Interconnection remains the largest obstacle facing both utility-scale and community solar projects.

At the end of 2025, roughly 8,200 projects—representing more than 2,060 GW of generation and storage—were waiting in U.S. interconnection queues. Projects completed in 2025 spent a median of more than five years moving from interconnection request to commercial operation. Historically, only about 13% of requested capacity has ultimately reached operation.

But the problem is not just the wait. It is the uncertainty surrounding the final grid-upgrade cost.

Berkeley Lab found that completed projects from 2018 through 2024 averaged approximately $194 per kW in interconnection costs. Active and withdrawn projects received significantly higher estimates, largely because of required network upgrades.

Utility-scale solar

Transmission studies may trigger the need for new substations, reconductoring, reactive-power equipment, or major regional transmission upgrades. Those requirements can add tens of millions of dollars to a project.

Community solar

A 1–5 MW project may appear relatively small, but it can still overload a feeder, transformer, or substation. One unexpected upgrade can be enough to make the entire project financially unworkable.

The core challenge: developers often invest heavily in land control, engineering, environmental studies, and permitting before they know the final interconnection cost—or when the project will actually be allowed to connect.

Until interconnection becomes faster, more transparent, and more predictable, viable solar projects will continue to stall before construction ever begins.

For utility-scale solar, permitting and local opposition are nearly as significant as interconnection when it comes to delaying or killing a project.

A Berkeley Lab survey of 123 renewable-development professionals found that approximately one-third of recent solar and wind siting applications were canceled, while about half experienced delays of six months or more. Local ordinances and zoning, interconnection challenges, and community opposition were among the leading causes.

For canceled solar projects, average sunk costs reportedly exceeded $2 million per project.

The challenge is not always that the written rules are impossible to meet. In many cases, opponents use public hearings, permitting proceedings, appeals, and litigation to delay, reshape, or stop a project entirely.

Common concerns

• Loss of farmland
• Appearance and property-value impacts
• Drainage and stormwater runoff
• Wildlife and habitat disruption
• Glare, fencing, setbacks, and screening
• Fire risk when battery storage is included
• Decommissioning responsibility
• The perception that the power and profits leave the community

For utility-scale solar, the amount of land involved makes the project highly visible and often politically controversial. Community solar typically requires less acreage, but it still faces agricultural zoning restrictions, conditional-use permits, setback requirements, landscaping standards, and decommissioning bonds.

The biggest strategic mistake developers can make is treating community engagement as something that happens after site control. By the time opposition appears, the developer may already be locked into a parcel, layout, and interconnection plan with little flexibility left to make meaningful changes.

Permitting is not just a regulatory process. It is a stakeholder-management process.

A solar project can secure land, complete permitting, and receive interconnection approval—and still never reach construction because the capital stack no longer works.

Solar projects are developed over multiple years, and the economics can change significantly between the original financial model and the final investment decision.

Key variables include

• Interest rates and the cost of capital
• Module, transformer, switchgear, steel, labor, and construction costs
• Tax-credit eligibility and timing
• Import restrictions and tariffs
• Power purchase agreement pricing
• Utility bill-credit rates
• Community-benefit and prevailing-wage requirements
• Interconnection deposits and grid-upgrade costs

A project that appeared financially viable when development began may no longer produce an acceptable return by the time it is ready to build.

Utility-scale solar

Solar projects tend to generate heavily during the same daytime hours. As more solar enters a market, that concentrated generation can suppress wholesale electricity prices during peak solar-production periods. Projects may cost more to build while the power they generate becomes less valuable during the hours when they produce the most.

Community solar

Community solar faces an additional layer of risk because its economics are highly dependent on state policy and utility-program design. Program capacity limits, bill-credit calculations, subscriber eligibility rules, low-income participation requirements, utility billing processes, and incentives can materially alter project economics.

The core issue is timing: developers make land, engineering, permitting, and interconnection investments today based on assumptions about financing, incentives, construction costs, and energy value years into the future.

A solar project does not become financeable simply because it can generate electricity. Lenders need confidence that the project will produce predictable revenue over the life of the financing.

Utility-scale solar

Utility-scale projects typically depend on a creditworthy utility, corporation, municipality, cooperative, or other buyer willing to sign a long-term power purchase agreement. The PPA is often the foundation of the project’s financing, but several issues can weaken that foundation:

• The offtaker will not accept current pricing
• The agreement does not adequately address curtailment
• Interconnection delays push the project beyond contractual milestones
• Equipment and construction costs increase after the PPA price is locked
• The buyer requires guarantees or damages the developer cannot accept
• Merchant-market exposure creates too much risk for lenders

Community solar

Community solar replaces one large buyer with hundreds—or sometimes thousands—of smaller subscribers. That creates an entirely different operating model involving subscriber acquisition, eligibility qualification, credit requirements, customer education, utility billing-data integration, move-outs and cancellations, subscriber replacement, accurate allocation of bill credits, and customer service when savings fluctuate.

DOE has identified uncertainty around maintaining subscriber enrollment as a community-solar financing barrier. Confusing billing makes the problem even harder.

In plain terms: community solar is partly a power-generation business and partly a high-volume subscription, billing, and customer-retention business.

Reliable generation matters. Reliable revenue is what makes the project financeable.

Reaching construction does not mean the risk is over. Developers still have to deliver the project at the cost, schedule, and output promised years earlier—and then keep it operating for decades.

Common execution risks include

• Transformer and switchgear lead times
• Module or inverter substitutions
• Labor availability and subcontractor performance
• Poor soil conditions and civil-work challenges
• Underground wiring damage or installation errors
• Tracker alignment and commissioning failures
• Utility witness-test delays
• Weather, drainage, and site-access problems
• SCADA, metering, communications, and data failures
• Module degradation, inverter outages, vegetation, and O&M response
• Battery-control and dispatch limitations on solar-plus-storage projects

Storage can improve project value, but it also adds equipment, controls, safety reviews, commissioning requirements, dispatch and forecasting requirements, and operating complexity.

Completing construction is not the finish line. The project must operate, communicate, dispatch, and produce as required for the next 20 to 35 years.

The fundamental industry challenge is that developers must spend substantial money before the largest risks are resolved. Land, engineering, permitting, deposits, customer acquisition, and development costs continue to accumulate while interconnection cost, approval timing, construction pricing, and final revenue remain uncertain.