Power Flexibility Paradigm Shift: From Macro Assets to Distributed Intelligence Layer

Author: Benji Siem, IOSG

1. Introduction

This research begins with a simple observation: the power system is being asked to perform a task it was never designed for.

As the penetration of renewable energy accelerates, electrification advances across sectors, and AI-driven data centers demand surges, the traditional model of “building more generation and transmission capacity to meet peak loads” is breaking down. Infrastructure buildout cycles are too long, grid interconnection queues are backloged, and capital intensity remains high.

Against this backdrop, flexibility—i.e., the ability to dynamically adjust supply and demand in real time—has risen from a supporting role to become a core pillar of grid reliability. The flexibility supply, once mainly from large industrial loads and peaking plants, is evolving into a complex multi-layered market, coordinating millions of assets through distributed energy resources (DER), software platforms, and aggregators to maintain system balance.

We are at a structural inflection point. The winners of this transformation will not be the players controlling generation assets, but those building the connectivity and orchestration layers, enabling large-scale flexibility deployment. Emerging crypto-native coordination models and token-based incentive mechanisms could further accelerate this shift, enabling decentralized participation, transparent settlement, and global liquidity for flexibility services.

As this paper explores in depth, flexibility is no longer just a technical capability; it is becoming an emerging economic infrastructure—creating new value pools through revenue stacking across capacity markets, ancillary services, demand response, and local markets, reshaping how energy is traded, managed, and monetized.

Core Thesis

The electricity flexibility market is at an inflection point. Rising renewable penetration, growing data center demand, and regulatory pushes are creating a structural imbalance between supply and demand for flexibility services.

• The demand for power to fuel AI and application development is rapidly surpassing grid supply capacity, driven mainly by:

• Global data center electricity consumption is projected to double by 2030 to about 945 TWh, slightly above Japan’s current total electricity use. AI is the primary driver of this growth, alongside increasing demand for other digital services. Notably, a lack of flexibility could become a bottleneck for AI expansion.

The power market urgently needs operational efficiency and flexibility to mitigate risks. Under infrastructure lag, the demand and necessity for flexibility services are significantly increasing.

• Many regions’ grids are under immense stress: an estimated 20% of planned data center projects may face delays unless capacity risks are addressed.

• In the US, grid operators face congestion issues: approximately 10,300 projects are queued, with a total capacity of 2,300 GW—twice the current US generation capacity.

The middle layer of aggregation and connectivity infrastructure will be the biggest winner. It bridges the supply side (users with idle capacity) and the demand side (strained grid operators).

• Software-centric platforms that aggregate and optimize DER will capture disproportionate value as markets expand from about $98.2 billion in 2025 to roughly $293.6 billion in 2034 (CAGR 12.94%).

2. Overview of Flexibility Markets

What is flexibility in energy markets?

In power systems, flexibility = the ability to rapidly adjust generation and/or demand in response to signals (electric prices, grid congestion, frequency, etc.) to maintain supply-demand balance and prevent outages.

Historically, flexibility came mainly from flexible generators (gas peaking plants, hydro). As renewable energy and electrification scale up, system operators now also procure flexibility from:

• Demand response: load reduction or shifting

• Storage: batteries, EVs, thermal storage

• Distributed generation: rooftop PV, small CHP systems

A “flexibility market” encompasses the markets and contracts where this flexibility is bought and sold, including wholesale markets, ancillary services, capacity markets, and local distribution system platforms. Aggregators act as intermediaries, providing platforms for grid operators to procure flexibility from end-users, forming a critical infrastructure layer (see “Flexibility Trading and Pricing” chapter). Settlements are handled by Transmission System Operators (TSOs), who pay aggregators, who deduct commissions before paying customers.

Flexibility delivery occurs via two modes:

• Implicit Flexibility: achieved automatically through static price signals, e.g., time-of-use pricing. For example, smart EV chargers delay charging to low-price night periods, driven by price signals.

• Explicit Flexibility: involves active response to specific grid operator requests, coordinated via market platforms, with direct compensation.

Detailed Example

Step 1: Customer Registration

An aggregator (e.g., CPower) signs a manufacturing company, installs monitoring devices (smart meters, controllers), and connects to its building management system. The customer agrees to reduce 2 MW when called upon.

Step 2: Registration with Grid Operator

The aggregator registers this 2 MW (along with thousands of other sites) as a “demand response resource” with the ISO. It must demonstrate the resource’s deliverability, including baseline calculation, metering protocols, and sometimes testing.

Step 3: Market Participation

The aggregator bids capacity into various markets:

• Capacity Market (annual/multi-year): “I commit to maintaining 500 MW available during summer peak”

• Day-Ahead Energy Market: “I can reduce 200 MW between 16:00-20:00 tomorrow”

• Real-Time Ancillary Services: “I can respond within 10 minutes to frequency deviations”

Step 4: Dispatch

When the grid needs flexibility, the TSO sends a signal. The aggregator’s platform executes: notifying registered customers (via SMS, email, auto-control signals); activating pre-programmed load reductions (e.g., raising thermostat setpoints, dimming lighting, pausing industrial processes); monitoring performance in real time.

Step 5: Settlement

After the event, the ISO measures actual delivered vs. committed amounts. Funds flow: ISO → aggregator → customer (minus commissions).

3. Key Participants

Market Platforms — Exchanges

Flexibility trading venues that match buyers (DSO/TSO) and sellers (aggregators, DER owners). Fast frequency reserve markets also provide trading platforms.

Sample Projects

EPEX SPOT, Nord Pool, Piclo Flex, NODES, GOPACS, Enera

Business Models

• Transaction fees (typically 0.5-2% of traded value or €0.01-0.05/MWh)

• Market access subscription/membership fees (annual participant fees)

• Some platforms operate as regulated utilities (recovered via grid tariffs), others commercially.

Pricing

• Platforms do not set prices but facilitate price discovery via auctions (pay-as-bid or uniform clearing)

• Local flexibility platforms (Piclo, NODES) congestion prices typically €50-200/MWh

• Wholesale balancing markets can spike above €1,000+/MWh during scarcity events

• Classic wholesale markets (e.g., EPEX) may have negative prices, effectively incentivizing active flexibility procurement in dedicated markets

Aggregators / Virtual Power Plants (VPPs)

Control clusters of flexible assets; revenues depend on winning contracts and proper dispatch.

Sample Companies

Enel X, CPower, Voltus, Next Kraftwerke, Flexitricity, Limejump

Business Models

• Revenue sharing with asset owners: 20-50% of market revenues retained by aggregators, rest paid to customers

• Upfront registration or SaaS fees from asset owners

• Performance bonuses for exceeding dispatch targets from utilities

Pricing

• Capacity payments: $30-150/kW/year (varies by market/product)

• Energy payments: market prices passed through (minus aggregator margin)

• Typical customer returns: C&I loads $50-200/kW/year, residential batteries $100-400/year

DER Management Systems (DERMS) / Optimization Software

Smart software enabling forecasting, control, bidding, and compliance, forming the intelligent layer of the system. Can be embedded within aggregator platforms.

Sample Companies

AutoGrid (Uplight), Enbala (Generac), Opus One, Smarter Grid Solutions, GE GridOS, Siemens EnergyIP

Business Models

• Enterprise SaaS licenses: annual contracts based on MW managed or assets controlled

• Implementation/integration fees: one-time projects for utilities ($500K–$5M+)

• Managed services: ongoing optimization-as-a-service based on performance

Pricing

• Software licenses typically $2-10/kW/year (varies by features and scale)

• Large utility DERMS deployments can reach $50-200 million+ over 5+ years

• Some vendors offer revenue-sharing models (5-15% of incremental value)

Asset Owners

Physical supply-side assets: EVs, batteries, thermostats, heat pumps, industrial loads.

Grid Buyers

Demand-side entities: utilities and system operators procuring flexibility to manage congestion, balance, and peak loads, including DSO, TSO, vendors, and municipalities.

Sample Entities

PJM, CAISO, National Grid ESO, TenneT, UK Power Networks, E.ON, Con Edison

Business Models

• Regulated entities recovering costs via grid tariffs or capacity charges

• Procurement when flexibility is cheaper than infrastructure upgrades (“non-wires alternatives”)

• Some vertically integrated utilities include DR projects internally, others outsource to aggregators

Procurement Pricing

• Capacity: $20-330/MW·day (PJM auction in 2026-27 reached $329/MW·day)

• Ancillary services: $5-50/MW·hour (frequency response, spinning reserves)

• Local flexibility (DSO): €50-300/MWh (auction-based, bid-based)

• Rule of thumb: flexibility must be ~30-40% cheaper than grid reinforcement

Figure 1: Mechanism Illustration

• Distribution System Operator (DSO): manages local distribution network (lines, substations), responsible for delivering power from main transmission lines to homes and businesses.

• Transmission System Operator (TSO): manages high-voltage network (grid, gas pipelines), responsible for long-distance energy transport from producers to local distributors or large consumers.

Estimated Revenue Scale of Participants

4. Industry Status

The power system faces a structural supply-demand imbalance in generation capacity and grid infrastructure. This manifests in two interconnected issues: unprecedented backlog in interconnection queues and surging demand from electrification and data centers.

Interconnection Queue Backlog

By end 2024, over 2,300 GW of generation and storage capacity are seeking grid connection in the US alone—more than double the existing capacity (1,280 GW). This backlog is a major bottleneck for clean energy deployment.

Demand-Side Pressures

• Data centers: global electricity demand expected to double by 2030 to 1,000–1,200 TWh (equivalent to Japan’s total consumption)

• PJM capacity prices: from $28.92/MW·day (2024-25) to $329.17/MW·day (2026-27), over 10x increase driven mainly by data center commitments

• US grid planners’ 5-year demand forecasts nearly double; AI data centers require 99.999% uptime and massive power

• Grid upgrade costs: EU needs €730 billion in distribution + €477 billion in transmission investments by 2040; flexibility can save 30-40% compared to infrastructure buildout

Flexibility Trading and Pricing

Grid operators (e.g., PJM, ERCOT, CAISO) need real-time balance but cannot directly communicate with millions of DERs (thermostats, batteries, industrial loads). Aggregators act as intermediaries.

Our analysis of aggregators (Enel X, CPower, Voltus) positions them between:

2. Grid operators/utilities needing flexible capacity

3. End customers with flexible loads or assets

They bundle thousands of small DERs into a “virtual power plant” (VPP) to participate in wholesale markets as a single entity.

Settlement Mechanisms

Unlike generation (measured in MWh output), demand response measures unconsumed MWh. This requires establishing a “baseline”—the amount of energy the customer would have consumed without DR events. Common baseline methods include:

• 10-of-10: average consumption over the past 10 similar days at the same time

• Weather-adjusted baseline

• Pre- and during-event metering comparisons

Settlement example:

Aggregators then pay customers based on contracts (typically 50-80% of total revenue), with the remainder retained as aggregator income.

Flexibility is monetized through various market mechanisms, each with different timeframes, product types, and pricing structures. Vendors can perform “revenue stacking” across multiple markets to maximize returns.

Additionally, energy communities—locally organized citizen and small business groups empowered by EU policies—are becoming key flexibility aggregators. There are about 9,000 communities across the EU representing roughly 1.5 million participants.

• By aggregating assets like PV, batteries, and controllable loads, these communities overcome scale and coordination barriers that typically prevent individual households from capturing multiple revenue streams.

• This aligns with research findings: flexibility providers can “stack” value across capacity markets, ancillary services, energy arbitrage, demand response, and local DSO markets. Energy communities create organizational and operational frameworks for cross-market participation, turning dispersed DER into coordinated portfolios, democratizing flexibility income, and supporting grid decarbonization and resilience.

Why Flexibility Matters

Flexibility services offer a faster, cheaper alternative to building new generation and transmission. Virtual power plants can be “built” as fast as customer registration—no interconnection queues. Brattle estimates VPP peaking capacity is 40-60% cheaper than gas peaking plants or utility-scale batteries. ENTSO-E estimates that in the EU alone, flexibility can save €5 billion annually in generation costs.

For grid operators: real-time balancing; reducing reliance on costly peaking plants and grid upgrades; better integration of renewables; increased resilience during extreme weather.

For asset owners: new revenue streams from existing assets (batteries, EVs, HVAC, industrial loads); multi-service stacking can boost returns by 30-50%; minimal operational disruption.

For consumers: demand response incentives lower electricity bills; avoided infrastructure costs; improved reliability and fewer outages.

For energy transition: higher renewable penetration without curtailment; decarbonizing grid services (replacing gas peakers); faster deployment compared to infrastructure-limited alternatives.

Structural Tailwinds

2. Regulatory momentum: FERC Orders 2222/2023 (US), EU demand response regulations (2027), UK BSC P483 enable 345,000 households to participate. Over 45 countries are introducing flexibility markets.

3. Grid investment surge: US utilities expect $1.1 trillion in grid investments by 2029. EU needs €730 billion in distribution + €477 billion in transmission upgrades by 2040. Flexibility is a more economical alternative.

4. Data center demand: global data center power use doubles by 2030 to 1,000–1,200 TWh. PJM capacity prices surge 10x (2024→2027). Creates both flexibility demand (grid stress) and supply.

5. DER proliferation: over 4 million US residential PV systems; 240,000+ home batteries; 1 million+ EV sales in 2023. Critical mass reached, empowering aggregators and DER economics.

Key Risks to Watch

2. Oversupply after 2030: large-scale battery investments may compress flexibility market margins. Some markets revive pumped hydro.

3. Cybersecurity: millions of DERs expand attack surface. EU AI Act classifies grid operation as “high risk.” NFPA 855 increases city battery storage costs by 15-25%.

5. Aggregator Business Models

Revenue Sources

2. Capacity payments ($/MW/year or $/MW/day): the largest and most predictable income stream. Customers paid for availability, even if not dispatched. For example, PJM’s 2026-27 auction reached $329/MW·day.

3. Energy payments ($/MWh): actual load reduction during events. More volatile, depends on dispatch frequency and market prices.

4. Ancillary services ($/MW + $/MWh): frequency regulation, spinning reserves, etc. Higher value but require faster response (seconds to minutes). Voltus pioneered access to these higher-margin products.

Cost Structure

Unit Economics Example (C&I Customers)

Revenue Stacking: How Aggregators Maximize Value

The most mature aggregators stack multiple revenue streams from the same assets:

Example: 10 MW industrial load in PJM

This is why Enel’s DER.OS and Tesla’s Autobidder emphasize “synergistic optimization”—their AI determines at each moment which market to participate in to maximize total returns.

6. Deep Dive: Key Players in the VPP/Aggregator Space

Enel X — Global Market Leader

Company Overview

Enel X is a division of Enel Group, one of the world’s largest utilities (€86 billion+ annual revenue), specializing in demand response and distributed energy. Originating from EnerNOC—pioneers in demand response founded in 2001, acquired by Enel in 2017—Enel X now operates the world’s largest commercial & industrial VPP, with over 9 GW of demand response capacity and 110+ active projects across 18 countries.

Scale & Reach

• Over 9 GW managed (Q1 2025), aiming for 13 GW

• North America: ~5 GW, covering 10,000+ sites across 31 US states and 2 Canadian provinces

• Projects: 80+ demand response projects, 30+ utility partnerships (including 11 exclusive bilateral agreements)

• Payments to DR participants since 2011: nearly $2 billion

• Tech investment: over $200 million in platform development

Strategic Partnerships

In September 2024, Enel X partnered with Google to aggregate 1 GW of flexible load from data centers—creating the world’s largest enterprise VPP. This exemplifies the convergence of data center demand growth and flexibility supply: large cloud providers with massive UPS batteries and load shifting capabilities can become key demand-side flexibility providers, driven by grid stress.

Technology Platform: DER.OS

Enel X’s DER.OS uses machine learning-driven scheduling optimization, which internal audits show can boost profitability by 12% over rule-based strategies. It streams data from 16,000+ sites and operates 24/7/365 control centers for real-time dispatch and monitoring.

Core Customers: C&I Facilities

These are large power consumers with interruptible loads—capable of temporary reduction without major disruption:

Key Insights

These customers already own “assets” (their loads). Enel X simply helps monetize hidden flexibility. The company positions itself on the demand side, asset-light, not owning generation assets. Demand reduction is equivalent to supply increase in grid effect.

Deep Meaning of Google Partnership

The September 2024 deal with Google is transformative:

• Traditional model: Enel X recruits facilities → aggregates into VPP → sells to grid

• Google model: Google data centers become flexible assets → Enel X operates VPP → grid operators buy flexibility

Google’s data centers have large UPS batteries (for backup), flexible cooling loads, and some workload scheduling flexibility. Google no longer just consumes grid flexibility but provides it—Enel X orchestrates. This exemplifies the “data center as grid asset” thesis.

Revenue Model Breakdown

Competitive Position

• Strengths: Largest global scale, deep utility relationships, integrated clean energy ecosystem (11 GW renewables + 1 GW storage), mature platform, financial backing from Enel Group

• Weaknesses: Traditional enterprise sales model, slower innovation cycle compared to pure startups, higher corporate overhead

• Strategy: Focus on C&I niche, utility-scale renewable integration, data center flexibility partnerships

Voltus — Software-First Challenger

Company Overview

Founded in 2016 by former EnerNOC executives Gregg Dixon and Matt Plante, Voltus positions itself as a tech-first alternative to traditional demand response providers. Its argument: superior software and broader market coverage can overcome scale disadvantages. By September 2025, Voltus ranked first in North American VPP capacity managed, for three consecutive years, according to Wood Mackenzie.

Scale & Funding

• Over 7.5 GW capacity (September 2025), up from 2 GW in 2021

• Active across all 9 US wholesale markets and Canada—most geographically extensive among pure startups

• Total funding: $121 million (investors include Equinor Ventures, Activate Capital, Prelude Ventures)

• SPAC attempt: Announced in December 2021 a $1.3 billion merger (valuation $1.3B), but not completed

Differentiation Strategy

Voltus differentiates on three axes: (1) pioneering innovation—first to open access to operating reserves across multiple grid operators; (2) broadest market coverage—participating in projects others avoid due to complexity; (3) DER partnerships—not competing with OEMs but collaborating with Resideo, Carrier, aggregating their install base into VPP.

Data Center Focus

In 2025, Voltus launched “Bring Your Own Capacity” (BYOC), tailored for data centers and hyperscale cloud providers. BYOC allows data center developers to deploy VPP-driven grid flexibility during project construction, offsetting capacity needs by purchasing flexibility from Voltus’s distributed network, shortening energization time. Partners include Cloverleaf Infrastructure.

Core Customers: C&I Facilities (similar to Enel X)

OEM Partnerships

Why OEM Model Matters

Customer acquisition cost (CAC) is the biggest expense for aggregators. OEM partnerships:

• OEM handles customer relationships

• Voltus provides software and market access

• Revenue is shared among OEM, Voltus, and end customer

• CAC is significantly lower than direct enterprise sales

Revenue Differences: Voltus vs Enel X

Enel X: Primarily capacity market—predictable, annual auctions, low $/kW but large volume, requires large MW commitments.

Voltus: Deliberately pursuing ancillary services that competitors avoid—higher $/kW (2-3x capacity market), fewer competitors (due to complexity), relies on advanced software, but assets must respond faster.

Competitive Position

• Strengths: Technical sophistication, broad market coverage, regulatory influence (former FERC chair Jon Wellinghoff as chief regulator), OEM partnership strategy, data center focus

• Weaknesses: Smaller scale than Enel X, no utility-scale assets, higher burn rate supported by VC, SPAC failure

• Strategy: Monetize third-party DER via software, lead in ancillary services, partner with data centers

7. Investment Criteria for VPP/Aggregator Evaluation

EU vs US Markets

With supportive regulation and highly interconnected infrastructure, the EU leads in system-wide flexibility expansion. Eurelectric notes that liberalized EU markets effectively incentivize producer and consumer participation, continuously increasing flexibility supply; large-scale smart meter rollout and time-of-use pricing lay the foundation for demand-side shifting.

• Market design: Liberalized markets drive proactive participation on both sides, with smart meters enabling load shifting via time-of-use tariffs

• Interconnected grids: Robust cross-border interconnections reduce outages and durations, providing stable power for industry

The US has vast untapped customer-side flexibility potential; studies suggest large-scale load reductions (~100 GW) are feasible with minimal impact on users.

• Grid-edge focus: Rapid growth of DER makes “edge” flexibility management increasingly critical for US utilities

“The inherent fragility of the grid demands careful management of every asset connected, ensuring reliable supply matches forecasted demand. The rapid growth of intermittent sources and electrification waves (peak demand) pose severe challenges to the power system.” — a16z

8. Conclusion

So far, macro-flexibilities—large industrial assets (>200 kW) connected at transmission or high-voltage distribution levels—have dominated. These assets are attractive due to ease of identification, contracting, and dispatch. But this model is hitting structural bottlenecks. Macro-flexibility alone is no longer sufficient, leading to supply shortages and chain issues like interconnection delays, increasing system vulnerability and becoming a bottleneck for AI-driven load growth.

The next frontier is inevitably micro-flexibility—small assets in the 1-10 kW range connected at medium- and low-voltage levels, including EV chargers, heat pumps, HVAC, batteries, and household appliances. These assets, when aggregated, represent capacity several orders of magnitude larger than macro sources but are far harder to access.

Current methods leave significant value on the table, creating opportunities for flexibility owners to capture and participate in the ecosystem. A direct-to-critical-scale owner, independent of vendor or device brand, can generate strong pull effects. Once users are horizontally aggregated, energy companies and OEMs will be economically motivated to participate proactively, rather than trying to control customer relationships from the outset.

At the core of all this, I believe DePIN (Decentralized Physical Infrastructure Networks) holds the greatest potential to disrupt this space and create long-term value through crypto-native infrastructure and incentive mechanisms. By increasing capacity and opening new pathways to access flexibility, this niche will revolutionize current energy markets, enabling AI to continuously reshape the world under unconstrained conditions.