Brooks Sherman on What Changes When Companies Model the Energy Transition as a Capital Decision Rather Than an Operating Cost

In his research on battery storage markets, Brooks Sherman has encountered a recurring framing: energy-transition spending is often treated primarily as a cost center, something a company or utility absorbs because regulation or reputation requires it. The capital allocation numbers tell a different story.

One pattern that stands out is how often financial modeling still reflects an older assumption. Sherman puts it plainly: “At this point, the money is already moving toward electricity and storage at a scale that doesn’t match a cost-center framing. What matters is whether planning and financial models are catching up to where investment and demand are headed.”

That disconnect has real consequences for planning and budgeting. Treating energy-transition spending primarily as an expense to be minimized can obscure the returns it may deliver through reliability, deferred infrastructure spending, and capacity for future demand.

Where the Capital Is Going

The clearest signal is where global energy investment is headed, not where it has been. The International Energy Agency projects global energy investment will reach a record $3.3 trillion in 2025, with clean energy technologies drawing roughly $2.2 trillion of that total, about twice what fossil fuels are expected to attract. That scale does not make policy, tax incentives, or market design irrelevant, but it does show that spending on electricity, grids, storage, and low-emissions generation cannot be understood only as compliance or reputational spending.

The same IEA reporting notes a structural shift worth sitting with. A decade ago, fossil fuel investment ran about 30% higher than spending on electricity generation, grids, and storage combined. This year, electricity investment is expected to run roughly 50% higher than total spending on bringing oil, natural gas, and coal to market. The change reflects the infrastructure needed to electrify more of the economy, integrate new generation, and serve rising electricity demand.

“If the money is flowing toward electricity and storage at that pace, calling it a cost starts to look like a modeling choice more than a market reality,” Sherman says. “The more useful question is what a particular investment can return through reliability, avoided or deferred upgrades, and capacity to serve future demand over its useful life.”

Storage Economics Have Moved Faster Than the Narrative

Part of what keeps the cost framing alive is that battery storage economics have changed quickly enough that institutional planning has not always caught up. BloombergNEF’s 2025 survey found lithium-ion battery pack prices fell to a record low of $108 per kilowatt-hour, down 8% from 2024 and 93% lower than in 2010. Stationary storage specifically saw an even steeper decline. BNEF found battery pack prices for stationary storage fell to $70 per kilowatt-hour in 2025, a 45% decrease from the year before, making it the lowest-priced segment of the battery market for the first time.

Drawing on his 2025 MBA capstone on battery-storage markets, Sherman sees the price curve as one reason storage is being evaluated differently. “In a growing number of markets and applications, storage can make economic sense on more than a purely climate or resilience basis,” he says. “But the economics are still local. They depend on the duration required, market rules, interconnection costs, financing, and what alternative infrastructure the asset might replace or defer.”

His capstone research examined next-generation chemistries, including sodium-ion, iron-air, and flow batteries, alongside more familiar lithium-ion systems, considering how they may fit across grid-scale and distributed applications. That range matters because storage isn’t one investment case or one cost curve. Different technologies carry different duration profiles, commercialization timelines, project risks, and possible revenue models.

What Storage Displaces

The investment case sharpens when storage is measured against what it replaces, rather than against doing nothing. Utilities have increasingly used batteries as what the industry calls non-wires alternatives, deploying storage to defer, reduce, or in some cases avoid transmission and distribution upgrades that are expensive, slow to permit, and often deeply unpopular with the communities they affect. Rocky Mountain Institute analysis estimates that using distributed energy resources as non-wires alternatives could avoid roughly $17 billion in transmission and distribution costs through 2030.

“If a battery enables you to avoid a transmission upgrade, it should be evaluated and financed on comparable terms,” Sherman says. “Right now, it often isn’t.”

That mismatch is partly regulatory and partly a matter of habit. Storage assets are often evaluated as generators or discretionary upgrades rather than as alternatives to conventional infrastructure spending. When a battery keeps the lights on during a heat wave, defers or reduces the need for a major transmission or distribution upgrade, or keeps a hospital microgrid running through a hurricane, the value is closer to that of core infrastructure than an optional add-on.

The Demand Side Adds Urgency

The urgency behind this argument isn’t hypothetical. Electricity demand growth, driven substantially by data centers and AI workloads, is forcing utilities and investors to confront grid capacity questions on a shorter timeline than most planning cycles were built for. Goldman Sachs Research estimates that roughly $720 billion of grid spending may be needed through 2030 to accommodate the data center-driven increase in power demand. S&P Global’s 451 Research projects that US data center power demand will nearly triple by 2030, reaching roughly 134 gigawatts.

“The technology is ready,” Sherman says. “The economics are increasingly compelling. What we’re working through now is whether we have the institutional imagination to treat storage the way we treat a bridge or a water main, not as another product to buy and sell, but as something we build and maintain together because the alternative is worse.”

That kind of demand growth leaves less room to treat storage and grid investment as discretionary spending that can simply be trimmed when budgets tighten. The question becomes whether capital is allocated ahead of demand or only after congestion, delayed connections, and reliability problems have already imposed costs.

Where the Investment Framing Has Limits

None of this means every storage project pencils out, or that policy and financing frameworks have caught up to the pace of technology development and changing market conditions. Regulatory categories still vary by jurisdiction, and how a storage asset gets classified can materially affect its financing, ownership, revenue opportunities, and role in system planning. “You can’t plan or invest efficiently in a resource if its category shifts depending on who’s regulating it,” Sherman says.

The technologies are also moving faster than the frameworks built around them. “That’s not unusual in energy, but the risk is that we lock in rules built around today’s four-hour batteries and then struggle to integrate 100-hour systems a few years down the line,” Sherman says. “Treating storage as infrastructure now gives us more room to adapt as those longer-duration technologies mature.”

That caution matters, because the cost-versus-investment argument is not a call to treat every dollar spent on storage or grid buildout as automatically justified. It is an argument about the starting point for analysis. A cost framing asks how little can be spent to satisfy a requirement. An investment framing asks what return, in avoided infrastructure spending, reliability, and capacity for future demand, a given dollar generates.

The Strategic Stakes

For companies and investors still treating the transition primarily as a compliance line item, the risk isn’t simply missing a trend. It is relying on planning and financial models that may not fully account for changing electricity demand, infrastructure needs, and the potential value of storage and grid capacity. Over successive budget cycles, that can lead organizations to underinvest in assets that improve reliability, defer upgrades, or enable future growth.

In his research, the organizations that appear best positioned aren’t necessarily the ones spending the most. Sherman puts it this way: “They are not necessarily the ones spending the most. They are the ones whose planning recognizes that storage and grid capacity can be core infrastructure decisions, not optional add-ons.”

Whether that perspective becomes standard practice or remains concentrated in the fastest-moving parts of the market will be an important strategy question in energy over the next several years.

Published Originally — https://calbizjournal.com/brooks-sherman-on-what-changes-when-companies-model-the-energy-transition-as-a-capital-decision-rather-than-an-operating-cost/