Commercial electricity supply for industrial processing, manufacturing and refining is moving beyond the conventional relationship between a licensed supplier and a consumption meter. Large industrial buyers increasingly require a combination of price stability, renewable-energy access, operational resilience, controlled imbalance exposure and auditable electricity data that can be allocated to specific production lines and exported products.
Battery energy storage can support this transition, but behind-the-meter and front-of-the-meter batteries perform different commercial functions. A BTM battery protects and optimises the industrial site. An FTM battery shapes the electricity portfolio before power reaches the buyer. The strongest industrial supply model combines both layers with renewable generation, wholesale-market procurement, balancing services and a unified metering and MRV architecture.
A battery is not an electricity source. It stores energy purchased or generated at another point and releases it later. Its commercial value therefore depends on where it is connected, who controls dispatch, how charging energy is priced and identified, and which party receives the resulting savings or market revenues.
For industrial buyers, this distinction is essential. A battery located at a factory cannot automatically perform the same market function as a grid-connected asset, while an FTM battery cannot directly manage every operational issue within the factory’s electrical network. Treating the two configurations as interchangeable usually produces an incomplete supply contract and an unreliable investment case.
A behind-the-meter battery is installed within the industrial buyer’s connection boundary. It operates alongside the plant’s internal distribution system, production loads, onsite generation and main grid connection. The battery is therefore part of the industrial facility rather than a standalone electricity-market asset.
Its first commercial function is load optimisation. Industrial facilities rarely consume electricity at a constant level. Furnaces, crushers, mills, compressors, pumps, refrigeration systems, electrolytic processes and batch-production lines can create sharp peaks even when average consumption remains relatively stable. A BTM battery can discharge during these periods and recharge when the site load or electricity price is lower.
For a facility consuming an average of 20 MW, with peaks reaching 30 MW and annual demand of approximately 160 GWh, a 10 MW/20 MWh BTM battery would not replace the commercial electricity supply. It could, however, reduce short-duration peaks, absorb excess onsite generation, manage intraday price exposure and provide temporary support for critical processes.
The battery’s value would depend on the frequency and duration of the peaks. A two-hour battery may be appropriate where the plant experiences relatively short demand increases, but it would have limited value against an eight-hour production peak. Battery sizing must therefore begin with interval load data rather than a standard percentage of the site’s contracted power.
Clarion.Engineer’s BTM methodology uses at least 12 to 24 months of interval data, supported by production schedules, internal submetering, transformer loading, planned shutdowns and SCADA information. This establishes the relationship between electricity consumption and industrial output before the battery capacity is selected.
The commercial baseline can then quantify energy-cost reduction, peak limitation, renewable self-consumption, avoided production interruption and power-quality improvement. These benefits must be separated because they are not equally bankable. Electricity-price savings and contracted demand reduction can be measured directly. The financial value of resilience is more difficult to finance unless the buyer has documented the cost of outages and established an agreed method for calculating avoided losses.
BTM storage can also improve the commercial use of onsite solar generation. An industrial facility with midday solar production and a relatively flat or evening-weighted demand profile may otherwise export surplus electricity or curtail generation. The battery allows part of that production to be transferred to later consumption periods.
Wind integration is different. Wind production is less concentrated around predictable daylight hours and usually requires a broader portfolio and market-balancing approach. A factory-side battery can manage short deviations, but FTM storage and supplier-level portfolio management are more appropriate for shaping wind production into an industrial delivery profile.
A BTM battery can be owned directly by the industrial buyer, financed through an equipment lease, supplied under a battery-as-a-service structure or owned by the electricity supplier. Each option allocates investment and operational risk differently.
Direct ownership gives the industrial company full control over dispatch, operating data and savings. It also places the capital expenditure, technology risk, maintenance obligation and augmentation costs on the buyer’s balance sheet. A service model reduces initial capital requirements but requires a long-term contract defining availability, minimum savings, dispatch rights, payment structure and early-termination compensation.
For a representative 10 MW/20 MWh industrial battery, a planning-level installed investment envelope could be placed at approximately €7 million to €11 million, depending on cell technology, fire safety, civil works, power-conversion equipment, internal network reinforcement, control-system integration and warranty requirements. This is an indicative FEED-stage range rather than a tender price.
A well-structured BTM case may target an unlevered project return in the region of 10–16 per cent, with an upside case approaching 15–20 per cent where the battery combines peak reduction, onsite renewable optimisation, intraday price management and measurable resilience value. Returns weaken quickly when the asset is sized against assumed rather than recorded peaks, or when the operating strategy conflicts with the warranty.
The FTM battery performs a broader electricity-supply function. It sits on the grid side of the industrial buyer and may be developed as a standalone project, attached to a wind or solar plant, or incorporated into the supplier’s wider generation and trading portfolio.
Its principal role is to reshape variable electricity into a more commercially usable delivery product. Renewable generation rarely follows the consumption curve of an industrial plant. Solar production is concentrated during daylight hours, while wind production varies according to weather conditions and may be strongest when industrial demand is lower. The supplier must manage the difference between contracted generation and actual customer consumption.
An FTM battery can charge during surplus production or low-price periods and discharge when the industrial portfolio is short. It can reduce imbalance costs, support nominated delivery schedules and provide access to arbitrage, balancing and ancillary-service revenues. The same asset may also support congestion management or act as a hedge within a wider supply portfolio.
For the illustrative 160 GWh industrial buyer, a supplier could combine a renewable PPA covering 60–70 per cent of annual consumption with wholesale-market purchases and an FTM battery. A 25 MW/50 MWh FTM battery could reshape short-duration deviations and reduce exposure during expensive hours, but it would not convert intermittent renewable generation into a continuously firm baseload product by itself.
The remaining volume would continue to be managed through a licensed supplier or balance-responsible party. The supplier would nominate generation and consumption, purchase residual electricity, sell excess volumes and settle imbalances. The battery would reduce the portfolio’s shape and timing mismatch rather than remove the need for market procurement.
A representative 25 MW/50 MWh FTM asset could require approximately €13 million to €20 million, excluding unusually expensive grid reinforcement or land-related costs. The final envelope would depend on the connection voltage, substation works, grid studies, duration, dispatch requirements and revenue-market qualification.
An FTM investment may target a base-case unlevered return of approximately 11–17 per cent, with an upside case of 16–22 per cent where market spreads, balancing revenues and ancillary-service demand remain supportive. These returns are inherently more merchant than the BTM savings case. Lenders will therefore apply haircuts to revenues, require downside scenarios and place significant weight on contracted capacity or tolling arrangements.
A battery revenue stack cannot be treated as a collection of independent income lines. Arbitrage, balancing, ancillary services and industrial firming all compete for the same power capacity and state of charge. The commercial model must allocate priority between them.
An industrial supply commitment may require the battery to retain capacity for scheduled delivery, limiting its ability to pursue higher short-term market revenues. Conversely, unrestricted market dispatch can leave the asset unavailable when the industrial portfolio requires firming. The supply contract and battery dispatch agreement must establish which obligation takes priority and who carries the opportunity cost.
The commercial model can be structured through a tolling agreement, capacity reservation, shaped PPA or supplier-owned portfolio. Under a tolling arrangement, the industrial buyer or supplier pays for the right to dispatch a defined portion of the battery. The BESS owner receives a fixed availability payment and may retain some market upside.
A shaped PPA integrates renewable generation, storage and residual market supply into a defined delivery profile. The industrial buyer purchases electricity according to an agreed hourly or block structure, while the supplier manages the generation and storage assets required to meet it. The contract price includes the underlying energy cost, shaping premium, balancing cost, grid charges, environmental attributes and supplier margin.
An effective industrial electricity contract should make the shaping and firming costs visible. A low headline PPA price can be misleading when imbalance, profile, residual supply and battery-capacity charges are priced separately. The buyer needs a consolidated delivered-cost model rather than comparison of the generation price alone.
BTM and FTM batteries become most valuable when they are combined. The FTM system manages the external supply portfolio, while the BTM system manages the final industrial load. The supplier does not need to size the FTM battery against every short-lived factory deviation, and the industrial buyer does not need to use its internal battery to manage all wholesale-market risks.
The FTM asset can shape renewable production, manage market imbalances and deliver an agreed electricity profile to the connection point. The BTM battery then handles the remaining differences between the scheduled profile and actual plant operation. This creates a two-layer optimisation model.
The first layer includes renewable generators, the FTM battery, market purchases and the supplier’s balancing portfolio. The second layer includes the industrial meter, BTM battery, onsite generation, production loads and internal electrical network. The two layers are connected through dispatch instructions, commercial settlement and a common data architecture.
For manufacturing, the combined model can follow shift changes, batch production and scheduled maintenance. Manufacturing loads often provide some operational flexibility, particularly where production can be moved between lower- and higher-price periods without affecting output.
Processing facilities usually have more continuous loads and narrower operating tolerances. Mining and mineral-processing plants may combine crushers, mills, pumps and ventilation systems with different levels of flexibility. A battery can support short-duration peak management and process stability, while a supplier-managed FTM portfolio handles longer supply variations.
Refineries and large chemical facilities present a stricter reliability requirement. Their continuous processes, safety systems, compressors, pumps and control infrastructure cannot be treated as interruptible loads without detailed engineering assessment. BTM batteries can provide ride-through capability, power-quality support and temporary supply to selected critical systems, but they are not a substitute for properly designed emergency generation or redundant grid connections.
For these facilities, the commercial supply strategy must distinguish between energy supply, operational resilience and emergency power. Combining them into one assumed battery benefit can produce an overstated business case and an inadequate safety design.
The metering and MRV system is central to the combined structure. An industrial buyer may require evidence that renewable electricity was generated, delivered, stored and allocated to specific production activities. This is particularly important for companies producing steel, aluminium, fertilisers, chemicals, cement, processed minerals and other export-facing products.
The battery does not create renewable electricity or a low-carbon attribute. It changes the time at which electricity is consumed or delivered. The underlying electricity source, meter boundary, charging period, storage losses, discharge allocation and certificate treatment must remain traceable.
A credible system begins with revenue-grade meters and internal submeters. SCADA and energy-management-system data record charging and discharging, while data controls address quality, retention, access rights and missing intervals. The allocation methodology connects electricity consumption to production lines, batches or tonnes of output.
For BTM batteries, the MRV system must separate grid electricity, onsite renewable generation, battery charging, battery losses and discharged energy. For FTM batteries, it must connect renewable generation, wholesale purchases, battery operation, market settlement and delivered supply volumes.
Certificates or Guarantees of Origin can form part of the commercial evidence, but contractual attributes must be reconciled with physical meter data and production allocation. The same renewable volume cannot be claimed simultaneously by the generator, supplier and industrial customer.
This is particularly relevant where electricity evidence supports CBAM-related reporting or low-carbon product claims. Battery dispatch can improve hourly alignment between renewable generation and industrial consumption, but the claim remains dependent on the accepted emissions-accounting methodology and supporting documentation. The MRV architecture must therefore be designed before commercial operation rather than reconstructed later from incomplete data.
The Serbian implementation of such a model would require alignment between the industrial buyer, licensed electricity supplier, balance-responsible party, Elektromreža Srbije, Elektrodistribucija Srbije where the site is distribution-connected, and the applicable wholesale-market arrangements through SEEPEX and bilateral contracts. Grid connection, metering, balancing responsibility and market settlement must remain clearly allocated.
FTM connection risk is one of the most important constraints. A 12–18 month grid delay can postpone all commercial revenues while interest during construction, commitment fees, development expenditure and equipment-related costs continue. Depending on leverage and the expected revenue stack, such a delay can reduce equity IRR by approximately 2–5 percentage points and increase the required contingency or sponsor-equity contribution.
BTM projects may face a lower external connection risk where they use an existing industrial connection, but internal network studies and operator approvals remain necessary. Transformer loading, export limitations, protection settings and reverse-power flows can restrict battery operation. A BTM project can also be delayed by fire approval, insurer requirements, site shutdown availability or internal capital procedures.
Clarion.Engineer’s commercial supply model integrates these issues through a common FEED, Owner’s Engineer and project-management framework. The work begins with the industrial load, generation sources and commercial objectives before moving into battery sizing, grid configuration, metering, market access, contractual allocation and lender evidence.
The financial model should include base, downside and upside cases for energy prices, market spreads, imbalance costs, degradation, availability, curtailment, production changes and grid delays. The technical model must use the same operating assumptions as the commercial case. The warranty, dispatch strategy and revenue forecast must describe the same duty cycle.
The procurement package then allocates responsibility across the battery supplier, PCS provider, grid contractor, SCADA and EMS integrator, fire-protection contractor, licensed supplier and market operator. Commissioning tests confirm not only that the equipment has been energised, but that the complete electricity-supply structure can dispatch, meter, settle and document electricity as contracted.
The resulting model gives industrial buyers a commercially usable electricity product rather than a collection of separate technologies. FTM storage shapes generation and wholesale exposure. BTM storage protects the site and optimises final consumption. The electricity supplier manages residual volumes and balancing, while the MRV system preserves the evidence chain from generation and storage to the production line and final industrial product.