In Texas, we routinely connect a residential solar-plus-storage system in under two weeks. In North Carolina, an identical job can take 70 days. The two installations used the same equipment, the same installation methods, and met the same safety standards. One just ran into a lot more bureaucracy than the other.
That gap is why distributed solar isn’t scaling as fast as the grid needs it to. Freedom Power has deployed thousands of residential solar and storage systems across five states, navigating utility territories that range from frictionless to Byzantine. After all those installations, I can tell you with confidence that the technology is not the problem.
The grid needs distributed solar
Grid operators face historic load growth challenges across the country. In Texas alone, consumer electric rates are projected to rise 29% over the next five years. Nationally, residential electricity costs have increased by 30% since 2021. The centralized grid infrastructure built in the twentieth century doesn’t meet today’s demand, and the timelines for bringing new systems online don’t match the urgency. For some perspective, a new gas plant takes five to ten years to permit and build. Distributed solar-plus-storage can be commissioned in under two years, with no utility capital outlay.
Texas led the country in new solar capacity installed in both 2023 and 2024, adding nearly 10 gigawatts last year alone. In the summer of 2025, batteries on the ERCOT grid were supplying an average of 4 gigawatts during the 8 p.m. hour, right when solar output falls and demand remains high. Last summer in California, tens of thousands of home battery systems, many paired with rooftop solar, discharged more than 500 megawatts back to the grid during evening heat waves. In Puerto Rico, residential batteries prevented blackouts during four separate grid emergencies. The technology works. The barriers are cost, process, and policy, which are entirely within our control to fix.
Hardware choices and process efficiency drive down costs
It’s easy to blame tariffs or federal policy for high installation costs. Some of the most impactful levers are in our own hands.
Take roof utilization as an example. In jurisdictions that allow spanning over drain-waste vents, installers see 10 to 20% more capacity on the same roof and hardware savings of $0.04 to $0.07 per watt. Yet code variations across jurisdictions create inconsistent access.
Inverter selection also directly impacts project margins. A Tesla Energy report found that string inverters cost $0.10 to $0.20 per watt less than microinverters and deliver better economics for 93% of installations. Microinverters make sense in high-shade scenarios, but those account for only about 7% of jobs. Yet the 45X Advanced Manufacturing Production tax credit structure has historically favored microinverters, adding an avoidable $960 to $1,920 per typical residential system. Policy incentives should be technology-neutral.
Then there’s customer acquisition, which remains the industry’s most expensive and least examined cost center. Industry-wide customer acquisition runs roughly $0.87 per watt, or about $8,400 per average job. That figure reflects a sales-heavy model built around overcoming skepticism rather than systematically educating customers. When utilities provide itemized billing that separates generation, transmission, and distribution costs, homeowners can actually understand what they’re paying for. With rates rising across ERCOT, the math sells itself. Conversion rates improve, acquisition costs fall, and utilities gain a partnership opportunity that almost no one is maximizing.
The utilities that have deployed VPP models have real numbers to show for it. Green Mountain Power’s virtual power plant delivers approximately $3 million in annual savings for all customers through peak shaving and avoided transmission charges, with Vermont’s PUC calculating a positive lifetime net present value of $2,749 per battery system for ratepayers. Massachusetts’ ConnectedSolutions program returned a 2.14-to-1 benefit-cost ratio for residential ratepayers. The model works. The question is how quickly utilities elsewhere choose to replicate it.
Survey, design, and project management remain manual even when automation is available, but adoption is slow. Long timelines compound the problem. Every week of delay reduces solar conversion rates as circumstances change and financing expires. Those sunk costs get priced into everyone’s systems, raising prices and shrinking the addressable market.
Interconnection standardization is the unlock
The 13-day versus 70-day gap isn’t an anomaly. Delays remain the norm across a fragmented interconnection landscape.
In Texas, Oncor and CenterPoint run straightforward online portals, charge no fees, and maintain sub-1% rejection rates. Their average interconnection timeline runs under two weeks. That standard should apply to every utility. Regulators must push for even progress, as localized bottlenecks persist. Dallas still uses two separate online portals that aren’t connected to each other, with multiple city staffers reviewing applications in sequence rather than simultaneously. One major installer told Environment Texas they stopped operating in Dallas entirely to avoid the delays.
Delays hold back clean capacity when the grid needs it most. There are 6,050 megawatts of distributed energy resources already connected to the ERCOT grid, and rooftop solar alone accounts for more than 3,100 megawatts of that total. ERCOT projects that number to reach 4,000 megawatts and beyond.
Texas passed a third-party solar permitting law that gets municipal permits issued within three business days of plan approval. That policy represents real progress. But interconnection with transmission and distribution utilities—Oncor, CenterPoint, AEP, and others—falls outside that law, leaving the core bottlenecks unresolved.
SolarAPP+, the DOE-funded automated permitting platform, now processes 17% of all California solar permits with near-instant approvals. Other states should adopt it or an equivalent platform immediately.
Nationally, there are 3,000 utilities across the U.S. that maintain 3,000 different interconnection processes, with no alignment on the core data set that every utility legitimately needs. Today, utilities conduct an engineering study on every single system before granting connection, despite only 2% of residential installations requiring any infrastructure upgrades at all. A “connect and manage” framework for systems under 50 kilowatts would change that: allow immediate operation after commissioning, with grid export authorized following documentation review. In practice, the 98% of installations that create no infrastructure issues would no longer wait months for approvals.
A partnership model that scales
The right relationship between installers and utilities requires clear division of labor. Manufacturers and installers handle customer acquisition, education, financing, installation, and maintenance. Private companies carry the business risk. Utilities provide grid integration expertise, emergency dispatch coordination, and rate structures that fairly value grid services.
In markets where that relationship functions well, it’s genuinely a win for everyone. The economics support it, given that only 2% of residential installations require infrastructure upgrades. Strategically placed distributed systems reduce peak loads and defer expensive substation work. For a grid like ERCOT—where 77% of new generation interconnection requests in 2025 were solar and energy storage—distributed resources aren’t a fringe strategy. They represent the core strategy.
Time-varying export compensation—paying more for power delivered during peak demand—ensures fair cost recovery while recognizing the real grid value solar provides. Programs modeled after Green Mountain Power and Massachusetts ensure the utility, the solar customer, and all ratepayers each capture a net benefit.
Three actions to unlock scale
Projects succeed or stall based on utility processes, hardware choices, and installation discipline. To get from fragmented projects to a true distributed power plant model, stakeholders must move on three fronts:
The market Is already moving
The grid of the future runs on both centralized baseload generation and distributed resources for peaks. In some states, including Texas, it’s already the reality. Solar and wind together hit 37% of ERCOT’s electricity supply in 2025. Battery storage is now a meaningful part of evening reliability, and ERCOT forecasts for the Texas grid alone are expected to reach over 100,000 megawatts of total capacity by 2030.
Nothing accelerates distributed solar faster than the price of power. Not incentives, rebates, or financing, which remain short-term drivers. When power gets expensive, solar becomes the obvious answer for customers, installers, and the utilities smart enough to build relationships with distributed energy companies now rather than later.
By Bret Biggart: Biggart is CEO of Freedom Power, one of the largest residential solar installers in the
United States. He is also an endurance athlete and a native Texan.
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