Ofgem’s cap and floor scheme aims to unlock investment in Long Duration Energy Storage (LDES), which will become increasingly important in maintaining grid stability as the UK transitions towards a more renewable electricity system. This article explores the proposed mechanism to determine cap and floor levels and what this means for the financing and bankability of LDES projects.

The dramatic increase in renewable generation in the UK in recent years, coupled with its inherent intermittency, has increased the need for flexible assets capable of storing electricity during periods of excess renewable generation, and discharging it when demand exceeds supply. LDES can also help to reduce renewable curtailment by storing generation that would otherwise be constrained by the grid, an issue that is becoming increasingly prevalent as the penetration of weather dependent assets continues to grow.

An often-asked question in the context of a renewable-dominated system is “what happens if the sun doesn’t shine, or the wind doesn’t blow?”. The latter is particularly problematic: both because of the relative volumes coming from offshore wind (several GW / year of capacity awarded, with only minimal signs of slowing down), and because low wind periods can last for several days (rather than merely several hours) at a time. Whilst short-duration storage provides valuable intra-day flexibility, it cannot bridge these prolonged periods of supply-demand imbalances; maintaining adequate supply through such events requires assets capable of storing and dispatching energy over significantly longer durations. This encompasses technologies such as pumped hydro, liquid air energy storage, compressed air energy storage and long-duration batteries.

The need for these assets is clear; however, their capital-intensive nature and the uncertainty around their long-term revenues can make projects economically unattractive to developers and challenging to finance for lenders.

The UK government announced its intention to implement a cap and floor scheme in October 2024. Following a period of consultation and detailed project assessment, Ofgem published its ‘minded-to-decisions’ list, naming a portfolio of 16 projects provisionally selected to benefit from the support scheme (out of 77 which met the initial eligibility criteria).

he proposed portfolio comprises exclusively new-build assets, with a combined capacity of 7,645MW, split as follows:

• • Pumped Storage Hydro (PSH): 3900MW (3 projects)
  • Lithium-ion BESS (Li-ion BESS): 3630MW (11 projects)
  • Vanadium Flow/Zinc Battery (VFB/Zn): 65MW (1 project)
  • Compressed Air Energy Storage (CAES): 50MW (1 project)

Ofgem is now consulting on its minded-to decisions and proposed licence conditions for Window 1 projects, with final cap and floor awards expected in autumn 2026. As such, some elements of the scheme are still under review and may be subject to change.

Cap and floor mechanism

The support mechanism proposed by Ofgem aims to stabilise project revenues within a pre-determined cap and floor range. These levels are designed to strike a balance between providing sufficient support to incentivise investment while ensuring the subsidy costs remain proportionate. The revenue support mechanism, as well as the concepts used in calculating the cap and floor, are derived from the existing interconnector subsidy regime, with several nuances tailored to reflect differences in the characteristics of the respective markets and technologies.

Administrative Cap

The cap acts as a “soft” limit on the annual revenue that can be achieved by the project. Where revenues exceed the pre-determined cap, in a given annual period, 70% of the excess is returned to consumers, while the remaining 30% is retained by the project. This represents a key difference from the interconnector regime, which applies a hard cap, and is intended to preserve the asset owner’s incentive to maximise revenues even once the cap has been exceeded.

Following a period of consultation, Ofgem has decided to adopt a single administrative approach to determine the unique cap for each eligible asset (moving away from the two-approach methodology, administrative and competitive caps, proposed prior to consultation).

The level of the administrative cap will be determined in large part based on the project’s Regulatory Asset Value (RAV). The RAV represents what Ofgem takes to be the project’s value measured by its economically efficient costs, and comprises development expenditure, capital expenditure, spares, interest during construction (IDC) at an Ofgem-specified rate, transaction costs and replacement costs.

The project-specific cap is then calculated based on opex, decommissioning costs, depreciation of the RAV, the return on the RAV and a tax allowance. The return component will be calculated by applying a notional cost of equity to 100% of the Regulatory Asset Value (RAV). This is a real return (indexed at CPIH), derived from the output of a CAPM model, and will be subject to change based on economic conditions at FID. The revenue sharing mechanism above the cap also allows realised project returns to exceed this level.

Floor(s)

As the name suggests, the floor acts as downside protection, ensuring a minimum level of revenue is achieved in each annual period – mitigating the risk of adverse merchant conditions leading to returns insufficient to cover efficient costs and debt service requirements of the project.

Unlike the cap, project-financed assets can access two distinct floors: an administrative floor and an actual cost of debt (ACOD) floor. Before setting out how these are calculated, it is worth highlighting what these are intended to capture and why the distinction is important.

The administrative floor mirrors the cap in being derived from the project’s RAV, and is therefore a measure of what Ofgem thinks the floor should be; the ACOD floor reflects the project’s actual debt service obligations and is therefore a target guarantee level which lenders would (ideally) seek before providing project finance. Where projects benefit from support at a level below the ACOD floor but above the administrative floor, they are required to make repayments to consumers, on an annual basis via the system operator, before any equity distributions can be made. This ensures a level playing field between balance sheet-funded and project-financed assets and shields consumers from the cost of excessive gearing (which is capped at 80% by Ofgem or such lower level as dictated by lenders’ credit requirements) or overpriced debt.

Administrative floor

Follows a similar ‘building-block’ approach to the administrative cap, with the key difference being the return on RAV component. For the floor, this is based on a notional cost of debt, rather than the notional cost of equity, with the cost of debt determined using a low investment grade benchmark index as at the relevant reference date.

Building blocks of the administrative cap and floor levels

Actual cost of debt (ACOD) floor

Ofgem recognises that the administrative floor may be insufficient to cover the debt service requirements of project-financed assets. Projects can therefore elect to also benefit from an ACOD floor, which is based on the actual financing terms achieved through a competitively secured financing process. The ACOD floor is intended to cover only the project’s debt service obligations and is thus calculated independently to the asset’s cost base / RAV. The administrative floor is derived from the RAV, which is akin to an accounting measure of the asset’s value; in contrast the ACOD floor is based on the project’s actual cash financing requirements. But cashflows can be volatile, and so further work will be required to ensure that the guarantee provided by the ACOD floor succeeds in protecting lenders.

Financing considerations

The similarities with the existing interconnector C&F regime, which has successfully supported project finance, provide a strong precedent for the bankability of the LDES framework. Some of the key financing considerations include:

Revenue certainty

The ACOD floor guarantees lenders that the project will have sufficient cash flow, on average, to service 100% of their annual debt service obligations, which will translate to more aggressive debt sizing and gearing potential for successful projects. This will provide lenders with more comfort than a typical floor structure we have seen for shorter duration batteries, whereby the floor level is often below the lender breakeven amount.

Availability and liquidity

Whilst the floor provides considerable lender comfort, there are conditions attached. For LDES assets to be eligible to benefit from floor top-ups in any annual period, they are required to meet a project specific minimum availability threshold (MAT), which will likely be an area of lender focus and sensitivity analysis. In addition, to the extent that there is a misalignment between the timing of LDES floor payments and debt service obligations becoming due, lenders may require some form of liquidity reserve account to manage any temporary periods of cash shortfalls. This isn’t solely a feature of annual floors vs semi-annual debt payments; the floor is calculated as an average over the debt life, rather than on a period-by-period basis as is typical for project finance debt sculpting. This creates cash flow timing and inflation risks that need to be managed.

Optimisation constraints

To avoid cannibalisation of unsubsidised short-duration batteries, it remains unclear whether LDES assets will face restrictions on trading strategies or market participation. Lenders will require any such restrictions to be fully reflected in the merchant revenue assumptions.

Debt tenor

As is typical with other government support schemes across renewable technologies, we would typically expect lenders to be comfortable with extending the debt tenor out until near the end of the regime length, possibly with a 1–2-year tail, depending on the strength of the warranty package or expected asset life. Ofgem currently assumes a 25-year regime length as its default assumption; however, developers can request for the final duration to be longer or shorter depending on the specific technology and project characteristics.

Asset optimisation and offtake strategy

The C&F regime is compatible with floors, tolls and virtual tolls, but developers should consider how these structures interact with the C&F, including the allocation of merchant upside/downside and which associated costs are eligible within the C&F cost base. This will be key to optimising project economics and debt capacity.

Technology specific factors

Some factors are specific to the technology in question e.g. asset life, MAT, technology track record, degradation etc. and should also be carefully considered during the financing process.

Our approach

Elgar Middleton has advised on over 2.1GW of BESS transactions across both debt and M&A, including raising £1bn+ of debt across a range of offtake strategies, including tolls, floors, financial tolls and fully merchant structures. This breadth of experience has given us a deep understanding of the technical and commercial aspects of the dominant technology in the LDES Cap and Floor regime and positions us well to structure complex transactions and navigate the financing and revenue considerations outlined above.

If you are considering a financing of a UK LDES project, we would be delighted to discuss how our experience can help you navigate the complexities and secure an optimal outcome.

Elgar Middleton is delighted to extend our partnership with Field by closing 1GWh of BESS senior debt financings across two transactions within a week.

Hartmoor is a 200MW 4-hour asset in North East England; its strategic importance lies in its ability to offer grid stability services and its proximity to both the Hartlepool nuclear power station and the Dogger Bank offshore wind farm. The asset was financed through a term loan, LC facility, and DSRF from ABN Amro and Rabobank.

The Hartmoor financial close was pipped to the post by the Keith site, a 39MW 5-hour system in Scotland (north of the congested B4 boundary) that represents the longest duration asset to reach financial close in GB to date. Debt was provided by ING and Rabobank as an extension to the previous facility arranged by Elgar Middleton in early 2025.

All assets are optimised by Gaia, Field’s in-house trading platform, and both portfolios are supported by day-ahead swaps to reduce revenue volatility to the benefit of both debt and equity providers.

Flexible Connection Agreements (FCAs) are aiming to enable the rollout of German BESS in a way that ensures grid stability can be maintained. This article looks at the impact of these on the financing of BESS assets and the complexity they can add.

Across various markets, grid constraints are leading to connection delays as grid operators look to manage large queues of renewable and energy storage assets which are looking to connect to systems that in most cases were not built to manage increasingly intermittent generation, as well as a growing mismatch between supply and demand, both temporally and geographically. While physical grid infrastructure is being upgraded on a large scale, this is clearly a longer term solution and with ambitious targets around renewables and increasing demand for electricity there is a need for shorter term solutions as well.

In the UK, NESO’s connection reform aims to re-order the connections delivery pipeline to prioritise the most well-developed projects and those in more favourable locations. This aims to provide more certainty on connection dates although has led to many projects facing significant delays. There are also increasingly non-firm connection offers given to manage these queues, and a similar approach is being rolled out on some scale in Germany.

Flexible Connection Agreements (FCAs) are bilateral agreements between the asset owner and the Transmission/Distribution System Operator (TSO/DSO). They allow the owner to connect to the grid significantly faster than would otherwise be the case in return for accepting certain constraints. They may also reduce grid fees such as the Baukostenzuschuss (BKZ) which is often a material component of the capex for German BESS projects.

Why accept an FCA?

Another key reason that many BESS assets are signing up for FCAs is the risk of further regulatory change, particularly in the shorter term. There is a current 20 year exemption to grid fees for BESS assets commissioned prior to August 2029 which the German Federal Network Agency (BNetzA) has confirmed will not remain in place indefinitely – the final framework for these grid fees is due around the end of 2026 and only assets with FID taken prior to this being published will benefit from the ‘grandfathering’ protections from capacity fees, which are the known component that were announced by BNetzA on 27 May 2026. However, dynamic grid fees are still coming and are excluded from this ‘grandfathering’ .

As well as the financial impact of not utilising a valuable assets, there is also the risk of a materially worse project at the point of connection as these grid fees may impact returns more than an FCA would (although the results will be highly asset specific and dependent on duration, location etc). Of course, assets connecting post August 2029 may also be forced to connect under FCAs as well as paying the grid fees – physical upgrades to grid infrastructure will take time and every suggestion is that FCAs are here to stay.

From the perspective of the TSO/DSO, the constraints imposed under these FCAs are able to help them to manage battery dispatch and ensure that the grid remains able to operate. Importantly, they are not standardised, so the impact can vary significantly from project to project. Some common constraints imposed under FCAs include (but are certainly not limited to):

• Curtailment – limits ability to charge and discharge into the grid during certain times.
• Ramp rates – limits ability to change the power input/output
• Ancillary services – limits participation in these markets (e.g. a Frequency Restoration Reserve (FRR)).

Some of these constraints may also only apply to parts of the assets capacity and so may be imbalanced between the import/export legs.

These can have significant impacts on asset revenue (your preferred market advisor/revenue curve provider would likely be capable of modelling these), but they also add complexity to various other key parts of the financing process.

Managing additional complexity

Many lenders are uncomfortable with high levels of merchant risk in BESS and the presence of fixed revenues improves the terms that can be achieved. Assets that are configured to benefit from synthetic inertia contracts can achieve small amounts of fixed revenue from these, but for the majority of lenders, more fixed revenue is preferred if not required.

Well established route to market solutions such as tolls and floors have always seen some price variation across assets but these differences will grow and grow as more assets are looking to sign up to FCAs which will reduce the prices that can be achieved. Day ahead swaps/other similar products won’t necessarily see such price variations but will require more thought at the structuring stage as to how the ‘floating’ legs paid out to swap counterparties relate to the actual revenues that can be earned by BESS in an environment where these revenues are being impacted by FCAs. Off-the-shelf solutions won’t work in the same way across different assets.

Our approach

An experienced financial advisor can assist with analysing these different structures, compare equity returns, and providing analysis of various terms received from lenders, but we aim to go further at Elgar Middleton. We are involved across all aspects of the transactions we work on and so take a proactive approach to structuring them. Our technical understanding allows us to look at each project/client individually and structure around constraints (whether FCA imposed or otherwise!), achieving the most attractive terms possible with our comprehensive approach to term sheet negotiations.

Elgar Middleton has closed almost 2GWh of BESS, both RtB sales and numerous debt transactions using a whole range of RtM strategies and understands the unique idiosyncrasies of each. Our experience in the UK market as well as more recently in Germany makes us very well placed to navigate the issues discussed in this article.

If you are planning a financing or considering a sale in the renewables sector and want an advisor who will not only secure capital but also manage the complexity of the process, we would be delighted to speak with you.

The UK BESS market has moved beyond its infancy and into a phase defined by scale, structural reform, and financial sophistication. This article explores the structural fundamentals, revenue dynamics, and bankability considerations shaping UK BESS in 2026 and beyond.

The United Kingdom has established itself as one of the most advanced and investable battery energy storage system (BESS) markets in Europe. This position reflects both structural features of the UK power system and deliberate policy choices that have prioritised decarbonisation, system flexibility, and market‑based solutions. Rapid deployment of offshore and onshore wind, alongside increasing solar penetration, has materially changed the generation mix. At the same time, the closure of coal-fired power stations and the aging of the gas fleet have reduced the availability of conventional dispatchable capacity. The result is a power system characterised by greater volatility in wholesale prices, more frequent imbalance events, and increasing reliance on the balancing mechanism and ancillary services to maintain stability.

Battery storage has emerged as a highly effective response to these dynamics. BESS assets can respond within milliseconds, arbitrage intraday and capture real time price spreads, to either realise a gain prior to physical delivery or dispatch, as well as provide essential system services such as frequency response and reserves on standby.

BESS occupies an unusual but attractive position. It lacks the long-term revenue certainty associated with government backed contracts such as Contracts for Difference (CfDs), yet it avoids many of the risks inherent in traditional power generation such as fuel supply uncertainty. This makes BESS a hybrid asset class: riskier than contracted renewables, but with materially higher return potential especially given the price reduction of storage systems over the past two years. Mid to upper teen returns is a reality when senior debt is factored into the capital structure whereas solar CfDs achieve an upper single digit return.

Planning Pipeline

The UK has one of the deepest BESS pipelines in Europe, reflecting the growing need for flexibility in a power system with rising renewable penetration with deep liquid wholesale and balancing markets.

Selected renewables technology capacity by year in which planning permission was granted (Source: Cornwall Insight)

Planning approvals have accelerated significantly. Around 30GWh of BESS capacity was consented in 2025, almost double the 2024 level, the highest annual total to date, with larger projects with longer duration becoming the norm, numerous single site schemes now exceed 1GWh. Cumulatively, approved projects now exceed 160GWh, while around 22GWh is under construction and over 13GWh is operational. Strong demand remains for well developed ‘Ready to Build’ BESS projects and Elgar Middleton is in contact with over 100 interested and willing buyers for the right project.

Grid Reform

The UK is undergoing the most significant reform of its electricity grid framework in decades, driven by the urgent need to connect low carbon generation, storage, and demand more quickly, while supporting the Government’s Clean Power by 2030 target. The centrepiece of reform is a wholesale overhaul of the grid connections process, led by the National Energy System Operator (NESO). Historically, grid access operated on a “first come, first served” basis, resulting in a severely congested queue of more than 700GW of generation and storage projects, many of which were speculative or inactive. Under the new “first ready, first connected” regime, projects must demonstrate planning progress, land rights, and strategic alignment with national energy needs to retain or secure a connection offer.

As of late January, NESO announced the 2026/27 transmission projects will not receive their offers by the end of January putting increased pressure on 2026/27 connection dates for both transmission and distribution projects. Many projects are in a state of limbo with neither equity investors nor debt providers willing to commit capital until the actual connection time and cost are confirmed for 2026/27 projects. With long lead times of 12-15 months for such item as switchgear and transformers, from order to installation timeframes means 2026 is near impossible for pre-construction projects and 2027 is becoming increasingly challenging. This could result in a depleted pipeline of constructed projects in 2026/27 putting even more pressure on the 2028 to 2030 rollout.

Revenue Stack Fundamentals

UK BESS revenues are typically derived from a diversified “revenue stack” rather than a single contracted offtake. The core components include:

• • Wholesale Market (WM), capturing intraday and day-ahead price spreads;
  • Balancing Mechanism (BM) participation, responding to system imbalances;
  • Ancillary services, such as Dynamic Containment, Dynamic Regulation and Dynamic Moderation whereby assets are available to maintain grid stability and which are procured close to real time; and
  • Capacity Market (CM) contracts, rewarding assets’ contribution to security of supply and which are often secured well in advance of construction.

The composition of the revenue stack is fluid. The suite of ancillary services has changed over time, and the current products historically offered attractive margins, particularly during early market phases when competition was limited. However, these revenues have shown rapid price erosion as new capacity enters the market and markets saturated. In contrast, WM and BM revenues are deeper and structurally more durable, but all trading revenues are inherently volatile and exposed to macro drivers such as gas prices, interconnector availability, and weather.

For debt providers, the critical question is not whether any particular revenue stream(s) can form a business case for a storage asset but whether a combination of these can be underwritten with sufficient confidence over the debt tenor. Fully merchant revenue stacks may be acceptable for equity investors seeking upside, but they pose challenges for lenders required to size debt against downside scenarios. As a result, bankability is increasingly linked to revenue stabilisation mechanisms; however, where lenders have a high degree of confidence in and understanding of the revenue forecasts, material levels of non-recourse debt can be supported by merchant cashflows for appropriately structured projects.

Revenue Volatility, Forecasting and Duration

Market forecasting lies at the heart of BESS financing and is often the most heavily scrutinised element of lender due diligence. Unlike contracted renewables, BESS revenues cannot be extrapolated from a fixed tariff or a single price curve. Instead, they require sophisticated modelling of, dispatch optimisation based on the appropriate level of foresight available to traders at the time. The modelling is more challenging still in less developed storage markets in which rules for market participants are still evolving. Most financings rely on independent market consultants to develop merchant revenue forecasts. These forecasts typically combine historical price data, forward market curves, and fundamental modelling of supply, demand, and capacity additions. Importantly, they also attempt to capture the impact of increasing BESS penetration on future profit pools, such as in ancillary services where saturation can (and did) occur quickly.

Sensitivity analysis is also critical. Lenders will test downside scenarios including reduced price volatility, faster than expected battery build out, and increased competition from flexible gas or new interconnectors. Unlike in the financing of renewable generators, lenders also need to consider the performance of the asset optimisers; this is typically covered both by sensitivity analysis but also by ensuring debt and equity providers are able to incentivise optimiser performance appropriately.

A further challenge for forecasters is that there is no such thing as a generic asset. Location (which informs the ability to capture outsize revenues in the BM) and technical parameters (including round-trip efficiency, degradation, and duration) are important inputs into the dispatch modelling. There is often an iterative process required to determine the best site configuration taking into account site-specific constraints (available land, planning permission, any grid limitations) and the economics of longer / shorter durations, higher / lower cycling, etc.

As a consequence of reduced cells prices and increased cell density the UK market can now support up to 4 hour duration as a realistic base case system, but analysis of market forecasters curves and cell prices has demonstrated this may not necessarily be optimal and a one size fits all is not the way forward. Elgar Middleton is working closely with a number of equity investors and debt providers to find an optimal solution for each client, taking into consideration round-trip efficiency, degradation, and durations ranging between two and four hours.

A further dimension is operational strategy: aggressive cycling to maximise short term revenue may reduce long term asset value through accelerated degradation. Elgar Middleton has structured loan agreements with a number of debt providers to offer equity investors maximum flexibility to cycle an asset aggressively when the market dictates it makes sense, while aligning short term dispatch strategies with warranty constraints, lifecycle optimisation and senior debt tenor by using structured upside and downside cash sweep structures.

Revenue Structures

The UK market has rapidly evolved with many optimisers now active in the market with a range of products. While the market is predominantly dominated by the big utility companies, other optimisers include dedicated boutiques with bespoke trading algorithms, energy trading desks of investment banks, equipment manufacturers and in-house specialists using their platform to manage their own assets. Leaderboards of all publicly traded markets rank the various optimisers performance, although the producers of those benchmarks would be the first to acknowledge their limitations – not least that they will not capture all revenue sources of the various optimisers.

Several contractual structures are now common:

• • Fully merchant optimisation, where a specialist provider operates the asset in return for a performance‑linked fee.
  • Tolling arrangements (physical or virtual), under which a counterparty pays a fixed or semi‑fixed fee for control of dispatch.
  • Revenue guarantees or minimum revenue floors, providing partial revenue protection in exchange for more limited upside.

From a lender’s perspective, the value of these contracts lies not just in reducing volatility, but in reallocating risk to parties better able to manage it. Counterparty credit quality, contractual tenor, benchmarking and termination rights are all debated at great length with lenders in order to find a bankable solution.

In the current market, the majority of clients of Elgar Middleton wish to maximise gearing in order to optimise equity IRR – and given the significant divergence between the cost of capital of equity and debt; structured debt significantly improves equity returns. As more assets reach operation and performance data accumulates, both optimisers and capital providers are converging on structures that balance risk sharing with economic efficiency, thereby improving overall bankability. Two years ago, floors were all the rage while tolls offered little value to equity investors given the relative pricing of floors vs tolls. Fast forward to today and the floor market is now thin while there is healthy competition between physical and virtual tolls and as duration increases, there is more flexibility to hedge only a portion of the total MWh to find an optimal mix of hedge vs merchant component in order to structure a highly geared project with equity upside.

Elgar Middleton undertakes this analysis using a bespoke financial model for each client as there are some subtle differences between each route to obtaining a level of contracted revenue capable of supporting high levels of debt.

Outlook for UK BESS Financing

The outlook for UK BESS financing is positive, but increasingly nuanced. Demand for grid scale storage is structurally supported by the UK’s decarbonisation trajectory, electrification of heat and transport, and continued renewable build out. As a result, BESS is likely to remain a core component of the UK power system for decades.

Not all BESS projects will be treated equally. Elgar Middleton can attest from the sale of our clients’ RtB projects that those that combine strong grid locations, strong phase 2 grid offers, low or no curtailment, longer duration and limited planning conditions will always attract strong interest.

Equity investors are rightly focussed on grid reform at the moment and concerned about the timing of (1) grid offers and (2) actual connection dates which has proved critical to some given the challenges of actually building out the upgraded grid network up and down the country.

Lenders are mostly concerned with revenue structures, cycling strategies and counterparty risk especially given the multitude of varying solutions available from the market but as more structured products become available debt tenor and levels of gearing are both increasing.

Elgar Middleton has closed almost 2GWh of BESS, both RtB sales and numerous debt transaction using fully merchant, floors and tolls and understands the unique idiosyncrasies of each. Ultimately, successful financing of UK BESS projects will depend on a clear understanding of where risk truly sits and structuring projects accordingly.

Project management sits at the heart of every successful financing. At Elgar Middleton, it is a core capability that sets us apart and drives smoother processes and better outcomes for our clients

In the project finance industry, headlines typically focus on who provided the debt, the structure of the deal, or the scale of the assets involved. What often goes unnoticed, however, is the orchestration that sits behind every successful close.

Complex financings require the input of multiple advisors – legal, technical, insurance, tax, and market consultants – each with their own specialist language, priorities, and deliverables. Without strong project management, these parallel workstreams risk misalignment, delays, or even jeopardising bankability.

At EM, we believe project management is not a side task – it is a core capability. It is one of the ways we distinguish ourselves as a financial advisor, ensuring that complex transactions run smoothly, efficiently, and with fewer surprises.

Our approach brings structure and momentum to every financing process, giving clients confidence that all moving parts are being managed in a coordinated and proactive way.

Turning Complexity into Coordination

EM typically runs the Request For Proposal (RFP) processes for all key advisors on a debt raise, supporting the client in selecting them; as we know the expected scope of lenders will expect we can streamline the due diligence and also ensure there is no overlap between advisors – the most material of which is any duplication of work between the borrower’s lawyers and the lenders’ lawyers – which can result in a substantial cost saving in addition to efficiency. EM also manages the entire execution process through to financial close; this means coordinating weekly calls across all stakeholders, ensuring high quality deliverables are produced on time, and bridging the inevitable gaps between disciplines. EM often kick-start workstreams long before a borrower or its other advisors would necessarily commence them, (for instance direct agreements or title searches) which otherwise can be left to the last minute.

We actively engage with each workstream, and our team is fluent in the language of each discipline. This “translation” role is often the difference between issues being resolved in real time or becoming bottlenecks late in the process.

For example, when the lender’s legal advisor requires confirmation on battery warranties, we ensure the lender’s technical advisor provides clear, bankable input. If market consultants update their revenue forecasts, we work with the technical advisor to confirm that assumptions are accurately reflected in the technical model. And when insurance advisors flag gaps in cover, we make sure these are addressed in the contract suite before they create a financing risk.

Tangible Benefits for Clients

For our clients, this hands-on project management translates directly into better outcomes. By identifying and resolving issues early, we reduce execution risk and prevent costly surprises. With all workstreams aligned and momentum maintained, transactions move more quickly to close, saving valuable time and management focus. At the same time, cohesive and comprehensive deliverables give lenders greater confidence.

In short, EM allows sponsors to concentrate on growing their business and developing projects, while we drive the financing to completion.

Most financial advisors provide good NPV analysis of the term sheets submitted as part of a financing process but EM goes much further. EM has a bespoke term sheet for each renewables sub-sector and these are well understood by all active lenders in the UK market. Detailed term sheet negotiations not only make commercial sense but increase efficiency; this approach gives us existing precedents with most competitive UK lenders and therefore fast tracks the facility agreement negotiations – again, saving time and fees.

A Unique Approach in the UK Market

This level of embedded project management requires not only transaction expertise, but also a deep technical understanding and a willingness to take ownership of the detail. For EM, it is part of our DNA.

We see our role not just as financial advisors, but as the glue that binds every workstream together – giving sponsors and lenders the confidence that their transaction is being advanced on all fronts.

If you are planning a financing or considering a sale in the renewables sector and want an advisor who will not only secure capital but also manage the complexity of the process, we would be delighted to speak with you.

Elgar Middleton is please to have advised Terra One on the cross-border mezzanine financing to support the build-out of their German battery storage portfolio.

Elgar Middleton is pleased to announce its role as exclusive financial advisor to Terra One on securing up to €150 million in mezzanine financing from Aviva Investors, supporting the build-out of a pipeline of battery energy storage system (BESS) assets across Germany.

The investment will be used to fund asset level equity contributions toward the construction and operation of a large portfolio of grid-scale battery projects, representing a critical step in advancing Europe’s energy transition. The facility structure allows for drawdowns against a broad pool of eligible projects and includes an accordion feature to support future growth.

Importantly, it enables Terra One to build out and wholly own its BESS portfolio without dilution, while retaining full flexibility to maximise trading revenues through the use of its proprietary optimisation software and in-house trading team.

The transaction forms part of a wider capitalisation strategy, enabling Terra One to invest up to €750 million into its BESS platform – with a target of deploying approximately 3 GWh of storage capacity across the continent.

 

Elgar Middleton is pleased to have advised SAE on the financing of the 120MW Afon Wysg BESS asset.

Elgar Middleton is pleased to announce its role as exclusive financial advisor to SAE Renewables (“SAE”) on the financial close of the 120MW / 240MWh AW1 battery energy storage system (BESS) project, located in Uskmouth, South Wales.

The financing structure combined multiple capital sources across several layers of the capital stack. SAE’s equity contribution was underpinned by a combination of internal funding, a £8.5m corporate-level loan from Cardiff Capital Region (CCR), £9 million of proceeds from the sale of project land to Electric Land, which it subsequently leased back, and a contribution from a global renewable energy group as minority investor. Senior debt of £45.3 million was provided by Norddeutsche Landesbank (Nord/LB).

The AW1 project has a contracted grid connection date of October 2026 that will allow for project commissioning, and an anticipated full commercial operations start date during Q1 2027. It is SAE’s flagship project within its pipeline at the Uskmouth Sustainable Energy Park, which has the potential to be one of the largest battery storage sites in the UK. The successful financing establishes SAE’s continued commitment to renewing the Uskmouth site and surrounding area.

This transaction highlights Elgar Middleton’s proven track record in delivering complex, multi-party financings for cutting-edge energy infrastructure. Our team worked closely with SAE and all counterparties to design and execute a tailored capital structure that met the project’s unique commercial and strategic objectives.

For more information about our work in the energy transition and battery storage sectors, please contact the Elgar Middleton team

Elgar Middleton is pleased to have advised Cambridge Power on the sale of their co-located BESS/solar asset.

Elgar Middleton is pleased to announce its role as exclusive financial advisor to Cambridge Power on the successful sale of a co-located 49.9MW / 100MWh battery energy storage system (BESS) and 70MWp solar PV project to AGR Renewables .

The ready-to-build project, located in Yorkshire, represents a significant contribution to the UK’s growing pipeline of co-located renewable energy assets and highlights the continued investor appetite for high-quality development sites within the solar and storage sectors.

AGR Renewables will take the project forward through construction and into operation, continuing its investment in flexible, renewable infrastructure across the UK.

This transaction adds to Elgar Middleton’s extensive track record in the UK battery storage sector, where the firm has advised on a wide range of M&A and project financing mandates across both standalone and co-located BESS projects.

Elgar Middleton is pleased to have advised Field on the financing of their latest portfolio of assets.

Elgar Middleton managed the financing from lender selection through to financial close. Rabobank and ING provided £42m of debt comprising a term loan, DSRF and VAT facility.

The term loan is to be used to fund the construction and operation of 3x 2-hr BESS assets. Field’s in-house trading platform Gaia will be utilised for asset optimisation once the assets reach operations. The transaction included a number of structural protections for the lenders for a range of different scenarios to enable them to offer higher gearing than would otherwise have been available and to offer Field maximum operational flexibility.

This is the second financing on which Elgar Middleton has advised the Field team and we remain committed to assisting Field in their efforts to grow their UK and European portfolios.

Without wishing to bring politics into it, one may wonder whether endorsing Karl Marx might be somewhat career-limiting for a representative of a firm whose raison d’être is to facilitate the efficient allocation of capital. But in one respect, at least, he had a point. One of his many disputes with classical economists concerned division of labour: whilst Adam Smith, famously, saw this as a foundation for economic progress, Marx saw it as a way to achieve bad results (albeit he may have accepted that it would achieve those bad results pretty quickly and effectively). Where we as a firm are out-and-out Marxists is that we do not believe that division of labour leads to good financial models or good financial advice.

First, a bit of context. In the world of energy transition assets or businesses, financial models fall broadly into three categories: appraisal, transaction, or operational. Appraisal models are used to assess investment opportunities and need to be flexible to easily evaluate different financing or revenue structures; transaction models are used to support specific investments and need to be a precise reflection of the underlying asset or business; and operational models are used as a monitoring or reporting tool that need to accommodate actual data (some of which may not have been envisaged in earlier model iterations). These types of models have different and often competing priorities – but the approach to model building and maintenance often fails to reflect this.

A caricature of your average financial modeller in energy and infrastructure teams – whether advisor or principal side – is the (or, possibly, one of the) junior team members who, after a year or two, will graduate from the modelling team and join the ranks of their esteemed colleagues who might occasionally be permitted to talk to a human being that works at a separate organisation. This is equally applicable irrespective of the type of model being developed. This sort of division of labour means that there is correspondingly a split between the individuals who build and operate the model, and those who interpret the results and best understand the broader context.

One can understand the appeal of such a team structure and why it is as common as it is. It might be appropriate for appraisal modelling (where ‘close enough’ may be good enough, and where everyone is working at risk) or for operational modelling (where asset management teams need ‘pure’ modelling support to integrate a new front end to the model which better reflects reality). It is also quite profitable as it involves delegating work that can be done fairly well to cheaper people. However when it comes to transaction modelling, ‘fairly well’ or ‘close enough’ often won’t cut it.

Risks

The big risks associated with the division of labour come from a model giving the wrong answers without anyone being any the wiser. It isn’t hard to see how this might come about: say, a new set of model inputs arrives and there’s a cost missing; or a revenue projection arrives and there is an embedded implicit assumption around asset availability that is inappropriate for your site – but there isn’t the knowledge or experience base to query these inputs. As a result, you end up a few £m out on capex or you overstate your revenues by a few %.

Whilst modelling oversights are best avoided at any stage, there is a greater chance of minimising the impact in appraisal models; significant contingencies are frequently included to manage the unknown risks, and errors may only lead to an opportunity cost based on a misevaluation. But as part of a transaction these mistakes can be fatal: you end up basing an investment decision on a flawed model. Routine due diligence checks don’t always pick up these points; for example, a model audit will check that the model inputs align with documentation, but they won’t tell you if there’s something missing from or inappropriate about said inputs.

Another risk is highlighted by comparing two approaches: do you model the negotiations, or do you negotiate using the model? Division of labour between negotiator and modeller nudges you towards the former, but the latter is clearly preferable – you don’t want to agree principles that when quantified turn out to be unworkable or suboptimal. However, if it is to be delivered then it is necessary for the negotiating team to have a deep understanding of both the model and the market.

An added bonus of negotiating from the model is that principles that are slightly ambiguous can often be firmed up in a manner suiting both borrowers and lenders. Such opportunities are liable to be missed if the person staring at the spreadsheet has only a limited awareness of the broader deal context. We’ve seen this on a few occasions on recent UK BESS deals where we have found ways to meet certain covenants imposed by lenders without making overly large concessions; the alternatives were often high cost (to equity) and low benefit (to everyone).

Value

As well as reducing downside, minimising friction between the deal team and the modelling team (ideally by making them one and the same) has clear ‘base case’ benefits.

We typically find that there is a time saving to be had because modelling can be better integrated into the deal as a whole and it avoids too much back-and-forth between those doing the work and those checking the work. An experienced and informed modeller will have (or will more rapidly develop) a good sense of what analysis is necessary or helpful, thereby improving the quality of output. Instead, a modeller who is divorced from the broader transaction often ends up running scenario after scenario without any great appreciation for the end goal. This is supposed to get to the same point eventually, and perhaps it will – but at best it will take longer.

There is also an opportunity for extracting the most from every pocket of value when modelling can be done by those who know how to get the best out of the model. To give an example of this kind of financial engineering: a typical approach to debt sizing around multiple constraints is to assess the debt (profile and amount) in a lender base case, to assess the debt (profile and amount) in a downside case, and to take the lower of the two. This guarantees meeting one of your two constraints, but tends to leave projects both undergeared and at risk in certain periods (i.e. lower return, higher risk). Instead this should be approached period-by-period, which effectively requires the running of multiple cases concurrently. In order to achieve this, some (but not an enormous amount of) technical modelling skill is required. However, if you are asking the modeller the questions “does this work for lenders?” and “is this fully optimised?”, it will take more than just that modelling skill to give you confidence in their answers – it takes some transaction knowledge and transaction experience.

Conclusion

Financial modelling in support of transactions should not be treated as a standalone workstream. At least one of the individuals responsible for knowing pretty much everything about the broader deal should also know pretty much everything about the model: where the inputs come from, how robust they are, how they are treated in calculations, and where the resulting pinch points may be.

This is (and has always been) our preferred approach at Elgar Middleton where transaction experience and expertise is fully integrated with the financial modelling. Delivery of a transaction is not the same as the sum of the parts – too much division of labour and you will end up with a worse, riskier, deal. Financial modelling is not the only component that is extracted from the broader transaction work, but it is often the most tempting; it is a temptation that should be resisted.