Grid-Interactive Buildings: $74B by 2035 — When the Controls Stack Becomes an Income Line
Artificial intelligence, onsite storage, and distributed energy management now let a commercial building manage money the way it once managed temperature.
By Keith Reynolds | Publisher & Editor, ChargedUp!
For years, the building automation system answered to one master: the thermostat. Schedules were fixed, comfort was binary, and the utility bill arrived like weather. That habit is ending. The same controls layer now behaves like a trader with rules — responding to grid signals, prices, and risk — and can create a new line of income without disrupting tenants. That’s a shift owners can measure in NOI and buyers can underwrite.
Grid-interactive buildings connect BAS, AI, storage, and DERMS so properties can shift load, shave peaks, and sell flexibility. Frost & Sullivan values the market at $18.57B in 2026 on route to $74.31B by 2035. LBNL finds up to 30% of peak load can move without tenant impact. New VPP tariffs and the recent Google/Voltus and Leap/Verantum deals show the controls layer now earns money, not just manages temperature.
Key Takeaways
The controls stack converts a cost center into a flexibility asset, and energy-as-a-service contracts move the capital risk off the owner's balance sheet.
Regulation increasingly requires participation, as seen in the Illinois virtual power plant tariffs and a wave of large-load tariffs since 2018.
A building with integrated controls, onsite storage, and a documented flexibility revenue stream reads as lower risk to an acquirer.
What is a grid-interactive building?
A property whose building automation system (BAS), onsite storage, and software can move or shed load in response to grid and price signals, turning energy management from a fixed schedule into a savings-and-revenue function.
How big is the grid-interactive market — and what’s driving it?
Frost & Sullivan values it at $18.57 billion in 2026, on a path to $74.31 billion by 2035, served by roughly 130 companies selling demand response, DERMS, and AI optimization.
Market size: Frost & Sullivan values global grid-interactive building solutions at $18.57B in 2026, projecting $74.31B by 2035 (CAGR >16%).
Load flexibility: According to Lawrence Berkeley National Laboratory(LBNL), Up to 30% of commercial peak load can shift or shed with minimal tenant impact.
Program pull: Utilities and ISOs are paying for flexibility through demand response, VPPs, and new large-load tariffs.
Stack maturity: Vendors now contract to outcomes (savings and grid revenue), not just features, often as energy-as-a-service.
How does the controls stack actually work?
Think in four coordinated layers. These can be sourced from one provider or integrated across several:
Grid participation layer: Smart grid platforms (e.g., EnergyHub, Uplight, AutoGrid, Itron) connect building assets to utility/ISO programs and automate enrollment, dispatch, and settlement.
DERMS / microgrid control: Orchestrates onsite generation and storage; can island during outages to protect operations.
Storage optimization: Decides when to charge/discharge to capture demand charge avoidance, time-of-use arbitrage, and event revenue while protecting battery life.
Flexible-load management: Coordinates HVAC, ventilation, thermal mass, and high-load assets like EV charging to avoid peak collisions.
Packaging matters: outcome-guaranteed performance or EaaS contracts can move capital off the owner’s balance sheet and tie payment to delivered value — a decision a CFO can underwrite.
Which deals prove the model is live?
Google × Voltus (PJM, 100 MW): Voltus will assemble 100 MW of distributed flexibility across PJM, compensating homes and businesses that supply it.
Leap × Verantum (Dollar Tree portfolios): Leap and Verantum are enrolling connected commercial sites in CA, NY, and TX into automated demand response and grid services.
Both runs use the same engine: existing building controls, orchestrated by software, become a revenue-generating grid resource across different property types.
What policies are pushing buildings to participate?
Illinois VPP Tariffs (2026): Under the Clean and Reliable Grid Affordability Act, utilities filed VPP tariffs that must enroll customer-sited resources — explicitly including commercial BAS, batteries, and EV chargers — and pay when assets respond.
Large-load tariffs since 2018: Energy + Environmental Economics (E3) counts at least 38 large-load tariffs established since 2018, with 30 in 2025–2026.
Broader backdrop: ISO market rules and interoperability protocols (e.g., OpenADR) make automated participation repeatable across portfolios.
The direction of travel is clear: the building that can answer a grid signal becomes preferred — and the building that cannot becomes a stranded cost.
How does flexibility affect net operating income (NOI) and asset value?
Each controllable kilowatt can drive avoided demand charges, capacity/event payments, and outage continuity; because value is set by a cap rate applied to NOI, durable savings and program revenues can translate into higher asset value.
Demand charge avoidance: Reduce monthly peaks that often dominate the bill.
Capacity and event payments: Earn for being available and for actual dispatch in DR/VPP programs.
Outage continuity: Islanding plus prioritized loads protect revenue operations and tenant SLAs.
Illustrative arithmetic (example portfolio):
Callable load: 500 kW; 10 events/year at 2 hours each.
Demand charges avoided: $12/kW-month → ~$72,000/year (seasonality varies).
Capacity/event revenue: $5–$12/kW-month effective → ~$30,000–$72,000/year.
Operational continuity: avoided losses are property-specific; many owners treat this as risk reduction supporting a pricing premium.
NOI impact: $102,000–$144,000/year. At a 6.5% cap rate, that’s ~$1.57–$2.22 million in implied asset value.
Institutional buyers are starting to price this durability. A building with integrated controls, storage, and a documented flexibility revenue stream earns through volatility and reads as lower risk to an acquirer.
What should owners evaluate before they commit?
Comfort guardrails: Define pre-cooling, temperature bands, and escalation logic so tenants never feel events.
Telemetry and M&V: Interval data, submetering, and program-grade measurement & verification are non-negotiable for settlements.
Cyber and IT policy: Segment OT networks; require vendor security attestations and patch policies.
Load candidates: HVAC, ventilation, chilled water, thermal storage, elevators (non-peak), lighting (limited), EVSE.
Program fit: Response speed, duration, seasonality, and baselining rules can swing economics; model before you enroll.
Capex, performance, or EaaS — which contract aligns with risk?
Capex purchase: You own hardware/software; highest upside, higher upfront risk; you manage upgrades and performance.
Performance contract: Shared savings/revenue; vendor is paid from verified outcomes; good for aligning incentives.
Energy-as-a-service (EaaS): Off–balance sheet; predictable fee; vendor carries capital and performance risk; easiest to roll across portfolios.
Which metrics matter when comparing vendors?
Callable kW and response time: How much can you curtail in how many minutes?
Event duration and fatigue: Performance decay over multi-hour events.
Battery cycle strategy: Annual cycles, degradation assumptions, warranty terms.
$/kW-month (effective): All-in revenue rate after fees and penalties.
Baseline method: How is your reference load set, and can it be gamed or penalized?
Integration footprint: Protocols supported (BACnet/Modbus), OpenADR, IT security posture.
What’s the practical 90-day path to participation?
Treat flexibility like any other income line: size it, price it, and contract for it with clear guardrails. Pilot one site for 90 days; require vendor to guarantee outcomes and document dispatch logic. Then, standardize the playbook and scale to the rest of the portfolio.
Week 1–2: Run a 12-month peak analysis and quantify callable kW by asset with comfort limits. Identify peak windows; shortlist controllable loads and comfort limits.
Week 3–4: Shortlist 2–3 program paths (utility DR, ISO aggregation, VPP) and model $/kW-month economics under your tariff.
Week 5–8: Select contract model (Capex, performance, EaaS); align M&V, cybersecurity, and warranty terms, finalize IT requirements.
Week 9–12: Commission controls; run non-revenue test events; set dispatch rules; enroll.
When the controls stack is integrated and documented, the building stops reading as a pure operating cost and starts reading as a flexibility asset — one with cash flows acquirers can value.
Sources
https://store.frost.com/grid-interactive-building-solutions-market-global-2026-2035.html
https://mgrid.org/2026/01/09/illinois-3-gw-storage-vpp-mandate-2030/
https://www.ethree.com/electricity-rate-drivers-data-center-role-2026/
Additional Frequently Asked Questions
Will tenants notice demand response or VPP events?
Well-tuned BAS strategies (pre-cooling, narrow temperature bands, ventilation timing) keep comfort intact; LBNL research indicates up to 30% of peak load can move with minimal impact when controls are designed thoughtfully.
Which equipment usually provides the best flexibility?
HVAC and ventilation lead; batteries and thermal storage amplify results; EV charging is a strong candidate when orchestrated to avoid building peak collisions.
