IOSG | Power Flexibility Paradigm Shift: From Macro Assets to Distributed Intelligence Layer
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IOSG | Power Flexibility Paradigm Shift: From Macro Assets to Distributed Intelligence Layer
The middleware layer that aggregates and connects infrastructure will be the biggest winner.
Navigating Web3 tides with focused insightsAuthor: Benji Siem, IOSG
I. Introduction
This study begins with a simple observation: power systems are being asked to perform a task they were never designed for.
As renewable energy penetration accelerates, electrification advances comprehensively, and AI-driven data center demand surges, the traditional model of “building more generation and transmission infrastructure to meet peak load” is collapsing. Infrastructure construction cycles are excessively long, interconnection queues are severely congested, and capital intensity remains stubbornly high.
Against this backdrop, flexibility—the ability to dynamically adjust supply and demand in real time—has evolved from an auxiliary function into a core pillar of grid reliability. Historically reliant on large industrial loads and peaking power plants, flexibility supply is now transforming into a complex, multi-layered market where distributed energy resources (DERs), software platforms, and aggregators coordinate millions of assets to maintain system balance.
We stand at a structural inflection point. The winners of this transition will not be players who control generation assets, but those who build the connectivity and orchestration layers—unlocking flexibility at scale. 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 explores in depth, flexibility is no longer merely a technical capability; it is emerging as a new economic infrastructure—creating novel value pools and reshaping how energy is traded, managed, and monetized through revenue stacking across capacity markets, ancillary services, demand response, and local markets.
Core Thesis
The electricity flexibility market is at an inflection point. Rising renewable penetration, growing data center demand, and regulatory momentum are creating a structural supply-demand imbalance for flexibility services.
- Demand for power to support AI and application development is rapidly outpacing available grid supply capacity, driven primarily by:
- Global data center electricity consumption is projected to double to ~945 TWh by 2030—slightly above Japan’s current total electricity consumption. AI is the single largest driver of this growth, while demand from other digital services continues to climb. Notably, lack of flexibility may itself become a constraint on AI growth.
Electricity markets urgently require operational efficiency and flexibility to mitigate risk. Against a backdrop of lagging infrastructure build-out, demand for—and necessity of—flexibility services has risen sharply.
- Grids across many regions are already under severe stress: an estimated ~20% of planned data center projects may face delays unless capacity risks are resolved.
- In the U.S., approximately 10,300 power projects—totaling 2,300 GW—are queued for interconnection, due to grid operators’ difficulty managing congestion. That volume equals roughly twice the nation’s current installed generation capacity.
The middleware layer—aggregation and connectivity infrastructure—will be the biggest winner. It serves as 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 (DERs) are poised to capture a disproportionate share of value as the market expands from ~$9.82 billion in 2025 to ~$29.36 billion in 2034 (CAGR of 12.94% from 2025–2034).
II. Flexibility Market Overview
What Is Flexibility in Energy Markets?
In power systems, flexibility = the system’s ability to quickly adjust generation and/or demand in response to signals (e.g., price, grid congestion, frequency) to maintain supply-demand balance and avoid blackouts.
Historically, flexibility came almost exclusively from flexible generation units (gas-fired peakers, hydro). As renewables and electrification scale, system operators now also procure flexibility from:
- Demand Response (DR): Load that can be curtailed or shifted in time
- Energy Storage: Batteries, EVs, thermal storage
- Distributed Generation: Rooftop PV, small-scale CHP, etc.
The “flexibility market” refers to the 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 “Trading and Pricing Flexibility” section). Settlement is handled by transmission system operators (TSOs), who pay aggregators, who in turn pay customers after deducting commissions.
Flexibility is delivered in two ways:
- Implicit Flexibility: Automatically achieved via static price signals, such as time-of-use (TOU) pricing. For example, smart EV chargers automatically delay charging to overnight low-price periods. Price signals drive behavior.
- Explicit Flexibility: Involves active response to specific requests from grid operators. These actions are consciously executed and coordinated via market platforms to receive direct compensation.
Detailed Example
#Step 1: Customer Enrollment
An aggregator (e.g., CPower) signs a manufacturing company, installs monitoring equipment (smart meters, controllers), and integrates with its building management system. The customer agrees to curtail 2 MW of load when called upon.
#Step 2: Registration with Grid Operator
The aggregator registers this 2 MW (alongside thousands of other sites) as a “demand response resource” with the ISO. The aggregator must demonstrate deliverability—via baseline calculations, metering agreements, and sometimes test dispatches.
#Step 3: Market Participation
The aggregator bids aggregated capacity into multiple markets:
- Capacity Market (annual/multi-year): “I commit to keeping 500 MW available during summer peak hours.”
- Day-Ahead Energy Market: “I can curtail 200 MW of load tomorrow from 4–8 PM.”
- Real-Time Ancillary Services: “I can respond to frequency deviations within 10 minutes.”
#Step 4: Dispatch
When the grid requires flexibility, the TSO sends a signal to the aggregator. Its software platform executes: notifying enrolled customers (SMS, email, automated control signals); activating pre-programmed load reduction (e.g., raising HVAC setpoints, dimming lighting, pausing industrial processes); and monitoring performance in real time.
#Step 5: Settlement
After the event, the ISO measures actual delivery versus committed quantity. Funds flow: ISO → Aggregator → Customer (minus aggregator commission).
III. Key Players
Exchanges — Market Platforms
Marketplaces for trading flexibility—matching buyers (DSOs/TSOs) with sellers (aggregators, DER owners). Fast frequency reserve markets provide another trading venue.
#Representative Projects
EPEX SPOT, Nord Pool, Piclo Flex, NODES, GOPACS, Enera
#Business Models
- Transaction fees on cleared trades (typically 0.5–2% of trade value or €0.01–0.05/MWh)
- Subscription/member fees for market access (annual participant fee)
- Some platforms operate as regulated utilities (cost recovery via grid tariffs); others operate commercially
#Pricing
- Platforms do not set prices; instead, they facilitate price discovery via auctions (pay-as-bid or uniform clearing)
- Congestion management prices on local flexibility platforms (e.g., Piclo, NODES) typically range from €50–200/MWh
- Wholesale balancing markets can spike to €1,000+/MWh during scarcity events
- Classic wholesale markets (e.g., EPEX) may see negative prices—functionally equivalent to proactively procuring flexibility in dedicated flexibility markets
Aggregators / Virtual Power Plants (VPPs)
Control clusters of flexible assets; revenues depend on winning contracts and correctly dispatching load/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; remainder paid to customers
- Some charge upfront registration fees or monthly SaaS fees to asset owners
- May earn 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 margin)
- Typical customer earnings: Commercial & Industrial (C&I) loads $50–200/kW·year; residential batteries $100–400/year
Distributed Energy Resource Management Systems (DERMS) / Optimization Software
Software enabling forecasting, control, bidding, and compliance—the intelligent layer of the entire system. May be embedded within aggregator platforms.
#Representative Companies
AutoGrid (Uplight), Enbala (Generac), Opus One, Smarter Grid Solutions, GE GridOS, Siemens EnergyIP
#Business Models
- Enterprise SaaS licensing: Annual contracts based on MW managed or number of controlled assets
- Implementation/integration fees: One-time project fees for utility deployments ($500k–$5M+)
- Managed services: Performance-based continuous optimization-as-a-service
#Pricing
- Software licensing typically $2–10/kW·year (varies by features and scale)
- Total contract value for large utility DERMS deployments can reach $5M–$20M+ (5+ years)
- Some vendors offer revenue-sharing models (5–15% of incremental value)
Asset Side
Physical suppliers: EVs, batteries, thermostats, heat pumps, industrial loads, etc.
Grid Buyers
Buyers: Utilities and system operators purchasing flexibility to manage congestion, balancing, and peak loads—including DSOs, TSOs, suppliers, and municipal utilities.
#Representative Institutions
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 levied on users
- Procure flexibility when cheaper than infrastructure alternatives (“non-wires alternatives”)
- Some vertically integrated utilities run internal DR programs; 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 pay-as-bid auctions)
- Rule of thumb: Flexibility must be cheaper than grid reinforcement (targeting ~30–40% savings)
#Figure 1: Mechanism Diagram
- Distribution System Operator (DSO): A company managing the local electricity network (distribution lines, substations), responsible for delivering power from main transmission lines to homes and businesses.
- Transmission System Operator (TSO): A key entity managing and maintaining the high-voltage network (grid and gas pipelines), responsible for transporting energy over long distances from producers to local distributors or large users.
Estimated Revenue Scale by Participant
IV. Industry Landscape
Power systems face a structural supply-demand imbalance in both generation capacity and grid infrastructure. This tension manifests in two interrelated problems: unprecedented interconnection queue congestion and surging demand from electrification and data centers.
Interconnection Queue Congestion
As of end-2024, over 2,300 GW of generation and storage capacity were seeking interconnection in the U.S. alone—more than double existing installed capacity (1,280 GW). This backlog has become a primary bottleneck for clean energy deployment.
Demand-Side Pressure
- Data Centers: Global electricity demand projected 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)—over a 10x increase—primarily driven by data center commitments
- U.S. grid planners’ 5-year demand forecasts have nearly doubled; AI data centers require 99.999% uptime and massive power draw
- Grid upgrade costs: EU needs €730B in distribution investment + €477B in transmission investment by 2040; flexibility offers 30–40% cost savings vs. infrastructure build-out
Trading and Pricing Flexibility
Grid operators (e.g., PJM, ERCOT, CAISO—ISO/RTOs) need to balance supply and demand in real time—but cannot communicate directly with millions of distributed assets (thermostats, batteries, industrial loads). Aggregators thus serve as intermediaries.
The aggregators we analyze (Enel X, CPower, Voltus) sit between:
- Grid operators/utilities needing flexible capacity
- End customers owning flexible loads or assets
Aggregators bundle thousands of small distributed resources into a single “virtual power plant,” bidding into wholesale markets as if they were conventional generators.
Settlement Mechanism
Unlike generation (which measures MWh produced), demand response measures MWh *not consumed*. This requires establishing a “baseline”—i.e., how much the customer would have consumed absent the DR event. Common baseline methods include:
- 10-of-10 Method: Average consumption over the prior 10 similar days during the same hour
- Weather-Adjusted Method: Baseline adjusted for temperature deviation
- Pre/In-Event Metering: Compare consumption before and during the event
Settlement Example:
The aggregator then pays customers per contract (typically 50–80% of gross revenue), retaining the balance as income.
Flexibility is monetized through multiple market mechanisms—each with distinct time horizons, product forms, and pricing structures. Providers engage in “revenue stacking” across markets to maximize asset returns.
Additionally, Energy Communities—localized citizen and SME cooperatives enabled by EU policy—are emerging as major forces in flexibility aggregation. Across the EU, ~9,000 communities represent ~1.5 million participants.
- By pooling behind-the-meter assets (e.g., PV, batteries, controllable loads), these communities overcome the scale and coordination barriers that typically prevent individual households from accessing multiple flexibility revenue streams.
- This aligns directly with our finding: 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 needed for reliable cross-market participation—transforming fragmented DERs into coordinated portfolios, democratizing flexibility revenue while supporting grid decarbonization and resilience.
Why Flexibility Matters
Flexibility services offer faster, cheaper alternatives to building new generation and transmission infrastructure. A VPP “builds” as fast as customers enroll—no interconnection queue required. Brattle Group estimates VPP peaking capacity is 40–60% cheaper than gas peakers or utility-scale batteries. ENTSO-E estimates flexibility saves €5B/year in generation costs across the EU alone.
For grid operators: Real-time supply-demand balancing; reduced reliance on expensive peakers and transmission upgrades; improved renewable integration; enhanced grid resilience during extreme weather.
For asset owners: New revenue streams from existing assets (batteries, EVs, HVAC, industrial loads); 30–50% higher returns via multi-service stacking; minimal operational disruption.
For consumers: Lower electricity bills via DR incentives; avoided costs from deferred infrastructure investment; improved reliability and fewer outages.
For energy transition: Higher renewable penetration without curtailment; decarbonized grid services (replacing gas peakers); accelerated deployment vs. infrastructure-constrained alternatives.
Structural Tailwinds
- Regulatory Momentum: FERC Orders 2222/2023 (U.S.), EU Demand Response Network Regulation (2027), UK BSC P483 enabling 345,000 households. Over 45 countries globally are launching flexibility markets.
- Grid Investment Wave: U.S. utilities forecast $1.1T in grid investment by 2029. EU needs €730B in distribution + €477B in transmission upgrades by 2040. Flexibility is the more economical alternative.
- Data Center Demand: Global data center electricity consumption to double to 1,000–1,200 TWh by 2030. PJM capacity prices up 10x (2024→2027). Simultaneously creates both flexibility demand (grid stress) and supply.
- DER Proliferation: 4M+ U.S. residential PV systems; 240K+ home batteries; 1M+ EVs sold in 2023. Critical mass has been reached—enabling aggregator and DER economics.
Key Risks to Watch
- Oversupply Post-2030: Massive battery storage investments may compress flexibility market margins. Some markets see a resurgence of pumped hydro.
- Cybersecurity: Millions of distributed assets expand the attack surface. EU AI Act classifies grid operations as “high-risk.” NFPA 855 increases urban battery storage costs by 15–25%.
V. Aggregator Business Models
Revenue Streams
- Capacity Payments ($/MW·year or $/MW·day): Largest and most predictable revenue stream. Customers are paid for availability—even if never dispatched. Example: PJM capacity price hit $329/MW·day in the 2026–27 auction.
- Energy Payments ($/MWh): Payment for actual load reduction during events. More volatile—depends on dispatch frequency and market prices.
- Ancillary Services ($/MW + $/MWh): Frequency regulation, spinning reserves, etc. Higher-value but requires faster response (seconds to minutes). Voltus pioneered access to these higher-margin products.
Cost Structure
Unit Economics Example (C&I Customer)
Revenue Stacking: How Aggregators Maximize Value
The most mature aggregators stack multiple revenue streams from the same asset:
Example: 10 MW Industrial Load in PJM
This is precisely why Enel’s DER.OS and Tesla’s Autobidder emphasize “co-optimization”—their AI decides, every moment, which market to participate in to maximize total return.
VI. Deep Dive: 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 world’s largest utilities (annual revenue > €86B). Its lineage traces to EnerNOC, a demand response pioneer founded in 2001 and acquired by Enel in 2017. Today, Enel X operates the world’s largest commercial & industrial virtual power plant, managing over 9 GW of demand response capacity across 18 countries and running 110+ active projects.
#Scale & Coverage
- Global Capacity: 9+ GW managed (Q1 2025), targeting 13 GW
- North America: ~5 GW, covering 10,000+ sites across 31 U.S. states and 2 Canadian provinces
- Projects: 80+ DR projects, 30+ utility partnerships (including 11 exclusive bilateral agreements)
- Customer Payouts: Distributed nearly $2B to DR participants since 2011
- Tech Investment: >$200M 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 exemplifies the convergence of data center demand growth and flexibility supply: hyperscale cloud providers—traditionally drivers of grid stress—can simultaneously become major demand-side flexibility providers via their UPS batteries and load-shifting capabilities.
#Technology Platform: DER.OS
Enel X’s DER.OS platform employs machine learning–driven dispatch optimization, increasing profitability by 12% versus rule-based strategies, according to internal audits. The platform streams data from 16,000+ enterprise sites and operates a 24/7/365 network operations center for real-time dispatch management and monitoring.
#Core Customers: Commercial & Industrial (C&I) Facilities
These are large electricity consumers with interruptible loads—processes that can be temporarily curtailed without major disruption:
Key Insight
These customers already own “assets”—their electricity loads. Enel X simply helps them monetize flexibility they didn’t know they had. Enel X explicitly positions itself on the demand side with a light-asset model—building or owning no generation assets. Reducing demand has the same grid effect as adding supply.
#Deep Implications of the Google Partnership
The September 2024 Google deal is noteworthy because it flips the traditional model:
- 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 data centers possess large UPS battery banks (typically for backup), flexible cooling loads, and some workload scheduling flexibility. Google no longer consumes grid flexibility—it provides it. Enel X is the orchestration layer. This is the real-world embodiment of the “data center as grid asset” thesis.
#Revenue Model Breakdown
#Competitive Positioning
- 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 vs. pure startups, higher corporate overhead
- Strategy: Focus on C&I segment, 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 as a tech-first alternative to traditional demand response providers. Its thesis: superior software and broader market coverage can overcome scale disadvantages. As of September 2025, Voltus ranked #1 in managed GW for the third consecutive year in Wood Mackenzie’s North American VPP report.
#Scale & Funding
- Capacity: 7.5+ GW managed (September 2025), up sharply from 2 GW in 2021
- Market Coverage: Active in all 9 U.S. wholesale electricity markets and Canada—the geographically broadest coverage among pure-play startup aggregators
- Funding: $121M raised to date (investors include Equinor Ventures, Activate Capital, Prelude Ventures)
- SPAC Attempt: Announced a $1.3B SPAC merger (valuation $1.3B) in December 2021; transaction did not close
#Differentiation Strategy
Voltus differentiates across three dimensions: (1) First-to-market innovation—pioneering access to operating reserve programs across multiple grid operators; (2) Broadest market coverage—active in programs competitors avoid due to complexity; (3) DER partnership model—not competing with equipment OEMs, but partnering with Resideo and Carrier to aggregate their installed base into VPPs.
#Data Center Focus
In 2025, Voltus launched its “Bring Your Own Capacity” (BYOC) product, designed specifically for data centers and hyperscale cloud providers. BYOC allows data center developers to deploy grid flexibility powered by VPPs concurrently with construction—offsetting capacity requirements by procuring flexibility from Voltus’s distributed network, thereby shortening time-to-energization. Partners include Cloverleaf Infrastructure.
#Core Customers: C&I Facilities (similar to Enel X)
#OEM Partnership Model
#Why the OEM Model Matters
Customer acquisition cost (CAC) is aggregators’ largest expense. Through OEM partnerships:
- OEMs handle 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 Source Differences: Voltus vs Enel X
#Enel X: Capacity-Market Dominant
- Predictable (annual auctions)
- Lower $/kW but higher volume
- Requires large MW commitments
#Voltus: Intentionally Targets Ancillary Service Programs Avoided by Competitors
#Why Ancillary Services?
Higher $/kW (2–3x capacity markets); fewer competitors (complexity acts as barrier); requires sophisticated software (Voltus’s strength); but demands faster-response assets.
Competitive Positioning
- Strengths: Technical precision, broadest market coverage, regulatory influence (former FERC Chair Jon Wellinghoff as Chief Regulatory Officer), OEM partnership strategy, data center focus
- Weaknesses: Smaller scale than Enel X, no utility-scale asset base, VC-funded 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. Markets
With robust supportive regulation and highly interconnected infrastructure, the EU has pulled ahead of the U.S. in scaling system-wide flexibility. Eurelectric notes that liberalized EU markets effectively incentivize both producers and consumers to participate, continuously expanding flexibility supply; meanwhile, widespread smart meter deployment has enabled time-of-use pricing, laying the foundation for demand-side shifting.
- Market Design: Liberalized market mechanisms drive proactive participation on both supply and demand sides; smart meters combined with TOU pricing enable load shifting
- Interconnected Grid: The EU’s stable cross-border interconnected grid significantly reduces outage frequency and duration, providing industrial users with stable, reliable power supply
The U.S. holds vast untapped customer-side flexibility potential. Studies show large-scale load reduction (e.g., 100 GW) is achievable with minimal impact on users.
- Grid Edge Focus: Rapid proliferation of distributed energy resources (DERs) makes flexibility management at the “grid edge” increasingly critical for U.S. utilities
“The inherent fragility of the grid demands careful scrutiny of every connected asset to ensure reliable supply matches predicted demand. The rapid growth of intermittent sources (unstable supply) coincides with the electrification wave (peaky demand), posing severe challenges to the power system.” — a16z
VIII. Conclusion
To date, flexibility has been dominated by “macro-flexibilities”—large industrial-scale assets (>200 kW) connected at the transmission or high-voltage distribution level. These assets are attractive due to their ease of identification, contracting, and dispatch. But this model is hitting a structural bottleneck. Macro-flexibility is no longer sufficient—leading to power shortages and cascading issues like interconnection delays. This increases system vulnerability and is becoming a key bottleneck for AI-driven load growth.
Therefore, the next frontier is inevitable: micro-flexibilities. These are small, behind-the-meter assets (1–10 kW) connected to medium- and low-voltage grids—including EV chargers, heat pumps, HVAC systems, batteries, and household appliances. Aggregated, these assets represent capacity orders of magnitude greater than macro-sources—but are far harder to access.
Current methods for accessing this flexibility leave substantial unclaimed value—creating opportunity for flexibility owners to fill the gap and participate in the ecosystem. An aggregator that directly reaches critical-mass owners, independent of supplier or device brand, can generate powerful pull-through effects. Once users are horizontally aggregated, energy companies and OEMs alike will be economically incentivized to actively participate—not attempt to control customer relationships from day one.
At the heart of all this, I believe DePIN holds the greatest opportunity to disrupt this sector and create lasting value through crypto-native infrastructure and incentive mechanisms. By increasing capacity and opening new pathways to access flexibility, this segment will revolutionize today’s electricity markets—enabling AI to reshape the world, unconstrained.
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