Over the past 6 to 12 months, domestic production of solar equipment in the United States has gone into full throttle. What started with mounting systems quickly expanded to inverters, then to partial component manufacturing, and more recently to full solar module production using domestically manufactured cells. Many of the major solar manufacturers have now set up factories in the US, not only for module assembly, which existed to some extent before, but also for upstream cell production.
This build‑out of local manufacturing capacity has created real momentum. Domestic content is no longer a niche or symbolic choice. In many cases, it is now technically feasible, increasingly available, and more competitively priced than it was even a year ago. That alone has changed the conversation around whether using domestic equipment in solar projects makes sense.
Why This Has Been Happening Recently
This shift is driven by what we can think of as two plus one forces. Two are very explicit and financial in nature, while the third is more strategic and policy‑driven.
- Manufacturing incentives under the IRA: Following the directives of the Inflation Reduction Act, solar equipment manufacturers can claim manufacturing tax credits. These incentives subsidize production costs and allow manufacturers to operate profitably while targeting domestic sourcing and domestic manufacturing.
- A higher ITC for developers and investors: Developers and investors can claim a higher Investment Tax Credit if they choose to use qualifying domestic solar equipment. In a standard case, the base ITC is 30 percent of total eligible project costs. This can be boosted by an additional 10 percent, bringing the total to 40 percent, if domestic content requirements are met.
- A strategic push for supply chain resilience: The third driver is broader and less financial, at least on the surface. It is about reducing US reliance on imported equipment, strengthening local supply chains, and improving economic and energy security. In theory, this is a goal most countries would agree with. Heavy dependence on outsourced materials can become a serious vulnerability during supply chain disruptions, as many of us witnessed during COVID.
I will not go too deep into that last point here, as it quickly moves into policy and geopolitics. The first two points, however, are squarely in the realm of finance and economics. On paper, better incentives should naturally push developers and investors toward domestic equipment.
Incentives Help, But They Do Not Eliminate Tradeoffs
In theory, more incentives are always good. In practice, things are rarely that simple.
Domestic equipment typically comes with a price premium. Even today, choosing domestic modules, inverters, or racking systems often means paying more upfront compared to non‑domestic alternatives. On top of that, there is now additional complexity in determining domestic content eligibility. Developers must account for how much of each component qualifies, how it contributes to total project cost, and whether it satisfies safe harbor guidance issued under the IRA. This often involves accountants, tax advisors, and an added layer of execution risk.
Setting all of that aside, and assuming the problem can be simplified to one key question, the core issue becomes this. Is the extra capital spent on domestic equipment justified by the additional 10 percent ITC?
At some point, there must be a breakeven. Below that point, paying a premium makes sense because the incentive outweighs the added cost. Above that point, the premium erodes project returns faster than the incentive can compensate. The benefit stops being a benefit.
So where is that breakeven?
Turning The Question Into A Model
If you enjoy math, Excel, or any coding language, this is actually a very approachable question. One simple way to look at it is to plot a project return metric against the premium paid for domestic equipment, and then compare that curve to a baseline project that does not claim the domestic content adder.
Initially, one option would be to use LCOE as the comparison metric. The issue is that LCOE depends heavily on the assumed WACC, which itself is subjective. Cost of debt, cost of equity, and perceived risk all vary by developer, investor, and market conditions.
Instead, we can use IRR (Internal Rate of Return). While IRR has its own limitations, it is a relatively intuitive measure of how sensitive a project’s cash flows are to time. Lower IRRs imply that time has a stronger negative effect on value, making future cash flows less attractive. Higher IRRs indicate the opposite. In simple terms, higher IRR generally means a more feasible project.
For this analysis, the absolute IRR value is not what matters. What matters is the comparison. If Project A has a higher IRR than Project B, then Project A is more financially attractive under the same assumptions.
The approach is straightforward. Compare the IRR of projects that claim the domestic bonus ITC while paying a CAPEX premium, against the IRR of projects that do not claim the adder and therefore do not pay that premium. Then plot IRR as a function of the premium.
To keep the analysis transparent and easy to follow, we can use a simple and generic project setup as a baseline. The snapshot below summarizes the key assumptions. It represents a small commercial-scale solar project with realistic production, pricing, operating costs, tax rates, and a standard 30-year lifetime. None of these inputs are meant to optimize the outcome. They are intentionally conservative and broadly representative, allowing the comparison to focus on the effect of the domestic premium and the ITC adder, rather than on aggressive assumptions.
One additional layer is important here. Premiums do not exist in a vacuum. Different project sizes have very different base capital costs due to economies of scale. Residential projects are typically much more expensive on a dollar‑per‑watt basis than commercial projects, which in turn are more expensive than utility‑scale projects.
To account for this, we can consider three representative cases. A residential‑scale project with a base CAPEX of 3 dollars per watt. A commercial‑scale project with a base CAPEX of 2 dollars per watt. And a utility‑scale project with a base CAPEX of 1 dollar per watt.
Results
With those assumptions in place, we can now look at the results.
The results are intuitive once you see them, but they are not always obvious beforehand.
Figure 1 – Residential-scale project ($3/W base CAPEX): IRR sensitivity to domestic equipment premium for a residential-scale solar project. Higher baseline CAPEX provides more flexibility, allowing the project to absorb a larger premium for domestic equipment while still benefiting from the 10 percent domestic ITC adder. The breakeven point occurs at a relatively high premium (54 UScents/W), indicating lower sensitivity compared to larger-scale projects.
Figure 2 – Commercial-scale project ($2/W base CAPEX): IRR versus domestic equipment premium for a commercial-scale solar project. Compared to residential systems, the margin for absorbing higher domestic premiums narrows. The domestic ITC adder remains beneficial over a moderate range of premiums, but the breakeven point is reached sooner (33 UScents/W) as each incremental cost has a more noticeable impact on returns.
Figure 3 – Utility-scale project ($1/W base CAPEX): IRR sensitivity for a utility-scale solar project with low base CAPEX. These projects are highly sensitive to domestic equipment premiums, with a relatively narrow range (13 UScents/W) where the ITC domestic bonus adder improves returns. Even small cost increases can quickly offset the incentive benefit.
Across all three cases, the baseline project with a standard 30 percent ITC shows a flat IRR. This is expected, since its capital cost does not change. The project claiming the domestic content adder, on the other hand, starts with a higher IRR thanks to the additional 10 percent ITC, but that advantage steadily erodes as the CAPEX premium for domestic equipment increases.
What differs materially between the three cases is how quickly that erosion happens.
For projects with a relatively high base CAPEX, such as residential-scale systems, the domestic premium is absorbed more easily. In these cases, the project has more bandwidth to pay extra for domestic equipment while still benefiting from the ITC adder. The breakeven point, where the IRR of the domestic-content project drops to match the baseline project, occurs at a relatively high premium. In practical terms, higher-cost projects are less sensitive to incremental increases in equipment pricing.
Put in simpler terms, for a homeowner this means there is room to pay meaningfully more for domestic equipment and still come out ahead. Based on these assumptions, a homeowner could pay up to roughly 53 cents per watt more for domestic equipment and still achieve a better return than with a standard 30 percent ITC project. Beyond that premium, the math flips. Using domestic equipment purely to claim the ITC adder stops being worth it, and the homeowner effectively starts losing money because the additional upfront cost outweighs the incentive benefit.
Commercial-scale projects sit somewhere in the middle. The domestic bonus ITC remains beneficial over a moderate range of premiums, but the window is narrower than in the residential case. As the base CAPEX decreases, each additional cent per watt paid for domestic equipment has a more noticeable impact on returns. The breakeven point arrives sooner, and the margin for error shrinks.
Utility-scale projects tell the most restrictive story. Because these projects start with very low base CAPEX, they are highly sensitive to any premium added on top. Even small increases in cost translate into meaningful IRR compression. As a result, the effective bandwidth where the domestic bonus ITC actually improves returns is relatively short. Beyond that narrow range, the premium outweighs the incentive, and the domestic-content project quickly becomes less attractive than the baseline alternative.
Taken together, the main takeaway is clear. The lower the base CAPEX of a project, the more sensitive it is to domestic equipment premiums, and the less effective the ITC domestic bonus adder becomes as a tool to offset higher costs. Utility-scale projects therefore face the tightest constraints, while residential projects, or projects with inherently higher capital intensity, have more flexibility to absorb premiums and still come out ahead.
This does not mean that domestic equipment never makes sense for large-scale projects. It simply means that the decision window is much narrower, and pricing discipline becomes critical. The bonus ITC is a powerful incentive, but it is not unlimited, and its effectiveness depends strongly on where a project sits on the cost curve.
Does electricity price change the picture?
A natural follow-up question is whether electricity rates, and therefore project revenues, materially change these conclusions. That is a very fair question, and it is something we can test directly in the model.
To explore this effect, we can look at a commercial-scale project with the same base CAPEX of 2 dollars per watt, but with higher revenues driven by a higher electricity rate. In this reference case, the electricity price is increased to 20 cents per kilowatt-hour instead of 10 cents per kilowatt-hour. As expected, higher revenues improve overall project returns, and the IRR levels across the curve shift upward.
Figure 4 – Commercial-scale project with higher electricity rates: IRR versus domestic equipment premium for a commercial-scale project assuming higher electricity revenues. While increased electricity prices shift overall returns upward, the project’s sensitivity to domestic equipment premiums changes only marginally. Higher revenues help, but they do not fundamentally alter the cost-benefit tradeoff of the domestic ITC adder.
What is more interesting, however, is what does not change very much. The sensitivity of the project to the domestic equipment premium remains largely the same. While higher electricity prices do make projects slightly less sensitive to CAPEX premiums, the shift is relatively slow. In other words, better revenues help, but they do not fundamentally reshape the tradeoff between the premium paid and the value of the ITC adder.
This observation has important implications when we scale up. Utility-scale projects typically assume electricity revenues in the range of 8 to 10 cents per kilowatt-hour, which is materially lower than what is common for commercial projects and significantly lower than residential retail rates. If anything, this means the earlier results are somewhat optimistic for large projects. In real-world conditions, each project type would likely be slightly more sensitive to domestic equipment premiums than shown.
Once again, the pattern reinforces itself. The larger the project and the lower its revenue per kilowatt-hour, the more sensitive it becomes to premiums paid for domestic components in order to claim the ITC domestic bonus adder.
Something To Keep In Mind
None of this should be read as a critique of domestic manufacturing or local supply chains. On the contrary, building domestic production capacity is critical for long-term energy security, supply chain resilience, and industrial policy goals. Those benefits are real, even if they are difficult to capture cleanly in a spreadsheet.
What this analysis tries to do is much narrower. At a purely financial level, and strictly on paper, it highlights the importance of cost-benefit thinking. Incentives matter, but they interact with project scale, base CAPEX, and revenues in very specific ways. Understanding where those interactions work in your favor, and where they stop, can make the difference between a project that quietly underperforms and one that is truly robust.
One important caveat is timing. The conclusions here rely on the current domestic content framework, which is not permanent. For projects that begin construction after June 2026, the rules change, and the specific conclusions in this article may no longer apply. The math, however, does not expire. The idea of comparing incentives against real cost premiums will remain relevant regardless of policy structure.
Looking ahead, battery projects are a natural next area to explore. Standalone storage remains eligible for the ITC beyond 2026, and the economics are driven by a different mix of costs, revenues, and incentives. That combination makes batteries a particularly interesting case for applying the same kind of framework.
For now, the takeaway is simple. Domestic content incentives are powerful tools, but they are not magic. They work best when they are paired with disciplined pricing and a clear understanding of project economics. And sometimes, the most useful insight comes not from asking whether an incentive exists, but from asking how far it can realistically take you.
Optional Reading Sources
Anza Solar Module Pricing Insights (quarterly report): https://www.anzarenewables.com/solar-module-pricing-insights/
IRS Domestic Content Bonus Credit (official): https://www.irs.gov/credits-deductions/domestic-content-bonus-credit?utm_source=chatgpt.com
IRA incentives fueling U.S. solar manufacturing surge: https://www.powermag.com/ira-incentives-fuel-u-s-solar-manufacturing-surge/?utm_source=chatgpt.com
Recent Module Price Data (Market): https://www.pv-tech.org/us-solar-module-prices-stabilise-us-0-28-w-november/?utm_source=chatgpt.com
The Watt Studio 
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