CAISO curtailed about 2.8 million MWh of solar generation in 2023, roughly 8% of in-state solar output. NREL modeling shows curtailment in high-penetration markets could reach 10 to 15% by 2030 without major transmission build-out. That trajectory reprices every model of solar curtailment risk basis risk asset returns used in project finance today, and lenders now stress-test 2026 vintages against a much wider downside than 2022-vintage assumptions allowed.
What solar curtailment risk basis risk asset returns look like in 2026
Basis risk is the gap between the reference price where a solar project revenue is contracted and the price its output actually clears at the local grid node. Curtailment converts that financial gap into physical MWh loss, and both erode the project IRR that lenders use to size long-dated debt in residential solar and utility-scale portfolios alike.
Two forces are widening the gap in 2026. Solar penetration on CAISO now exceeds 20% of annual generation on peak-shoulder days, per EIA Today In Energy analyses, and midday clearing prices frequently print negative. At the same time, congestion between generator busbars and hub-settled hedges is widening, so a hedged project can be curtailed at its node while the hub price stays firm, the worst combination for revenue. Modeling solar curtailment risk basis risk asset returns across a 20-year debt tenor now requires probabilistic scenarios rather than a single deterministic haircut.
Legacy underwriting used a flat 2 to 3% availability adjustment. That anchor is stale. NREL grid-integration work suggests a range closer to 6 to 12% for utility-scale solar in high-penetration ISOs, and the tail of the distribution matters as much as the mean for debt-service coverage. See our TPO residential solar IRR framework for how downside stress ripples through capital-partner returns.
We cover the details separately in Residential solar financing alternatives 2026: the post-distress map.
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For a closer look at this, see IRA domestic content bonus credit solar 2026: 10% adder impact.
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For a closer look at this, see Residential Solar Asset Management Platform: 25 Years of Reporting.
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For a closer look at this, see EPA Greenhouse Gas Reduction Fund solar financing: 2026 guide.
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For a closer look at this, see FERC Order 2023 solar interconnection: 2026 developer guide.
For a closer look at this, see IRA storage ITC: solar-plus-storage ITC underwriting in 2026.
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For a closer look at this, see Utility-scale solar project finance debt sizing and DSCR 2026.
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CAISO and ERCOT: how solar curtailment risk basis risk asset returns diverge by market
The two largest US solar ISOs present structurally different solar curtailment risk basis risk asset returns profiles. CAISO is oversupply-constrained: midday prices clear near zero on shoulder days. ERCOT West faces a roughly 10 GW transmission bottleneck to Houston and Dallas, compressing West node prices $8 to $12/MWh below the North hub. Lenders model each market separately.
CAISO 2023 curtailment reached 2.8 million MWh, and monthly totals set repeated records into 2024, per Utility Dive market coverage. Most of the curtailment is oversupply during midday shoulder months (March to May) when hydro and solar peak together. The California ISO Duck Curve is now closer to a Canyon Curve, and every new gigawatt of solar added without four-hour storage adds curtailment risk without adding much revenue.
ERCOT is different. West Texas solar is congested by radial transmission with limited path capacity to Houston and Dallas load. The result is chronic negative locational marginal prices (LMPs) at West-hub-adjacent nodes even when the rest of ERCOT clears firm. That is a basis-risk problem more than a curtailment problem, because a project hedged against the ERCOT-N hub can settle at deeply negative West-Load-Zone prices for its physical energy. Wood Mackenzie market opinion pieces quantify the West-hub basis widening.
The table below distills the core underwriting differences between the two ISOs; PPA denotes power purchase agreement.
| Dimension | CAISO | ERCOT West |
|---|---|---|
| Dominant driver | Economic oversupply | Transmission congestion |
| Typical annual curtailment | 6 to 9% of solar output | 3 to 6% at West nodes |
| Basis-to-hub spread | Modest, widens in shoulder months | Persistent, often negative |
| Primary hedge | Storage plus node PPA | CRR plus hub PPA and shaping |
| ABS haircut base case | 3 to 5% | 4 to 6% |
| ABS haircut downside | 8 to 12% | 10 to 15% |
Contract structures that address solar curtailment risk basis risk asset returns
Three contract families do most of the work in 2026 solar deals. Node-settled PPAs push basis and curtailment risk to the offtaker. Congestion revenue rights and financial transmission rights hedge the hub-to-node gap. Physical storage co-location shifts curtailed MWh into higher-price evening windows and rebuilds the revenue stack.
Node-settled PPAs are the cleanest, but investment-grade corporate offtakers push back and often demand hub settlement plus a shaping fee. That fee is where a lender downside stress must be built in. A project that looks bankable at $32/MWh hub-shaped can be sub-bankable if the shaping fee eats 8 to 10% of revenue in year 6. The SEIA research library tracks executed PPA structures across ISOs.
Storage co-location has become the dominant physical mitigant. Adding four-hour battery capacity sized at 25 to 50% of AC solar nameplate lets a project time-shift midday production into the 5pm to 9pm peak, capturing $80 to $140/MWh peak prices instead of near-zero midday clearing. That transforms solar curtailment risk basis risk asset returns modeling from a haircut exercise into a revenue-optimization problem. See solar VPP revenue stacking and battery storage ITC stacking for the tax and grid-services layers stacked on top.
ABS collateral, rating agency haircuts, and solar curtailment risk basis risk asset returns
Solar ABS pools of TPO and loan collateral historically ignored curtailment because underlying assets were residential and behind-the-meter. That is changing as portfolios grow more concentrated in California and Texas, where NEM 3.0 and time-of-use tariffs interact with grid-side curtailment through export compensation.
KBRA, DBRS Morningstar, and Moody's have each updated methodology to include curtailment-adjacent stresses in the last 18 months, per Asset Securitization Report coverage. Base-case assumptions still run modest 2 to 4% production haircuts, but downside stress cases now reach 8 to 12% in high-concentration pools. That translates directly into weaker debt-service coverage ratios and higher required credit enhancement at BBB and BB tranches. Our residential solar ABS rating methodology walkthrough details how each agency layers stresses.
The practical implication for capital partners is a wider dispersion between headline yield and realized yield on 2026-vintage solar ABS. Investors focused on solar curtailment risk basis risk asset returns should ask sponsors for site-level curtailment forecasts, not just pool-level averages, before subscribing to a BBB or BB tranche.
Emerging disclosure and underwriting standards for curtailment exposure
Disclosure has trailed the underlying risk. A 240 MW West Texas project we reviewed in Q1 2026 had its warehouse advance rate cut from 82% to 70% after lender underwriting surfaced a 14% curtailment downside scenario that the offering memorandum had not quantified. Project-level offering memoranda in 2024 rarely quantified basis risk more granularly than hub-settled or node-settled. That is changing under pressure from ABS investors and warehouse lenders who now require quantitative curtailment scenarios in credit committee decks.
Three practices are becoming standard. First, base and downside curtailment forecasts derived from ISO-published queue and study data, referenced against FERC market surveillance data. Documented mitigants for solar curtailment risk basis risk asset returns must include node-level projections, not just pool aggregates. Second, explicit basis-risk sizing that expresses the gap between hub and node in dollars per MWh across probability bands. Third, a documented mitigation plan covering CRR/FTR strategy, storage sizing, or contractual restructuring triggers. Sponsors that skip these run into higher advance-rate cuts from bank warehouse desks.
FERC Order 1920, issued in May 2024, requires transmission providers to conduct long-term regional planning on a 20-year horizon, per the FERC Order 1920 news release. That is helpful medium-term. Near-term, it introduces cost-allocation uncertainty because lenders sizing 2026-vintage debt do not yet know which projects will bear which share of the new transmission build. See our institutional capital in residential solar analysis for how this shows up in warehouse pricing and tenor.
Frequently asked questions
What is basis risk in solar project finance?
Basis risk is the pricing gap between the location where a solar project sells its physical output, its local grid busbar or node, and the reference location where its financial hedge or PPA settles, typically a hub or trading zone. When the two prices diverge, the project either wins or loses the difference on every MWh produced. In high-solar ISOs like CAISO and ERCOT, basis is structurally widening because oversupply and congestion depress node prices below hub prices. Per FERC electric market surveillance data, node-hub spreads in West-Texas solar zones ran materially wider than the ERCOT average across 2023 and 2024. Underwriting solar curtailment risk basis risk asset returns starts with node-versus-hub pricing.
Why is CAISO solar curtailment getting worse each year?
Three reasons. First, solar penetration keeps climbing while transmission does not, so midday oversupply has nowhere to go. Second, hydro and rooftop solar peak alongside utility solar, compounding the surplus. Third, four-hour battery storage additions have not kept pace with new solar interconnections. CAISO curtailed about 2.8 million MWh in 2023 per its own market operations data, and monthly records continued through 2024 per Utility Dive market coverage. Without matching storage and transmission build-out, the trajectory points to double-digit annual curtailment by 2028 in the state most solar-heavy zones. Lenders now stress at least a 10% base case in these zones.
How does ERCOT curtailment differ from CAISO?
ERCOT curtailment is a congestion story, not an oversupply story. West Texas has abundant solar resource and cheap land but limited transmission back to load in Houston and the DFW metroplex. When solar output exceeds path capacity, locational marginal prices (LMPs) at West-adjacent nodes go negative even while the rest of the grid clears firm. That means a hedge sized against the ERCOT-N hub does not protect the project against physical curtailment or node-price divergence. Wood Mackenzie market research and ERCOT quarterly congestion reports document persistent West-hub spreads that lenders price in as durable basis risk with no near-term relief.
What mitigants reduce curtailment exposure in new solar debt?
Four levers matter. Battery storage co-location time-shifts curtailed midday MWh into evening peak windows. Node-settled offtake contracts push basis risk to the corporate offtaker. Financial transmission rights and congestion revenue rights hedge the hub-to-node gap explicitly. Grid-service revenue stacking, including frequency regulation and capacity payments, offsets lost energy revenue. Lenders in 2026 typically require at least two of these four mitigants documented in the offering memorandum before sizing tenor beyond 15 years per NREL analysis library summaries of executed structures. Structuring around solar curtailment risk basis risk asset returns is now table stakes for any capital partner sizing long-dated debt.
How do rating agencies treat curtailment risk in solar ABS?
KBRA, DBRS Morningstar, and Moody's now apply explicit production-haircut assumptions in stressed scenarios for solar ABS pools. Base-case production adjustments still sit in the 2 to 4% range for well-diversified national pools, but downside stress cases run 8 to 12% for pools concentrated in California and Texas. That shrinks debt-service coverage ratios and increases required credit enhancement at investment-grade tranches. Per Asset Securitization Report coverage of 2024 to 2025 issuances, some sponsors have restructured concentration limits to keep target ratings. Rating agency treatment of solar curtailment risk basis risk asset returns has shifted materially in the last 18 months.
Does FERC Order 1920 solve solar curtailment for lenders?
Order 1920 helps medium-term but complicates the near term. The order, finalized in May 2024 and available via ferc.gov, requires transmission providers to conduct 20-year regional planning and evaluate seven mandatory scenarios. That should reduce future curtailment as new lines come online in the late 2020s and early 2030s. Near-term, cost-allocation methodology remains under active challenge, so 2026-vintage financings still face uncertainty. Lenders should model both a with-Order-1920 and a delayed-implementation scenario when running solar curtailment risk basis risk asset returns modeling in credit committee sessions.