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How forward-thinking utilities are deferring billions in infrastructure costs — without sacrificing reliability.
With material costs up and supply chain queues long, non-wires alternatives provide short-term relief to expensive transmission and distribution upgrades. So how can you get started?
Every utility executive knows the pressure. Load is growing. Aging infrastructure is straining under peak demand. Capital plans are full of expensive substation upgrades, new feeder lines, and transformer replacements — projects that take years to permit, years to build, and hundreds of millions of dollars to complete.
And yet, the underlying problem driving most of those investments happens for a relatively few, but growing, hours a year: peak energy demand events.
That’s the paradox at the heart of modern grid planning: we build for the peak, not the average. A transformer that runs comfortably at 60% utilization for 8,700 hours a year gets replaced because it’s overwhelmed. A substation upgrade gets pushed into the capital plan not because of chronic overload — but because of a handful of summer afternoons.
What if there were a way to shave those peaks without building anything new? Through demand flexibility initiatives like demand response, virtual power plants (VPPs), and EV charging, non-wires alternatives are crucial in mitigating these costs while meeting rising demand.
The Real Cost Driver: Peak Demand, Not Average Load
When planning teams model the need for a new substation or feeder upgrade, they’re not modeling an average Tuesday in October. They’re modeling the worst-case scenario — the hottest day of the year, when air conditioners run full tilt, EVs come home to charge, and every industrial customer is at full production.
That peak moment sets the sizing requirement. Which sets the capital cost. Which ends up in your rate case.
– Amber Mullaney, VP of Marketing, Virtual Peaker
The math is straightforward, but the implication is easy to miss: even a modest, reliable reduction in peak demand can eliminate or defer a capital project entirely.
A 10–15% reduction in demand at the right place and the right time — the specific feeder, the specific hour — these non-wires alternatives can push a $50 million substation upgrade five, ten, or even fifteen years into the future. The present value of that deferral is enormous. And it shows up directly in your avoided capital costs.
Non-Wires Alternatives: Shift the Load. Defer the Steel.
The concept is simple: instead of building more capacity to meet peak demand, change when that demand occurs.
Industrial customers can shift energy-intensive processes to off-peak hours. Commercial buildings can pre-cool before peak windows and ride through them with less draw. EV fleets can be charged overnight rather than in the late afternoon. Water heaters, battery storage, and smart thermostats across thousands of residential customers can collectively flatten the curve.
None of this requires customers to use less energy. They use the same amount — just at different times. And for the utility, the effect can be dramatic: the peak that was threatening to breach your infrastructure limits disappears, or shrinks to manageable levels, and the capital project that seemed inevitable suddenly isn’t.
This is what the industry calls non-wires alternatives — meeting a capacity need through demand-side flexibility rather than poles, wires, and transformers. Regulators in an increasing number of states now require utilities to evaluate non-wires alternatives before approving traditional capital spend. But even where it isn’t required, the economics are making the case on their own.
This Isn’t Future Technology. It’s Here Now.
Utilities across the country are already doing this — and the results are measurable.
Utilities in Vermont have used demand flexibility programs to defer tens of millions of dollars in transmission infrastructure costs. California-based utilities have leaned on demand response and flexible load management to navigate capacity constraints in certain areas of their service territories. Utilities in the Southeast are using behind-the-meter flexibility to manage distribution-level peaks without adding iron.
The tools to orchestrate this kind of demand flexibility have matured significantly in the last five years. Sophisticated software platforms including Grid-Edge distributed energy resource management systems (DERMS) can now coordinate thousands of customer resources — large commercial and industrial loads, EV chargers, battery storage, smart thermostats — in real time, dispatching them precisely when and where the grid needs relief. These aren’t blunt, interruptible load programs from the 1980s. They’re intelligent, automated, and largely invisible to the customer.
More importantly, they can be targeted. Rather than running a grid-wide demand response event, utilities can now respond to congestion on a specific feeder or substation — activating flexibility through the non-wires alternatives from participating customers in that area, only at the hours that matter. That precision is what makes the infrastructure deferral case so compelling.
What This Means for Capital Planning
The conversation this opens up for utility leadership is not about eliminating capital investment — it’s about sequencing it more intelligently.
Instead of building to meet a peak that may shift as the mix of customer-owned, behind-the-meter distributed energy resources (DERs) evolves (more EVs, more solar, more storage), you create time. Time to understand how load is actually developing. Time to let technology costs continue to fall. Time to avoid over-building for a scenario that may look quite different in five years.
In the meantime, you’re delivering real value to customers: rate pressure is reduced, reliability is maintained, and the utility demonstrates that it is actively pursuing cost-effective solutions before reaching for the rate case.
For commissioners and regulators, as public pressure on electric costs rises, that story is increasingly important. For customers watching their bills, it’s essential. And for your balance sheet, the avoided capital — or even the deferred capital — is real money.
The Question Worth Asking
Before the next major infrastructure project moves from your long-range plan to your capital budget, there’s a question worth asking your planning and operations teams:
What would it take to defer this project by five years — and what is that deferral worth?
In many cases, the answer will surprise you. The capacity you need to free up is achievable. The tools to do it reliably exist. And the economics, when you model the present value of deferral against the cost of an intelligent demand flexibility program, often make the case on their own.
The cheapest megawatt really is the one you never have to build. The question is whether you have the right strategy to capture it. And non-wires alternatives can help realize those goals quickly and affordably, while increasing grid resiliency and lowering operational costs.
Glossary of Key Terms
- Non-wires alternatives (NWAs) – Approaches to meeting electric grid capacity needs through demand-side resources — such as demand response, energy efficiency, or distributed generation — rather than building new physical infrastructure like poles, wires, substations, or transformers.
- Peak demand – The highest level of electricity consumption on a grid during a given period — typically occurring on the hottest or coldest days of the year. Peak demand drives infrastructure sizing requirements because the grid must be built to handle worst-case load, not average load.
- Demand flexibility – The ability of electricity customers to adjust when — and sometimes how much — energy they consume in response to grid signals, price incentives, or utility dispatch. Encompasses demand response, virtual power plants, managed EV charging, and other load-shifting strategies.
- Demand response (DR) – A utility program that compensates customers — residential, commercial, or industrial — for voluntarily reducing or shifting their electricity use during grid stress events, such as peak demand periods or supply shortages.
- Virtual power plant (VPP) – A network of distributed customer-owned energy resources — such as rooftop solar, battery storage, smart thermostats, and EV chargers — that are aggregated and coordinated by software to act collectively as a single, dispatchable grid resource.
- EV managed charging – A strategy in which electric vehicle charging is scheduled or shifted — automatically or through customer incentives — to avoid peak demand windows, typically pushing charging to overnight or other off-peak hours when grid capacity is ample.
- Load shifting – Moving electricity consumption from peak periods to off-peak periods without reducing the total amount of energy used. Customers consume the same energy — just at a different time — which smooths the demand curve and reduces strain on the grid at critical hours.
- Distributed energy resources (DERs) – Small-scale energy assets located at or near the point of use — including rooftop solar panels, battery storage systems, EV chargers, smart thermostats, and controllable appliances. DERs can be coordinated to support grid operations when aggregated in sufficient numbers.
- Behind-the-meter (BTM) – Energy assets and activities that occur on the customer side of the utility meter — such as rooftop solar generation, home battery storage, or smart thermostat control. These resources are owned by the customer but can be leveraged by utilities through programs and incentives.
- Avoided capital costs – Infrastructure spending that is permanently eliminated — not just delayed — because demand-side flexibility or other non-wires measures fully satisfy the capacity need that would have required new construction. Distinct from capital deferral, where the investment is postponed rather than cancelled.
- Grid-Edge – Referring to the portion of the electric grid closest to end customers — the distribution network, including feeders, transformers, meters, and behind-the-meter resources. Grid-edge intelligence enables utilities to manage load and dispatch flexibility at the most granular, localized level of the system.
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