Where Projects Stall: The Solar and Storage Bottlenecks That Got Worse

Two years ago, a developer asked where its utility-scale solar or battery project was most likely to stall would have given the same answer on both sides of the Atlantic: the interconnection queue. That answer no longer holds in the United States, and in Europe it understates the problem.

This first part of our series looks at six constraints on utility-scale solar and storage development — interconnection, permitting, equipment and trade, tax-credit qualification, construction cost, and financing and revenue — and asks which have deteriorated most since late 2024. Parts 2 to 4 follow the consequences through to asset sales, pipeline valuation and the decision to hold rather than sell.

Scorecard: what got worse, and where

Odette assessment of direction of change from Q4 2024 to Q4 2026, based on the sources cited below.

United States

Permission, not the queue, became the binding constraint

The largest new obstacle for U.S. developers is federal permission. A July 15, 2025 Interior Department directive requires the Secretary’s personal sign-off on nearly 70 permit and action types for solar and wind. A secretarial order in August 2025 added a “capacity density” test, and in September 2025 the Army Corps deprioritised Clean Water Act Section 404 permits for both technologies. Any project with a federal nexus — public land, a wetlands permit, a protected-species consultation — now runs through that process.

The effect has been close to a freeze. Only one renewable project on Bureau of Land Management land advanced between July 2025 and January 2026. By July 2026, SEIA counted 445 solar and storage projects totalling 97 GW at risk from the review regime. A federal court enjoined the five Interior and Army Corps actions on April 21, 2026, but the injunction covers only the plaintiffs and their members, and Interior has said it will appeal.

Local opposition is adding to the attrition rather than replacing it. Columbia’s Sabin Center counts 888 state and local restrictions on renewable projects. Contested projects totalling about 9.8 GW were cancelled in 2025, three times the previous annual high, although the pace of new local restrictions has slowed since 2023.

The tax credit is now a compliance exercise

The One Big Beautiful Bill Act, signed July 4, 2025, required wind and solar projects to begin construction by July 4, 2026, or be placed in service by the end of 2027, to claim the technology-neutral credits. Treasury then tightened what “begin construction” meant, before a court reversed it weeks before the deadline.

The near-term build is protected. Wood Mackenzie estimates that 216–240 GWdc of utility-scale solar was safe-harboured between mid-2024 and the deadline, and SEIA and Wood Mackenzie expect safe-harboured pipelines to support about 44 GW of installations a year through 2030. The pressure falls on what comes after: solar projects that did not start in time, and storage projects that must now prove their supply chain.

For storage, the foreign-entity rules have become the main cost driver. Anza estimates that FEOC-compliant battery systems carry a premium of $70–80/kWh, and up to $150–200/kWh for some configurations, and some developers are choosing to forgo the investment tax credit rather than comply. The credits themselves have also lost value. Transfer volumes fell 12.5% year on year to $21 billion in the first half of 2026, and investment tax credits for solar and storage now trade at 90–93 cents on the dollar, with technology-neutral credits at 88–91 cents.

Equipment and construction: higher costs, higher floor

U.S. projects pay a structural premium for equipment, and trade policy is raising the floor. Final anti-dumping and countervailing duty determinations on cells and modules from India, Indonesia and Laos, issued on September 11, 2026, set combined rates as high as 268%. The Section 232 polysilicon proclamation adds a 15% tariff and minimum import prices from December 4. Module prices are already high: Anza’s Q1 2026 U.S. median was $0.28/W, and $0.46/W for modules built with U.S.-made cells.

Tariff policy also remains unsettled. The Supreme Court struck down the IEEPA-based tariffs on February 20, 2026. A temporary 10% tariff under Section 122 replaced them, the President announced plans to raise it to 15%, and further action under Sections 232 and 301 has been signalled. For imported Chinese battery systems, the all-in tariff stack is therefore uncertain, and developers are pricing that uncertainty into procurement.

Balance-of-system costs are rising too. SEIA and Wood Mackenzie put single-axis tracker system prices at $1.06/W in Q2 2026, up 2% year on year even though modules got cheaper, with logistics costs up about 15% on higher oil and gas prices. Lead times are about 128 weeks for power transformers and 144 weeks for generator step-up units, and power transformer prices are up 77% since 2019.

Interconnection: chronic, not newly worse

The U.S. queue has passed its peak. Berkeley Lab’s Queued Up 2026 counts 2,061 GW of active requests at the end of 2025, down 10% on the year, after more than 750 GW withdrew. But time to market keeps lengthening: the median project now waits more than five years from request to commercial operation. The mix is also shifting away from solar. Queued solar fell 19% in 2025, while queued gas rose 86%.

Financing and revenue: the late-breaking deterioration

Until mid-2026 the financing story was benign. Construction loans priced around SOFR plus 150 basis points, and Norton Rose Fulbright reported spreads about 12.5 basis points tighter year on year going into 2026. The change has come through base rates. The Federal Reserve raised its target range by 25 basis points to 3.75–4.00% on September 16, 2026, its first increase since 2023, and the 10-year Treasury yield stood above 5.2% in mid-October.

Revenue risk is concentrated in merchant storage. ERCOT shows what happens when a fast-growing battery fleet meets a thin ancillary services market. Revenues fell 85% in two years as batteries moved into energy arbitrage. Solar PPA prices are also softening: LevelTen’s North American solar index fell 4.8% quarter on quarter in Q2 2026, to $61.40/MWh, its first fall in two years.

Europe

The queue has become a cap

In Europe the grid is no longer a waiting line that projects move through, slowly. In the busiest markets there is simply no capacity left to allocate.

A widely quoted figure of 1,700 GW for Europe’s total grid backlog has no identifiable primary source. Ember’s more conservative count is almost 700 GW of renewables in connection queues across eight reporting countries, plus more than 340 GW across eleven countries that holds agreements but is not yet online.

Revenue: a crowded grid pays less

Where the grid is full of solar, solar earns less. Spain recorded 397 hours of negative wholesale prices in the first quarter of 2026 alone, compared with 48 in the same quarter of 2025 and 555 in the whole of 2025. Spain does not compensate technical curtailment. In Germany, solar captured 29.7% of the average market price in May 2025, a record low, and new German PV earns no feed-in support in any interval with a negative price.

The contract market has moved accordingly. Pexapark reports that standalone solar PPA volumes fell 42% in the first half of 2026, while flexibility contracts such as battery tolls and revenue floors rose 182%. In Spain, DLA Piper reports lenders facing coverage-ratio breaches and cash lock-ups, and renewable M&A deal count fell 30% in 2025.

Batteries are not immune. German battery revenue was €191k/MW-year in August 2026, 15% below a year earlier, as secondary reserve (aFRR) capacity prices fell by about half. Lenders now haircut merchant revenue forecasts by up to 30% and push for tolls or floors, and a draft regulatory proposal of August 2026 would add a grid fee of about €5/kW-year for batteries that miss grandfathering. Where storage is contracted, prices are competitive: Italy’s first MACSE auction awarded 10 GWh at an average €12,959/MWh-year, about a third of the reserve price.

Rates have risen here too. The ECB raised its deposit rate in June and again in September 2026, to 2.50%, and the 10-year Bund reached 3.55% on September 16, its highest since 2009.

What is not the problem in Europe

Two constraints that dominate the U.S. debate matter less in Europe. Permitting is slow but is not the scarce input: in Spain, Italy and Poland the queue problem is too many permitted or speculative projects, not too few permits. EU-mandated renewables acceleration areas are behind schedule, with none of eleven member states tracked by CAN Europe having designated them ahead of the February 2026 deadline.

Equipment has become cheaper. BloombergNEF’s turnkey storage system price for Europe fell from about $275/kWh in its 2024 survey to $177/kWh in 2025. Module prices rose in 2026 from record lows after China removed its export VAT rebate on April 1 and silver prices climbed, with the pvXchange high-efficiency index up from €0.115/Wp in January to €0.150/Wp in May, but that does not change the direction of travel.

What it means for valuation and M&A

The bottlenecks that worsened most are the ones buyers now underwrite first. In the U.S., value has concentrated in projects that are permitted, safe-harboured and hold signed interconnection agreements; solar projects starting construction after the deadline carry a policy discount. In Europe, the grid connection itself has become the scarce asset, and a firm connection date before 2030 is often worth more than the project’s other attributes combined. Part 2 looks at what buyers are paying for each.

Data as of October 15, 2026. Figures are from the public sources listed below; where sources conflict, we use the more conservative figure. Market characterisations are directional and change with each rule cycle and court decision. This piece is for informational purposes only and does not constitute investment, tax or legal advice.