By Jason Turner Co-Founder & CEO
Flat participation gets treated as a neutral outcome. It isn’t. Every quarter the needle doesn’t move, the costs compound — in undeployed dollars, regulatory exposure, and customer trust that doesn’t come back.
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There’s a particular kind of inertia that settles into organizations when a problem is chronic but not acute. The quarterly numbers come in flat. The conversation happens. Someone mentions the awareness campaign that’s planned for next quarter. Someone else notes that budget constraints limit what’s possible. The VP reminds the group about the latest IRA funding status. The meeting ends. Nothing changes.
This is how most utilities are managing their incentive participation problem right now. Not with denial — most program managers know generally what their participation rates are and know they’re at risk of underperforming. But with a quiet tolerance for flatness that treats low participation as a stable, if unfortunate, steady state.
It isn’t stable. It’s accumulating.
The cost of doing nothing on participation is not a fixed number. It compounds. It shows up in different ledgers — financial, regulatory, competitive, reputational — on different timelines. And because most of those costs are not labeled ‘participation failure’ when they land, the connection between the inaction and the consequence is easy to miss until it’s very hard to fix.
This is an attempt to make that connection visible.
The money leaving the table every quarter
Start with the number that should be hardest to ignore: the undeployed dollars.
Lawrence Berkeley National Laboratory data puts unclaimed local electric utility incentives at roughly $1 billion annually. That figure represents programs that were funded, approved by regulators, and made available to customers — and that customers didn’t claim. Not because the incentives weren’t valuable. Because the path to claiming them was too difficult to navigate.
For an individual utility, the math scales down but the proportions hold. A utility running $10 million in annual incentive programs at a 5 percent participation rate against a realistic 20 percent ceiling is leaving $1.5 million a year on the table — money that was budgeted, rate-based in customer bills, and approved for deployment toward electrification and efficiency outcomes that didn’t materialize.
That money doesn’t simply evaporate. Depending on program structure, it rolls forward into future program years, gets reallocated within the DSM portfolio, or returns to regulators. None of those outcomes are cost-free. Rolled-forward dollars create pressure to demonstrate deployment in future cycles. Reallocated dollars shift program priorities in ways that may not reflect actual customer demand. Returned dollars are a visible signal to regulators that the program underperformed.
In each case, the utility has paid the administrative and rate-case cost of running the program without capturing the customer adoption and electrification outcomes the program was designed to produce. The cost was incurred. The benefit wasn’t.
A utility leaving $1.5 million in participation on the table annually isn’t saving money. It’s paying the full cost of running programs and capturing a fraction of the value. That’s not fiscal prudence. That’s a bad trade.
And that’s before accounting for what participation failure costs on the other side of the ledger — the customer side. Every customer who attempted to enroll and failed, who heard about the program and couldn’t navigate it, who installed the equipment without claiming the rebate, represents a degraded relationship with the utility. That degradation has a value. It just doesn’t show up on the program’s budget line.
The regulatory exposure that’s building quietly
Utilities operate under integrated resource plans, demand-side management targets, and electrification commitments that were filed with public utility commissions and, in many cases, announced publicly. Those commitments have participation assumptions embedded in them. When participation falls short, the commitments do too.
For most utilities, the regulatory conversation about DSM performance happens on an annual cycle. Program results are filed. Commissions review them. Shortfalls get noted. In a single bad year, the conversation is usually manageable — there are explanations, there are mitigating factors, there’s next year.
What’s harder to manage is the pattern. A utility that files three consecutive years of DSM participation below target has moved from explaining a shortfall to defending a track record. The commission’s posture shifts from inquiry to scrutiny. The questions become harder: what has the utility done to address participation? What changed between last year and this year? Why should the commission approve next year’s program budget when the current year’s budget went substantially undeployed?
That conversation is happening right now at utilities across the country. Not in crisis mode — yet. But the trajectory is visible to anyone paying attention to rate case filings and DSM annual reports. The gap between what utilities commit to and what they deliver on participation is not shrinking. In most markets, it’s widening as electrification targets escalate faster than the infrastructure to achieve them.
One flat participation year is an explanation. Three flat participation years is a track record. Commissions notice the difference — and the questions they ask in year three are not the same questions they asked in year one.
The regulatory cost of chronic participation underperformance is not hypothetical. It shows up in program budget scrutiny during rate cases, in conditions attached to program approvals, and in the political capital utilities need to spend defending the gap between their electrification commitments and their electrification results. That capital is finite. Every cycle spent defending underperformance is a cycle not spent advancing the next program expansion or the next strategic initiative.
There is also a less obvious regulatory cost: the risk of policy intervention. When regulators lose confidence that utilities can self-manage program participation, they begin to mandate solutions — third-party program administrators, required customer experience standards, prescribed application timelines. Those mandates reduce utility control over program design and implementation, often at higher cost than the utility would have spent solving the problem proactively.
The JD Power score that nobody connects to participation
Customer satisfaction measurement in the utility sector has converged on JD Power as the dominant benchmark. Utilities track their scores. Executives discuss them in earnings calls. Regulatory proceedings reference them. There is a general awareness that scores matter.
What’s less commonly discussed is where the scores come from — and what’s actually driving movement in them.
JD Power’s residential customer satisfaction methodology weights several factors, including power quality, billing, and price. But digital experience and ease of interacting with the utility — which includes finding and using programs — have become increasingly significant contributors to overall satisfaction as customers’ baseline expectations for digital interactions have risen.
The utilities at the top of JD Power regional rankings are not uniformly the cheapest or the ones with the highest rebate amounts. They are disproportionately the ones whose programs are findable, whose application experiences are straightforward, and whose post-submission communication is clear. Customers who successfully navigate a utility incentive program come away with a materially more positive view of the utility than customers who attempted the same program and failed.
That should be obvious. But the connection between incentive program usability and customer satisfaction scores is rarely made explicit inside utilities — because program managers and customer experience teams often sit in different departments, with different budgets, different metrics, and limited coordination.
The utilities at the top of JD Power rankings aren’t there because they have the biggest rebates. They’re there because their programs are actually usable. Customer satisfaction and participation rate are measuring the same thing from different angles.
The cost of that disconnect compounds. A customer who tried to claim a rebate, couldn’t navigate the process, and gave up is not a neutral customer afterward. She’s a dissatisfied one. She’s more likely to score the utility poorly on satisfaction surveys. She’s more likely to complain to her neighbors. She’s less likely to engage with the next program the utility launches. And in markets where retail choice exists, she’s more likely to explore alternatives.
The participation failure that looked like a DSM metric shortfall is also a JD Power score driver. The utility measuring them separately is missing the relationship between them.
The compounding problem with contractor relationships
Contractors are the distribution network for utility incentive programs. They are in front of customers at the moment of decision — when a quote is on the table and a customer is deciding whether to move forward with an upgrade. A contractor who actively mentions and helps navigate utility incentives can meaningfully change that decision. A contractor who has given up on utility incentive programs — because the paperwork is too burdensome, the approval timelines are too slow, or the customer experience is too unpredictable — removes that influence from the equation entirely.
The utility industry significantly underestimates how many contractors are in the second category.
Rocky Mountain Institute estimates that contractors spend 30 to 40 percent of their project time navigating incentive paperwork when they engage with these programs. For contractors running lean operations, that burden is not sustainable. The rational response — and it’s a rational one — is to stop engaging. Stop mentioning the rebates. Focus on the installation. Let the customer figure out the incentive process on their own, if they want to.
When contractors make that decision, the utility loses its most effective distribution channel at zero cost to the contractor and at enormous cost to program participation.
When a contractor stops mentioning your rebate program, you don’t get a notification. You just get lower participation — and you keep paying the administrative cost of a program that’s no longer being distributed.
The erosion is gradual and therefore easy to miss. A utility doesn’t lose all its contractor relationships in a single quarter. It loses them one frustrated contractor at a time, over multiple program cycles, as the cumulative friction exceeds the cumulative benefit of engagement. By the time the pattern is visible in participation data, the relationships have already been degraded — and rebuilding them requires more than a program update. It requires demonstrating, credibly, that the experience has actually changed.
That’s a longer and more expensive recovery than the investment required to prevent the erosion in the first place.
The electrification timeline cost nobody is calculating
Pull back further and the cost of participation inaction becomes a strategic one.
Utilities have made public commitments to electrification outcomes — X percent of heating converted by a certain year, Y megawatts of load shifted, Z percent reduction in residential emissions. Those commitments were built on models that assumed certain participation rates in the programs designed to drive them. When participation rates chronically underperform those assumptions, the models break.
The adjustment is usually made quietly. Targets get revised in planning documents. Timelines get extended. The original commitment, which may have been used to justify a rate case approval or a regulatory filing, is no longer operational — but it’s also not explicitly retracted, because retracting public commitments has its own costs.
The result is a gap between what utilities have committed to and what they are actually on track to deliver — a gap that widens every quarter participation stays flat, and that will eventually require either a genuine participation breakthrough or a public reckoning with missed targets.
The IEA and domestic clean energy modeling increasingly show that the residential electrification transition depends on rapid acceleration of customer adoption through the mid-2020s. Programs that assumed 15 percent participation and are achieving 5 percent are not on a path to meet their modeled contribution to that transition. The timeline cost is not a rounding error. At scale, it is measured in years — years of carbon reduction that doesn’t happen, grid load flexibility that isn’t available, and infrastructure investment cycles that get planned around electrification assumptions that the participation data doesn’t support.
Every quarter participation stays flat, electrification timelines extend. That’s not abstract. It’s load forecasts that don’t materialize, carbon commitments that slip, and infrastructure investment planned around adoption curves that the program data isn’t supporting.
What ‘doing something’ actually costs
The case against inaction is only half the argument. The other half is what the alternative actually requires — because one reason utilities tolerate chronic participation underperformance is a perception that fixing it is expensive, disruptive, or both.
It doesn’t have to be.
The interventions that have moved participation rates at utilities that have genuinely improved them share a pattern: they focused on the navigation layer between customers and programs rather than on program size or marketing spend. They reduced the number of steps between eligible and enrolled. They improved cross-program visibility so customers could see all the incentives relevant to their project in one place. They streamlined the claim routing process so applications reached the right implementer the first time, without requiring contractors to be navigators.
Those interventions don’t require rebuilding existing program infrastructure. They don’t require renegotiating regulatory approvals. They don’t require replacing contractor relationships or launching new programs. They require building — or deploying — the layer between customers and programs that currently doesn’t exist: the navigation infrastructure that turns program awareness into program enrollment.
The cost of that infrastructure is measurable and bounded. The cost of not building it — in undeployed dollars, regulatory exposure, JD Power score drag, eroding contractor relationships, and missed electrification timelines — is open-ended and compounding.
That’s the trade utilities are making when they choose inaction. Not the trade between spending and not spending. The trade between a known, bounded investment and an accumulating liability that shows up in different ledgers on different schedules and is easy to miss until it isn’t.
The quarter to start is this one
The instinct to wait — for the next budget cycle, for the new administration’s guidance on IRA implementation, for the awareness campaign to run and see if it moves the numbers — is understandable. It’s also the instinct that has kept participation rates flat for three years while the costs accumulated.
The awareness campaign will not move the needle. Not because awareness doesn’t matter, but because awareness was never the binding constraint. The customers who tried and couldn’t navigate the program didn’t fail because they didn’t know about it. They failed because the path was too hard. More marketing puts more customers at the beginning of the same hard path.
The regulatory filing deadline for next year’s DSM performance doesn’t move because this quarter’s participation was difficult. The JD Power survey doesn’t wait for the new program to launch. The contractor who decided to stop mentioning rebates made that decision three projects ago and isn’t reconsidering it on his own.
The costs are running. The question is not whether to act but when the accumulation becomes impossible to rationalize continuing to absorb.
The utilities that will lead on electrification outcomes over the next decade are not the ones with the biggest rebate budgets. They are the ones that built the infrastructure to actually deliver their programs to the customers those programs were funded to serve.
That infrastructure exists. The choice to deploy it is the one sitting on the table right now.
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Sources
Lawrence Berkeley National Laboratory, Utility Energy Efficiency Program participation and incentive deployment data, 2023.
JD Power U.S. Electric Utility Residential Customer Satisfaction Study, 2023–2024.
Rocky Mountain Institute, electrification program friction and contractor time-cost analysis.
IRS Statistics of Income, Energy Credits under the Inflation Reduction Act, 2023 tax year.
International Energy Agency, Net Zero by 2050 residential electrification modeling.
U.S. Department of Energy, HEEHRA program guidance and state implementation data.
National Association of State Utility Consumer Advocates, DSM program performance filings, 2022–2024.