Four-hour battery storage now costs less than new open-cycle gas turbines in all 43 markets where Wood Mackenzie modeled both technologies, according to research released October 8. The finding gives utilities a sharper economic reason to test batteries before committing to another generation of gas peaking plants. The comparison is about modeled lifetime electricity costs, not a claim that batteries can replace every gas plant or supply unlimited backup. Its importance is narrower and more practical: for the daily peak-shifting service that four-hour systems can provide, new gas equipment is facing a competitor whose manufacturing base is expanding while turbine supply remains constrained. The comparison at a glance 43 markets Four-hour batteries beat new open-cycle gas turbines in every modeled comparison. 4 hours The modeled storage duration, not a promise of unlimited backup. Source: Wood Mackenzie, October 8, 2026. Hero: AI-generated conceptual illustration, not a named project. The cost crossover is no longer a single-market story Wood Mackenzie attributes the change to two forces moving in opposite directions. Battery manufacturing scale is lowering storage costs over time, while gas turbine shortages and fuel-price uncertainty are making new peaking capacity more expensive. The research covers Europe, North America, Latin America, Asia Pacific, and the Middle East and Africa. For U.S. projects entering commercial operation in 2026, a Wood Mackenzie spokesperson told Utility Dive that four-hour storage was 65% to 75% cheaper than new open-cycle gas peakers, depending on state-level carbon pricing. Those figures are a reported model comparison, not a universal project quote. Site conditions, financing, charging arrangements, and the required operating pattern still determine an individual investment. The result also should not be confused with a comparison against an existing, paid-off gas turbine. A decision to build a new plant involves capital that an operating plant has already spent. Whether to retire an existing generator requires a separate assessment of operating costs, reliability obligations, refurbishment needs, and the replacement portfolio. Regional numbers show why local assumptions matter In the Middle East and Africa, Wood Mackenzie puts four-hour storage at $120 per MWh in 2026 and forecasts $80 per MWh by 2035. That is a projected decline of roughly one-third. Strong solar resources help explain the commercial interest in shifting daytime electricity into later hours, although the cost and availability of charging energy remain essential to any actual project. China sets the lowest storage benchmark in the study, at more than 55% below the $134 per MWh average for the rest of Asia Pacific. Wood Mackenzie expects that rest-of-region average to fall to $92 per MWh by 2036. Import duties, installation costs, and domestic manufacturing policies can preserve premiums in markets including Japan, Australia, and the Philippines. Europe supplies an important counterpoint to the idea that every battery price falls every year. The firm reports that turnkey battery capital costs rose about 2% in 2026 after cell prices rebounded around 10% from their 2025 low. It still forecasts a 12% decline in turnkey costs by 2031. A long-term competitive advantage can therefore coexist with a near-term purchasing squeeze. A four-hour battery is not an unlimited fuel supply Storage shifts electricity rather than producing a new fuel source. A nominal 100 MW, four-hour system corresponds to 400 MWh of rated energy, but the usable energy at the grid connection depends on the design and contractual measurement boundary. A buyer must specify whether ratings include conversion losses, auxiliary consumption, degradation allowances, and reserved state of charge. That distinction becomes decisive when the grid faces consecutive stressed hours or multiple difficult days. A gas turbine can continue operating while fuel is available. A battery must recharge, and cheap charging power is not guaranteed during a prolonged supply shortage. Comparing the two resources requires matching their actual service obligations, not just their nameplate megawatts. The public Wood Mackenzie release summarizes the headline findings and regional trends rather than supplying a complete set of project-level assumptions. Readers should not treat its dollar-per-MWh numbers as turnkey equipment prices or as proof of equivalent capacity value. Utility procurement still needs hourly modeling, realistic outage assumptions, and a charging strategy that survives the periods when the battery is most valuable. North America faces two different supply-chain problems Wood Mackenzie describes North American gas-generation investment as entering a supply deficit cycle through the late 2030s, with data-center electricity demand helping sustain pressure on thermal capital costs. Battery suppliers face a different challenge: sourcing restrictions, tax-credit eligibility, and domestic manufacturing capacity can separate the cheapest global equipment from the equipment a U.S. project can actually finance and install. The firm says tax credits continue to support storage competitiveness while partially offsetting foreign entity of concern restrictions and supply-chain constraints. Its forecast anticipates a cost increase after investment tax credits phase out from 2038, followed by longer-term gains from new chemistries, more standardized hardware, and domestic supply expansion. These are the report’s modeling assumptions and forecasts, not a guarantee of future policy or procurement prices. For buyers, the useful comparison is therefore between deliverable bids. A low battery-system price can lose its appeal if the equipment cannot meet sourcing requirements, secure interconnection, or arrive before a capacity deadline. A gas proposal carries its own exposure to turbine availability, fuel infrastructure, and construction schedules. Neither technology escapes execution risk simply by winning a cost model. What utilities should ask for next The immediate implication is not to cancel every proposed gas plant. It is to require a credible storage alternative when the stated need is a few hours of peak capacity. Requests for proposals can define the service window, recharge opportunities, minimum availability, and performance after years of cycling, then compare bids against that same obligation. Financing teams also need to distinguish cost competitiveness from revenue certainty. A battery can be cheaper than a new peaker yet struggle to finance if its income depends on volatile energy-price spreads. Long-term capacity or tolling contracts can assign operating responsibilities and make cash flows more predictable, but their terms decide who pays for losses, degradation, and missed dispatch. The October 8 research changes the starting question. Instead of assuming gas is the default and asking whether batteries are affordable enough to supplement it, planners have evidence to ask why a new gas peaker is necessary for a particular duty. The answer may still involve fuel-backed generation, longer-duration storage, demand response, or a mix. It now needs to demonstrate a system benefit that outweighs the modeled cost advantage of four-hour batteries. The bottom line: Wood Mackenzie’s 43-market comparison strengthens the case for batteries in new peaking-capacity procurement. Turning that advantage into reliable power still requires the right charging supply, enforceable performance guarantees, and a project that can be delivered on time. Sources Wood Mackenzie: October 8 global cost study announcement Utility Dive: U.S. comparison and analyst reporting pv magazine USA: regional findings and trade context