In this last of three blog articles examining Behind the Meter energy assets, I’ll look at why BtM only scales when the commercial value chain works for all participants: customers see a reason to participate, aggregators can cover acquisition and integration costs (and make a profit), and system benefits are captured through grid and market efficiencies.

Where do value and risk lie?

BtM flexibility changes the model because small fluctuations in demand can be controlled and aggregated.

Independent aggregators (and supplier-aggregators) typically monetise BtM through a mix of:

• Retail value: time-of-use optimisation, dynamic tariffs, and peak reduction that lowers customer bills
• Network value: payments from constraint management and local flexibility markets
• System and wholesale value: selling the aggregated capacity into ancillary services, balancing, and wholesale markets

All fine, unless you’re the supplier with the retail relationship: if a supplier has forecast a customer’s expected load and an aggregator later reduces consumption at peak times, someone is left holding the imbalance unless the arrangements explicitly allocate it. Market design focuses on clarifying roles, baselines, and settlement responsibilities, with suppliers being compensated for shortfalls.

Value flows

A simple way to describe the cashflows:

• Customer receives: bill savings, incentive payments, or a cheaper bundled tariff
• Aggregator receives: a share of those savings, plus market/network revenues where available
• System receives: reduced peak demand, avoided reinforcement or curtailment, improved operability

Risks

• Performance risk: devices don’t respond; customers opt out; comms failure
• Measurement risk: baselines and data disputes
• Conflict risk: a device can’t simultaneously solve a local network constraint and a national frequency event without clear prioritisation rules
• Regulatory risk: market access rules change; product definitions evolve

UK: formalising routes to market

GB has been moving from “supplier-mediated” demand response towards clearer access routes for independent aggregation.

• Demand Flexibility Service (DFS): Winter 2022/23 saw 1.6 million households and businesses participate, shifting/saving over 3.3 GWh; later seasons expanded participation (NESO DFS reporting).
• Wholesale access via VLPs: Elexon’s P415 establishes a route for “Virtual Lead Parties” to participate in the wholesale market for flexibility dispatch (Elexon P415 page and Ofgem approval notice). This was a huge step forward in market design for flexibility.
• Local flexibility: UK DSOs procure flexibility to manage distribution constraints (e.g., NG Electricity Distribution flexibility markets overview).

The commercial direction is towards a world where aggregated BtM can behave like a properly governed market participant — provided the settlement and responsibility model is robust.

Germany: scale first, then system integration

Germany illustrates what happens when rooftop PV and residential batteries scale quickly.

• Installed solar capacity was about 99.3 GW at end-2024 (Bundesnetzagentur).
• Aggregation is well established: Next Kraftwerke reported 10,000 MW aggregated capacity (and sector reporting places its network in the low-double-digit GW range).
• Residential batteries are being networked for system services: sonnen has described 25,000 batteries already connected in Germany (sonnen press release).

Germany’s commercial landscape is strongly shaped by support mechanisms and market design under the EEG, alongside a clear focus on secure metering/control architectures (for example, the Smart Meter Gateway approach). The practical point for BtM is that market access, compliance, and security requirements can be as important as physical architecture and kW to MW scale economics.

US: market unlocking via FERC 2222, but patchy execution

In the US “BtM” is not in one market but many. A critical federal lever is FERC Order 2222, intended to enable aggregated distributed energy resources to participate in ISO/RTO wholesale markets (FERC explainer; NREL primer provides a technical summary).

Commercially, US BtM often starts with demand charges and resilience economics for C&I sites, then expands into market participation where rules and interconnection processes allow.

Australia: BtM as the default operating condition

Australia is frequently used as the “stress test” case: high rooftop solar penetration, operational challenges on sunny days, and fast-moving DER standards. The Clean Energy Council reports over 4 million rooftop systems. The result is that distribution-level operability and export management become everyday concerns, not edge cases.

What happens next (and what to watch)

BtM is moving from “interesting pilots” to integrated infrastructure: better device standards, data security and protocols, tighter market participation routes, and increasing overlap between retail optimisation and system services. The next phase is about scaling device adoption and coupling that with governance, verification, and coordination – especially as EVs and electrified heat expand the flexible load base.

The commercial viability of aggregating and trading flexible Behind the Meter assets is, potentially, a multi-billion dollar sector. It’s complex but we’re engineering our way out of that complexity with IoT connected hardware, emerging standardisation, sensible market design and industry wide cooperation.

The opportunity is in managing the vast amounts of data and aggregating to manageable, dispatchable and tradable products.

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