Part 2 - Unlocking energy investment at scale: contracts, infrastructure and market confidence

The evolution of battery offtake arrangements has continued at pace. In our Big batteries in 2025 Insight, we highlighted the rapid development and adoption of virtual offtake agreements as a preferred offtake contracting model. Over the past year, this shift from physical offtakes has further solidified, with around 50% of offtake arrangements across both operating and pipeline projects now structured as virtual tolls, revenue‑share or capacity swap arrangements, or firmed power purchase agreements.¹

A clear marker of this evolution was ENGIE and AGL entering into the first 100% virtual storage agreement to be entirely delinked from a physical asset.² The five-year, derivatives-only agreement, based on hypothetical energy storage capacity, represents a step-change in how energy storage can be commercialised and traded, and demonstrates a demand among energy traders for innovative financial instruments that support portfolio diversification and risk management.

Financiers are recognising the increasing sophistication of developers and offtakers, and becoming more comfortable with virtual offtake arrangements by seeking protection through the inclusion of trading parameters in the facility agreement. These parameters protect financiers from downside risk by ensuring the project trades under the offtake agreement within agreed parameters, which facilitates predictable and transparent trading behaviour. As a result, these types of offtake arrangements—viewed as novel only a short time ago—are becoming an established feature of the battery offtake landscape.

Capacity swaps agreements have also entered the mainstream. A halfway house between a physical tolling agreement (which offered no market upside for the developer) and a virtual tolling agreement (where the market downside can add challenges from a bankability perspective), capacity swaps give the developer a fixed revenue line (crucial for project financing) and control over the asset, while sharing in the upside with the offtaker. Performance guarantees, revenue benchmarking, step-in rights, grid risk and negative pricing are key points for parties negotiating these types of arrangements.

The size of utility-scale batteries is growing—we are most commonly seeing 200MW +, 4-hour + BESS come online. Building assets of this scale demands a lot of upfront capital, and banks typically want a higher degree of revenue certainty before lending.

We are seeing developers increasingly exploring the bankability of BESS projects with contracted revenue profiles that are supported by a Long-term Energy Storage Agreement (LTESA) or Capacity Investment Scheme Agreement (CISA). However, to date, the more dominant trend has involved financiers becoming more comfortable with riskier or more bespoke offtakes where there is additional support from a government support arrangement. For example, a BESS that may have achieved more conservative debt sizing based on a riskier offtake alone may be able to access better project financing terms where it sits alongside an LTESA or CISA.

Developers are therefore seeking to revenue stack 'riskier' offtakes alongside government support arrangements, which they use as bargaining chips to negotiate their offtakes and project financing terms.

Developers' ability to obtain attractive debt sizing terms where their project is supported solely by a CISA or an LTESA is something that we expect to play out further this year, as more BESS projects seek funding and the project finance market continues to evolve for this asset class. 

While battery investment is accelerating, parts of the renewable generation market are under increasing pressure. Sustained curtailment, congestion and negative pricing in high‑penetration regions have materially eroded revenues for some utility‑scale solar projects. 

Projects that were financed on assumptions of more stable price distributions, lower curtailment and stronger marginal loss factors have seen debt service coverage ratios deteriorate sharply. In several cases, prolonged revenue compression has resulted in covenant breaches or events of default under project finance facilities.

This, combined with structural and market-wide challenges for solar projects, has resulted in lenders increasingly pursuing restructurings that are not merely deferrals of amortisation but strategic resets of the asset’s revenue profile. Against this backdrop, batteries are increasingly being deployed as a strategic solution, rather than an optional add‑on. Lenders are requiring co‑located or adjacent storage as a condition of standstills or extensions, seeking to reshape revenue profiles, mitigate volatility and improve long‑term bankability.

By adding storage, sponsors can capture arbitrage opportunities, mitigate negative pricing exposure, smooth revenue volatility and enhance overall project bankability. For lenders, this approach seeks to transform a structurally challenged pure-solar asset into a hybrid project better aligned with current NEM dynamics, improving the prospects of long-term recovery and refinancing.

However, and as discussed below, the process to 'bolt on' a BESS to a solar farm, while potentially adding value from a vendor and financier perspective, is not without its challenges.  

Investment in BESS projects continues to be at the forefront of M&A activity in the renewables sector in Australia. Whether in the form of standalone or co-located assets, a robust BESS development pipeline has played an important role in attracting investment in recent significant transactions, including KKR's investment into the HMC Energy Transition platform and Aula's acquisition of a solar and BESS portfolio from Lightsource bp. The features of a BESS project that attract investors remain the same: quicker to develop, less capex required and a broader scope of revenue options once operational.

In our 2025 update, we discussed the growing prevalence of co-location BESS 'add-ons'—where vendors looking to sell a solar or wind project add a BESS development opportunity to it. This approach remains common, and can certainly add value and sale potential to a project. However, as we predicted last year, this has resulted in procedural challenges, particularly regarding the connection process. Where a project is sold at 'notice to proceed' (NTB) / 'ready to build' (RTB) stage—which, from an investor appetite perspective, remains the most attractive time to sell a BESS project—the amendments to the connection arrangements are a further complication to an already challenging balancing act. The timing of the sale process must be aligned with the construction, connection and, if applicable, financing and offtake documentation processes.

We have seen similar challenges arise where, during a sale process, the developer has sought to amend its connection arrangements to reflect changes to a BESS project's technical specifications (eg going from a two- to four-hour duration). If there is a decision point during a sale process as to whether the connection arrangements need to be amended to reflect a BESS development 'add-on' or new specifications of the battery, considered planning and implementation is essential to ensure that process's success.  

The rise in portfolio financings has enabled an acceleration in more innovative debt terms, given the typically more diversified cashflows, spread of risk across a pool of assets and the value of cross-collateralisation across multiple assets. In particular, we are seeing financiers becoming more willing to provide attractive project finance debt sizing where there is a degree of sub-investment grade offtakes and some level of merchant exposure. This has particularly been the case where:

1. Debt sizing parameters can be split based on asset class (with separate minimum debt service coverage ratios (DSCRs) for solar, wind and BESS), and also distinguished by whether the cashflows are contracted (with separate sizing for cashflows from investment versus sub-investment grade offtake agreements) or merchant (ie the project sells electricity into the market for the wholesale price, which can be volatile). The threshold for how much sub-investment grade cashflow can be counted towards meeting financial covenants is often negotiated.
2. Review events can be negotiated for termination of key contracts, such as offtake agreements. In a single asset financing, financiers typically seek to protect certainty of the revenue profile, by ensuring that the majority of the project's output is secured by an offtake agreement and providing for a default outcome where, subject to an equity cure period, that offtake agreement is terminated. However, in a portfolio, by cross-collateralising the assets across it, financiers look at the overall cashflows. Therefore, instead of a portfolio-wide consequence if an individual offtake agreement falls away, there will typically be a review event that provides the equity sponsor with an opportunity to demonstrate that the portfolio is still able to meet the debt-sizing parameters. Where this is not the case, the consequence is limited to the proportionate impact of the relevant offtake or the project involved.

Considerations such as these demonstrate the importance of a diversified portfolio. Developers may not be able to fully capitalise on the advantages of a portfolio if it is made up of a single asset class, as the debt sizing will be the same, and project-specific risks can affect the entire portfolio. The rise of BESS projects as a bankable asset class has meant that financiers are looking favourably on portfolios that incorporate BESS, which perform more reliably and can often have stronger offtakes via tolling arrangements in contrast to some renewable generation projects.

We are already starting to see some of the above principles leak into large-scale single asset BESS financings. This, coupled with the rise of more bespoke and innovative offtake arrangements, may provide further opportunities for developers.

Planning and environmental approval frameworks for large‑scale batteries continue to evolve across jurisdictions, with governments refining pathways to support the transition, while responding to growing community, environmental and infrastructure considerations.

At a high level, recent developments include:

• Federal—Progressive reforms to the Environment Protection and Biodiversity Act 1999 (Cth) (the EPBC Act) are reshaping assessment pathways for major infrastructure projects, with further changes expected to streamline approvals and introduce new national environmental standards relevant to large‑scale storage. Read our deep-dive into the reforms here.
• Victoria—Large batteries continue to benefit from fast‑tracked approvals under the Development Facilitation Program, supported by broader planning reforms designed to accelerate decision‑making and limit appeal rights. See our deep-dive into the broader reforms here.
• New South Wales—Batteries are typically approved as State Significant Developments, with a growing trend of adding storage to existing renewable projects via consent modifications, alongside broader planning system reforms focused on risk‑based assessment. Read about the reforms here.
• Queensland—A more interventionist framework now applies to large‑scale BESS, with expanded social impact, community benefit and public notification requirements increasing approval complexity, cost and timeframes. Read about these changes here.
• Western Australia—Planning reforms are underway through a new Renewable Energy Planning Code, intended to provide a clearer and more consistent framework for assessing renewable energy and storage projects.
• South Australia—A new 'one‑window' licensing regime for larger renewable energy infrastructure, including BESS, replaces traditional planning approvals and is intended to streamline assessment for qualifying projects.
• Tasmania—the Tasmanian Government has committed to planning reform, with the Tasmanian Planning Policies set to take effect this year, promoting and supporting renewable energy and ancillary infrastructure in appropriate locations across the state.

Despite differing approaches across jurisdictions, common planning risks for large‑scale battery projects remain consistent. These include amenity and visual impacts, noise, biodiversity considerations, fire risk, grid connection constraints and water availability. Given increasing scrutiny of BESS developments, early engagement with planning, technical, environmental and legal advisers remains critical to managing approval risk and delivering projects efficiently.