Demand response programs are no longer experimental grid management tools — they are economic necessities. As unprecedented load growth from data centers, electrification, and EV adoption strains grid infrastructure, utilities face a stark choice: invest billions in new generation and transmission assets, or deploy software-driven flexibility that extracts more value from existing resources.

This paper examines the business case for demand response across three dimensions: avoided infrastructure costs through non-wire alternatives, new revenue streams from wholesale market participation, and customer engagement as a competitive moat against third-party aggregators. Drawing on regulatory developments (FERC Order 2222, state-level mandates, and the EU Network Code) and real-world deployment data, we argue that demand response is no longer optional — and that speed to market is now the decisive strategic variable.

Executive Summary

The economics of demand response have shifted decisively. What was once a regulatory compliance checkbox is now a core revenue strategy and infrastructure cost-avoidance mechanism.

The Problem: Grid operators face load growth projections that exceed historical models. Building new transmission and generation assets requires decade-long planning cycles and billions in capital. Meanwhile, third-party aggregators are enrolling utility customers directly, capturing value that could remain within the utility’s ecosystem.

The Opportunity: Demand response offers a three-part value proposition. First, it functions as a non-wire alternative — providing capacity and reliability services at a fraction of the cost of new infrastructure. Second, FERC Order 2222 has opened wholesale markets to aggregated distributed energy resources, creating new revenue streams for utilities and OEMs that can meet protocol requirements. Third, DR programs deepen customer relationships, reducing churn and creating recurring engagement touchpoints.

The Barrier: Protocol complexity remains the primary obstacle. OpenADR 2.0b/3.0, IEEE 2030.5, CTA-2045, and EEBUS require deep technical expertise that most organizations lack internally. Building from scratch takes many months — time that regulators, markets, and competitors will not grant.

The Path Forward: A hybrid approach — using pre-certified accelerators to achieve rapid protocol compliance, then customizing for specific market needs — delivers the speed-to-market required without sacrificing long-term flexibility. Organizations that move now will capture the early-mover advantage; those that delay will find themselves buying market share back from aggregators who got there first.

Why DR Economics Have Changed

For decades, demand response occupied a narrow operational niche — the emergency brake utilities pulled during extreme heat waves or unexpected generation outages. It was a reliability tool, not a business strategy. That calculus has fundamentally shifted.

The evidence is structural, not anecdotal. PJM Interconnection, the largest wholesale electricity market in the United States, committed 7.9 GW of demand response resources for Summer 2025. That figure represents not a pilot program or a regulatory experiment, but a core capacity resource that grid operators count on with the same confidence they extend to thermal generation. Demand response has graduated from backstop to baseline.

Three forces are driving this transition. First, unprecedented load growth — driven by data center expansion, manufacturing reshoring, and broad electrification — has outpaced the traditional planning cycle for new generation and transmission assets. Building new infrastructure takes years; deploying software-driven flexibility takes weeks. The arithmetic favors the latter.

Second, regulatory frameworks have matured to treat demand response as a first-class market participant. FERC Order 2222, fully effective since 2024, mandates that wholesale markets allow aggregated distributed energy resources to compete directly against traditional supply-side resources. The playing field is no longer tilted against flexibility.

Third, the cost dynamics have inverted. Building a gigawatt of new peaking capacity requires billions in capital and decade-long permitting cycles. Enrolling a gigawatt of demand-side capacity requires software, protocols, and customer relationships that utilities and aggregators can deploy in months. The non-wire alternative is no longer the exception — it is increasingly the default.

For utilities and OEMs still treating demand response as a compliance exercise rather than a revenue strategy, the market has moved on. The question is no longer whether demand response makes economic sense. The question is whether your organization is positioned to capture its value before competitors do.

The Regulatory Landscape: USA and EU

Regulatory momentum is accelerating on both sides of the Atlantic, transforming demand response from a voluntary program into a mandated capability. Organizations that treat this as distant policy risk are misreading the calendar.

United States: State-Level Mandates Proliferate

FERC Order 2222 established the federal foundation, but state legislatures are now adding specific mandates. Texas SB 1699, signed into law in 2025, targets a 25% residential load reduction by 2030 — an aggressive goal that will require utilities and retail energy providers to deploy demand response infrastructure at scale, not as an optional program but as a compliance requirement.

Ohio has followed a similar trajectory. Senate Bill 2 passed the state Senate in March 2025 and now moves through the House, mandating that utilities offer demand response programs to customers. The Midwest, historically slower to adopt distributed energy policies, is signaling that DR is no longer a coastal phenomenon.

California offers a cautionary lesson. The Demand Response Auction Mechanism (DRAM), once the state’s flagship program for integrating third-party DR into utility resource planning, was discontinued after 2024. The program struggled with the transition from pilot to permanent procurement — a challenge that other states and utilities should study carefully. The new capacity accreditation process taking effect in 2026 signals California’s intent to integrate DR more rigorously into resource adequacy, but the DRAM experience demonstrates that program design matters as much as policy intent.

European Union: Network Code Creates Continental Framework

The European regulatory shift is equally significant. In March 2025, ACER submitted its proposed Network Code on Demand Response to the European Commission. National enforcement is expected by 2027. The code’s most consequential provision mandates Local Flexibility Markets, creating a standardized mechanism for distributed resources to provide grid services at the distribution level, not just in wholesale markets.

The United Kingdom, post-Brexit, is pursuing its own path. The Market-wide Half-Hourly Settlement (MHHS) program reached Milestone 10 in September 2025, with migration beginning in October and full implementation scheduled for May 2027. Half-hourly settlement creates the price signal granularity that makes demand response economically viable for residential and small commercial customers.

The regulatory message is unambiguous: demand response is moving from optional to obligatory, from pilot to permanent. Organizations that begin compliance now will shape these markets; those that wait will be shaped by them.

Program Types and Market Access

Understanding demand response requires distinguishing between program types — each with different triggers, compensation structures, and technical requirements. The choice of which markets to pursue determines not just revenue potential but the entire technology stack required to participate.

Emergency vs. Economic Demand Response

Emergency demand response — the traditional model — activates only during grid stress events: extreme weather, unexpected generation outages, or transmission constraints. Compensation is typically event-based, and activation may occur only a handful of times per year. The value proposition is reliability insurance.

Economic demand response operates on a fundamentally different logic. Resources are dispatched based on market prices, not emergency conditions. When wholesale prices spike — whether due to demand peaks, transmission congestion, or generation scarcity — economic DR resources reduce load and capture the price differential. This model transforms demand response from an occasional emergency tool into a continuous revenue stream.

Market Access Points

Four primary markets offer demand response revenue opportunities:

Capacity markets compensate resources for being available to deliver load reduction when called. PJM’s 7.9 GW commitment demonstrates the scale of this market. Capacity payments provide predictable, recurring revenue — but require meeting stringent performance and availability requirements.

Energy markets allow demand response to compete directly with generation in day-ahead and real-time wholesale markets. FERC Order 2222 mandates this access for aggregated distributed resources across all ISOs.

Ancillary services — frequency regulation, spinning reserves, non-spinning reserves — require faster response times but offer premium compensation. These markets favor resources with automated, sub-second control capabilities.

Local flexibility markets, mandated by the EU Network Code, represent an emerging category. These markets compensate resources for relieving constraints at the distribution level — voltage management, congestion relief, and local balancing. As distribution grids absorb more solar, EVs, and heat pumps, local flexibility becomes increasingly valuable.

The strategic imperative is revenue stacking: participating across multiple markets to maximize the value of each enrolled megawatt. Single-market participation leaves money on the table. Multi-market participation requires protocol compliance, aggregator partnerships, and technology platforms capable of managing complex dispatch obligations. For organizations building aggregation capabilities, Codibly’s work with optimizers and aggregators demonstrates how platform architecture enables simultaneous market participation.

Protocol Requirements: The Certification Gate

Market access increasingly runs through protocol certification. “Demand response ready” no longer means a device can reduce load on command — it means the device speaks the languages that utilities, aggregators, and grid operators require. And those languages differ by geography.

North American Protocol Landscape

Three protocol families dominate US demand response:

OpenADR (Open Automated Demand Response) remains the primary signaling standard for utility-to-aggregator and aggregator-to-device communication. Version 2.0b is widely deployed; version 3.0 introduced RESTful APIs, JSON payloads, and the “program” construct that simplifies multi-market enrollment. OpenADR 3.1.0, released in September 2025, refined these capabilities — and the first certified products from E.ON, EVoke, and Universal Devices demonstrate that the ecosystem is maturing rapidly. For a deeper technical analysis of the 3.0 specification’s architectural changes, see Convention over Specification: A Deep Dive into OpenADR 3.0.

IEEE 2030.5, particularly its Common Smart Inverter Profile (CSIP) implementation, governs inverter-to-utility communication. California Rule 21 mandates IEEE 2030.5 CSIP certification for grid-connected inverters — making it non-negotiable for DER manufacturers targeting that market.

CTA-2045 addresses device-level control for appliances: water heaters, HVAC systems, pool pumps, and EV chargers. Washington, Oregon, and California (via SB 49) mandate CTA-2045 compatibility for certain appliance categories.

European Protocol Landscape

European markets rely on a different — though sometimes overlapping — protocol stack:

EEBUS provides the communication framework for home energy management across Germany and increasingly the broader EU. Its SPINE protocol enables device interoperability for heating systems, EV chargers, and battery storage within residential and commercial settings.

IEC 61850, originally designed for substation automation, is extending into DER communication as utilities integrate distributed resources into grid operations. The EU Network Code on Demand Response will accelerate standardization requirements for resources participating in Local Flexibility Markets.

UK MHHS compatibility requires systems to support half-hourly settlement data flows — a technical prerequisite for participating in the granular pricing environment that makes residential DR economically viable.

Protocol Geography Primary Use Case Mandate / Driver
OpenADR 2.0b / 3.x US (expanding globally) Utility ↔ aggregator signaling CA SB 49; OpenADR Alliance certification
IEEE 2030.5 (CSIP) US (California) Inverter ↔ utility communication CA Rule 21 mandate
CTA-2045 US (Pacific NW, CA) Appliance-level control (HVAC, water heaters, EVs) WA, OR, CA state mandates
EEBUS / SPINE Germany → EU Home energy management EU Network Code alignment
IEC 61850 EU Substation + DER communication Extending into DR via EU standardization

Certification as Market Access

The practical implication is consistent across geographies: without certified protocol implementations, devices cannot participate in utility programs or aggregator platforms. Certification is the gate — and the protocols required depend on which markets you intend to serve.

Revenue Stacking: The Aggregator Playbook

The demand response aggregator market is projected to grow from $2.85 billion in 2024 to $8.44 billion by 2033 — a 14.2% compound annual growth rate. Capturing a share of that value requires understanding how aggregators actually make money, and why multi-market participation is the difference between marginal returns and sustainable business models.

Revenue Stream Mechanics

Aggregators generate revenue through four primary channels:

Capacity payments provide the foundation. By committing enrolled resources to be available during system peaks, aggregators earn recurring payments — typically structured as dollars per kilowatt-year. PJM, ISO-NE, and NYISO all operate capacity markets where demand response competes directly with generation. The revenue is predictable, but performance requirements are strict: fail to deliver when called, and penalties can exceed the original payment.

Energy market arbitrage captures the spread between wholesale prices and the cost of curtailment. When real-time prices spike — whether due to demand peaks, transmission congestion, or generation scarcity — aggregators dispatch enrolled resources and pocket the differential. This revenue stream is variable but can be substantial during high-price events.

Ancillary services — frequency regulation, spinning reserves, and non-spinning reserves — offer premium compensation for resources capable of fast, automated response. These markets favor aggregators with sophisticated control platforms and sub-minute dispatch capabilities.

Local flexibility markets, emerging under the EU Network Code, compensate resources for relieving distribution-level constraints. As European grids absorb increasing volumes of rooftop solar, EVs, and heat pumps, the value of local flexibility is growing rapidly.

The Stacking Imperative

Single-market participation leaves significant value unrealized. An aggregator enrolling resources only in capacity markets forfeits energy arbitrage opportunities. One focused solely on wholesale markets misses local flexibility revenue in jurisdictions where it exists.

The aggregators capturing the most value per enrolled megawatt are those with technology platforms capable of managing simultaneous participation across multiple markets — optimizing dispatch decisions in real time based on which revenue stream offers the highest return at any given moment. Protocol compliance is the entry ticket; revenue stacking is the competitive advantage.

Barriers and Counter-Arguments

An honest assessment of demand response must acknowledge the barriers that have slowed adoption — and continue to create friction for utilities, aggregators, and OEMs.

Revenue Uncertainty

The most persistent objection from CFOs and finance teams is straightforward: demand response revenue is difficult to predict. Capacity market payments depend on auction outcomes. Energy arbitrage depends on price volatility. Ancillary service revenue depends on grid conditions. For organizations accustomed to stable, predictable revenue streams, the variability is uncomfortable. Multi-market revenue stacking mitigates this risk by diversifying income sources, but it does not eliminate it.

Residential Participation Gaps

Despite a decade of smart thermostat adoption and utility program investment, only 38% of residential customers participate in demand response programs. The technology exists; the engagement does not. This is fundamentally a program design problem — unclear value propositions, complex enrollment processes, and insufficient price signals all contribute. Solving it requires better customer experience, not just better hardware.

Pilot-to-Permanent Transition

California’s DRAM discontinuation offers a cautionary lesson. The program successfully demonstrated that third-party aggregators could provide reliable capacity — but struggled with the transition from pilot to permanent procurement mechanism. Utilities, aggregators, and regulators must design programs with long-term sustainability in mind from the outset, not as an afterthought.

Protocol Fragmentation

The coexistence of OpenADR, IEEE 2030.5, CTA-2045, EEBUS, and IEC 61850 creates complexity for manufacturers and aggregators operating across multiple markets. Each protocol requires distinct implementation effort, testing, and certification. This fragmentation is real — though it also represents an opportunity for organizations that can navigate it efficiently.

Implementation Pathways

Organizations pursuing demand response face a fundamental build-versus-buy decision — but a third option often proves more effective: accelerate.

Build from Scratch

Internal development offers maximum control and customization. It also requires 12-18 months of engineering effort for protocol implementation alone, followed by certification testing. For organizations with deep software teams and extended timelines, this path can work. For most, it cannot.

Buy Off-the-Shelf

SaaS platforms and turnkey solutions offer speed but create dependencies. Per-device pricing models that seem economical at pilot scale become punishing at fleet scale. Vendor lock-in limits future flexibility. And when the platform’s roadmap diverges from your market needs, you have limited recourse.

Accelerate with Pre-Certified Components

A hybrid approach — using pre-certified protocol accelerators as the foundation, then customizing for specific market and product requirements — delivers the speed of buying with the flexibility of building. The organization owns the codebase, avoids recurring licensing costs, and retains the ability to modify and extend. The OpenADR VEN/VTN Accelerator and IEEE 2030.5 Accelerator provide the pre-certified foundation, while demand response program integration services address the broader platform requirements.

Feature Build from Scratch Buy Off-the-Shelf Accelerate (Hybrid)
Timeline 12–18 months: Protocol implementation + certification testing. Weeks: Plug-and-play standard features. 6–8 weeks: Pre-certified core with custom deployment.
Control Full Ownership: Maximum customization, your engineering team drives the roadmap. Vendor-Dependent: Limited to vendor roadmap and standard API config. Client-Owned: You own the source code. Complete independence.
Recurring Costs Engineering Headcount: Ongoing maintenance and protocol updates fall on your team. Per-Device Licensing: Monthly fees per endpoint. Costs rise as you scale. None After Delivery: Fixed engagement fee. Costs remain flat regardless of fleet size.
Flexibility Unlimited but Slow: Any capability is possible — given enough time. Low: Locked into vendor’s feature set and update cycle. Unlimited: Full freedom to build custom IP and features on top.
Best For… Organizations with deep software teams and extended timelines. Small-scale pilots or organizations prioritizing simplicity over control. Scaling enterprises prioritizing speed-to-market without sacrificing ownership.

Proof Points

The timeline compression is substantial. A pool equipment manufacturer achieved full OpenADR 2.0b certification in six weeks using an accelerator approach — meeting California SB 49 requirements ahead of competitors still scoping internal builds. A battery storage provider reached IEEE 2030.5 CSIP certification in eight weeks, unlocking California Rule 21 market access months faster than a from-scratch timeline would permit.

In markets where regulatory deadlines are fixed and competitors are moving, speed to certification is not an operational detail — it is a strategic variable that determines who captures early-mover advantage and who spends years buying back market share.

Conclusion

The business case for demand response is no longer theoretical. PJM commits 7.9 GW of DR to meet summer peaks. State legislatures from Texas to Ohio are mandating utility program offerings. The EU Network Code will require Local Flexibility Markets across member states by 2027. The market for demand response aggregation is projected to nearly triple over the next decade.

For utilities, the calculus is straightforward: deploy demand response as a non-wire alternative, or invest billions in infrastructure that takes a decade to permit and build. For OEMs, the choice is equally clear: achieve protocol certification and access growing markets, or watch competitors capture the customers you could have served. For aggregators, the opportunity is immense — but only for those with the technology platforms to stack revenue across capacity, energy, ancillary, and flexibility markets simultaneously.

The barriers are real. Revenue uncertainty persists. Residential participation remains stubbornly below potential. Protocol fragmentation creates implementation complexity. But these are engineering and design problems, not fundamental obstacles — and organizations that solve them will define the next phase of grid modernization.

The window for early-mover advantage is open, but it will not remain so indefinitely. Regulatory deadlines are fixed. Competitors are moving. The organizations that act now — achieving certification, enrolling resources, and building multi-market capabilities — will shape these markets. Those that delay will find themselves buying back market share from those who got there first.

The question is no longer whether demand response makes business sense. The question is whether your organization is positioned to capture its value.