This is an extract from a recent report “US Solar Market Insight” by Wood Mackenzie and the SEIA. 

The US solar industry installed 10.8 GWdc of capacity in the first quarter of 2025. Despite both a quarterly and annual decline in capacity, Q1 2025 was the industry’s fourth-best quarter. The utility-scale segment followed a similar trend, with 9 GWdc of capacity, which is lower than both Q1 2024 and Q4 2024. However, Q1 2025 still ranks among the segment’s top quarters ever. Sixty-five percent of the quarterly utility-scale installations were concentrated in five states: Texas, Florida, Ohio, Indiana and California. The distributed solar segments showed mixed performances last quarter. Commercial solar grew by 4%, installing 486 MWdc, making it the only solar segment to increase compared to Q1 2024. California’s NEM 2.0 installations continued to fuel the commercial segment, with the state adding more than 200 MWdc in Q1. Community solar installations, however, dropped significantly to 244 MWdc after a massive fourth quarter. A net metering deadline in Maine led to a surge in installations at the end of 2024, followed by a dramatic drop in Q1. New York continued to lead the way for community solar installations with more than 100 MWdc. Residential solar installed capacity reached its lowest point since Q3 2021, with 1,106 MWdc added last quarter. While the first quarter typically sees slower residential installations, the segment continues to face numerous headwinds, including consumer hesitancy to go solar due to economic uncertainty, tariffs, and the availability of the residential solar investment tax credit (ITC). Overall, photovoltaic (PV) solar accounted for 69% of all new electricity-generating capacity additions in the first quarter of 2025, remaining the dominant form of new electricity-generating capacity in the US. 

The solar industry faces a perfect storm of Federal policy challenges 

The US solar industry faces significant policy headwinds due to multiple recent federal actions. The proposed House budget reconciliation bill, passed by the House on May 22, would, if enacted, eliminate the residential tax credits for both customer-owned and third-party owned lease projects starting in 2026. Section 48E (utility-scale, commercial & industrial, and community solar) projects would have to start construction within 60 days of enactment and be placed in service by the end of 2028 (or the end of 2025 for residential third-party financed systems). While this bill passed the House by one vote, it must now make it through the Senate, where any changes would require the House and Senate to work out a compromise. The change from “start of construction” to “placed in service” requirements for tax credit eligibility adds further complexity and risk for developers, as does the elimination of tax credit transferability after 2028. However, many of those points are largely moot, given the short timeline available to begin construction. Likewise, the bill cuts other funding, much of which spending freezes are already holding up. Furthermore, the executive order to “reinvigorate America’s beautiful clean coal industry” signals a stark pivot in federal energy priorities. By elevating fossil fuels and critical minerals while excluding solar, wind and storage from the definition of energy resources, this order aims to accelerate the production of coal, oil, natural gas and uranium. Such a reorientation of federal policy could redirect funding and regulatory support away from solar and towards conventional energy sources, though none of these actions are likely to remedy the gas turbine shortage over the next five years.

Trade-action whirlwind exacerbates uncertainty 

The US solar industry faces a complex and evolving trade landscape that will significantly impact development over the next five years. The flurry of recent trade actions, both industry-specific and non-industry-specific, is reshaping the economics of solar projects and supply chains. The Trump administration implemented significant trade policy changes in Q1 2025 by modifying and introducing new tariffs. Initially set to take effect in February, a 25% duty was imposed on imports from Canada and Mexico starting March 4, with exceptions for goods under the USMCA trade agreement and a 10% limit on Canadian energy resources and critical minerals. Modifications to Section 232 duties on all imports of steel and aluminum articles followed this action. The new scope of Section 232 removed country exemptions and terminated the exclusion process for steel and aluminum imports; it also equalized the aluminum tariff rate by increasing the duty from 10% to 25% (most recently increased to 50% on June 4). Although the US solar industry doesn’t materially import assembled equipment from Canada or Mexico, these tariffs have an indirect impact on the sector. Some components used in the production of inverters and trackers are sourced from these countries, effectively raising production costs for US manufacturers. Notably, despite the US solar industry’s reliance on domestically produced steel, market forces triggered an immediate increase in the domestic steel index. This unexpected rise has increased the production costs of tracker manufacturers, potentially affecting project economics. Additionally, US module manufacturers face increased frame costs.

While the US solar industry doesn’t significantly rely on equipment imports from China, the frequent tariff adjustments have introduced considerable uncertainty into the market. The growth of the solar industry also depends on the development of storage resources. Swings in tariff policy toward China introduce volatility to storage costs, due to China’s significant share of the battery manufacturing market. This turbulence may impact supply chain strategies, potentially influencing sourcing decisions and risk assessments for developers and investors. In particular, domestic manufacturers may have to pay increased costs for specific manufacturing equipment and components that are difficult to source from outside China.  Adding to this complexity, on April 20, the Department of Commerce (DOC) issued its final determination in the anti-dumping and countervailing duties (AD/CVD) investigation on solar cells and modules. The ruling set cumulative duty rates ranging between 14.64% and 3,500% for manufacturers from Cambodia, Malaysia, Thailand, and Vietnam (CMTV), exceeding the preliminary determination levels. This decision has introduced significant uncertainty for developers who have historically relied on imports from these countries.

On May 20, the International Trade Commission issued a final affirmative injury decision. It will trigger a resumption of AD/CVD duty collection at final rates when the Federal Register publishes the final ITC report. Although the final decision was only recently issued, there have been some shifts in solar imports. Specifically, module import patterns have already started to change, while cell import trends have yet to undergo significant shifts. Module imports from CMTV have plummeted from an average of 3.8 GW per month in 2024 to an average of 1.1 GW per month in Q1 2025. Module imports from Cambodia, whose mandatory respondents withdrew from participation in the AD investigation and received the highest company-specific and country-wide AD/CVD rates, have dropped to 0 GW in 2025. Concurrently, an increased presence of alternative sourcing locations in the US module import mix was observed. For example, the share of module imports from Indonesia and Laos has grown to 34.6% in Q1 2025. The solar industry continues to be nimble, but the rapid proliferation of trade action poses potential challenges in maintaining a steady supply and managing costs. State-level initiatives and corporate demand will gain more relevance in driving solar growth, partially offsetting federal headwinds. The industry’s ability to adapt to this shifting policy terrain will be crucial in determining the pace of US solar deployment through 2030 and beyond.

Distributed solar-plus-storage

Solar-plus-storage accounted for 38% of residential solar installations in Q1 2025 (up from 32% in Q4 2024). Solar-plus-storage accounted for 6% of non-residential solar installations in Q1 2025, including commercial and community solar, (comparable to Q4 2024). California and Puerto Rico dominated the market, accounting for 54% and 29% of national installations, respectively. Residential solar-plus-storage installers are preparing for battery price volatility due to tariffs imposed on China. After Liberation Day, residential battery prices increased by 10-15%. Despite recent adjustments in tariffs, both the duties themselves and the uncertainty surrounding implementation introduce risk to the market. Some installers and financiers with strong balance sheets have managed to secure a supply, but others have not been able to do so. Supply constraints have also limited growth in the residential solar-plus-storage market. Installers have reported Powerwall shortages since Q3 2024. Tariff uncertainty may extend these constraints to other battery manufacturers, potentially dampening a pull-in of demand, caused by the possible elimination of the residential investment tax credit.

Residential PV

In Q1 2025, the residential solar market added 1,106 MWdc, declining 13% year-over-year and 4% quarter-over-quarter. Compared to Q1 2024, 22 states experienced drops in installed capacity. California continued to lead the residential solar state capacity rankings with 255 MWdc despite experiencing its lowest quarter since 2020. Puerto Rico and Florida followed, rounding out the top three markets. Challenging market conditions continue to plague the segment, with some installers describing this time as unprecedented turmoil. The residential solar market faces significant uncertainty in 2025, grappling with supply chain challenges due to tariffs, the potential elimination of tax credits, and continued high interest rates. These combined headwinds are a perfect storm and unchartered territory for the residential segment, resulting in a more challenging value proposition. On top of low demand, some installers are confronting additional challenges in customer acquisition (besides the high cost). The House reconciliation bill’s proposed provisions present a major downside risk, including the elimination of the tax credits under Section 25D for customer-owned solar and Section 48E for TPO leased systems. If this aspect of the bill moves forward, a market contraction would follow, resulting in a significantly smaller residential solar market than currently projected. 

Commercial PV

The commercial solar market reached its highest first quarter of installation capacity on record in Q1 2025. The segment added 486 MWdc, a 4% year-over-year increase. Installations declined by 28% compared to last quarter, reflecting the typical difference between the year-end Q4 rush and regular Q1 new capacity. The surge in unprecedented Q1 growth was largely driven by the lasting wave of NEM 2.0 installations in California. In congested state markets like New York and Illinois, developers are advancing their current project pipelines. However, maintaining the present rate of installation growth will not be feasible in the long term without significant interconnection enhancements. Massachusetts is an example of a state that had a weaker Q1 2025, with only 2.9 MWdc installed, a 66% year-over-year decline. Amid federal policy uncertainty, developers are pushing forward with projects to maintain pipeline momentum and operational continuity. Growing concerns within the industry about the potential discontinuation of the transferability market are beginning to impact deal flow and negotiations. Smaller-scale commercial projects may face greater challenges in establishing safeguards.

Community solar PV

Community solar installations declined 22% year-over-year in Q1 2025, resulting in 244 MWdc of new capacity. Five out of 15 state markets experienced quarterly declines compared to Q1 2024. Massachusetts and New Jersey saw particularly sharp drops, with installed capacity falling by 78% and 98% year-over-year, respectively. In Maine, capacity plummeted 85% year-over-year, confirming the expected drop-off following the Net Energy Billing incentive deadline in December 2024. New volumes in New York also declined slightly, yet the state continues to command 52% of the total market. Community solar capacity under development and construction significantly exceeds near-term outlook. Developer surveys and project-level data reveal a national pipeline of around 7.5 GWdc in the 15 state markets Wood Mackenzie currently forecast. New York and Illinois alone have a community solar pipeline totaling nearly 5 GWdc as of Q1 2025. However, due to lengthy interconnection studies and grid upgrades, only a fraction of that capacity is expected to come online each year. The pipeline is more than double the 3 GWdc expected to come online by the end of 2026. In addition to grid upgrades, the cyclical nature of community solar incentive programs poses a key obstacle to efficient interconnection. Program administrators process hundreds of new applications simultaneously when new capacity blocks are released, inevitably leading to delays. This is consistently true in states with newer programs, such as Delaware, Virginia, and New Mexico. Despite longer project timelines, pipelines in key community solar state markets remain healthy, supporting the market’s health through five-year outlook. Stakeholders continue to advocate for interconnection reform to help alleviate backlogs in the current pipeline.

Utility PV

The utility-scale sector installed 9.0 GWdc of projects in Q1 2025, representing a 7% decline year-over-year. The top five states with the largest installations include Texas, Florida, Ohio, Indiana, and California, making up over 65% of total installations this quarter. Contracted projects reached 5.7 GWdc in Q1 2025, a 2% increase year-over-year. Large technology corporate buyers including Meta, Amazon, and Verizon secured 55% of the contracted projects in Q1 2025 to support their growing energy needs and clean energy goals. The bulk of projects with corporate off-takers were in Texas, with the highest activity coming from Meta’s PPA contracts.

National solar PV system pricing

In Q1 2025, US solar PV system prices showed mixed trends across segments. Residential prices remained stable at $3.36/Wdc, despite a 3% increase in inverter costs as market share shifts to domestic module-level power electronics (MLPE). Commercial system prices rose 1% quarter-on-quarter to $1.47/Wdc, driven by higher structural balance-of-system costs and module prices and partially mitigated by lower inverter prices and stable labor costs. Module costs increased by an average of 3% in Q1 2025 across all segments following the DOC’s preliminary determination in the AD/CVD investigation on PV cells and modules from Cambodia, Malaysia, Thailand, and Vietnam in Q4 2024. Utility-scale system prices saw greater increases, with fixed-tilt and single-axis tracking systems rising 3% and 4% quarter-over-quarter to $1.08/Wdc and $1.23/Wdc, respectively. Engineering procurement and construction companies (EPC) faced challenges including labor shortages, extended lead times, and tariff uncertainties, leading to a 20% surge in overhead and margin costs. The adoption of Tunnel Oxide Passivated Contact (TOPCon) modules helps offset some of the cost increases through higher efficiencies, providing savings on labor and balance of plant equipment. 

Access the report here