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

Written by: Benji Siem @IOSG

Introduction

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

As renewable energy penetration 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 development cycles are too long, grid connection 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 an auxiliary function to a core pillar of grid reliability. Previously relying mainly on large industrial loads and peaking power plants, flexibility provision 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 inflection point. The winners of this transformation will not be players controlling generation assets, but those building the connectivity and orchestration layers that enable large-scale flexibility deployment. Emerging crypto-native coordination models and token-based incentive mechanisms could further accelerate this shift by enabling decentralized participation, transparent settlement, and global liquidity for flexibility services.

As this paper will explore 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.

Key Arguments

The electricity flexibility market is at a tipping point. Rising renewable penetration, increasing data center demand, and regulatory pushes are creating structural supply-demand imbalances 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 rising 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. Infrastructure lagging behind, the demand for flexibility services and their necessity are significantly increasing.

Many regions’ grids are under immense pressure: it’s estimated that, unless capacity risks are addressed, about 20% of planned data center projects could face delays.

In the US, grid operators struggle with interconnection congestion, with approximately 10,300 projects queued, totaling 2,300 GW—twice the current total installed generation capacity.

The middle layer of aggregating and connecting infrastructure will become the biggest winner. It acts as a crucial bridge between the supply side (users with idle capacity) and the demand side (strained grid operators).

Platforms that focus on software, aggregating and optimizing DERs, are expected to grow from about $98.2 billion in 2025 to approximately $293.6 billion by 2034 (CAGR of 12.94%), capturing an outsized share of value.

Flexibility Market Overview

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

Demand Response: load reductions or shifting

Storage: batteries, electric vehicles, thermal storage

Distributed Generation: rooftop PV, small CHP units

The “flexibility market” encompasses the markets and contracts where this flexibility is bought and sold, including wholesale markets, balancing/ancillary services, capacity markets, and local distribution system operator (DSO) platforms. Aggregators act as intermediaries, providing platforms that enable grid operators to procure flexibility from end-users, forming a key infrastructure layer (see “Flexibility Trading and Pricing” chapter). Settlement is handled by transmission system operators (TSOs), who pay aggregators, who deduct commissions before paying customers.

Flexibility delivery methods:

Implicit Flexibility: achieved automatically via 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 responses to specific requests from grid operators. These behaviors are consciously executed and directly compensated through market platforms.

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 of load 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. The aggregator must demonstrate the resource’s deliverability, including baseline calculation, metering protocols, and sometimes testing dispatch.

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 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 to the aggregator. The aggregator’s platform executes: sending notifications (SMS, email, automatic control signals) to registered customers; activating pre-programmed load reductions (e.g., raising thermostat setpoints, dimming lighting, pausing industrial processes); and monitoring real-time performance.

Step 5: Settlement

After the event, the ISO measures actual delivered versus committed quantities. Funds flow as: ISO → aggregator → customer (minus aggregator’s commission).

Key Participants

Exchange — Market Platform

A marketplace where buyers (DSO/TSO) and sellers (aggregators, DER owners) meet. Fast frequency reserve markets also provide another trading platform.

Representative Platforms

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

Business Model

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

Market access subscription/ membership fees (annual participant fees)

Some platforms operate as regulated utilities (recover costs 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) often have congestion management prices of €50-200/MWh. Wholesale balancing markets can spike above €1,000+/MWh during scarcity. Traditional wholesale markets (e.g., EPEX) may have negative prices, effectively representing active procurement of flexibility in dedicated markets.

Aggregator / Virtual Power Plant (VPP)

Controls a cluster of flexible assets; revenue depends on winning contracts and properly dispatching loads/storage.

Representative Companies

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

Business Model

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

Some charge upfront registration or monthly SaaS fees

May earn performance bonuses for exceeding dispatch targets

Pricing

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

Energy payments: market prices minus aggregator margin

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

DER Management Systems / Optimization Software

Smart software enabling forecasting, control, bidding, and compliance—serving as the intelligence layer. Can be embedded within aggregator platforms.

Representative Companies

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

Business Model

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

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

Managed services: ongoing optimization-as-a-service, performance-based

Pricing

Software licenses typically $2-10/kW·year (depending on features and scale)

Large utility DERMS deployments can reach $50M–$200M+ over 5+ years

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

Asset Side

Physical supply: EVs, batteries, thermostats, heat pumps, industrial loads

Grid Buyers

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

Representative Agencies

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

Business Model

Regulated entities recovering costs via grid tariffs or capacity charges

Procure flexibility when cheaper than infrastructure upgrades (“non-wire alternatives”)

Some vertically integrated utilities run internal DR programs, others outsource to aggregators

Procurement Pricing

Capacity: $20-330/MW·day (PJM auction 2026-27 up to $329/MW·day)

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

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 Diagram

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 and pipelines), responsible for long-distance energy transport from producers to local distributors or large consumers.

Estimated Revenue Scale of Participants

Industry Status

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

Interconnection Queue Backlog

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

Demand-Side Pressures

Data centers: global power demand expected to double by 2030 to 1,000-1,200 TWh (comparable to Japan’s total electricity consumption)

PJM capacity market: prices soared 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 consumption

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

Flexibility Trading and Pricing

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

Our analyzed aggregators (Enel X, CPower, Voltus) sit between:

Grid/utility needing flexibility

Owners of flexible loads/assets

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

Settlement Mechanism

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 during the same period over the past 10 similar days

Weather-adjusted: baseline adjusted for temperature differences

Pre- and during-event metering: comparing consumption before and during the event

Settlement example:

Aggregators pay customers based on contract terms (typically 50-80% of total revenue), with the remainder retained by the aggregator.

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—local citizen and small business cooperatives empowered by EU policies—are becoming key players in flexibility aggregation. 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, transforming 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 infrastructure. The speed of virtual power plant “construction” equals customer registration speed—no interconnection queues. Brattle Group 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.

Benefits include:

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

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

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

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

Structural Tailwinds

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

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.

Data center demand: global data center power use doubles to 1,000-1,200 TWh by 2030. PJM capacity prices increase tenfold (2024→2027). This creates both flexibility demand (grid stress) and supply.

DER proliferation: over 4 million US residential PV systems; 240,000+ home batteries; 1 million+ EVs sold in 2023. Critical mass achieved, empowering aggregators and DER economics.

Key Risks to Watch

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

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%.

Aggregator Business Models

Revenue Sources

Capacity payments ($/MW·year or $/MW·day): largest, most predictable revenue—paid for availability even if not dispatched. Example: PJM capacity price hit $329/MW·day in 2026-27 auction.

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

Ancillary services ($/MW + $/MWh): frequency regulation, spinning reserve, higher value but requiring faster response (seconds to minutes). Voltus pioneered these higher-margin products.

Cost Structure

Unit Economics (C&I customer example)

Revenue stacking: how aggregators maximize value from a single asset:

Example: 10 MW industrial load in PJM

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

Deep Dive into Key Players

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 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

Global capacity: over 9 GW managed (Q1 2025), aiming for 13 GW

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

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

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

Tech Investment: over $200 million in platform development

Strategic Partnerships

September 2024: Enel X partners with Google to aggregate 1 GW of flexible load from data centers—world’s largest enterprise VPP. This showcases the convergence of data center demand growth and flexibility supply: large cloud providers with massive cloud services and UPS batteries can become key flexibility providers.

Platform: DER.OS

Enel X’s DER.OS uses machine learning-driven scheduling optimization, improving profitability by 12% over rule-based strategies (per internal audit). 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

Large energy consumers with interruptible loads—can temporarily reduce load without major disruption:

Key Insights

These customers already have “assets” (their loads). Enel X helps monetize hidden flexibility. It is asset-light, demand-side focused, and does not own generation assets. Demand reduction is equivalent to increasing supply at the grid level.

Deep Meaning of Google Partnership

The September 2024 deal is disruptive:

Traditional: 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. They no longer just consume grid flexibility—they provide it. Enel X orchestrates. This exemplifies “data centers as grid assets.”

Revenue Model Breakdown

Competitive Position

Advantages: largest global scale, strong utility relationships, integrated clean energy ecosystem (11 GW renewables + 1 GW storage), mature platform, financial backing from Enel

Disadvantages: traditional sales approach, slower innovation cycle compared to startups, higher corporate overhead

Strategy: focus on C&I, utility-scale renewables, 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. As of September 2025, Voltus ranks first in managing GW capacity in Wood Mackenzie’s North American VPP report for the third consecutive year.

Scale & Funding

Capacity: over 7.5 GW managed (September 2025), up from 2 GW in 2021

Market Coverage: active across all 9 US wholesale markets and Canada—most geographically extensive among pure-play aggregators

Funding: $121 million total, including investments from Equinor Ventures, Activate Capital, Prelude Ventures

SPAC Attempt: announced in December 2021 a $1.3 billion SPAC merger (valuation $1.3B), 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—participates in projects others avoid due to complexity; (3) DER partnerships—not competing with OEMs but collaborating with Resideo, Carrier, aggregating their installed bases into VPPs.

Data Center Focus

By 2025, Voltus launched “Bring Your Own Capacity” (BYOC) products, designed for data centers and hyperscale cloud providers. BYOC allows data centers 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 models matter

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

OEM handles customer relationships

Voltus provides software and market access

Revenue is shared among OEM, Voltus, and end customers

CAC is significantly lower than direct enterprise sales

Revenue Model Comparison: Voltus vs Enel X

Enel X: capacity market focus

Predictable (annual auctions)

Lower $/kW but large volume

Requires large MW commitments

Voltus: targeting hard-to-serve ancillary services

Why ancillary services?

Higher $/kW (2-3x capacity market); fewer competitors (barrier: complexity); requires precise software (Voltus’s strength); assets need faster response.

Market Position

Strengths: advanced technology, broad market coverage, regulatory influence (former FERC chair Jon Wellinghoff as chief regulator), OEM partnerships, 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 software, lead in ancillary services, partner with data centers

VPP/Aggregator Investment Criteria

EU vs US Markets

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

Grid Interconnection: EU’s robust cross-border interconnections reduce outages and provide stable power, supporting industrial reliability.

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

Edge Focus: rapid DER proliferation makes flexibility at the “grid edge” increasingly critical for US utilities.

“Grid inherent fragility demands careful management of every connection point to ensure reliable supply and demand matching. The rapid growth of intermittent sources and electrification peaks pose serious challenges.” — a16z

Conclusion

So far, macro-flexibilities—large industrial assets (>200 kW) connected at transmission or high-voltage distribution levels—dominate. These assets are attractive due to ease of identification, contracting, and dispatch. But this model is hitting structural bottlenecks. Macro-flexibility alone is insufficient, leading to under-supply 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—assets connected at medium/low voltage levels, in the 1-10 kW range, 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 much harder to access.

Current methods leave significant value unclaimed, creating opportunities for flexibility owners to participate and for ecosystems to develop. A direct-to-critical-scale owner, independent of vendor or device brand, can generate strong pull effects. Once 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.