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

Author: Benji Siem, IOSG

I. Introduction

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

With the accelerated increase in renewable energy penetration, the comprehensive advancement of electrification, and the surge in demand for AI-driven data centers, the traditional model of "building more generation and transmission facilities to meet peak loads" is collapsing. The infrastructure construction cycle is too long, there is a severe backlog in grid connection queues, and capital intensity remains high.

In this context, flexibility—the ability to dynamically adjust supply and demand in real-time—has shifted from being an auxiliary function to a core pillar of grid reliability. The past reliance on the flexibility provided by large industrial loads and peaking power plants is evolving into a complex multi-layered market where distributed energy resources (DER), software platforms, and aggregators coordinate millions of assets to maintain system balance.

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

As this article will explore in depth, flexibility is no longer just a technical capability; it is becoming an emerging economic infrastructure—creating new value pools by stacking revenues across capacity markets, ancillary services, demand response, and local markets, reshaping the ways energy is traded, managed, and monetized.

Core Argument
The electricity flexibility market is at a turning point. The rising penetration of renewable energy, growing demand from data centers, and regulatory push are creating a structural imbalance in the supply and demand for flexibility services.

• The demand for power to support AI and application development is rapidly outpacing the available supply capacity of the grid, driven primarily by:

• Global data center electricity consumption is expected to double to approximately 945 TWh by 2030, slightly exceeding Japan's current total electricity consumption. AI is the most significant driver of this growth, while demand for other digital services continues to rise. Notably, the lack of flexibility may also become a limiting factor for AI growth.

The electricity market urgently needs operational efficiency and flexibility to mitigate risks. In the context of lagging infrastructure construction, the demand and necessity for flexibility services have significantly increased.

• Many grids are under immense pressure: it is estimated that about 20% of planned data center projects may face delays unless capacity risks are addressed.

• In the U.S., approximately 10,300 power projects are currently queued due to difficulties faced by grid operators in managing grid congestion, with a total capacity of 2,300 GW—equivalent to twice the existing total installed capacity in the U.S.

The intermediate layer that aggregates and connects infrastructure will be the biggest winner. It builds a critical bridge between the supply side (users with idle capacity) and the demand side (stressed grid operators).

• Software-centric platforms that aggregate and optimize distributed energy resources (DER) will capture a disproportionate share of value as the market expands from approximately $98.2 billion in 2025 to about $293.6 billion in 2034 (CAGR of 12.94% from 2025-2034).

II. Overview of the Flexibility Market

What is flexibility in the energy market?
In the power system, flexibility = the ability of the system to quickly adjust generation and/or demand in response to signals (electricity prices, grid congestion, frequency, etc.) to maintain supply-demand balance and avoid blackouts.

Historically, flexibility has come almost entirely from flexible generation units (gas peaking plants, hydropower). As the scale of renewable energy and electrification expands, system operators are now procuring flexibility from the following sources:

• Demand Response: Load that can be curtailed or shifted

• Energy Storage: Batteries, electric vehicles, thermal storage

• Distributed Generation: Rooftop photovoltaics, small combined heat and power, etc.

The "flexibility market" is a collection of markets and contracts where flexibility is bought and sold, including wholesale markets, balancing/ancillary service products, capacity markets, and local distribution system operator (DSO) flexibility platforms. Aggregators act as intermediaries, providing platforms that enable grid operators to procure flexibility from end users, forming a critical infrastructure layer (see the "Trading and Pricing of Flexibility" section). Settlements are handled by transmission system operators (TSO), who pay aggregators, who then pay customers after deducting their commission.

There are two ways to deliver flexibility:

• Implicit Flexibility: Automatically realized through static price signals, such as time-of-use pricing. For example, smart EV chargers automatically delay charging to nighttime low-price periods. Price signals drive behavior.

• Explicit Flexibility: Involves proactive responses to specific requests from grid operators. These actions are consciously executed and coordinated through market platforms for direct compensation.

Detailed Example
# Step 1: Customer Registration
An aggregator (such as CPower) signs a contract with a manufacturing enterprise, installs monitoring equipment (smart meters, controllers), and connects to its building management system. The customer agrees to reduce 2 MW of load when called upon.
# Step 2: Registration with the Grid Operator
The aggregator registers this 2 MW (along with thousands of other sites) as a "demand response resource" with the ISO. The aggregator must prove that the resource can indeed deliver, including baseline calculations, measurement protocols, and sometimes testing schedules.
# Step 3: Market Participation
The aggregator bids the aggregated capacity into various markets:

• Capacity Market (annual/multi-year): "I commit to keeping 500 MW available during summer peak demand."

• Day-Ahead Energy Market: "I can reduce 200 MW of load tomorrow from 16:00 to 20:00."

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

# Step 4: Dispatch
When the grid needs flexibility, the TSO sends a signal to the aggregator. The aggregator's software platform then executes: sends notifications to registered customers (SMS, email, automated control signals); activates pre-programmed load reductions (such as raising temperature control set points, dimming lights, pausing industrial processes); and monitors performance in real-time.
# Step 5: Settlement
After the event, the ISO measures the difference between the actual delivered amount and the committed amount, with the cash flow as follows: ISO → Aggregator → Customer (after deducting the aggregator's commission).

III. Key Participants

Exchanges—Market Platforms
The trading venues for flexibility, these platforms facilitate transactions between buyers (DSO/TSO) and sellers (aggregators, DER owners). The fast frequency reserve market also provides another trading platform.
# Representative Projects
EPEX SPOT, Nord Pool, Piclo Flex, NODES, GOPACS, Enera
# Business Models

• Transaction fees for cleared trades (typically 0.5-2% of the transaction amount or €0.01-0.05/MWh)

• Subscription/membership fees for market access (annual fees for participants)

• Some platforms operate as regulated utilities (cost recovery through grid tariffs), while others are commercial operations

# Pricing

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

• Local flexibility platform congestion management prices typically range from €50-200/MWh

• Wholesale balancing market prices can soar to €1,000+/MWh during scarcity events

• Classic wholesale market prices (such as EPEX) may be negative, effectively equivalent to actively procuring flexibility in dedicated flexibility markets

Aggregators / Virtual Power Plants (VPP)
Control clusters of flexible assets, with revenue dependent on winning contracts and correctly dispatching loads/storage.
# Representative Companies
Enel X, CPower, Voltus, Next Kraftwerke, Flexitricity, Limejump
# Business Models

• Revenue sharing with asset owners: Aggregators retain 20-50% of market revenue, with the remainder paid to customers

• Some charge asset owners upfront registration fees or monthly SaaS fees

• May receive performance bonuses from utilities for exceeding dispatch targets

# Pricing

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

• Energy payments: Pass-through of market prices (less aggregator profit)

• Typical customer revenues: Commercial and industrial (C&I) loads $50-200/kW·year, residential batteries $100-400/year

Distributed Energy Resource Management Systems (DERMS) / Optimization Software
Software that enables forecasting, control, bidding, and compliance, serving as the intelligence layer of the entire system. Can be embedded in aggregator platforms.
# Representative Companies
AutoGrid (Uplight), Enbala (Generac), Opus One, Smarter Grid Solutions, GE GridOS, Siemens EnergyIP
# Business Models

• Enterprise-level SaaS licensing: Annual contracts based on the number of MW managed or assets controlled

• Implementation/integration fees: One-time project fees for utility deployments ($500,000 - $5 million+)

• Managed services: Performance-based ongoing optimization as a service

# Pricing

• Software licenses typically range from $2-10/kW·year (varies by functionality and scale)

• Total contract value for large utility DERMS deployments can reach $5-20 million+ (over 5 years)

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

Asset Side
Physical suppliers: Electric vehicles, batteries, thermostats, heat pumps, industrial loads, etc.
Grid Buyers
Demand side: Utilities and system operators procuring flexibility to manage congestion, balance, and peak loads, including DSOs, TSOs, suppliers, and municipal utilities.
# Representative Agencies
PJM, CAISO, National Grid ESO, TenneT, UK Power Networks, E.ON, Con Edison
# Business Models

• Regulated entities, recovering costs through grid tariffs or capacity fees from users

• Procure when flexibility is cheaper than infrastructure alternatives ("non-wires alternatives")

• Some vertically integrated utilities operate internal DR projects, while others outsource to aggregators

# Procurement Pricing

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

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

• DSO local flexibility: €50-300/MWh (typically auctioned on a pay-as-bid basis)

• Rule of thumb: Flexibility must be cheaper than grid reinforcement (target savings of about 30-40%)

# Figure 1: Mechanism Diagram

• Distribution System Operator (DSO): A company managing local power networks (distribution lines, substations), responsible for delivering electricity from main transmission lines to homes and businesses.

• Transmission System Operator (TSO): A key entity managing and maintaining high-voltage networks (grids and gas pipelines), responsible for transporting energy from producers over long distances to local distributors or large users.

Estimated Revenue Scale of Participants

IV. Industry Status

The power system faces a structural imbalance in generation capacity and grid infrastructure. This contradiction is reflected in two interrelated issues: an unprecedented backlog in grid connection queues and a surge in demand from electrification and data centers.
Grid Connection Backlog
As of the end of 2024, there are over 2,300 GW of generation and storage capacity seeking grid connection in the U.S.—more than twice the existing total installed capacity (1,280 GW). This backlog has become a major bottleneck for clean energy deployment.
Demand Side Pressure

• Data Centers: Global electricity demand is expected to double to 1,000-1,200 TWh by 2030 (equivalent to Japan's total electricity consumption)

• PJM Capacity Market: Prices surged from $28.92/MW·day (2024-25) to $329.17/MW·day (2026-27), an increase of over 10 times, primarily driven by commitments from data centers

• The 5-year demand forecast from U.S. grid planners nearly doubled; AI data centers require 99.999% uptime and massive electricity consumption

• Grid upgrade costs: The EU needs €730 billion in distribution investments + €477 billion in transmission upgrades by 2040; flexibility can provide 30-40% cost savings compared to infrastructure construction

Trading and Pricing of Flexibility
Grid operators (such as PJM, ERCOT, CAISO, etc.) need to balance supply and demand in real-time, but they cannot directly communicate with millions of distributed assets (thermostats, batteries, industrial loads). Therefore, aggregators act as intermediaries.

The aggregators we analyzed (Enel X, CPower, Voltus) sit between two parties:

1. Grid operators/utilities needing flexible capacity

2. End customers with flexible loads or assets

Aggregators bundle thousands of small distributed resources into a single "virtual power plant" to participate in wholesale market bidding as traditional power plants.
Settlement Mechanism
Unlike generation (measured in MWh output), demand response measures the MWh not consumed. This requires establishing a "baseline"—the amount of electricity the customer would have consumed without a DR event. Common baseline methods include:

• 10-of-10 Method: Taking the average consumption during the same time period over the past 10 similar days

• Weather Adjustment Method: Adjusting the baseline based on temperature differences

• Pre/Post Measurement Method: Comparing consumption before and during the event

Settlement Example:

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

Flexibility is monetized through various market mechanisms, each with different time frames, product forms, and pricing structures. Suppliers can engage in "revenue stacking" across multiple markets to maximize asset returns.

Additionally, energy communities—localized cooperatives of citizens and small businesses empowered by EU policy—are becoming a significant force in flexibility aggregation. There are approximately 9,000 communities across the EU, representing about 1.5 million participants.

• By aggregating behind-the-meter assets (such as photovoltaics, batteries, and controllable loads), these communities overcome the scale and coordination barriers that typically prevent individual households from accessing multiple streams of flexibility revenue.

• This aligns directly with research findings: flexibility providers can "stack" value across capacity markets, ancillary services, energy arbitrage, demand response, and local DSO markets. Energy communities create the organizational and operational frameworks necessary for reliable cross-market participation, transforming decentralized DER into coordinated portfolios, democratizing flexibility revenue while supporting grid decarbonization and resilience.

Why Flexibility Matters
Flexibility services provide a faster and cheaper alternative than building new generation and transmission facilities. The "construction" speed of virtual power plants is equivalent to the speed of customer registration—no grid connection queues are needed. The Brattle Group estimates that VPP peaking capacity is 40-60% cheaper than gas peaking plants or utility-scale batteries. ENTSO-E estimates that flexibility can save €5 billion in generation costs annually in the EU alone.

For grid operators: real-time balancing of supply and demand; reduced reliance on expensive peaking plants and transmission upgrades; improved integration of renewable energy; enhanced grid resilience during extreme weather.

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

For consumers: reduced electricity bills through demand response incentives; costs avoided due to deferred infrastructure investments; improved reliability and reduced outages.

For the energy transition: achieving higher renewable energy penetration without curtailing wind and solar; decarbonizing grid services (replacing gas peaking plants); accelerating deployment compared to infrastructure-constrained alternatives.
Structural Tailwinds

1. Regulatory momentum: FERC Orders 2222/2023 (U.S.), EU demand response network regulations (2027), UK BSC P483 enabling 345,000 households to participate. Over 45 countries globally are introducing flexibility markets.

2. Wave of grid investments: U.S. utilities are expected to invest $1.1 trillion in the grid by 2029. The EU needs €730 billion in distribution + €477 billion in transmission upgrades by 2040. Flexibility is a more economical alternative.

3. Data center demand: Global electricity consumption by data centers is expected to double to 1,000-1,200 TWh by 2030. PJM capacity prices have increased tenfold (2024→2027). This creates both demand (grid pressure) and supply for flexibility.

4. Proliferation of DER: Over 4 million residential photovoltaic systems in the U.S.; over 240,000 home batteries; over 1 million EV sales in 2023. Critical scale has been reached, empowering aggregators and the economics of DER.

Key Risks to Watch

1. Oversupply after 2030: Large-scale battery storage investments may compress flexibility market margins. Some markets may see a revival of pumped storage.

2. Cybersecurity: Millions of distributed assets expand the attack surface. The EU AI Act classifies grid operations as "high-risk." NFPA 855 increases urban battery storage costs by 15-25%.

V. Aggregator Business Models

Revenue Sources

1. Capacity Payments ($/MW·year or $/MW·day): The largest and most predictable revenue stream. Customers are compensated for availability, even if never dispatched. Example: PJM capacity prices reached $329/MW·day in the 2026-27 auction.

2. Energy Payments ($/MWh): Payments for actual load reductions during events. More volatile, depending on dispatch frequency and market prices.

3. Ancillary Services ($/MW + $/MWh): Frequency regulation, spinning reserves, etc. Higher value but require faster responses (seconds to minutes). Voltus has pioneered access to these higher-margin products.

Cost Structure

Unit Economic Model Example (C&I Customers)

Revenue Stacking: How Aggregators Maximize Value
The most mature aggregators stack multiple revenue streams from the same asset:

Example: 10 MW of industrial load in PJM

This is precisely why Enel's DER.OS and Tesla's Autobidder emphasize "synergistic optimization"—their AI determines at every moment which market to participate in to maximize total returns.

VI. In-Depth Analysis of Key Players in the Aggregator Layer

Enel X—Global Market Leader
# Company Overview
Enel X is the demand response and distributed energy business unit of Enel Group, one of the largest utility companies in the world (annual revenue over €86 billion). The company's roots trace back to EnerNOC—a demand response pioneer founded in 2001, acquired by Enel in 2017. Today, Enel X operates the world's largest commercial and industrial virtual power plant, with over 9 GW of demand response capacity and 110+ active projects across 18 countries.
# Scale and Coverage

• Global Capacity: 9+ GW under management (Q1 2025), targeting 13 GW

• North America: ~5 GW, covering over 10,000 sites in 31 U.S. states and 2 Canadian provinces

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

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

• Technology Investment: Over $200 million invested in platform development

# Strategic Partnerships
In September 2024, Enel X partnered with Google to aggregate 1 GW of flexible load from data centers—the world's largest corporate VPP. This partnership showcases the convergence of growing demand from data centers and the supply of flexibility: massive cloud service providers driving grid pressure while also becoming significant providers of demand-side flexibility through their UPS batteries and load-shifting capabilities.
# Technology Platform: DER.OS
Enel X's DER.OS platform utilizes machine learning-driven scheduling optimization, which, according to internal audits, can improve profitability by 12% compared to rule-based strategies. The platform streams data from over 16,000 enterprise sites and operates a 24/7/365 network operations center for real-time scheduling management and monitoring.
# Core Customers: Commercial and Industrial (C&I) Facilities
These are large electricity consumers with interruptible loads—processes that can be temporarily curtailed without causing significant disruption:

Key Insight
These customers already possess "assets" (their electricity loads). Enel X simply helps them monetize the flexibility they may not even realize exists. Enel X is clearly positioned on the demand side and is asset-light, not building or owning generation assets. Reducing demand has the same effect on the grid as increasing supply.
# Deep Implications of the Google Partnership
The Google deal in September 2024 is noteworthy as it disrupts traditional models:

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

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

Google data centers have large UPS battery systems (typically used for backup), flexible cooling loads, and some workload scheduling flexibility. Google is no longer consuming grid flexibility but is providing it—Enel X is the orchestration layer. This is a real-world embodiment of the argument that "data centers are grid assets."
# Revenue Model Breakdown

# Competitive Position

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

• Disadvantages: Traditional enterprise sales model, slower innovation cycles compared to pure startups, higher corporate management costs

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

Voltus—Software-First Challenger
# Company Overview
Voltus was founded in 2016 by former EnerNOC executives Gregg Dixon and Matt Plante, positioning itself as a technology-first alternative to traditional demand response providers. The company's argument is that superior software and broader market coverage can overcome scale disadvantages. As of September 2025, Voltus ranked first in managing GW capacity in Wood Mackenzie's North America VPP report for the third consecutive year.
# Scale and Financing

• Capacity: 7.5+ GW under management (September 2025), a significant increase from 2 GW in 2021

• Market Coverage: Active in all 9 U.S. wholesale power markets and Canada—broadest geographical coverage among pure-play aggregators

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

• SPAC Attempt: Announced a $1.3 billion SPAC merger in December 2021 (valuation of $1.3 billion), transaction was not completed

# Differentiation Strategy
Voltus differentiates itself on three dimensions: (1) pioneering innovation—first to open operational reserve project access among multiple grid operators; (2) the broadest market coverage—active in projects that competitors avoid due to complexity; (3) DER partnerships—does not compete with equipment manufacturers but collaborates with OEMs like Resideo and Carrier to aggregate their installation bases into VPPs.
# Focus on Data Centers
In 2025, Voltus launched the "Bring Your Own Capacity" (BYOC) product, designed specifically for data centers and hyperscale cloud service providers. BYOC allows data center developers to deploy VPP-driven grid flexibility while constructing projects, offsetting capacity needs by procuring flexibility from Voltus's distributed network, thereby shortening time to power. Partners include Cloverleaf Infrastructure.
# Core Customers: C&I Facilities (Similar to Enel X)

# OEM Partnerships

# Why OEM Models Matter
Customer acquisition costs (CAC) are the largest expense for aggregators. Through OEM partnerships:

• OEMs handle customer relationships

• Voltus provides software and market access

• Revenue is shared among OEMs, Voltus, and end customers

• CAC is significantly lower than direct enterprise sales

Revenue Source Differences: Voltus vs Enel X
# Enel X: Capacity Market Dominant

• Predictable (annual auctions)

• Lower unit $/kW but high volume

• Requires large MW commitments

# Voltus: Deliberately Pursuing Ancillary Service Projects Avoided by Competitors

# Why Choose Ancillary Services?
Higher unit $/kW (2-3 times that of capacity markets); fewer competitors (complexity creates barriers); requires sophisticated software (where Voltus excels); but demands faster responding assets.
Competitive Position

• Advantages: Technical sophistication, broadest market coverage, regulatory influence (former FERC chairman Jon Wellinghoff serves as chief regulatory officer), OEM partnership strategy, data center positioning

• Disadvantages: Smaller scale than Enel X, no utility-grade asset base, venture-backed burn rate, SPAC failure

• Strategy: Software monetization of third-party DERs, first-mover advantage in ancillary services, data center partnerships

VII. VPP/Aggregator Investment Evaluation Criteria

EU vs U.S. Market
With a well-established supportive regulatory framework and highly interconnected infrastructure, the EU is advancing faster than the U.S. in the expansion of system-wide flexibility. Eurelectric points out that the liberalized EU market effectively incentivizes joint participation from producers and consumers, continuously enhancing the supply of flexibility; meanwhile, the widespread adoption of smart meters has laid the groundwork for time-of-use pricing, facilitating demand-side shifts.

• Market Design: Liberalized market mechanisms drive proactive participation from both supply and demand sides, with smart meters enabling time-of-use pricing to achieve load shifting

• Interconnected Grid: The EU's robust transnational interconnected grid significantly reduces the frequency and duration of outages, providing stable and reliable power supply for industrial users

The U.S. has significant untapped customer-side flexibility potential, with studies indicating that large-scale load reductions (e.g., 100 GW) can be achieved with minimal impact on users.

• Grid Edge Focus: The rapid proliferation of distributed energy resources (DER) makes flexibility management at the "grid edge" increasingly critical for U.S. utilities

"The inherent vulnerability of the grid requires us to treat every connected asset with caution, ensuring reliable supply matches forecasted demand. The rapid growth of intermittent power sources (unstable supply) coinciding with the electrification wave (demand spikes) is posing severe challenges to the power system." ------ a16z

VIII. Conclusion

So far, flexibility has been dominated by "macro flexibilities"—large industrial-grade assets connected at the transmission or high-voltage distribution level (>200 kW). These assets are attractive due to their ease of identification, contracting, and dispatch. However, this model is reaching structural bottlenecks. Macro flexibility is no longer sufficient, leading to electricity supply shortages and cascading issues, such as grid connection delays. This increases system vulnerability and is becoming a key bottleneck for AI-driven load growth.

Thus, the next frontier is inevitable: micro flexibilities. This refers to small behind-the-meter assets in the 1-10 kW range connected to medium and low-voltage networks, including EV chargers, heat pumps, HVAC systems, batteries, and household appliances. These assets, when aggregated, represent several orders of magnitude more capacity than macro sources, but are significantly harder to access.

Current methods of accessing these flexibilities often leave substantial untapped value, creating opportunities for flexibility owners to fill this gap and participate in the ecosystem. An aggregator that directly reaches critical scale, independent of suppliers or equipment brands, can create powerful pull effects. Once users are horizontally aggregated, energy companies and OEMs will be economically incentivized to participate proactively, rather than attempting to control customer relationships from the outset.

At the core of all this, I believe DePIN has the greatest opportunity to disrupt this field and create long-term value through crypto-native infrastructure and incentive mechanisms. By increasing capacity and opening new avenues for accessing flexibility, this segment will revolutionize the current electricity market, enabling AI to continuously reshape the world without constraints.