Five panelists — three solar developers, a project finance banker and an infrastructure private credit investor — spoke at the Infocast New York conference in Albany on April 15, 2026 about how renewable energy projects are being developed and financed this year, and how the market will change after the federal tax credits for wind and solar are phased out under the One Big Beautiful Bill Act.
The panelists are:
Andrew Bernstein, chief executive officer of Kearsarge Energy; Stacey Hughes, chief financial officer of Sunlight General Capital; Mark Pallai, executive director in the project finance group for the Americas at Rabobank; Daniela Pangallo, senior director for partner development at Nautilus Solar; and Jorn Santegoeds, a director at Apterra Infrastructure Capital. The moderator is David Burton with Norton Rose Fulbright.
The panelists used several key terms. The “OBBB” is the One Big Beautiful Bill Act, the 2025 tax law that set end dates for the federal tax credits for wind and solar. A project that starts construction — often by buying equipment or doing physical work, a step colloquially referred to as “safe harboring” — by July 4, 2026 has until the end of 2030 to be placed in service and still qualify for the credits; a project that misses that date must be placed in service by the end of 2027. The “ITC” is the investment tax credit. “Transferability” is the ability, added in 2022, to sell tax credits for cash. “FEOC” refers to the foreign-entity-of-concern restrictions that limit the use of Chinese equipment and capital that were enacted as part of the OBBB.
MR. BURTON: Stacey, how is Sunlight General handling the push to do significant physical work — safe harboring — on projects by July 4 so that the projects are not subject to the requirement that they be placed in service by the end of 2027?
MS. HUGHES: It is a hot topic right now; everybody knows that. What we have been doing is not too different from a lot of our colleagues. Over the last year we tried to get ahead of it, even as the rules and guidance kept unfolding, and to take the safest routes we can. In the last quarter that meant buying a lot of equipment and putting designated contracts in place.
One thing we did, which is not that remarkable, was to ask which projects are most likely to make it across the finish line and have the best returns, and really zero in on those. That is not the only approach. Another is to buy far more than you need and safe harbor a whole variety of projects. We bought equipment and, in some cases, started construction. For projects under one megawatt, or portfolios of projects under one megawatt, we built structures ahead of time so we could decide whether to split them among different equity owners and bring them online over a calendar year. We were trying to meet a very complicated set of criteria so that we would have runway to build over the next couple of years.
The other approach people talk about, which is easier said than done, is to buy operating projects so you don’t have to worry about safe harboring. Sunlight does that, and I think my colleagues do too. But there are a lot of buyers for those projects, and they can come with strange characteristics or need a lot of repairs. So mainly we have been buying equipment and, in some cases, doing not-huge but real work that counts as the start of construction, even while we were finishing contracts — the first time we have ever started a little ahead like that. We have a handful of projects left, but I don’t really see many anymore. It is a very strange set of circumstances.
MR. BURTON: Daniela, do you want to talk about what Nautilus has done?
MS. PANGALLO: We have been making the same move for the last year, trying to fast-track as many projects as we can and start construction in any safe way. We are fairly conservative and try to see ahead to what tax equity will want, so we did not do anything too creative — mainly buying modules. We are looking at transformer strategies right now, but very cautiously. There are conversations among developers about acquiring transformers of various kinds. Not every buyer is comfortable with all of this, so we are being cautious and starting the conversation early with potential buyers to make sure that everything.
MR. BERNSTEIN: We started safe harboring in 2022. We started construction partly to avoid prevailing wage in some cases. We consistently bought gear and transformers, and you have a four-year window on that, which is a challenge, but worst case you take the equipment and put it on another project. We also bought significant quantities of panels. When you make these bespoke investments, you set up an LLC and put together a very thorough package with pictures and documentation, and we have used them in multiple financings where the tax attorneys had the final say to approve them. It has been a fine strategy, and the equipment is fungible, so we can look at a project, buy it and transfer the asset to it. T
MR. BURTON: That is all very interesting. It sounds like everybody is being prudent and doing what they can to qualify their pipeline. For those in the audience who don’t deal with this every day: up to 1.5 megawatts you can still use the 5% safe harbor, which for a project that small is relatively easy to meet. Over 1.5 megawatts, you need to do significant on-site or off-site work. Off site is typically a transformer; on site is often building a row, putting in racking or some other physical work at the site. Those are just examples; there are other options. If you do this before July 4, you have until the end of 2030 to place the project in service. If you miss July 4, it has to be placed in service by the end of 2027. And this applies only to wind and solar — standalone storage does not have this issue.
MR. BURTON: Daniela, tax credits can now be monetized through traditional tax equity structures, tax credit transfers or hybrid approaches that combine both. How does Nautilus approach the different options?
MS. PANGALLO: We welcome the optionality that transferability and hybrid structures now provide, but we have been transacting mainly through partnership flips. That is a function of who we are and the pipeline we have. We come to the tax equity market with large portfolios — usually 100 to 125 megawatts a year — so we have the size to keep using the partnership flip as a more asset- and capital-efficient way to monetize value.
That said, we welcome the added flexibility and certainty that hybrid structures and transferability can provide. Building on some of the conversation on this panel: our pipeline is ideal for partnership flips, but when you start thinking about flexible-interconnection projects or standalone storage, transferability and hybrid structures give you the extra tool that lets a project move fast and get to the finish line. Before, you needed real size and a big portfolio to attract tax equity; now there are different tools, and each one fits a particular portfolio or sponsor.
MR. BURTON: Any other thoughts on tax credit monetization?
MR. PALLAI: We see a lot of different structures and approaches, so we have to keep abreast of them. I would love more standard partnership flips, but on the banking side we understand that developers have to look at other avenues. We try to avoid uncommitted tax credit sales, and where there is one we may require a lower advance rate. All of this is adding a lot of complexity. As an originator, we are often in these deals at the earliest stages, and we now stay closer to the process — closer to closing — to make sure the tax credits are actually being monetized. We just have to be aware of the different structures and where the market is.
MS. HUGHES: When we first heard about transferability, I thought it sounded great — many more potential investors, easier and quicker, a lot of things I would not have to deal with. What we ended up doing was a partnership flip with a transfer, a hybrid. I thought that was even better, because nobody really values the depreciation that much, so we could keep the depreciation in one place and transfer the credits. It does work, but it was far more work than a traditional partnership flip tax equity deal. Admittedly, we did it about a year and a half ago, so maybe we were early adopters and it is smoother now. But I have my doubts about how much the added complexity is worth.
MR. BURTON: The market consensus is that it is more complex, and I am certainly seeing that. Transferability is great and was supposed to democratize tax equity, and it has brought in new tax credit investors, which is good. But it has added complexity, largely because of all the optionality you now have, and it has added to the time it takes to get deals done. Any other thoughts on tax credits?
MR. BERNSTEIN: What we have done mostly is inverted leases, something U.S. Bank taught us about 14 or 15 years ago. It has been a great formula. We also do partnership flips. But to Stacey’s point about hybrids — why not do the hybrid with another developer? That takes out one of the most complex pieces. We are doing one right now, mainly for the depreciation, so we understand it better, and we actually provide tax equity ourselves. We have done a partnership flip and an inverted lease for another developer, and that gives you a different perspective. Developers working together is one way to get around some of the complexity.
MR. BURTON: That is really great — I had not heard of that. I don’t know how many developers have your appetite for tax depreciation, but since you do, that is innovative.
MR. BURTON: Andrew, what are you seeing in the M&A market at Kearsarge — opportunities to buy projects from other developers, and at what stages? Are you seeing platforms?
MR. BERNSTEIN: We are inundated, especially over the last three months. We see so many projects, and a lot of them are half-baked. We are seeing platforms, but also some interesting opportunities in different markets. We saw one in New York from a group of site finders who decided they wanted to develop the project themselves. There is so much coming in that we now have a weekly meeting just to prioritize.
MS. PANGALLO: We see the same thing — early stage, late stage, and now more deals under construction. Some of the largest developers are trying to take more control of the timeline, starting to build and looking for a buyer along the way. On the early-stage side, we see portfolios that sometimes don’t even have interconnection looking for a partner. Everyone is trying to find a home for these projects and move them faster, and honestly, finding the right partner is probably the best way to do that, because there is so much uncertainty that collaborating with buyers helps.
MR. SANTEGOEDS: We are getting a lot of inbounds as well, asking whether we can syndicate portfolios for sale with some urgency. It is a combination of interest rates that have risen, sponsors getting more familiar with distributed generation — which is not as easy as utility-scale solar — and now the threat of tax equity falling away. We are seeing a lot in the market. We may not be as close to it as the other three panelists, but it is a very dynamic environment.
MS. PANGALLO: Having seen a significant amount of M&A pipeline, what we see changing is the terms being offered. Everyone is getting more conservative about deadlines and interconnection, because everyone is getting hit by delays at every level. Until last year it was common for developers to be paid the developer fee at or very near closing. Now everyone is moving to pay it as the ITC is realized, which is harder in terms of timeline and spending, because the buyers cannot monetize and pay that developer fee upfront. It is also taking longer for a project to move from closing through permitting to completion, and because interest rates did not come down, the cost of capital is high — often adding six months to bring a project to the finish line.
MR. BERNSTEIN: Building on that, tax equity doesn’t want to give you full credit for the adders. A developer buys a project and says, “This is at 50% — it’s an energy community, it has X, Y and Z,” and wants more money for it. But it is only worth what tax equity will value it at, so you have to wait until the end. Most tax equity will say, “I’m not going to give you full value; I’m going to haircut it, because I don’t want to give you that large step-up — I think it’s a risk.”
MR. BURTON: For people who don’t work with this every day, the two adders we are focused on here are, first, a low-income adder that the Department of Energy has to award. It is not literally a lottery, but you don’t know whether you will get it, and there have been some issues. It can be 10% or 20%; you have to apply, be awarded it and then actually qualify. Second, there is an adder based on the location of the project, called the energy-community adder. If a project is in a community that had a lot of fossil-fuel jobs and has an unemployment rate at least at the national average, it qualifies. That is objective and easy — the areas are published in a table, so anyone can look it up. That is the problem: the landowner knows, the contractor knows, everybody knows, so everybody says, “If you’re getting more, I want more,” and it doesn’t benefit the developer as intended. Domestic content is a third adder, somewhere in the middle.
MR. BURTON: Shifting away from tax — we heard a bit about uncontracted storage projects and how hard they are to finance. Mark, how are lenders thinking about residual cash flows after the contracted period? How do you and the market approach uncontracted cash flow?
MR. PALLAI: I would love 100% contracted, but that is not going to happen in today’s world. At Rabobank, along with many other banks with a similar risk appetite, we evaluate how much merchant revenue there is as a proportion of cash flows, and whether it is front- or back-ended. We get reports from independent consultants and look at various cases, and we generally underwrite to a low case. There is no prescribed number; we look at the project, the type of merchant revenue and the overall story to get comfortable.
On batteries, arbitrage revenue is something we would not underwrite to. Historically, in some areas it comes down to just two variables, so there may be some value there, but for Rabobank and the other key banks it is more equity upside than something a bank underwrites to. A lot of these merchant revenues have a long lead time — sometimes 20 or 25 years out. Power prices are moving up, and there is some value there, but there is a lot of unknown. The story today is very different from a few years ago, let alone five or ten years out, so you want to be conservative. Most banks want a fair amount of certainty that repayment comes from contracted cash flows — how much is contracted, and can we sweep out all our debt, or is there a large balance left.
MR. SANTEGOEDS: It is similar for us, and it really depends on the asset class — solar, wind or battery. Like Mark said, if you lent against ERCOT a few years ago you are probably underwater now. We take a similar approach to how much merchant risk we are taking relative to the overall deal size, and we compare against historical rates. Everyone assumes power prices will rise because of load growth from electrification and data centers, so we run different cases — but the less merchant exposure, the better.
MR. PALLAI: I would add how this affects the capital stack. One of our underwriting criteria is equity contribution to the project. During construction there is a fair amount of equity, but in the past few years tax equity has been crowding the capital stack, and on top of that there is more debt. In a lot of cases there is little to no sponsor equity left at term conversion. So, you want alignment of incentives through operations, and you look at the residual value of future cash flows — it all ties back to merchant exposure and debt sizing.
MR. BURTON: Andrew, your thoughts?
MR. BERNSTEIN: On some of the standalone, larger 150-megawatt projects we have looked at in Texas, we talk to banks about debt financing, but the cost of debt is so expensive it is almost like preferred equity. So, we say, “Forget it — we’ll do tax equity and keep our own equity,” because the returns don’t make much sense given the uncertain merchant nature. If you believe there will be another Winter Storm Uri, you accept that you might be out there for four years before you get a big hit. It is a very different kind of investment, and tax equity can live with it. A tolling agreement is one way to bring in some banks, though you give away some of your upside.
MR. BURTON: Shifting gears — we have seen some high-profile solar developers, like Pine Gate and DSD, run into financial problems. What lessons can the industry learn from those situations?
MR. SANTEGOEDS: This is what I alluded to earlier. Five years ago, tax equity might cover 30% to 50% of the capital stack, interest rates were near zero, and there was a lot of dry powder from private equity funds going into renewables intending to build a platform and exit at a certain multiple after four or five years, assuming debt would still be cheap. That did not happen. It comes down to discipline — building your company, focusing on your core tasks and not trying to get ahead of yourself — because margins are still relatively thin and leverage is fairly high. P50 generation is never quite P50, and operations and maintenance expenses are never quite as expected, so the residual cash flows are thin. There is a lot more discipline in the industry now because of those cases, with debt more expensive and tax equity falling away.
MR. BURTON: Anyone else?
MS. HUGHES: I remember when we started, in 2009, and shortly after there was a lot of interest in renewables — and some high-profile bankruptcies over the following years. There has been another wave of it. It comes back to discipline. Solar projects very rarely earn a private-capital type of return — pick your number, 7%, 8%, 12%, 15%, plus some tax advantages. That is not a private-capital return and never will be, and it doesn’t matter how many panels you multiply. The way we think about it going forward is to look at each project: does it work? We are not trying to grow for its own sake; we are trying to make sure every project we can do actually works, and if we don’t get every project done, so be it.
When we were raising capital, we were very successful — we found lots of entities that wanted to give us money, often $200 to $300 million, and we weren’t taking it. It would have been too stressful; you can’t deploy it in the timeframe and at the yield you want, done the way you want. Later we found partners where it made more sense. The temptation is to take the money, and then they are calling you asking whether it has been deployed, and the next thing you know you are staring at a merchant curve telling yourself power prices are going up. Keep that discipline, and if some projects get away, that’s okay — you will be here to fight another day.
MS. PANGALLO: For us it is about being holistic and realistic about what we can do. We look hard at each project, and sometimes we pass on opportunities — but we find the ones that are right for our organization and that make sense.
MR. PALLAI: We talk a lot about interest rates and dry powder, but we are also underwriting people, not just assets. It is easy to look only at cash flows, location and the story, but there is a heightened focus on who is behind the project — who is operating it, who is developing it and who is backing them. That is part of the discipline theme: we are underwriting both the assets and the organization.
MR. BURTON: Back to Stacey — this is a New York conference, and we haven’t really touched on New York yet. What is the low-hanging fruit in New York in terms of policy changes to encourage more solar development?
MS. HUGHES: I love this question. Right now I don’t see a lot of low-hanging fruit, but I am here because I want that to change. I have been coming to this conference for years, and the theme has been huge goals — 300-megawatt projects, massive transmission, huge, huge, huge. Some things have been accomplished, but most of those goals are not achievable; there are just too many obstacles to giant projects in New York.
So, I would submit — and admittedly I am in the business of smaller projects, so take it with a grain of salt — that New York consider pivoting, as it has in the past, to incentivize smaller projects. There are rooftops everywhere; when you take off from an airport in the Northeast, you see empty roofs everywhere. I would like to see New York bring back the programs it had for batches of 200-kilowatt rooftops where the offtake could be for the city — those were very successful. There are all sorts of 1-to-2-megawatt projects where nobody is screaming, because they are not blocking anyone’s view. As New York thinks about its lofty goals, it should also create buckets and carve-outs for these smaller projects. They are sustainable in every sense — they are not eating up the countryside or causing protests. I know there is an effort to encourage this, and for anyone making decisions, remember the medium-sized projects too, because there is a lot of leverage there.
MR. BURTON: Any thoughts?
MR. BERNSTEIN: We are seeing a lot of battery storage, with increased focus because the new feeder curves are attractive. They also bring risk, and you have to understand how to permit them. If you want to see more happen in New York, you have to look at the whole permitting picture for batteries and help explain what makes them safe. A 5-megawatt battery now needs 8,000 to 10,000 square feet. I remember a meeting in New York last year where they said, “Oh, you’re the solar guy” — there is real pushback in parts of New York because so many large projects have taken down a lot of trees. But storage is a very efficient use of land, so it is a big opportunity, as long as you can correctly explain that a battery site is less likely to catch fire than a gas station.
MR. BURTON: We also heard this morning that New York leads the nation in battery moratoriums, so that is not helpful; we need to address it. Daniela, do you have thoughts on interconnection in New York? What has Nautilus done, and how is it going?
MS. PANGALLO: As I mentioned, we usually buy projects from developers, so we are not involved in the early-stage scouting like interconnection. Until last year, interconnection was essentially a box to check; we were comfortable with the timelines we were given for completing upgrades and interconnecting, and we planned around them. That is no longer the case. We are dealing with several delays, and it is affecting a lot of people. This is not just a New York problem — it is everywhere — and it has become a bigger issue now that more projects are being fast-tracked. Interconnection is probably the biggest problem in the industry right now, not just in New York. I am also encouraged by the conversation about battery storage interconnection. Hopefully, as an industry, we can find a way to make this work and unlock more of the grid’s potential for smaller projects.
MR. BURTON: Let’s pull back to the bigger picture, beyond New York — tariffs. It seems like tariffs change almost daily. Andrew, how is Kearsarge managing tariff risk?
MR. BERNSTEIN: It is fairly challenging. We purchased about 70 megawatts of batteries — all of our 100 megawatts for this year and 60 to 70 megawatts for next year. But I am taking a different approach now that the market is evolving so much; whether it is working around FEOC on batteries or tariffs, you can also wait and see. Every time in the last 8 to 10 years that I was sure battery prices were going to skyrocket and I bought them and put them in a warehouse, prices came down. This may sound oversimplified, but trying to be too smart can backfire. You can hedge, but I also believe the market will react if there is enough demand. We are seeing that with new battery factories going up. People saw what Ford did — it took a $46 billion write-off on its EV factories and is now shifting to build battery storage. There are real opportunities as major companies, including the Department of Defense, realize batteries are critical. So, it is a bit “Field of Dreams” — if you build it, they will come — but there are ways around the tariff issue.
MR. BURTON: Other thoughts on tariffs?
MR. SANTEGOEDS: From the lender’s side, we want to make sure that when we lend, the equity the sponsor puts in is enough to complete construction, so we are exposed to tariff risk as well. We are seeing clients go for domestic offtake, which mitigates or removes tariff risk. We are also seeing clients big enough to negotiate with their equipment providers so that the provider absorbs whatever the tariffs turn out to be, which gives us a lot of comfort as lenders. A third option is to size a contingency and see how large tariffs would have to be before they exhaust it.
MS. HUGHES: “Big enough to negotiate” is a good point — but sometimes a deal can be small enough to negotiate, too. We do equipment procurements in different pieces at different times, and it was not that hard to push the tariff onto the supplier, because the dollar amounts were relatively small. Sometimes, if you keep an open mind, you can be small enough to make the tariff not your problem.
MR. BERNSTEIN: I would add that we have negotiated tariffs back onto vendors. We will say, “Up to a 20% tariff, you take 100%; over that, we’ll take 50%; over 35%, we’ll take 75%.” We are making a bet — a fairly good one, we think — that tariffs won’t get that high, because there are too many reasons they shouldn’t. We are trying to guess what this administration will do, which is probably not a smart bet. Who knows.
MR. BURTON: Mark, what is the biggest challenge Rabobank faces in underwriting loans for renewable energy since the One Big Beautiful Bill passed?
MR. PALLAI: First, there has been an incredible amount of activity since the OBBB. I feel as busy as ever, and most people are not bored — there is a lot to do, much of it driven by the expiration of the tax credits. There is also a macro story: I sometimes joke that I am a hyperscaler banker now, because I am doing data centers too, where the offtake is often with a hyperscaler as the tenant. The greatest challenge is simply managing the workload; a lot of banks and investors are struggling to prioritize, and banks can feel like they are not being as responsive as they would like, just as a function of bandwidth.
The other challenge is that everything is getting really complex. I wish we could go back to a simpler world of just projects. Take tariffs — I am hearing different stories from different developers about how they are negotiating, and that touches many parts of the law, as does FEOC. Lenders and investors have to get involved in each idiosyncrasy; we can’t rely on a blanket statement. We work with lawyers, verify things ourselves and have a lot of conversations with developers, with the goal of being a partner. The best outcome for a bank is that the company does well, and we understand where people are struggling — whether it is interconnection or safe harboring — and can verify it and move forward. The challenge is the sheer volume of deals, compounded by the complexity the world is throwing at us.
MR. BURTON: Jorn, Apterra is an infrastructure private credit fund. There have been many headlines about problems certain sponsors of private credit funds are having. Have those problems affected Apterra?
MR. SANTEGOEDS: No — that is the easy answer. The issues in private credit really come down to the asset class; a majority of those funds hold software loans, and there is a lot of disruption from AI. Apterra is an infrastructure credit platform, so we lend to infrastructure projects — real physical assets that play a crucial role in society and are underpinned by relatively steady cash flows. So no, we don’t have that problem.
MR. BURTON: Part of our topic today is the post-ITC world. How much would PPA rates have to rise if the ITC in fact lapses? How much would the cost of power have to go up to make up for losing the ITC?
MS. HUGHES: I think it is about 40%. It depends on the deal — whether it is a low or high PPA rate — but something in the 40% neighborhood, which is achievable. Is it easy to sign PPAs at 40% higher? No, but it is not impossible either.
MR. PALLAI: What I am hearing is that PPA rates would have to adjust. When that time comes, there will be five other things to think about in tandem — supply chain, the price of equipment and everything else — so it will be an adjustment of many factors.
MR. SANTEGOEDS: One thing to add: a lot of loans are constrained by minimum equity, not just by existing cash flows, so the project could actually be larger than what you can finance today, where 30% to 50% of the capital is filled by tax equity. It is good that there is so much load growth now, which partially offsets the loss of the tax credits. Whether the PPA adjustment is 30% or 40% remains to be seen, but it is a good development for developers and lenders alike.
MR. BERNSTEIN: You should also look at the cost to build. People know panels in Europe cost less than 10 cents; in the U.S. they cost more, partly because of tariffs but also because manufacturers like the U.S. market since they get paid more here. The focus on domestic content will keep panel prices up. Still, we have seen utility-scale projects — some with batteries — that work today without the ITC.
MS. PANGALLO: We assume rates go up, but they could come down. We are seeing a shift toward PV-plus-storage, or storage-plus-PV, where lower equipment and module costs can make it work. Not easy, though.
MR. BURTON: If the tax credits go away, do you think New York will be a particularly attractive market, or would other parts of the country be more attractive?
MS. PANGALLO: For us, I don’t think New York would pencil as it is right now — the cost of building is high. We did some analysis and mapping, and the only projects that work at current rates are in lower-cost-of-building areas. In New York, the topography is very challenging; it is very difficult to find flat land, and the cost of building stays high.
MR. BERNSTEIN: You also have to look at the cost of labor. I don’t think New York makes a lot of sense given the overall cost, and the same goes for a lot of New England and the Mid-Atlantic. But if you look at Colorado, Kansas, and I know groups building in Mississippi and Missouri right now, those work. You have to drive down the cost of labor, which is probably 25% to 30% of the overall cost.
MR. BURTON: What level of curtailment, as a percentage of nameplate capacity, would be acceptable for financing flexible interconnection?
MS. PANGALLO: Let me start with what is not acceptable. We ran into a case where there was no cap on the amount of curtailment possible, and that is definitely not bankable. After that, anything known upfront can be baked in. It is not a single number; it depends on the project, where it is located and how much interconnection costs. It needs to be capped. Everyone goes into flexible interconnection assuming a 1% maximum.
MR. PALLAI: From the financing side, that is embedded in how we look at projections. There are different types of curtailment — grid and economic — and they have different historical variability. The key for us is to avoid highly variable curtailment; we have seen issues in regions like CAISO. I don’t know New York as well, but there is already a perception of higher curtailment there, which affects our ability to finance.
MR. BURTON: Is there a pathway for a bipartisan, technology-neutral return to the ITC, given a possible 40% increase in PPAs and a focus on affordability? I think there is a pathway, but the likelihood really depends on how the 2028 election comes out, which is very hard to handicap now. I don’t see it with this Congress, and probably not even after the midterm elections this November — but perhaps after the next presidential election. Anything is possible.
MR. BURTON: Finally, how can American solar developers negotiate panel prices down closer to European levels?
MR. BERNSTEIN: I don’t know. The challenge is that tariffs are higher here, and it will come down to supply and demand. One thing that will not lower prices is the focus on domestic content, which raises the price of panels. So, I don’t see a path to negotiating those prices much lower.