The road to the untapped grid

Electricity rates across the United States are rising faster than most households realize, and the path ahead looks even steeper. After climbing 17% over the past five years, projections from DNV’s Energy Transition Outlook North America 2025 forecasts residential electricity prices will increase another 22% through 2035 before inflation. 

Utilities are under pressure as they can no longer rely on the same old incremental adjustments to meet rising costs and customer expectations.   

Yet alongside this challenge lies a tangible opportunity. The Brattle Group's Untapped Grid report puts a number on one credible path: a 3.4% rate reduction and $110 to $170 billion in consumer savings over a decade. 

The mechanism is straightforward: when flexible load is shifted away from peak demand periods, utilities can defer the peaker plants and transmission upgrades that those peaks would otherwise require. Capital that never gets built never gets rate-based.   

For the Untapped Grid thesis to become a market reality, three things must be true. First, utility incentives have to shift so that flexibility competes on equal footing with capital investment. Second, customers have to receive price signals that make their assets visible to the grid. Finally, the aggregator market has to mature into something utility planners can actually rely on. While none of them exists at scale today, each of these conditions is achievable.  

The constraint is institutional, not technical  

The Untapped Grid asks demand side management (DSM) organizations to become something new: operators of dispatchable, flexible capacity integrated into real-time planning and operations. This is not a training issue. It is a fundamental redesign of organizational purpose inside siloed, heavily regulated, and risk-averse companies.

DSM groups were built for compliance: to manage rebate programs, meet efficiency targets, and report to commissions. They were not built to manage aggregator relationships, respond to dispatch signals, or embed flexibility into capacity planning.  

In our program design work, the will to change is often more common than the structural support needed to act on it. Three barriers recur consistently. 

First, capex bias: utilities earn regulated returns on physical infrastructure, but software platforms, VPP contracts, and aggregator relationships typically do not rate-base. That creates a structural disincentive to invest in flexibility, even when it provides clear system value. 

Second, visibility gaps: the core AMI issue is often latency more than availability, though saturation gaps are real. Many utilities still lack timely, granular telemetry to reliably see and dispatch premise-level assets. You cannot plan around what you cannot see. 

Third, valuation uncertainty: without clear, commission-accepted methods to quantify capacity, energy, and avoided infrastructure value, utilities struggle to make the internal business case, even when organizational will exists.  

These are solvable problems, but any credible implementation roadmap has to address them directly. Until utilities build that internal capability, outsourcing flexibility to aggregators will remain the only scalable path in many jurisdictions. But even that path depends on market structures and regulatory frameworks that most states have not yet fully built.  

Brattle briefly points to shared savings as one way to begin changing utility incentives. That matters. If utilities can retain a meaningful share of the net value created by demand-side and non-wires solutions, the incentive structure starts to shift. But that only works if commissions attach real performance value to flexibility and create mechanisms durable enough to support investment.

Rate design is an enabling layer, not the answer  

The 3.4% rate reduction needs flexible price signals for customers. Most residential and small business customers do not get them. Opt-in time-of-use rates have had little effect. They will not change much. States like California and Colorado defaulted customers onto time of use (TOU) rates and saw better results. The default TOU is not radical. It is a logical and necessary start.  

Rate design alone cannot solve the problem. Customer flexibility does not result solely from a price signal. It must be structured, signaled, and contracted. Premise-level flexibility requires a robust operating system that does not yet exist at scale.  

For a concrete example: I have solar-plus-storage at my home in North Carolina, on a volumetric rate with no aggregator path to monetize the battery’s capacity.  

An aggregator could dispatch my battery for two hours on about 100 days per year here. The system would gain real value, my bill would drop, and the grid would be less congested when it matters most. This cannot happen today, not because technology fails, but because the rate design hides my asset from the grid. There is also no market structure to connect my system.  

Multiply that by millions of customers with similar assets over the next five years. The unmonetized flexibility behind residential meters in this country is substantial. Each month this opportunity remains uncaptured, the 3.4% stays on the table rather than appearing on customers' bills.  

Aggregators are the operating bridge  

Aggregators are the only scalable mechanism for converting fragmented, premise-level distributed energy resources (DER) into something a utility planner can rely on. The system hierarchy explains why.  

The utility defines the system's needs and connects with aggregated resources via its distributed energy resources management system (DERMS). The aggregator manages portfolio-level dispatch and asset performance. It absorbs variability and delivers a firm, contractually committed resource to the utility. The premise-level DER: batteries, managed electric vehicle (EV) chargers, smart thermostats, and smart panels, respond as part of the aggregator's fleet, usually via Open Automated Demand Response (OpenADR) protocols.  

This architecture exists, and engineering challenges are solvable. What is missing is the regulatory and commercial framework. That framework must make the aggregator business model viable and give utility planners confidence that aggregator-delivered capacity is real and reliable.  

Aggregated DER portfolios using four-hour batteries and demand response cannot solve multi-day winter adequacy events. Flexibility can defer capacity investment and reduce everyday system stress. It cannot eliminate the need for firm resources during rare, severe events that set the standards for resource adequacy.  

Hyperscalers are already co-locating generation assets, negotiating custom interconnection arrangements, and demonstrating willingness to fund infrastructure that accelerates their timeline. The next logical step, pairing interconnection priority with demand flexibility commitments, is a deal structure that makes sense for both sides, does not require ratepayer funding to initiate, and is well within the commercial instincts of companies that have already shown they will pay for speed. Therefore, we should move quickly to formalize and standardize these structures through specific agreements and protocols.  

Why this moment is different  

The untapped grid is real, and the opportunity is as large as Brattle says it is. Now is the time to act as the convergence of political conditions, load growth pressure, and hyperscaler capital create space for change.  

Electricity affordability has become a salient political issue. From 2020 to 2025, average US retail electricity rates rose 5.6% a year, and the 2026 midterms may be the first where rate increases influence state elections. This creates a political window for reform.  

The data-center boom give utilities leverage, they can offer hyperscalers faster interconnection in exchange for flexible demand commitments. This could work because the companies building next-generation AI infrastructure want certainty and speed for the billion-dollar investments. Some hyperscalers are already working directly with utilities on demand flexibility programs, adjusting data center workloads during peak periods to ease grid strain.  

Utilities that move deliberately now will be positioned to deliver what customers and legislators are already demanding. 

DNV is ready to help forward thinking utilities identify priority use cases where flexibility is genuinely viable, surface the organizational blockers that stand between today's DSM structure and a reliable planning resource, and define the near-term implementation pathways that are realistic given your market and regulatory context.