Published October 13, 2026
By NZero
Battery storage has crossed a cost threshold that energy markets have watched for years. On October 8, 2026, Wood Mackenzie published its latest global levelized cost of electricity (LCOE) analysis. It found that four-hour battery storage is now less expensive than open-cycle gas turbines in all 43 markets where both technologies were modeled. Open-cycle gas turbines, often called peakers, are the plants that typically run during the highest-demand hours of the year. Those hours matter to facility leaders because they shape demand charges, capacity costs, and a large share of commercial and industrial energy bills. When the cost of serving peak demand changes, the economics of managing it change too. This article explains what the report found, why the outlook in North America is more complicated than the global headline suggests, and what manufacturers, commercial property owners, and data center operators can do with this information.
LCOE measures the total lifetime cost of building and operating a power asset, divided by the electricity it produces, and is expressed in dollars per megawatt-hour (MWh). It is a common benchmark for comparing technologies, although it does not capture every value a resource provides, such as location or grid reliability services.
According to Wood Mackenzie, two forces are widening the gap. Gas turbine shortages and fuel price volatility are increasing the cost of peaking power, while expanding battery manufacturing continues to push storage costs down. Principal analyst Ahmed Jameel Abdullah described the shift as decisive and still widening. The report’s main findings include:
The global trend does not translate evenly to every market. Wood Mackenzie’s North America findings point to several factors that U.S. and Canadian facility leaders should weigh.
First, data center growth is reshaping gas generation. The firm says investment in gas capacity is entering a supply deficit cycle through the late 2030s, driven by data center load growth. That dynamic keeps thermal capital costs elevated and strengthens the long-term case for renewables and storage.
Second, trade policy is raising near-term solar costs. Tariffs, anti-dumping and countervailing duty actions, and new Section 232 import restrictions are putting pressure on prices, and distributed generation is the most exposed. Utility-scale solar is partly protected by 168 GW of safe-harbored capacity, yet module prices are still expected to rise about 5% annually through 2030. For residential and commercial projects, module prices are forecast to rise 6% in 2027 and another 14% in 2028.
Third, tax credits continue to favor storage, partly offsetting foreign entity of concern (FEOC) restrictions and supply chain constraints. Wood Mackenzie expects a cost spike after the investment tax credit phases out from 2038, although new chemistries and domestic manufacturing should bring storage LCOE down 10% by 2060.
The outlook also has limits. The firm’s North America report notes that the region is the only one in its global comparison where renewable and storage costs are higher in 2040 than today, and that gas remains the cheapest firm option through an investment super-cycle. Battery costs are not falling everywhere either. In Europe, battery storage turnkey capex rose about 2% in 2026, the first increase in three years, as cell prices rebounded roughly 10% from their 2025 low.
Wood Mackenzie’s figures describe utility-scale projects, not batteries installed at an individual site. Behind-the-meter systems have different costs, sizes, and value streams, so the report is not a direct estimate of on-site project economics. It does, however, signal where the market is heading. As storage increasingly competes with gas to supply peak power, the tools available for managing peak demand are becoming more varied and more cost-competitive.
For most facilities, peak costs show up in two places. Demand charges are typically based on a site’s highest usage interval during a billing period, and in some markets they can make up a significant share of the electricity bill. Capacity costs reflect what the grid pays to have enough supply available at its peak. In regions where data center growth is tightening supply, these costs may stay under pressure regardless of how a facility manages its own load.
The right response depends on each site’s load profile. A practical starting point includes:
For organizations with many buildings, consistent utility data across the portfolio makes it easier to see which sites offer the largest peak reduction opportunity. NZero’s recent article on managing peak demand and energy costs covers these load management strategies in more detail.
Wood Mackenzie’s report confirms that the economics of peak power are changing. Four-hour storage now undercuts gas peakers on cost in every market the firm compared, driven by turbine shortages, fuel volatility, and the scale of battery manufacturing. In North America, however, tariffs, import restrictions, and the timing of tax credits mean costs will not follow a straight downward line. For facility leaders, the takeaway is neither to rush into storage nor to wait indefinitely. It is to understand when and why each site draws peak power. Organizations with accurate interval data will be better positioned to compare load management, on-site storage, and solar-plus-storage options as prices and policies evolve, and to act when the numbers work for their buildings.
