Big batteries – charging up for 2022

• Offtake structures: to date, for standalone BESS, we have seen a number of offtake structures take the form of tolling agreements. These tolling arrangements are akin to a long-term lease, where the offtaker pays the developer an annual fee over the term of the agreement. In exchange, the offtaker is able to charge and discharge the battery (at its discretion, but subject to a number of conditions); and is entitled to retain all wholesale market revenue, and is responsible for paying all costs, attributable to the battery's participation in the market.
  
  More recently, the Genex Bouldercombe Battery has adopted a unique long-term revenue sharing structure with Tesla, as auto-bidder software provider for the BESS. The structure involves Tesla guaranteeing a minimum amount of contracted merchant revenue for the BESS, enabling Genex to secure financing off the back of this contract. The upside for Tesla is a share in any revenue achieved over the guaranteed minimum.³
  
  
• Revenue stack: with batteries, it is of key importance to determine revenue stack over the course of the life of the asset. In the absence of a capacity market mechanism, revenue from frequency control ancillary services is a major part of the revenue stack. However, this is likely to change as the grid transforms. We expect that future profitability for new age batteries will come from energy arbitrage in the wholesale market, and also the provision of other grid support services, like inertia. Of course, if the Energy Security Board's capacity market proposals are implemented, revenue from the sale of Australian Reliability Certificates will also form part of the revenue stack.
• Network charges: a matter that remains unresolved is the possibility of transmission network providers levying transmission use of system charges (TUOS charges) on batteries for energy consumed from the grid. While most projects are currently able to negotiate a zero TUOS charge under existing connection arrangements, it is acknowledged that this could change at the discretion of the network service provider – resulting in BESS projects paying twice for network charges. With industry expressing concern that this could disincentivise investment, the issue of whether to provide an exemption to energy storage assets – currently at a disadvantage to coal and gas generators, who are not required to pay network charges – was considered by the AEMC as part of the 'integrating energy storage systems into the NEM' rule change described above. It ultimately found that further work is required to consider how network prices should apply to storage and other large flexible loads, and to consider the broader framework for recovery of network costs from storage and other market participants. The AEMC has indicated that it will prioritise work on any rule change submitted on this point.

While the BESS supply market in Australia is growing, there are still limited commercial battery suppliers who have firmly established themselves within the market. This lack of competition, supply chain impacts due to COVID-19, and unrivalled demand for batteries to provide network stability as part of the energy transition, have driven a supplier-friendly market. 

• Interface and integration risk: to date, most BESS projects have been procured on a standalone basis, rather than on an integrated basis as part of a larger renewable project development. This is probably because there are already a number of existing wind, solar and network assets that require storage support – meaning storage is being prioritised over new generation. Further, most major participants in the wind and solar construction market do not have the internal capacity to supply batteries, meaning a specialist third-party supplier is required. In such circumstances, engineering, procurement and construction (EPC) contractors are unwilling to wrap integration issues, and instead seek to provide back-to-back warranties and guarantees based on those it obtains from the supplier, which provides limited additional value to the owner.
• Sizing of LDs in hybrid projects: for hybrid projects, where there are multiple assets that can export to the grid, there is a question of how to manage delays to one aspect of the project (eg the wind farm) where another part (eg the BESS) is on track, particularly in the context of satisfying grid connection requirements and ability to export. This raises commercial considerations in relation to the sizing and application of liquidated damages, and whether the connection and revenue strategy should be staged on an asset-by-asset basis (to seek to maximise early revenue) or assume all aspects of the project connect simultaneously (to seek to provide certainty as to connection requirements).
• Split BESS scope: even on standalone BESS projects, battery suppliers are not always equipped or willing to deliver the associated civil and balance of plants works. This has resulted in split contracting structures, with supply and commissioning of the BESS sitting with the BESS supplier, and installation of the BESS and construction works sitting with a works contractor. While the relevant gap risks can be managed by the owner, it is critical to align programming, handover points and key milestones for the project, as well as clearly allocate responsibility for defects and non-performance.
• Dilution of security package: in addition to creating gap risk for owners, the splitting of procurement packages dilutes the aggregate liability caps and the quantum of security available for any particular defect or other issue, given these are typically sized against the split contract value, rather than overall project value.
• Technology/IP: technology remains particularly sensitive in the BESS market, with IP licences limited and escrow arrangements common in relation to sensitive technologies and software. Owners of projects need to carefully consider the circumstances in which that escrow material needs to be released in order for it to continue operations should the battery supplier cease to support the project.
• Performance guarantees and defects: presently, the structure and extent of defects liability and performance guarantees for batteries appear to be driven primarily by the relevant battery supplier, rather than the owner's requirements. Given the modular nature of BESS projects, serial defects regimes are standard, though the trigger for serial defects ranges from 5% to 15%, and the serial defects liability period ranges from 12 months to five years, depending on the overall warranty package regarding long-term defects (both under the EPC and operations and maintenance). Further, the performance guarantee packages range from providing round-trip efficiency, usable energy capacity and active power capacity guarantees (at varying thresholds), to alternate structures involving revenue risk sharing. The degradation profile of batteries, and its impacts on the guarantees (and associated revenue streams), also remains a key technology consideration in assessing the overall performance package.

While there has been a notable uptick in the volume of projects coming to market, battery storage remains an emerging technology and, with this, presents issues from a bankability perspective.

• Revenue risk: battery projects rely on price variability in the National Electricity Market. Their revenue streams are therefore uncertain and difficult to accurately forecast over the life of the asset. Certainty of revenue lines underpins project financing structures and, as a consequence, financiers have been unable to bank merchant battery projects, focusing instead on projects that have included contracted revenue streams through more traditional offtake arrangements.
  
  Diversification or ‘stacking’ of revenue sources, as discussed above, has assisted, to an extent, to overcome this challenge. All the battery projects in Australia to have reached financial close to date utilising external debt, have included a contracted revenue source, in the form of a capacity payment, FCAS or fixed-term offtake arrangement.
  
  A price arbitrage model is more attractive from a sponsor's perspective, given price volatility (ie large peaks and troughs in power prices) and that it has the potential to lead to greater equity upside. Similarly to other renewable asset classes, such as wind and solar, we are starting to see examples of financiers being willing to take on a greater degree of merchant risk, subject to inclusion of certain debt enhancements. The offtake arrangements for the Bouldercombe Battery Project are a good example of market evolution in this respect. While fully merchant, a minimum percentage of the project's revenue line is underwritten by Tesla, and therefore it has a demonstrable fixed revenue line against which external project financing has been advanced.
• Technology risk: operational constraints of battery technology represent a key consideration for financiers. We have seen a material increase in the volume and depth of due diligence undertaken by them for degradation profiles, operating standards and performance warranties.
  
  Degradation affects storage and output capacity and, with this, project revenues available for debt service. Financiers are therefore focused on ensuring that battery performance is optimised, the size and length of the supplier's performance warranties are adequate, and reasonable assumptions are adopted regarding forecast degradation levels. Strong emphasis is also placed on operating protocols, to ensure that the battery is not operated outside of parameters so as to invalidate the supplier's warranties, as this would be likely to reduce asset value and cash flows for servicing debt.
  
  To address technology risk, financiers have sought to strengthen their financing structures by adopting shorter debt tenors for battery projects, compared with other renewables projects; front-ended repayment profiles; more cash sweep mechanisms (including upside sharing); and lower gearing.
• Contingency: while batteries are an agile modular technology, as an emerging asset class they nevertheless carry an element of development risk. As a consequence, we have seen financiers highly focused on the extension of time and liquidated damages regimes, as well as requiring sponsors to build larger contingency packages into their modelling.

In August 2021, the Australian Energy Market Operator (AEMO) released its 'white paper' 'Application of Advanced Grid-scale inverters in the NEM', to encourage investment in advanced inverter capabilities, with an immediate focus on prioritising the deployment of 'grid-forming inverters' on grid-scale BESS – particularly given the pipeline of committed or proposed batteries.

The paper explains that the majority of batteries currently in the market are 'grid-following' inverters, which 'synchronise to the grid voltage waveform, adjusting power output to 'follow' voltage'. While these batteries can provide grid support (eg by the provision of frequency control ancillary services), the response speed of these systems, and the support systems they can provide to the grid, are limited. 'Grid-forming' inverters, on the other hand, set their own internal voltage waveform, which means they can be used for multiple functions. The paper states that grid-forming inverters, supported by a firm energy source, will be able to provide the same capabilities that synchronous generators are currently providing to the grid. This includes the ability to provide system strength, frequency response and inertia services, withstand disturbances on the grid, correct system weakness in areas of high renewables, support power system islands, and initiate or support system restoration.

The 50MW/75MWh Wallgrove BESS (50MW/75MWh), installed at TransGrid's Wallgrove substation in Western Sydney, is an example of a grid-forming inverter. This lithium-ion battery is connected directly to TransGrid's transmission network, and will pilot the provision of synthetic inertia and fast frequency response network services to assist with grid stability. Read more here.

Following the release of AEMO'S white paper, in December 2021, the Australian Renewable Energy Agency (ARENA) announced its $100 million Large Scale Battery Storage Funding Round, as part of the Advanced Renewables Program. The aim of this funding round is to promote the development of grid-scale battery projects equipped with advanced inverter technology at scale, with ARENA acknowledging the role this technology is expected to play in providing essential system services to the grid. It has indicated that it will fund at least three projects, with the provision of up to $35 million per project, and will accept new build, retrofit or expansion projects. Expressions of interest close 5pm on 31 March 2022.

On 2 December 2021, the Australian Energy Market Commission (the AEMC) made a final rule change determination to better facilitate the participation of energy storage and hybrid facilities in the National Electricity Market. Of particular relevance, the changes will:

• introduce a new registration category known as the 'Integrated Resource Provider', to simplify the registration, market participation and compliance requirements for different bi-directional market participants that export and import energy, and provide other ancillary services, to the grid. This will mean batteries will no longer have to register in, and comply with the requirements for, multiple participant categories (ie market generator and market customer), which will provide benefits from both an administrative and costs perspective; and
• clarify that the current approach of setting and measuring performance standards at the connection point will continue to apply to grid-scale batteries, including when they are part of a hybrid system. Those performance standards will, however, reflect the technical performance characteristics of each unit within the facility behind the connection point.

This rule change will come into effect on 3 June 2024 (with a phased implementation of certain elements of the rule change from March 2023).