not just another scheme. It is the most significant structural reform to the National Electricity Market (NEM) in a generation: a permanent, legislated, centralised contracting framework intended to replace the Capacity Investment Scheme (CIS) from 2027 and unlock tens of billions of dollars in investment. 

But ESEM contains a paradox. The features that make the proposed contracts attractive as market instruments (fungibility, standardisation and tradeability) may also make them harder to finance. That matters because Australia’s next wave of renewable projects will not be built on elegant market design alone. Someone still has to lend against the cashflows.

The policy ambition is clear. The harder question is whether that ambition can be translated into contracts that developers will bid, banks will debt-size and investors will back. If the mechanics do not work, the capital will not come.

What the pilot working group agreed and what it revealed

The pilot contract co-design working group has reached agreement on preferred instruments for each ESEM category: (a) an ex-post dispatch-weighted average swap (DWS) for bulk energy (settling against the average spot price received by a reference fleet, rather than the flat baseload swap or run-of-plant Power Purchase Agreement (PPA) familiar to existing participants); (b) heads and tails spreads for shaping; and (c) caps for firming. Capped and uncapped time-of-day block contracts remain the fallback if unresolved issues with the ex-post contracts prove intractable.

The contract attributes matter as much as the instruments. The group prioritised fungibility, simplicity of valuation, portfolio modularity, appropriate risk allocation, adaptability to future market conditions and cross-technology competition.

These are sensible criteria but also reveal a tension. Fungibility, valuation simplicity and portfolio modularity support a liquid secondary market. They are not necessarily what a limited-recourse lender would rank first when deciding whether to debt-size against a long-dated revenue contract. That tension matters most in the bulk energy contract, where the preferred instrument asks lenders to move furthest from what they already understand.

The DWS: a genuinely novel instrument

The dispatch-weighted average swap (DWS) at the heart of the bulk energy contract represents a fundamental departure from the contracting models on which much of Australia’s renewable energy fleet has been financed. 

Under a traditional run-of-plant PPA, a generator sells its actual output at a fixed price. Lenders are comfortable with this because revenue is a direct function of generation, a variable they can model using historical resource data and turbine performance curves.

The DWS works differently. The generator commits to a pre-agreed volume and settles against a dispatch-weighted average price calculated across a reference set of generators, rather than against its own output.

That creates two problems traditional PPAs largely avoid. First, volume risk: if actual output falls short of the contracted volume, the generator remains exposed on the shortfall. Second, profile or basis risk: the project’s revenue depends on the reference fleet’s dispatch-weighted price, not its own capture rate. If its output profile diverges from the reference set (for example, because of geography, technology, curtailment or fleet composition) it will face a settlement mismatch. 

Reference drift is the most acute problem. A project may be bankable at financial close against the forecast reference profile for its region and technology. But as projects enter, technology changes, curtailment evolves and the reference fleet shifts, the benchmark can move away from the project’s actual generation profile. 

The project has not failed; the reference has changed around it. 

That is system design risk, not ordinary resource risk. The question is who should bear that risk.

The DWS is not a bad instrument. For a generator highly correlated with the reference fleet (for example, a solar farm in a solar-heavy region, for instance) the DWS may reduce some forms of capture-price exposure because the project and reference-fleet production profiles should tend to move together. How much protection that provides will depend on the reference methodology and market conditions. The basis risk is real, but it is not uniformly negative. It is most acute for projects whose profiles diverge from the reference set.

There are also good structural reasons to prefer the DWS. It is more fungible than a run-of-plant PPA. It avoids bespoke bilateral contracts with each generator. It allows contracts to be recycled into the secondary market. Those are real advantages. But the question is whether they come at the cost of bankability and, if so, whether design features can bridge the gap.

A volume floor or collar could limit downside exposure. A contractual lock-in of the reference methodology could stop lenders modelling a moving target. Vintage-based pools could stop early projects being benchmarked against later projects with different technology or locations.

A reference-drift deadband could leave ordinary basis risk with the project but share outlier movements caused by fleet changes. A hybrid DWS/run-of-plant floor could give lenders a bankable base case while preserving upside fungibility.

Reserving may absorb short-term volatility, but it is a blunt answer. If lenders require a large reserve for a risk the project cannot control, the result is trapped capital, lower gearing and a higher delivered cost of energy. If the objective is competitive entry rather than merely tradeable contract liquidity, some systemic reference-design risk may need to sit with the ESEM Administrator or government.

The co-design working group should be testing these options now, not treating bankability as a constraint to be resolved after the contract form is settled. That is why the international comparison matters: it shows how far the ESEM is moving from the models lenders have previously accepted.

International precedent: why lenders cannot simply import a model

There appears to be no close international precedent for the combination ESEM proposes. The closest analogue is the United Kingdom’s (UK) Contracts for Difference (CfD) regime, where the Low Carbon Contracts Company enters into two-way CfDs with generators at auction-determined strike prices. But the UK CfD settles against actual metered output at a market reference price. The generator bears resource risk, but not the same profile or reference-drift risk embedded in the DWS. 

That comparison is necessarily simplified. These schemes are complex and evolving, but the structural point holds: Australian lenders cannot simply import an established financing methodology from an equivalent overseas regime. International experience does not invalidate the ESEM approach, however it underscores why the bankability question is not academic. It is the hinge between elegant market design and actual investment.

Bankability is a competition issue

The ESEM is premised on the NEM having a tenor gap. Generators cannot secure revenue contracts of sufficient length and certainty to underpin project finance for new-build assets. The CIS addressed that problem with government-backed contracts for difference.

The ESEM is meant to provide a more market-integrated, permanent answer. But there is a hard threshold question – will lenders size debt against the contract? If not, the mechanism will not deliver the entry it is designed to catalyse.

That question matters even more as financing conditions tighten. The next phase must navigate connection delays, curtailment, cannibalisation, shorter offtake tenor and more complex revenue stacks. ESEM is therefore not just market design.

It is a test of whether Australia can convert net zero ambition into bankable cashflows. If the contracts do not work for credit committees, they will not unlock the capital required for the next build-out.

This is not just a financing point. It is a competition point. If the intended entrants are vertically integrated gentailers and large balance-sheet developers, the project finance question is less acute. Those entities can absorb novel risk within a diversified portfolio.

If, however, ESEM is meant to work for independent developers financing projects through limited-recourse SPVs (the very model that built much of Australia’s existing wind and solar fleet) then the credit committee questions become binding constraints.

The Nelson Review’s ambition is broad entry, not entrenching incumbents with large balance sheets. That means the contracts need to work for project finance. Bankability goes to the very heart of whether ESEM will deliver competitive entry or consolidate the market further.

What a credit committee will ask

Presented with a DWS as the revenue foundation of a base-case financial model, a lender will ask four threshold questions. First, what is the contracted volume, and what is the probability that actual generation meets it?

Second, what is the basis risk between the generator’s capture rate and the dispatch-weighted average price? Lenders already model capture rate risk for merchant tails, but under a DWS it moves from a secondary consideration to the primary revenue driver.

Third, over a 15 or 20-year notional debt tenor, how stable is the reference fleet methodology? Finally, if the project is bankable on day one against a forecast local reference case, what happens when new projects change the reference profile in a way the project cannot match?

These questions will determine whether ESEM contracts can support gearing broadly comparable to conventional contracted renewables, or whether lenders demand significantly more equity, increasing the cost of capital and undermining ESEM’s ability to deliver entry at lower cost than the CIS.

A contract optimised for trading liquidity and one optimised for project finance bankability are not necessarily the same thing. The challenge is to make the instrument serve both purposes, or to design compensating features such as tenor, credit support and the role of the ESEM Administrator. That shifts the analysis from contract form to counterparty strength.

The central buyer’s credit and the administrator’s role

The legal status, creditworthiness and operational capacity of the entity at the centre of ESEM (currently expected to be AusEnergy Services Limited) are as important to bankability as the contract design itself. 

Under the ESEM model, the Central Buyer will be the counterparty to every contracted generator. It will run auctions, execute contracts, manage settlements and, if contracts are recycled into the secondary market, potentially act as a derivatives dealer or facilitate novation to retailers and other offtakers. Its creditworthiness will be fundamental to every generator’s revenue certainty and every lender’s credit assessment.

If the ESEM Administrator has a statutory structure, reliable cost-recovery mechanism and sufficiently robust payment architecture, lenders may be able to treat its contracts as quasi-sovereign credit. That means familiar project finance structures, familiar gearing and pricing driven by asset risk rather than counterparty risk.

If, however, lenders cannot trace the Administrator’s payment obligations back to a sufficiently reliable funding source, they will run a separate counterparty credit assessment. That will likely translate into higher pricing, lower gearing, additional credit support requirements or some combination of the three.

In a market where ESEM is intended to be the primary contracting pathway for new generation, that credit friction flows through to consumer costs. The Administrator’s credit status is not a governance question for later. It is a foundational design parameter.

Once the counterparty question is answered, the next issue is whether the same contract can be liquid enough for the market and bankable enough for lenders.

Fungibility versus entry: a false dichotomy?

It would be easy to frame this as a binary choice between fungibility and bankability. The NEM’s existing contract market is illiquid, opaque and concentrated. A mechanism that deepens liquidity and improves price transparency is genuinely valuable because liquid markets reduce the cost of capital for everyone.

However, the real question is whether the chosen instruments can do both jobs. There are reasons for cautious optimism: the formal working group has a broader composition and the Department’s interim guidelines explicitly contemplate bankability as a design parameter.

There are reasons for vigilance too. The formal working group is expected to deliver recommended term sheets by November 2026, with final templates in 2027 and a first tender anticipated for late 2027. That is ambitious. Lenders need time to model and obtain credit approval, developers need to test interaction with existing offtake arrangements and the ESEM Administrator needs to demonstrate operational readiness.

The tender process matters too. Even if the contract form is right, the agency rolling it out must get the procurement and award regime right. ESEM awards cannot become a cost-of-capital shoot-out in which sponsors bid artificially low numbers to win, only for lenders to conclude later that the revenue stream is not debt-sizeable.

That would repeat one practical limitation of Capacity Investment Scheme Agreements (CISA): the government-backed contract may support the equity case, but many financing structures may still require separate private offtake over the relevant debt tenor before lending at scale. The winning bid must be cheap and financeable. Otherwise, the auction selects the lowest nominal price, not the projects most likely to reach financial close and deliver capacity.

Queensland and the question of uniformity

The ESEM is designed as a national mechanism operating across the NEM, but Queensland did not provide in-principle agreement to the proposal at the December 2025 Energy and Climate Ministerial Council meeting. That matters because the DWS assumes a sufficiently large and diverse reference fleet.

If Queensland’s substantial generation base and renewable pipeline sit outside the mechanism, the reference fleet becomes smaller, less geographically diverse and more exposed to idiosyncratic dispatch patterns in the southern states. That affects basis risk and reduces the pool of contracts available for secondary market recycling.

More broadly, if ESEM becomes another fragmented, state-by-state framework, lenders will price that regulatory risk. Design, bankability, procurement and implementation all have to work together.

Framing the path forward

The questions this article has raised (bankability, counterparty credit, reference drift, fungibility, procurement discipline, timing and jurisdictional divergence) are not objections to the ESEM. They are the implementation agenda. If policymakers want the ESEM to do more than produce elegant term sheets, these issues need to be resolved before the first tender, not discovered after financial close fails.

One concrete step would help. When the formal working group delivers its recommended term sheets in November 2026, it should publish alongside them an independent bankability assessment prepared by an adviser with deep project-finance credentials.

That assessment should address how the proposed instruments interact with base-case revenue modelling, gearing assumptions, debt sizing, reference drift, counterparty credit and tender bid evaluation. It should be structured around credit committee questions, stress-tested across generator profiles and informed by consultation with a representative group of active Australian renewables lenders.

Policymakers should use it to refine contract and tender design before launch. If the contracts are robust, that process will accelerate market acceptance. If they are not, better to know in November 2026 than at the first failed auction in late 2027.

The NEM cannot afford to get this wrong. Not because the process lacks rigour, but because the window in which Australia can build the generation fleet it needs is not infinite.

ESEM will ultimately be judged not by the sophistication of its contract design, but by whether those contracts survive a lender’s credit committee. If they do, Australia may have created a genuinely new model for financing electricity market entry. If they do not, the risk is not simply that projects become harder to finance. It is that the market ESEM creates is accessible only to those with balance sheets large enough not to need it. 

This article is part of a series of articles and podcasts sponsored by Gilbert + Tobin. James Guthrie is a partner at the law firm’s Energy, Resources and Infrastructure group.