Distributed Energy Resources: A Smarter Answer to Soaring Power Bills

US electricity prices have climbed roughly 20–25% on average over the last five years, and in some states the jump has been far worse. Households feel it every month. Businesses see it in shrinking margins. Utilities face rising fuel costs, aging grids, and growing peak demand.

Most companies and communities respond by negotiating rates or hunting for cheaper supply. That’s treating the symptom, not the cause. The more effective move is to change how and where electricity is produced and managed.

This is where distributed energy resources (DERs) – rooftop solar, battery storage, electric vehicles, smart thermostats, backup generators, microgrids, and more – start to matter. When they’re coordinated intelligently, they don’t just lower emissions. They can flatten peaks, reduce infrastructure costs, and tame long‑term electricity prices.

This article is part of our Green Technology series, where we look at how digital intelligence and clean hardware work together in the real world. Here, we’ll break down how DERs can combat soaring power costs in the US, what’s working in states like California, Colorado, and North Carolina, and how AI and software turn scattered devices into a reliable, money‑saving energy resource.

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How DERs Actually Cut Electricity Costs

The core idea is simple: DERs reduce what you buy from the grid when it’s most expensive and most stressed. That cost relief shows up in three main ways.

1. Shaving Peaks (Where Bills Really Bite)

Wholesale power prices and many utility rate structures are driven by the most expensive hours, not the average ones. Those hot summer afternoons or deep‑freeze mornings push up:

• Capacity payments to power plants
• Distribution and transmission investments
• Demand charges for commercial and industrial customers

DERs attack that peak:

• Rooftop solar reduces grid demand during sunny daytime peaks.
• Battery storage discharges during the highest‑priced hours.
• Smart EV charging shifts charging away from peak periods.
• Automated demand response slightly reduces HVAC or process loads for short intervals.

The result: lower system-wide peak demand, which means the utility doesn’t need as many peaker plants or emergency market purchases at crazy prices. Over time, that dampens rate increases for everyone, not just the DER owners.

DERs are most valuable when they behave like a coordinated virtual power plant rather than a bunch of independent gadgets.

2. Avoiding Expensive Grid Upgrades

The traditional fix for a growing neighborhood or industrial area is to build more wires, transformers, and substations. That capital cost flows directly into customer bills.

Strategically located DERs can delay or avoid those upgrades:

• A battery near a constrained feeder can support local voltage and supply peak power.
• Community solar plus storage can serve growing load without replacing a substation.
• A microgrid at a campus or hospital can island during stress events, taking pressure off the local network.

Regulators have started to recognize this. In several US states, utilities now run “non‑wires alternatives” procurements, where DERs compete directly with poles‑and‑wires projects. When DERs are cheaper, customers win.

3. Giving Customers Control Over Their Bills

From a customer perspective, DERs create new levers:

• Households can offset usage with rooftop solar and home batteries.
• Businesses can cut demand charges using on‑site storage and flexible loads.
• Fleets can manage EV charging schedules to align with low‑price hours or on‑site solar.

The reality? You don’t have to be 100% self‑sufficient. Even modest DERs can reshape when you take from the grid so you’re buying more in the cheap hours and less in the expensive ones.

This is where green technology overlaps with smart technology. Without software and automation, DERs leave a lot of value on the table.

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The Role of AI and Software: Turning Devices into a Power Plant

Hardware alone doesn’t fix soaring electricity costs. AI, control software, and data are what make DERs useful at grid scale.

Virtual Power Plants (VPPs): Coordination at Scale

A virtual power plant aggregates thousands of small devices – home batteries, rooftop solar, EV chargers, smart thermostats – and operates them as if they were a single power plant.

Here’s what that looks like in practice:

• An aggregator (a utility, Sunrun, or a tech company) connects to devices via the cloud.
• AI forecasts solar output, customer usage, and wholesale prices.
• The platform decides when to charge, discharge, or adjust loads.
• The aggregated capacity is sold into capacity, energy, or ancillary services markets.

This does three things for costs:

1. Replaces or defers peaker plants with aggregated DERs.
2. Monetizes customer assets, providing bill credits or payments.
3. Improves grid stability, which reduces the need for expensive backup.

I’ve seen utilities underestimate how much value they can squeeze out of assets they don’t even own. With the right software, 10,000 home batteries can be a highly responsive 50–100 MW resource.

AI‑Driven Forecasting and Dispatch

Most companies get this wrong by focusing only on hardware payback. The real advantage shows up when AI optimizes dispatch across time, price, and grid constraints.

Modern DER management systems use:

• Short‑term load forecasting at feeder or building level
• Solar and wind generation forecasting down to 15‑minute intervals
• Real‑time price and grid condition signals

From there, they can:

• Charge batteries when renewables are abundant and cheap
• Discharge when prices spike or congestion builds
• Prioritize carbon intensity reductions when that’s part of the business case

The outcome: maximum economic value with minimum manual intervention.

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Real‑World DER Strategies from US States

States like California, Colorado, and North Carolina are quietly building the playbook for cost‑effective DERs. Each one starts from a different place but converges on the same pattern: align DER incentives with grid needs.

California: Solar, Storage, and a Stressed Grid

California is the lab where many DER ideas get tested first.

• Mass rooftop solar adoption created the famous “duck curve”, with steep evening ramps.
• Wildfires and PSPS events pushed communities toward microgrids and batteries.
• The CPUC (California Public Utilities Commission) has steered rate design toward time‑of‑use and dynamic pricing.

What’s working:

• Residential solar plus storage that shifts exports from noon to evening, reducing strain and peaker use.
• Community Choice Aggregators (CCAs) using DERs for local reliability and flexible capacity.
• Growing pilots where EVs and home batteries act as virtual power plants during peak or emergency events.

For customers, this means better resilience and a way to manage bills in a state with rising tariffs. For the grid, it’s a hedge against both extreme weather and high wholesale prices.

Colorado: Community‑Driven Clean Energy

Colorado has leaned into community solar, local storage, and performance‑based regulation.

Key trends:

• Community solar gardens let renters and small businesses participate without owning a roof.
• Distribution system planning increasingly considers DERs as alternatives to traditional upgrades.
• Local utilities and co‑ops are testing DER‑enabled microgrids in rural and mountain communities.

The cost angle is straightforward: it’s often cheaper to build local solar plus storage than to extend or reinforce long, remote power lines to serve growing or isolated loads.

North Carolina & Duke Energy: Utility‑Scale Meets Distributed

North Carolina combines large‑scale solar with a growing interest in behind‑the‑meter DERs. Duke Energy and others are experimenting with:

• Tariffs that reward load flexibility for commercial and industrial customers
• Demand response programs for HVAC, water heaters, and EV charging
• Front‑of‑the‑meter batteries placed at strategic grid nodes

What’s notable is the blending of utility‑scale assets and customer‑owned DERs, coordinated as one portfolio. That mix can dampen wholesale price spikes and reduce the need for new peaking capacity, helping to stabilize rates over the long term.

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How Businesses and Communities Can Use DERs Strategically

This isn’t just a utility story. If you manage facilities, fleets, or community infrastructure, DERs are now a core business and resilience tool, not a side project.

For Commercial and Industrial Customers

Here’s what typically delivers the strongest financial case:

1. Target demand charges first
   If your bill includes demand charges, even a small battery or flexible process load can pay for itself by clipping peaks.

2. Pair solar with storage, not just solar alone
   Solar cuts energy usage. Storage lets you time‑shift that benefit into the most expensive hours.

3. Use smart controls, not manual schedules
   A battery or flexible load on a fixed schedule is leaving money on the table. Modern control platforms can:

   • Track prices and grid signals
   • Respect your operational limits
   • Autonomously optimize for cost and carbon

4. Participate in utility or aggregator programs
   Capacity payments, demand response, and flexible load incentives can materially improve project economics.

For Cities, Campuses, and Communities

Distributed energy projects can directly support public goals:

• Microgrids for hospitals, emergency shelters, campuses, and key municipal services
• Solar‑plus‑storage at schools that double as resilience hubs
• Street‑level EV charging managed to avoid new peak loads

If you’re responsible for community infrastructure, think in terms of a distributed portfolio:

• Where can we reduce exposure to high‑price hours?
• Which critical facilities must ride through outages?
• How can we earn ongoing value by offering flexibility back to the grid?

Green technology here isn’t abstract. It’s line items in a city budget and fewer painful rate debates.

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Policy, Regulation, and the Path to Fair Cost Reductions

DERs only reduce system‑wide electricity costs if the rules of the game reward their actual value.

The most effective regulatory moves look like this:

• Time‑varying and dynamic rates that reflect real system costs by hour and season.
• Performance‑based regulation that rewards utilities for reliability, emissions cuts, and customer savings, not just capital spending.
• Interconnection reform so new DERs don’t wait years to connect.
• Tariffs for flexibility that pay DER owners for capacity, fast response, and local grid support.

The mistake regulators sometimes make is treating DERs as a pure subsidy play, rather than as an asset class that can compete on cost with traditional infrastructure. When DERs compete fairly, they often win – and customers benefit.

This is exactly where the Green Technology conversation needs to sit in 2026: not just celebrating clean electrons, but reshaping markets and software so those electrons are cheap, reliable, and intelligently used.

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Where This Is Heading – And What To Do Next

Distributed energy resources won’t magically erase rising electricity prices, but they change the trajectory. Instead of building more fossil peakers and ever‑bigger wires, we’re starting to build smarter, more local, and more flexible systems.

For businesses, cities, and energy managers, the next steps are clear:

• Audit where and when your energy costs spike.
• Identify which DERs – solar, storage, EVs, flexible loads – you already have or could add.
• Layer in software and AI that can orchestrate those assets against prices and grid conditions.
• Engage with utilities or aggregators to monetize your flexibility.

The energy system is becoming more distributed whether we plan for it or not. Those who treat DERs as core infrastructure – not as side projects – will see lower long‑term costs, higher resilience, and a real edge in meeting climate goals.

The question isn’t whether DERs can combat soaring electricity costs in the US. They already are. The real question is: how quickly do we scale the intelligence, incentives, and business models to let them do the heavy lifting?