The solar investment tax credit (ITC) is going away. The deadline to safe-harbor a solar project and secure a four-year window to complete the project and receive the ITC was July 4, 2026. For projects that start construction after July 4, they must be placed into service by December 31, 2027 to qualify, which is still achievable.
That’s the big bold headline about incentives. But incentives should not drive your onsite energy strategy, as the incentive environment is only one input. It’s not the driver of the entire deployment strategy.
Companies that build their onsite energy programs around chasing individual incentives tend to build the wrong things, in the wrong order, for the wrong reasons.
We dug into this topic in our most recent webinar. Dan Roberts and Calvin Fine, two of VECKTA’s co-founders and the heads of sales and operations, respectively, covered the structural shifts happening in electricity markets, what the ITC expiration actually means for project economics, and what a resilient procurement strategy looks like (and one that returns up to 45% in lower project costs).
Electricity costs are rising faster than most companies realize
In June, the U.S. Energy Information Administration published its April 2026 figures showing commercial electric costs are up 4.8% year over year. That’s roughly in line with recent years, but it’s not uniform; some markets are up more than 15% while others are flat.
What’s driving it: data center buildout is putting enormous strain on the grid, and utilities are responding with capital investment. Between 2026 and 2030, utilities are expected to invest $1.4 trillion into the grid in capacity expansion and hardening of transmission and distribution infrastructure. The 2025 capex figure was $204 billion and this year it’s approaching $240 billion, a 17% increase. Every dollar of that gets passed on to ratepayers.
The EIA’s near-term projections vary sharply by region. North Dakota is expected to see rates rise 1.2% over the next year. Maine and Washington D.C. are looking at 10.4%. Over a five-year horizon, the range runs from roughly 2% to 7.5% annually depending on location.
The business case for onsite energy is being built on structural rate increases that aren’t going away.
What the ITC expiration changes
Without the solar ITC, project economics shift, but not uniformly, and not fatally.
We modeled three real supermarket projects across California, North Carolina, and Massachusetts to show the actual impact.
In California, solar sizing came down modestly when the ITC goes to zero. NPV and IRR drop about 23%. That’s significant, but the project remains healthy because the state’s high demand charges, net metering structure, and rate environment keep it in the money.
North Carolina tells a different story. The same analysis shows IRR falling from above 17% to below 12%, and payback extending from 5.3 years to nearly 9. That’s a project that would likely lose internal approval under most capital allocation frameworks.
The Massachusetts project held with a slightly higher payback period and lower NPV, but was still well within the investment threshold.
The lesson isn’t that solar is dead in some markets and alive in others. It’s that you can’t evaluate projects in isolation. A portfolio-wide view is the only way to know where to focus, what the right system configuration is, and where the business case holds without federal incentives.
The cost structure is also changing in your favor
Most people aren’t accounting for the changes that will happen when the ITC rolls back, and efficiencies within origination, procurement, permitting and other admin areas.
The federal ITC comes with prevailing wage and apprenticeship requirements. Compliance adds real cost to projects because it requires paying higher wages and carrying documentation burden. Without these restrictions, installation labor costs are expected to fall 2% to 5%.
Developer margins are also under pressure. Companies that have been capturing a portion of the tax credit value in their margin will face a market that’s increasingly unwilling to pay it. The solar and battery construction market will likely compress back toward general construction margins. That won’t fully offset the ITC loss, but it meaningfully softens the blow.
What a resilient strategy actually looks like
The biggest mistake we see companies make is letting inbound proposals drive their program. A developer shows up, offers to save you $50,000 a year on one facility, and suddenly that becomes the project. Maybe it’s a good project. But is it the highest-value site in your portfolio? Is that the right system configuration? Did you compete the bid?
The answer to all three is usually no.
A resilient onsite energy program starts with a portfolio-wide view. Not one site. All of them. You figure out which locations have the best economics, which have the right load profiles and tariff structures, which markets have the most favorable rate trajectories or state incentive programs stepping in to replace federal ones. Then you rank by NPV and internal rate of return. Then you go to market.
The procurement side matters as much as the analysis. The bid spread between the lowest and highest qualified proposal on a real project we showed in the webinar was 40%. It had comparable solar panels and racking. On one project, the difference between the low bid and the high bid was the difference between a healthy IRR and a business case that doesn’t get approved. If you only talked to one developer — whoever showed up first — you have no idea where you landed on that spectrum.
Our data shows companies using a competitive marketplace process save up to 45% more in PPA costs and 25% more in energy savings compared to self-managed procurement. The upside from getting the process right is bigger than most buyers realize.
State programs are filling the void
As federal incentives pull back, state programs are stepping in. Illinois, New Jersey, and Maryland all have meaningful legislation active or under review. Solar renewable energy certificates in Illinois and New Jersey are trading at $40 to $50 per megawatt hour, compared to a standard REC at $3 to $5.
The catch is that you now need to track what’s happening on a state-by-state basis to take full advantage. For a company operating nationally across multiple utility territories, that’s genuinely hard to do without infrastructure built for it.
The opportunity for buyers is real. But the window for any specific program can close quickly, and the preparation work has to happen before the deadline.
Other value streams your analysis should include
Most initial business cases don’t account for every value stream available. The ones that often get overlooked:
Demand charge reduction. In markets with high demand charges (e.g. California businesses can pay $50 to $60 per kilowatt) a battery system that shaves peak consumption can be the primary driver of ROI, not energy offset. The EV charging example from the webinar is worth understanding: add high-capacity chargers to a facility that peaks at 100 kW, and a single busy moment could push peak demand to 1 MW. Your utility bills you for that peak for the rest of the billing period and sometimes the rest of the year under certain tariff structures.
Net metering. Varies enormously by market. California’s NEM 3.0 structure is minimal during most hours but can be lucrative during summer evenings.
Ancillary grid services and demand response. PJM’s capacity market and flexible load programs are increasingly active, particularly given the data center load growth in that territory.
Renewable energy certificates. If your sustainability team isn’t required to retire the RECs from your own system, there may be arbitrage value available, especially in markets with active SREC programs.
The cost of waiting
A Northeast manufacturer passed on an onsite energy project in 2020 even though the payback was under two years and projected annual savings were $1.2 million. Regional industrial rates have since risen 26%, which means that they could be saving $1.8 million per year today.
The policy environment is dynamic. The business case for onsite energy is not going away when the ITC does. What changes is the margin for error and the urgency of getting the process right.
A small deed done is better than a great deed planned. Get a couple of projects under your belt. Build the infrastructure to run more. The companies we see benefit most are the ones that started, even imperfectly, rather than waiting for the perfect policy moment that may never come.
