Recently, Hansen joined many of the industry at RE+ Northeast in Boston. Following the event, I caught up with one of the Hansen team - John Baksa - to hear from him on key insights and learnings. It struck me that others in this community might also be interested, so I hit record and have transcribed it below.
I hope you find it equally insightful!
John, you recently returned from RE+ Northeast in Boston. Before we get into specifics, what was your overall impression of the event?
John Baksa:
The most striking thing for me was the level of engagement. The show was well attended, and the conversations were very pragmatic. Despite ongoing policy uncertainty and some anti‑renewable rhetoric coming out of Washington, the U.S. solar and storage market is clearly still active. What’s changed is the tone. This is no longer about optimism or ambition. It’s about execution under tighter timelines and constraints.
David:
What were the dominant themes or questions you kept hearing from industry leaders?
John:
Two questions came up repeatedly. First: How is the U.S. going to meet the sharp increase in electricity demand we’re expecting over the next three to five years? Data centers, EV adoption, and electrified heating are all driving load growth at a pace the grid wasn’t designed for.
The second question was about federal legislation - specifically how recent changes are impacting solar and storage investment decisions right now, not five years from now.
David:
Let’s take the demand question first. What answers were people converging on?
John:
The consensus was clear: Distributed Energy Resources are the only viable near‑term solution. Large centralized options like nuclear or new gas turbines are simply too far out - often seven years or more. DER, on the other hand, can be deployed quickly and close to load.
We’re talking about distributed and community solar, battery storage, microgrids, virtual power plants, demand response, managed EV charging - assets that can be built and integrated now. Community solar, in particular, continues to stand out because it expands access to customers who can’t host on‑site generation, while also supporting utility reliability and state policy goals.
What was interesting is that DER is no longer viewed as a niche or supplemental resource. At RE+, it was being discussed as core grid infrastructure.
David:
How is that shift affecting the structure of the market?
John:
We’re seeing rapid consolidation. Smaller developers are exiting due to capital pressure and policy uncertainty, while larger operators are acquiring operating assets and expanding their portfolios. That creates scale - but it also creates complexity.
Managing large, multi‑state DER portfolios introduces new challenges around billing, customer crediting, regulatory compliance, and customer experience. The industry is realizing that success now depends less on building projects and more on operating them efficiently at scale.
That’s a major inflection point for utilities and developers alike.
David:
You also mentioned federal policy changes. How are those playing out on the ground?
John:
For solar, the biggest impact has been a compression of timelines. The long runway that developers previously assumed has effectively been replaced by a hard execution cliff. To preserve investment tax credits, projects now need to either begin construction by mid‑2026 or be placed in service by the end of 2027.
That’s triggered an intense rush of activity. But it’s important to note that this isn’t a market collapse. It’s a market acceleration. Developers are moving faster, utilities are under pressure to interconnect sooner, and operational readiness has become absolutely critical.
David:
And what about energy storage? Did that come up as well?
John:
Very much so - and storage was widely viewed as the relative winner. Federal support for energy storage extends well into the next decade, which has fundamentally repositioned it in the market.
When you pair solar with storage, you transform intermittent generation into dispatchable capacity. That unlocks entirely new value streams - capacity markets, ancillary services, virtual power plants, resilience services. It also allows DER to be treated as firm capacity rather than just energy.
At RE+, it was clear that storage is no longer an add‑on. It’s becoming central to how the U.S. plans, operates, and stabilizes the grid.
David:
How does this evolution change what utilities and energy providers need from their systems and platforms?
John:
The complexity increases dramatically. Dispatchable DER introduces new billing models, new settlement requirements, and new customer relationships. You’re no longer just crediting kilowatt‑hours. You're managing PPAs, performance‑based revenues, grid services, and customer participation in aggregated programs like VPPs.
That’s where I think companies like Hansen and the solutions that we (and others) offer become essential. The market’s biggest constraint today isn’t technology - it’s execution. Utilities and DER operators need systems that can scale, adapt to new market constructs, and maintain customer trust and regulatory compliance as portfolios grow.
David:
If you had to summarize your biggest takeaway from RE+ Northeast, what would it be?
John:
The U.S. renewable energy market isn’t slowing down. Rather, it’s re‑architecting itself around speed, flexibility, and operational excellence. Distributed energy and storage are now foundational to meeting near‑term demand growth, and the organizations that succeed will be the ones that can execute at scale.
In this next phase of the energy transition, megawatts still matter - but it's operational platforms will determine who leads.