Contributed by Deep Patel | Founder and CEO of Gigawatt Inc. 

U.S. utilities are approaching an inflection point that has been years in the making. For much of the past decade, distributed solar was treated as a sideshow, dismissed as too small, intermittent, or dependent on incentives to matter. Today, that posture has shifted. In many markets, utilities are no longer overlooking distributed generation; they are now actively pushing back against it with anti-solar lobbying. For instance, as we saw in California, NEM 3.0 was passed to disincentivize feeding solar into the grid. Meanwhile, in Arizona, the state moved away from NEM to NEB. And in the first half of 2025, 148 state bills were introduced that were either very or somewhat restrictive of solar siting.   

But the underlying trend is clear. Distributed solar and storage are not going away. In California, solar already produces 36.7% of the state’s electricity, while Texas, the fastest-growing state for solar, currently gets 10.75% and is expected to grow to 62% by 2030. Arizona is already at 16.76%, Florida is at 11%, and Nevada generates nearly one-third of its electricity from solar. As electricity demand rises, grid constraints intensify, and homeowners seek more control over their energy usage, solar and storage are becoming a structural part of the energy landscape. Utilities now face a choice: adapt to that reality, or risk being sidelined.

Pushback in Interconnection and Design

In some regions, utility resistance is already evident in interconnection delays, which are becoming more common, particularly in solar-saturated markets and fast-growing load centers. What was once a relatively straightforward process is now often characterized by longer timelines, more detailed technical reviews, and increasing uncertainty for both installers and homeowners. For example, while there are state-mandated timelines for IOUs in California, the five years of public data show that there are routine violations according to a CALSSA report on April 30, 2026: 

At the end of 2025, the interconnection delays were so bad in California that 18 state legislators wrote to the CPUC demanding that it hold PG&E and Southern California Edison accountable for “repeatedly missing state-mandated timelines to interconnect solar and storage.” 

The impact is not abstract. Projects that might have been approved in weeks are now taking months. According to CALSSA, installers are reporting a 7x increase in grid upgrades in PG&E territory compared to last year.  Homeowners are left waiting, and in some cases, reconsidering their plans altogether.  

Beyond delays, there is also a growing degree of what industry participants describe as “design friction.” Utilities are placing limits on system size, restricting export capacity, requiring design modifications, or claiming that costly grid upgrades will be required at the customer’s expense as a condition of interconnection. Below is a table from the same CALSSA report showing PG&E as an extreme outlier for grid upgrade requirements:

“PG&E and SCE have faced no consequences for routinely violating state-mandated interconnection timelines. Delays cost solar customers tens of thousands of dollars, but the utilities lose nothing, and profit from delays if those mean an opportunity to further upgrade the grid,” said Kevin Luo, policy and market development manager at CALSSA.

In practice, that often means downsizing systems, incorporating battery storage to manage when and how energy is exported to the grid, or demanding expensive premiums for system expansion. For example, Southern California Edison is charging a $800 fee to add new panels to an existing system. 

This shift is influencing how residential systems are designed. Rather than optimizing for maximum production and grid export under net metering, more projects are being built for self-consumption and backup power. Batteries are playing a larger role—not just as a value-add but as a necessary component for navigating interconnection constraints. 

From one perspective, this pushback reflects real challenges. Distribution grids in many areas were not designed for high levels of distributed generation, and capacity limitations are becoming more visible. But from another, it signals a deeper tension: a centralized system struggling to accommodate a rapidly decentralizing energy model. 

Early Adopters Show a Different Path

Not all utilities are responding the same way. Some are beginning to embrace distributed generation and demand-side flexibility as tools to manage grid constraints rather than a problem to contain. While still in initial phases, these efforts point toward a different model in which customer-sited resources are integrated into grid operations. For example, VPPs have already been deployed in Massachusetts, California, Utah, Puerto Rico, and North and South Carolina – providing rate reductions for rate payers and cutting costs for utilities.  

A common example is the rise of “bring-your-own-battery” (BYOB) programs for energy storage. Under these programs, homeowners can enroll their batteries and allow utilities to dispatch them during peak demand periods and be compensated with financial incentives or bill credits. For example, PG&E has partnered with Tesla to deploy a VPP as part of its Emergency Load Reduction Program (ELRP), Green Mountain Power in Vermont has a BYOD program, and National Grid in Massachusetts deployed its Connected Solutions VPP program, in which a 10 kW battery system can earn up to $2,750 annually.   

In some cases, utilities are piloting non-wires alternatives—using distributed energy resources to defer or avoid traditional infrastructure upgrades. Rather than building new substations or upgrading feeders, they are leveraging distributed solar, storage, and load management to reduce peak demand at specific points on the grid. For example, Con Edison’s Brooklyn-Queens Demand Management Response Program avoided approximately $1B for a new substation by deploying roughly 52 MW of DERs for a program cost of only $200M. And according to The Brattle Group, the benefits of a VPP in California significantly outweighed the program costs, providing a potential net system cost savings of up to $206 million between 2025 and 2028.  

While these programs remain relatively narrow and fragmented, they demonstrate an important shift in utility mindsets: distributed energy is increasingly being treated as a grid resource rather than a customer-side complication. 

The next step is scale. Moving from pilot programs to integrated platforms, in which solar, storage, EVs, and flexible loads are coordinated as part of a broader system, will determine whether these early efforts can meaningfully reshape grid operations.

The Risk of Not Adapting

While some utilities, such as Green Mountain Power, Hawaiian Electric, and Arizona Public Service, are adapting, others risk falling behind. As distributed solar, storage, and home electrification become more cost-effective, homeowners are gaining increasing control over how they produce, store, and consume energy. That does not necessarily mean widespread grid defection, but it does mean a shift in the grid’s role. 

If utilities don’t integrate distributed generation into their model, they risk becoming less relevant in the customer relationship. The grid could shift from being a primary service to more of a backup or balancing mechanism, especially in markets with high electricity costs or reliability concerns. 

This transition is already visible in early-adopter regions such as California, Hawaii, and Texas. In these markets, some homeowners are designing systems to maximize self-consumption, using the grid primarily as a supplemental resource rather than a central dependency. The likely near-term outcome is not full independence, but a hybrid model. Homes operate semi-independently for portions of the day or during outages, relying on solar and storage for core needs while maintaining a grid connection for flexibility and reliability. 

The risk for utilities is not an abrupt loss of customers, but a gradual erosion of relevance.

Rethinking the Utility Business Model

Adapting to this new reality requires more than incremental program changes. It requires a fundamental shift in how utilities define their role. Traditionally, utilities have operated as centralized providers of electricity—delivering power from large-scale generation assets through a one-way network to passive consumers. Distributed generation disrupts that model in two meaningful ways. One, it eliminates the utility’s monopoly status. So even when rate hikes are approved, they will apply to a shrinking number of customers. Two, it introduces millions of customer-sited resources that can generate, store, and manage energy independently, refocusing the utility from being a capital-intensive construction company to a platform orchestrator that trades electrons. 

The first step in adapting is integration. Utilities need better visibility into distributed resources and must incorporate them into distribution-level planning, forecasting, and operations. 

The second is engagement. As more customers adopt solar, storage, and EVs, utilities have an opportunity to offer programs that coordinate these assets through dynamic pricing, managed charging, and participation in grid services. The relationship becomes interactive and mutually beneficial rather than transactional.  

Finally, there is a shift in how value is created. Instead of relying primarily on capital investment in large infrastructure for ROE profitability, utilities need to begin generating value by improving system efficiency, such as reducing peak demand, deferring upgrades, and optimizing existing assets through coordination. With this perspective, distributed solar and storage is not a threat to be managed, it is a resource to be integrated. 

The utilities that succeed will be those that make it easier for these systems to connect, participate, and deliver value. Those that do not may find themselves in a diminished role, supporting a grid that is increasingly shaped not by centralized generation, but by the millions of systems operating at its edge. 

About the Author

Deep Patel is the founder and CEO of Gigawatt Inc., the parent company of Unbound Solar and Real Goods. Unbound Solar has provided DIY solar kits and expert support for over 19 years, serving homeowners, contractors, and professionals. Real Goods, established in 1978, is a legacy brand in the solar industry known for reliable solar and energy storage products. Through these brands, Deep is focused on expanding access to clean energy by combining education, high-quality components, and a customer-first approach.