Jigar Shah is founding advisory chair of Deploy Action. He led the U.S. Department of Energy's Loan Programs Office from 2021 to 2025.
The race to serve new electricity demand is on — and states are at risk of responding the wrong way. U.S. electricity demand is expected to grow by roughly 128 GW over the next five years, one of the sharpest increases in decades. If states respond as they have for decades — with massive capital plans designed to meet just 50 hours of peak load — customers will end up paying more to subsidize an underutilized grid. We will always need to build more generation and transmission. But the smartest near-term path is to squeeze more value out of the system we already have.
That is where distributed energy resources come in — especially community-scale solar and storage projects, typically between 1 MW and 10 MW. Deployed strategically on the distribution system, these resources can add flexible capacity close to where load is growing, coming online far faster than large transmission-connected generators that face years-long supply chain delays. But capturing that value requires more than setting targets. It requires procurement structures that give utilities clear incentives to move quickly, and that hold developers to strict cost and availability standards.
While customer-sited resources play an important role, the biggest near-term opportunity is on the distribution system itself. Front-of-the-meter community-scale storage — meaning utility-side assets, not customer-owned — can be targeted precisely to the substations and feeders (the power lines distributing electricity to neighborhoods) that need relief most. That targeting has to happen in coordination with utility planning, which means utilities need to open their data.
I have spent my career working to get clean energy deployed at scale — as an entrepreneur, investor and former head of the Department of Energy's Loan Programs Office. This is not about ideology; it is about outcomes. Utilities must be able to rely on these assets, and sometimes that means directly dispatching them. But if we want to add capacity quickly, affordably and reliably, utilities have to tell us transparently where to put these systems. That is the central ask.
The urgency is sharpest in regions like the PJM Interconnection — the grid operator covering the mid-Atlantic and Midwest — where customers are already feeling the consequences of a congested, slow-moving system. Interconnection wait times for transmission-connected generators now average roughly eight years, a staggering mismatch for a region facing sharp rate increases and urgent load growth. Distribution-connected assets, by contrast, can be deployed in months, closer to where demand is actually rising. Even modest improvements in grid utilization can keep distribution costs under control — and distribution costs are the single largest driver of rising utility bills.
The industry is beginning to align around this faster, more flexible approach. At CERAWeek 2026, more than 30 major players — utilities, independent system operators, hyperscalers and technology providers — backed a new initiative led by the Electric Power Research Institute to standardize how flexibility is defined and used to accelerate what the industry calls "time to power." That reflects a growing recognition that today's planning processes rely too heavily on worst-case assumptions, and that smarter use of existing assets can unlock capacity far faster than new construction alone.
But alignment is not enough. States need to pass laws requiring higher grid utilization — laws that unlock utility data and force a move from pilots to full rollouts. Community-scale, front-of-the-meter storage and solar projects are local, modular and can be built in six to 18 months. With the right program design, developers are ready to deliver tens of gigawatts of efficient, affordable capacity now, using assets that match the pace and geography of load growth.
The evidence that this approach lowers costs is already strong. Department of Energy analysis shows that virtual power plants can provide reliability at substantially lower cost than traditional alternatives and save up to $10 billion annually if scaled nationally. Massachusetts determined that optimized deployment of roughly 1,800 MW of distributed storage and solar would deliver $2.3 billion in ratepayer savings. Similar analyses show multi-billion-dollar savings potential in Ohio, and national modeling suggests up to $170 billion in cumulative savings from deploying storage and solar to shift up to 20% of peak demand.
The question, then, is not whether distributed capacity should scale — it may be the only solution that can meet this moment within the next 18 months. The question is whether states know how to structure programs that create cost discipline and genuinely protect customers.
Getting there requires a real market-building effort: launching quickly, learning fast, preserving flexibility and keeping ratepayers protected. The community solar industry has spent 15 years developing the expertise, financing structures and local relationships to deploy at scale. States should expand that industry's remit to include distributed battery storage — and hold everyone accountable for driving costs down.
Four principles should guide that effort.
First, require utilities to share data and identify where the grid needs help. If a state needs distribution-connected capacity, it should pinpoint where that capacity is needed and clear the path for developers to secure sites and deliver projects quickly.
Second, benchmark costs and risk across ownership models. The central question is not just what something costs, but who bears construction, performance and technology risk — and whether that allocation produces the best outcome for ratepayers.
Third, apply consistent interconnection and operational standards to all projects. If utilities can identify constrained circuits, they should also be able to streamline the interconnection process so projects move faster without compromising reliability.
Fourth, preserve strong commission oversight and transparency. State regulators need clear, ongoing visibility into cost, performance and the grid value actually delivered — not just promised.
None of this is an argument against long-term transmission buildout. That work is essential and must continue. But states cannot afford to wait for new transmission while the load crisis deepens. The best near-term answer is to deploy distributed storage into the grid we have already paid for — and to do it through competitive, transparent programs that give utilities a real role, give third-party developers a fair shot and deliver measurable value to customers.
States that get this right will scale faster, spend less and build a more durable energy market. The tools exist. The developers are ready. What is needed now is the policy will to move.
