When municipal utilities negotiate for a battery storage system, the first question is almost always the same: “What does the system cost?”<\/p>\n\n
It’s an understandable question. The investment sum is tangible, comparable, and appears as a clear figure in the offer. But it is also the most misleading key figure in the entire BESS business case. <\/p>\n\n
What determines whether your storage project is still profitable in year 10 is not the costs on the day of commissioning. It is OPEX, degradation, augmentation, and WACC \u2014 factors that are rarely included in the offer but significantly shape the business case over 15 years. <\/p>\n\n
This article explains which cost blocks require a complete TCO picture, where the typical blind spots lie \u2014 and why the financial buyer ultimately needs a stress-tested business case with reliable scenarios, not a promise of returns.<\/p>\n\n
The CAPEX calculation for a BESS project appears complete at first glance: battery containers, power electronics (PCS), transformer, grid connection costs, engineering, and commissioning. Some calculations also include permitting costs and initial spare parts. <\/p>\n\n
What is regularly underestimated:<\/p>\n\n
Grid connection costs as an uncertainty item.<\/strong> The actual costs for grid connection and substation are rarely precisely plannable at the start of a project. Grid operator requirements, cable length, and transformer sizing can cause real connection costs to deviate significantly from the initial estimate. Those who plan with too narrow a CAPEX corridor here will face their first stress test even before construction begins. <\/p>\n\n Ancillary project costs and internal expenses.<\/strong> External project managers, internal capacities for tendering and awarding contracts, legal advice for EPC contracts \u2014 these positions are real but rarely fully included in the initial budgeting.<\/p>\n\n Reserves for cost increases.<\/strong> Fluctuations in material costs, extended delivery times, or construction delays are not uncommon in infrastructure projects. A TCO model that does not include a sensitivity analysis over the CAPEX corridor (e.g., \u00b115%) is out of touch with reality. <\/p>\n\n In short: CAPEX is not a single figure \u2014 it is a distribution. Ignoring this provides controlling with a false sense of accuracy. <\/p>\n\n While CAPEX is a one-time expense, OPEX costs impact profitability year after year. Over a 15-year operating period, they add up to a significant portion of total costs \u2014 and are often set too optimistically in the initial business case. <\/p>\n\n Overview of relevant OPEX blocks:<\/p>\n\n O&M (Maintenance and Troubleshooting).<\/strong> Regular maintenance intervals, remote monitoring, response times for malfunctions \u2014 these are contractual services that come at a price. A well-structured O&M contract with clear SLAs (e.g., remote troubleshooting \u22642 hours, on-site service \u226424 hours) creates predictability. A poorly structured contract creates cost uncertainty during ongoing operations. <\/p>\n\n Insurance.<\/strong> Battery storage systems are high-value assets with specific risk profiles. Adequate property insurance (including business interruption) is necessary, but premiums are rarely included in the initial business case model. <\/p>\n\n Grid fees and auxiliary power.<\/strong> Self-consumption for air conditioning, control, and monitoring runs all year. Depending on the location and grid situation, changes in grid fee systematics (AgNes regulation) from 2029 onwards could additionally influence the OPEX calculation. A robust business case includes at least two scenarios for this. <\/p>\n\n Monitoring and Reporting.<\/strong> Operational transparency is not a luxury \u2014 regular performance reporting is standard for board resolutions, banks, and internal control. The costs for this are low but must be consistently considered. <\/p>\n\n A typical rule of thumb: OPEX over the lifetime is in the order of 1.0\u20132.0% of CAPEX per year<\/strong> \u2014 depending on system size, contract model, and location. For a medium-sized BESS project, this can account for a significant portion of total costs over 15 years. Underestimating this position optimizes the business case on paper \u2014 not in reality. <\/p>\n\n A battery storage system is not a static asset. Every charge and discharge cycle, every temperature fluctuation, every hour of operation leaves traces in its capacity. This effect is called degradation \u2014 and it is the most frequently underestimated factor in BESS business cases. <\/p>\n\n What degradation specifically means:<\/strong> LFP batteries (lithium iron phosphate), today the standard for large stationary storage, typically lose between 1.5% and 3% of their usable capacity per year. After ten years, the usable capacity can therefore be significantly below the nominal value \u2014 which has direct implications for achievable revenues. <\/p>\n\n The revenue effect.<\/strong> Anyone who needs to maintain a certain capacity for FCR prequalification requires a minimum capacity. Falling below this threshold means losing prequalification \u2014 and thus a central revenue driver. A business case model that assumes the same revenues in year 12 as in year 1 is not a model \u2014 it is wishful thinking. <\/p>\n\n When augmentation becomes economical.<\/strong> Augmentation means replacing or supplementing battery modules to restore capacity to the required level. When this step makes sense depends on the CAPEX for retrofitting, the lost revenues due to capacity loss, and the system’s technical options. Modular BESS systems \u2014 like AXSOL’s ECS platform \u2014 significantly facilitate augmentation because a full migration is not necessary. <\/p>\n\n What must be in the business case.<\/strong> Degradation is not an unknown \u2014 it can be modeled. A robust TCO model shows the capacity path over 15 years, quantifies the revenue effect, and defines the decision point for augmentation (including CAPEX reserve). <\/p>\n\n The most common mistake in a BESS business case is not a wrong number \u2014 it’s a wrong presentation. Presenting controlling with a single return metric (e.g., “IRR: 7.2%”) provides a point forecast. Point forecasts are misleading in infrastructure projects because they suggest certainty where there is none. <\/p>\n\n What the financial buyer actually needs is a sensitivity analysis<\/strong> \u2014 and the tool for this is called Tornado Analysis.<\/p>\n\n How a Tornado Analysis works in the BESS context:<\/strong><\/p>\n\n The most important input variables are varied individually (typically \u00b110\u201320%), while all others remain constant. The result shows which variable has the greatest impact on profitability \u2014 visualized as horizontal bars, ordered by leverage (hence: Tornado). <\/p>\n\n Typical variables for municipal utility BESS:<\/strong><\/p>\n\n The result of a Tornado Analysis is not a reassuring statement. It is an honest one: “Here are the three levers that most strongly influence your business case. And here are the scenarios under which it still works \u2014 and under which it does not.” <\/p>\n\n “What happens to our business case if revenues fall or grid fees change from 2029?”<\/em> The financial buyer \u2014 CFO, controlling, strategy \u2014 does not need optimistic projection charts. They need a model that they can defend before the supervisory board without exposing themselves. <\/p>\n\n This specifically means:<\/p>\n\n Three scenarios, not one.<\/strong> Base Case (most probable assumptions), Downside Case (conservative revenues, increased costs, worse degradation), and Worst Case (combined stress across all significant variables). Anyone who only presents the Base Case is providing advertising, not an investment memo. <\/p>\n\n Break-even analysis.<\/strong> At what revenue level \u2014 e.g., FCR price in \u20ac\/MW\/h \u2014 does the project become unprofitable? This threshold makes the business case suitable for committees because it defines concrete monitoring points. <\/p>\n\n TCO predictability as a contractual requirement.<\/strong> A fixed-price EPC contract limits CAPEX risk. A long-term O&M contract with defined SLAs and a transparent price structure limits OPEX risk. Guarantee packages for availability, performance, and capacity \u2014 issued by a German GmbH as a contractual partner \u2014 create bankable collateral. <\/p>\n\nOPEX Predictability: The Silent Cost Drivers Over 15 Years<\/h2>\n\n
Degradation: When Capacity Declines \u2014 and When Augmentation Becomes Necessary<\/h2>\n\n
Sensitivity Analysis: Tornado Analysis Instead of Point Forecast<\/h2>\n\n
Variable<\/th> Why relevant<\/th><\/tr><\/thead> CAPEX<\/td> Offer price, grid connection deviations, cost increases<\/td><\/tr> Revenue level FCR\/aFRR<\/td> Market saturation, competition, volatility<\/td><\/tr> OPEX<\/td> Contract structure, energy prices, insurance<\/td><\/tr> Degradation rate<\/td> Cell technology, operating strategy, air conditioning<\/td><\/tr> WACC<\/td> Interest rate development, equity ratio, refinancing conditions<\/td><\/tr> Grid fee systematics from 2029<\/td> AgNes regulation, regulatory uncertainty<\/td><\/tr><\/tbody><\/table><\/figure>\n\n \n
What the Financial Buyer Really Needs: Not a Promise of Returns, but Robustness<\/h2>\n\n