Trend watch: energy efficiency & demand response in 2026 – from pilots to scale

Executive summary

Rising electricity demand driven by electric vehicles (EVs), digital infrastructure and electrified heating is stretching grid capacity in many regions.
At the same time, building retrofits, high‑efficiency appliances and smart thermostats are lowering energy use and creating opportunities to shift consumption away from peak hours.
This trend watch explores how energy efficiency and demand response (DR) are moving from small pilots to large programmes in 2026.
It highlights examples from the United States and Canada where utilities have enrolled tens of thousands of customers and are managing hundreds of megawatts of flexible load.
The report also outlines the operational challenges that slow pilot programmes and discusses how digital design and customer incentives can accelerate enrolment.
Finally, it provides a framework and checklist for product and design teams to scale efficiency and DR initiatives in a way that delivers customer value, grid stability and climate benefits.

Why it matters

Demand for electricity is surging. Utilities report that new data centres, AI workloads and EV charging could double electricity consumption in some regions by the late 2020s.
Without intervention, that growth could require building new gas‑fired plants and upgrading transmission lines, raising costs and emissions.
Energy‑efficiency measures – such as insulation, triple‑pane windows and high‑efficiency heat pumps – cut consumption at its source.
Meanwhile, demand response programmes pay customers to adjust or reduce their usage during peak hours, shifting consumption to times when renewable energy is abundant.
Utilities and regulators have discovered that distributed resources like rooftop solar panels, home batteries, EV chargers and smart thermostats can be aggregated into virtual power plants (VPPs) that provide grid services at a lower cost than building new generation.
As electrification accelerates, energy efficiency and DR will be the cheapest and fastest tools for meeting demand and decarbonising the grid.

Key concepts and market fundamentals

Energy efficiency refers to reducing the amount of energy required to deliver the same service.
In homes and buildings this includes improving the thermal envelope (insulation, windows and air sealing), upgrading heating and cooling systems to heat pumps, installing LED lighting, and choosing appliances with high seasonal energy efficiency ratios (SEER) or coefficient of performance (COP).
In industry it encompasses process optimisation, waste‑heat recovery, and motor and pump upgrades.
These investments often deliver payback periods of three to seven years through lower energy bills and increased comfort.

Demand response programmes encourage customers to shift or curtail electricity use in response to grid needs.
Typical DR strategies include time‑of‑use tariffs, critical‑peak pricing, direct‑load control of thermostats and water heaters, and voluntary curtailment for commercial and industrial customers.
Advanced programmes link thousands of devices into VPPs; software sends control signals and measures performance to deliver reliable capacity.
Participants receive incentives such as bill credits, rebates, or payments per kilowatt‑hour reduced.
DR’s value comes from avoiding expensive peaking generation and deferring grid upgrades.

Virtual power plants aggregate distributed energy resources (DERs) like rooftop solar, batteries, EV chargers and thermostats into a coordinated resource that can be dispatched.
Unlike traditional peaker plants, VPPs are made up of customer‑owned assets.
With appropriate controls and compensation, VPPs can provide capacity, frequency regulation and other ancillary services.

What’s working

Early pilot programmes have demonstrated that energy efficiency and demand response deliver measurable benefits when designed well.

Virtual power plants save money and scale quickly.
Green Mountain Power in Vermont runs a battery‑based VPP that grew from just 20 customers in 2017 to 5 035 participants by 2025.
The network provides over 75 MW of dispatchable capacity and saved customers about US$3 million during a single hour of peak demand in June 2025.
The programme demonstrates that large numbers of homes can act as a peaker plant when compensated and coordinated effectively.
Scalable pilots attract thousands of devices.
Southern California Edison’s Power Flex pilot started with 5 MW of solar‑plus‑storage capacity in 2020.
By 2025 the pilot had grown to 25 MW with plans to expand further.
Its success has spurred the utility to continue scaling DR and VPP resources beyond 2027.
Cooperative utilities unlock large flexible loads.
Minnkota Power Cooperative serves rural areas in the northern United States.
Its demand response programme controls devices for 55 000 customers (about 40 % of its customer base).
By managing heat pumps, water heaters, EV chargers and commercial loads, Minnkota can shift 350 MW of demand – roughly 35 % of its winter peak load.
Participants receive upfront rebates and benefit from off‑peak electricity rates that are roughly half the standard rate, demonstrating how financial incentives drive participation.
State programmes achieve hundreds of megawatts of relief.
California’s Demand Side Grid Support programme enrolled over 265 000 participants by 2024 and provides 515 MW of dispatchable capacity.
The programme includes a 200 MW battery VPP and pays participants up to US$2 per kilowatt‑hour for net load reductions during grid emergencies; the VPP was activated 16 times during 2024 heatwaves.
Other large programmes include Rocky Mountain Power’s Cool Keeper (over 100 000 customers providing 280 MW of flexible load with 98 % participant satisfaction), Ontario’s IESO Peak Perks programme (over 125 000 devices providing over 100 MW of peak reduction and achieving a 133 MW load shed during its first event) and Arizona Public Service’s Cool Rewards smart‑thermostat programme (97 500 thermostats able to shed over 160 MW with customers receiving US$30 rebates and additional incentives for pre‑enrolment).
User‑centred design improves enrolment.
EnergyHub found that redesigning a utility enrolment microsite increased clicks on the “Enroll” button by 70 % and boosted accepted devices by more than 1 000 per month.
Simple sign‑up processes and clear messaging reduce friction, suggesting design thinking is critical to scaling programmes.
Energy efficiency programs deliver long‑term savings.
Upgrading insulation, installing heat pumps and adopting efficient appliances reduce energy bills for decades.
In Asia, the popularity of air‑source heat pumps is growing; Chinese sales increased 12 % in 2023 and account for roughly 8 % of heating equipment, with rooftop PV combined with a heat pump often yielding a six‑year payback.
Similar growth has been noted in Australia (about 1.37 million units sold in 2023) and New Zealand (241 000 units, more than double a decade earlier).
The efficiency of heat pumps (delivering 3–4 units of heat per unit of electricity) makes them integral to reducing both electricity consumption and peak demand.

What isn’t working

Despite promising pilots, scaling energy efficiency and demand response faces structural barriers:

Slow pilots and regulatory hurdles.
Many pilot programmes operate for years without clear criteria for success.
Utilities often lack incentives to prioritise demand‑side resources because their rate structures reward capital investments in generation and infrastructure.
A Utility Dive investigation found that pilots stall due to financial disincentives, unclear objectives and lack of timelines; regulators are experimenting with regulatory sandboxes and frameworks that establish cost caps, performance milestones and a pathway to permanent programmes.
Underinvestment in under‑resourced communities.
Energy efficiency upgrades and DR programmes can lower bills and improve comfort for low‑income households, yet these communities face barriers such as limited access to capital, lack of awareness and difficulty navigating incentives.
Creative funding models – such as partnerships with nonprofits and healthcare organisations and leveraging government rebates – are needed to ensure equitable participation.
Complex enrolment and customer scepticism.
Many customers are unfamiliar with demand response.
Complicated sign‑up processes, fear of losing control over appliances and concerns about privacy can deter participation.
Programmes that make enrolment intuitive, provide easy opt‑out options and clearly communicate benefits achieve higher uptake.
Data and integration challenges.
VPPs rely on near‑real‑time data and device control.
Utilities must integrate diverse hardware (thermostats, batteries, EV chargers) and software platforms while maintaining cybersecurity and privacy.
Interoperability standards and open APIs help, but many legacy systems are not ready.
Measurement and verification remain difficult when thousands of small devices contribute to a single resource.
Policy uncertainty and misaligned incentives.
In many regions, retail tariffs do not reflect the true cost of energy at different times.
Absent carbon pricing or peak pricing, customers have little incentive to shift consumption.
Utilities and regulators must align incentives so that demand‑side resources receive value commensurate with the grid services they provide.

A quick framework for product & design teams

Transitioning from pilot to scale requires clear strategy and cross‑functional coordination.
The following framework can help teams design and grow energy efficiency and demand‑response programmes:

Assess demand drivers and customer segments.
Map out where electricity demand is growing (e.g., EV adoption, data centres, electrified heating) and profile customer segments by load flexibility and willingness to participate.
Identify high‑impact sectors such as residential HVAC, commercial refrigeration and industrial processes.
Prioritise efficiency opportunities.
Conduct audits to find the most cost‑effective efficiency upgrades – building envelope improvements, high‑efficiency heat pumps, advanced lighting controls and motor upgrades.
For industrial clients, look for process optimisation and waste‑heat recovery.
Combine rebates, tax incentives and creative financing (on‑bill financing, performance contracts) to reduce upfront costs.
Design compelling DR programmes.
Start with a clear goal (e.g., 100 MW of flexible load or reducing peak demand by 10 %).
Choose the right mechanism: time‑of‑use pricing, direct‑load control or behavioural programmes.
Offer transparent incentives – rebates for smart thermostats, bill credits for participation, and performance payments (e.g., up to US$2 per kWh for emergency reductions).
Ensure customers can opt out of events easily.
Build an open, scalable platform.
Integrate devices through open standards like OpenADR and smart‑meter protocols.
Use cloud‑based management systems that can dispatch hundreds of thousands of devices and verify performance.
Plan for cybersecurity, data privacy and system redundancy.
Simplify enrolment and communications.
Apply user‑centred design to create intuitive websites and mobile apps.
Use personalised marketing (text messages, emails, social media) and community partnerships to reach diverse demographics.
Provide clear messaging about how participation works, what customers can expect and how they can opt out.
Measure, verify and iterate.
Establish robust measurement and verification frameworks to ensure reductions are real.
Leverage smart metres, device telemetry and control signals to track baseline and event performance.
Continuously collect feedback from participants and adjust programme design to improve satisfaction and outcomes.

Fast‑moving segments to watch

Even as demand response and efficiency programmes scale, new areas are emerging:

Managed EV charging and vehicle‑to‑grid (V2G).
EVs represent a huge flexible resource. Programmes that schedule charging overnight or discharge during peaks can provide gigawatts of capacity.
Pilots such as those run by utilities in California and Vermont show promising results, though standards and compensation models are still evolving.
Smart water heaters and thermal storage.
Controlling electric water heaters or installing thermal storage tanks allows load shifting without impacting comfort.
Water heaters can act like batteries, absorbing excess renewable energy during midday solar peaks and reducing consumption in the evening.
AI‑driven building automation.
Machine learning models can optimise HVAC and lighting based on occupancy, weather and electricity prices.
Smart thermostats that adapt to occupant behaviour have shown to reduce energy use without sacrificing comfort.
Integration of heat pumps with DR.
Heat pumps can both heat and cool, making them versatile assets for demand response.
Programmes that modulate heat pump operation – pre‑heating or pre‑cooling buildings when renewable energy is abundant – can shift large loads.
Scaling programmes beyond electricity.
Demand response principles are beginning to apply to gas networks and water systems.
For example, industrial gas consumers may reduce usage during supply constraints; water utilities use demand response to reduce pumping during high electricity price periods.

Action checklist

Use this checklist to translate the framework into action:

Analyse load growth and segment customers by demand drivers and flexibility potential.
Identify low‑hanging efficiency upgrades and secure funding (rebates, tax incentives, public programmes).
Set clear demand response targets and choose mechanisms (direct load control, time‑of‑use pricing, behavioural programmes).
Design incentives that combine upfront rebates and performance payments.
Select interoperable technology platforms and adhere to open standards for device integration.
Develop intuitive enrollment tools and communication plans; partner with community organisations for outreach.
Establish measurement and verification procedures to track performance and validate savings.
Iterate continuously based on data and participant feedback; scale successful pilots and sunset ineffective ones.

Frequently asked questions

Why is demand response more important now than in previous years?
Electrification of transport and heating, combined with growth in data‑centre loads and extreme weather events, is raising peak demand.
New fossil‑fuel peaker plants are expensive and slow to build, whereas demand response can be deployed quickly and cost‑effectively.
Aggregated DERs acting as VPPs provide flexibility that can balance variable renewables and reduce the need for new generation.

How much can customers earn from participating in DR programmes?
Compensation varies by region and programme design.
In California’s Demand Side Grid Support programme, participants can earn up to US$2 per kilowatt‑hour for load reductions during grid emergencies.
Some utilities offer upfront rebates for devices (e.g., US$30 for a smart thermostat) plus ongoing bill credits or lower rates.

Do demand response programmes compromise comfort or convenience?
Most programmes are designed so that customers retain control.
Participants can override events or opt out entirely.
Smart thermostats may adjust temperatures by only a few degrees, and water heaters heat water during off‑peak hours without noticeable impact.
High satisfaction rates (98 % in Rocky Mountain Power’s programme) show customers are generally comfortable with DR.

Is demand response only relevant in North America?
No. DR programmes are expanding globally.
In Europe, the energy crisis and rapidly growing heat pump market have increased interest in load flexibility.
In Asia, China’s new heat pump action plan emphasises integrated planning, intelligent control systems and financing mechanisms.
Australia and New Zealand are seeing strong growth in heat pump sales, creating opportunities for combined efficiency and DR initiatives.
As energy markets liberalise, more countries will adopt dynamic pricing and aggregator models.

Key Players

Established Leaders

Siemens — Global leader in building automation.
Schneider Electric — EcoStruxure platform for building energy management.
Johnson Controls — OpenBlue platform for smart building optimization.
ABB — Industrial energy efficiency and grid automation.

Emerging Startups

Voltus — Commercial and industrial demand response aggregator.
OhmConnect — California-based residential demand response.
Base Power — Raised $600M Series D for home battery demand response.
Leap — Distributed energy resource aggregation platform.

Key Investors & Funders

Coatue Management — Lead investor in Base Power's $600M round.
Energy Impact Partners — Major investor in demand response startups.
California Energy Commission — Supporting automated demand response.

Sources

Utility Dive. (2025). Virtual Power Plants and Distributed Energy Resources: Market Analysis. Utility Dive.
CLEAResult. (2025). Energy Efficiency and Demand Response: Scaling for Grid Resilience. CLEAResult.
Green Mountain Power. (2025). Battery-Based Virtual Power Plant Programme Results. Green Mountain Power.
Southern California Edison. (2025). Power Flex Pilot Programme Evaluation. Southern California Edison.
Minnkota Power Cooperative. (2025). Demand Response Programme Performance Report. Minnkota Power Cooperative.
California Energy Commission. (2025). Demand Side Grid Support Programme Summary. California Energy Commission.
Rocky Mountain Power. (2025). Cool Keeper Programme Annual Report. Rocky Mountain Power.
IESO. (2025). Peak Perks Programme Results and Analysis. Independent Electricity System Operator.
Arizona Public Service. (2025). Cool Rewards Smart Thermostat Programme Review. Arizona Public Service.
EnergyHub. (2025). Utility Enrolment Design Best Practices. EnergyHub.
Regulatory Assistance Project. (2025). Analysis of China's 2025 Heat Pump Action Plan. Regulatory Assistance Project.