When Battery Energy Storage Pays Off, and the Risks Buyers Must Price In

A decade ago, grid batteries were a curiosity: small pilots, mostly funded to prove a point. Today, battery energy storage is one of the fastest-growing parts of the American power system, and the question for utilities, developers and large energy buyers has shifted from whether batteries work to whether a specific project will pay off. The answer depends less on the chemistry than on market rules, construction costs, safety codes and tax policy, each of which has changed in the past few years.

This guide explains how grid-scale batteries make money, what they cost, which rules shape their economics, and the risks that can turn a promising project into a stranded one. It draws on federal data, national laboratory research, regulatory orders and published safety standards rather than on any company’s marketing.

Why Batteries Went From Niche to Mainstream

Federal statistics make the scale of the buildout easiest to see. According to the US Energy Information Administration, operational battery storage capacity on the US power system reached 43.6 gigawatts by the end of 2025. Operators added another 8.3 gigawatts in the first half of 2026, bringing the total to nearly 52 gigawatts. The EIA reported in August 2026 that capacity grew by an average of 70% per year over the previous three years.

The pipeline remains large. Operators told the EIA they expect to bring roughly 54 gigawatts of additional battery capacity online over the following two and a half years, with 14 gigawatts planned for the second half of 2026 and 26 gigawatts for 2027. Planned capacity is not the same as built capacity, and projects slip for reasons ranging from interconnection delays to equipment shortages. Even so, the planned additions point to continued growth.

Much of that growth is tied to solar. The EIA notes that the country’s largest battery installations sit alongside solar plants, which makes sense: solar output peaks at midday, while demand in many regions peaks in the early evening. A battery that charges from solar in the afternoon and discharges after sunset turns cheap midday energy into valuable evening supply. TechAmerica.ai’s climate coverage has followed this shift as storage moves from add-on to core grid asset.

How a Grid Battery Earns Revenue

A battery does not generate electricity. It moves energy through time, and it can respond to grid signals in fractions of a second. Those two traits create several ways to earn money, and most successful projects combine more than one. Industry practitioners call this revenue stacking.

Energy arbitrage

The simplest model is to buy low and sell high. In organized wholesale markets, prices change hour by hour and sometimes every five minutes. A battery charges when prices are low, often during midday solar peaks or overnight, and discharges when prices climb. The margin depends on the daily price spread, minus round-trip efficiency losses. As more batteries enter the same market, they tend to narrow the spreads they rely on, a real long-term risk for projects that depend mostly on arbitrage.

Capacity payments and resource adequacy

Many grid operators and utilities pay resources to be available during peak demand, whether or not they are called. Batteries can qualify for these payments if they can discharge for the required duration, often four hours. Capacity revenue is attractive because it is more predictable than arbitrage, and it can underpin project financing. However, each market sets the rules for how much credit a battery receives, and those rules can change as more storage is added.

Ancillary services

Grid operators also buy services that keep frequency and voltage stable, such as frequency regulation and operating reserves. Batteries respond faster than most thermal generators, making these markets an early revenue source. These markets are relatively small, though, and can saturate quickly as storage competes for them.

Contracts and avoided costs.

Outside wholesale markets, batteries often earn revenue through long-term contracts with utilities, known as tolling agreements or storage service agreements, in which the buyer pays a fixed fee for the right to dispatch the asset. For commercial and industrial customers, a battery behind the meter can reduce demand charges, provide backup power and help meet internal decarbonization targets. In some cases, utilities use storage to defer substation or transmission line upgrades.

The value of each stream varies widely by region, so that the same battery can be a strong investment in one market and a weak one in another. Analysis covered by TechAmerica.ai found battery storage is now cheaper than gas peaker plants in 43 markets, another sign that the answer depends on location.

What a Battery Project Costs

Capital cost is the starting point for any business case. The National Renewable Energy Laboratory publishes cost projections for utility-scale lithium-ion systems as part of its technology-cost research. In its 2023 update, NREL estimated the overnight capital cost of a four-hour utility-scale battery system at $482 per kilowatt-hour in 2022 dollars. Its mid-case projection fell to $326 per kilowatt-hour by 2030 and $226 by 2050, with low and high scenarios spanning a wide range.

NREL’s 2030 projections ranged from $245 to $403 per kilowatt-hour, reflecting uncertainty about raw material prices, manufacturing scale and supply chains. Buyers should treat any single cost figure as a scenario, not a forecast, and should check which year’s dollars and which system boundaries a quoted price uses. Some figures cover only battery racks, while others include inverters, transformers, grid connection and engineering.

Operating assumptions also shape the economics. NREL’s projections assume an 85% round-trip efficiency, meaning about 15% of the energy put into the battery is lost by the time it comes back out, and a 15-year lifetime. A project modeled on longer life or higher efficiency than the equipment can deliver will look better on paper than it performs in the field.

Costs beyond the battery

Several costs rarely appear in headline figures. Interconnection studies and upgrades can be expensive and slow, and queue delays can push a project years past its planned start. Land, permitting, fire protection, insurance, augmentation (adding capacity over time to offset degradation) and eventual decommissioning all belong in the model. Financing costs count too: because storage is capital-intensive, a small change in interest rates moves the result.

The Market Rules That Opened the Door

Batteries couldn’t compete in wholesale markets until the rules allowed them. The most important federal step was Order No. 841, which the Federal Energy Regulatory Commission issued in February 2018. It required each regional transmission organization and independent system operator to create a participation model for electric storage resources.

Under the order, storage must be eligible to provide every capacity, energy, and ancillary service it can technically provide. Storage must be dispatchable and able to set the wholesale market clearing price as both a buyer and a seller. Markets must account for storage’s physical and operational characteristics, set a minimum participation size no higher than 100 kilowatts, and price energy that storage buys from the market and resells at the wholesale locational marginal price.

FERC’s follow-up, Order No. 841-A, published in May 2019, clarified several points. Market operators were not required to create capacity products they did not already have, and they kept flexibility in how to model a battery’s state of charge. FERC also declined to let states opt out for storage connected to distribution systems, while noting that states keep authority over retail service and distribution matters.

For buyers, the lesson is that market design still varies by region. How a battery is credited for capacity, how state of charge is managed, and what transmission charges apply when it charges can all vary, and those details flow directly into revenue.

Safety Codes and Policy Risk

Lithium-ion cells can enter thermal runaway, a self-heating failure that can release flammable gases and spread to neighboring cells. Fires at battery sites draw public attention, and local opposition grounded in safety concerns has become a factor in permitting. The industry has responded with a layered set of standards that buyers should understand.

• UL 9540 is the product safety standard for energy storage systems.
• UL 9540A is a test method that evaluates thermal runaway and fire propagation at the cell, module, unit and installation levels.
• NFPA 855, published by the National Fire Protection Association, covers installation requirements for stationary storage systems, including spacing and fire protection.

These standards are tightening. According to UL Solutions, earlier editions of UL 9540A were sequential, and many products that passed unit-level criteria never faced an installation-level test. The sixth edition adds a large-scale, installation-level fire test with pass-and-fail criteria and intentionally ignites vented gases to create a fire condition. UL says the sixth edition takes effect on January 1, 2027.

The 2026 edition of NFPA 855 also emphasizes large-scale fire testing and adds guidance on fire spreading from one battery unit to another, including separation distances and active fire protection. For a developer, stricter codes can mean more land, more spacing and more testing costs. For a buyer or local official, they offer a clearer basis for asking whether a proposed system has been tested in conditions that resemble a real fire.

Tax credits and supply chain rules

Federal tax policy strongly affects storage economics. The 2022 Inflation Reduction Act made standalone storage eligible for the investment tax credit, later shifting it to the technology-neutral Section 48E credit. The tax and spending law signed on July 4, 2025, often called the One Big Beautiful Bill Act, sharply cut wind and solar credits but treated storage differently.

According to a July 2025 analysis by the law firm Pierce Atwood, storage credits under Sections 45Y and 48E phase down only for projects that begin construction after 2033: they drop to 75% for projects starting construction in 2034, 50% in 2035, and zero from 2036. Domestic content requirements for bonus credits also rise over time.

The same law added restrictions tied to prohibited foreign entities. Projects can lose credits if material assistance from such entities exceeds a threshold that rises over time, starting with projects that begin construction in 2026. Because much of the world’s battery cell and component manufacturing is concentrated in China, these rules force developers to trace supply chains in much more detail. Buyers should expect contract terms covering component origin, documentation and responsibility if a credit is later disallowed. Treasury guidance continues to shape how these rules are applied, so specialist tax advice is essential.

Degradation, Warranties and Measurable Outcomes

Batteries lose capacity as they age, and the rate depends on how they are used. Frequent deep cycling, high temperatures and high charge levels all speed degradation. A battery that cycles twice a day to chase price spreads will age faster than one held mostly in reserve for capacity events. That trade-off is central to how a project is operated.

Warranties typically guarantee a level of capacity retention over a set period, subject to limits on cycles, temperature and state of charge. Buyers should read those limits closely, because operating outside them can void coverage. Long-term service agreements and augmentation plans, which add new modules to maintain usable capacity, are common ways to manage this risk.

Measuring results is just as important as forecasting them. Useful metrics include availability (the share of time the system is ready to operate), round-trip efficiency in actual operation, capacity retention against the warranty curve, and revenue per kilowatt of capacity compared with the original model. Owners who track these from the start are better placed to hold suppliers accountable and to refine dispatch strategies.

Demand growth and the role of storage

Electricity demand is also rising. Projections that US data centers could rival Germany and Japan in natural gas use by 2035 show how quickly new load can reshape planning. Batteries cannot replace firm generation on their own because most systems discharge for hours, not days. They can, however, shave peaks, absorb surplus solar output and buy time for transmission upgrades.

Questions Buyers and Investors Should Ask

Whether you are a utility procurement team, a corporate energy buyer or an investor reviewing a portfolio, the same core questions apply. Asking them early can prevent expensive surprises.

1. Which revenue streams does the model rely on, and how sensitive is it to narrower price spreads or lower capacity credit as more storage enters the market?
2. What exactly is included in the quoted cost, and in which year’s dollars? Does it cover interconnection, fire protection, augmentation and decommissioning?
3. What UL 9540A results exist, at which levels, and has the product been tested under the large-scale criteria that will soon apply?
4. How does the design meet the edition of NFPA 855 adopted by the local jurisdiction, and what do local fire officials require?
5. What supply-chain documentation do cells and components require, and who bears the risk if tax credits are challenged?
6. What are the warranty limits on cycles, temperature and state of charge, and how do they fit the planned operating strategy?
7. How will performance be measured and reported after commissioning, and what remedies apply if the system falls short?

Clear answers to these questions do not guarantee a good investment, but vague ones are a warning sign.

Where the Business Case Stands

The case for grid batteries rests on three factors: falling equipment costs, market rules that let storage compete, and policy support that remains comparatively intact. Federal data show capacity growing quickly, and national laboratory projections point to cost declines further, though with wide uncertainty.

The risks are just as concrete. Revenue from arbitrage and ancillary services can shrink as more batteries compete. Stricter safety standards raise costs but should also improve public confidence. Supply chain rules attached to tax credits add documentation burdens and legal exposure. A disciplined buyer models each as a variable, not a footnote, and checks claims against standards, regulators, and measured performance instead of relying on projections alone.