Module degradation can quietly erode the energy yield and financial performance of commercial solar assets. This report distils a decade of field data to explain typical degradation rates, key drivers and what asset owners should realistically build into their models for rooftop and ground-mounted systems.
At Energy Solutions, we see module degradation as a second-order risk with first-order consequences for long-lived portfolios. Annual loss rates that look small on paper—0.4 % vs 0.7 %—can compound into material differences in cash flow and valuation, especially when combined with soiling, downtime and curtailment.
Degradation is often compressed into a single line in investment models: a fixed annual percentage loss applied to production. In reality, performance loss unfolds as a combination of early stabilisation effects, gradual wear-out and occasional step changes from equipment issues. The timing of these effects influences not just lifetime yield but also debt sizing, covenant headroom and hedge effectiveness.
For corporate offtakers entering 10–20 year PPAs or owning systems directly, using an overly optimistic degradation assumption risks underestimating variance in future energy costs. Conversely, excessively conservative assumptions may cause promising projects to be rejected. The goal is not to pick the most pessimistic number, but to align assumptions with technology vintage, site conditions and operational practices.
"Degradation" can refer to several related but distinct concepts: loss of module power under standard test conditions, loss of system-level performance ratio, or trend in normalised yield after adjusting for irradiance and temperature. Each lens reveals different aspects of asset health and is measured using differing datasets and tools.
Asset owners should be clear which metric is being used when benchmarking plants or comparing suppliers. Module power degradation measured in a lab does not directly translate to kWh at the meter, and short-term weather anomalies can mask or exaggerate underlying trends. Consistent methodologies and time windows are essential to avoid spurious conclusions.
Large datasets from utility and commercial plants built in the last decade suggest that median degradation rates for crystalline silicon modules have improved compared with earlier generations. Many well-installed systems cluster around 0.3–0.6 % per year, with tails extending higher for projects in hot, humid or highly irradiated climates, or those affected by specific failure modes such as backsheet cracking or potential-induced degradation.
However, spread matters as much as the median. Within a single portfolio of ostensibly similar assets, some plants exhibit negligible degradation while others underperform expectations by multiple percentage points. Differences in component selection, installation quality and O&M responsiveness all play a role. For corporate owners, this variability argues for project-specific assessment rather than assuming a fleet-wide constant rate.
| Context | Example Sites | Typical Range (%/year) | Comments |
|---|---|---|---|
| Temperate, well-designed | Rooftops in mild climates with good ventilation | 0.3–0.5 | Aligns with many modern portfolios; assumptions often used in investment cases. |
| Hot and dry | Desert or semi-arid ground mounts | 0.5–0.8 | Higher thermal stress and soiling risk; design and O&M practices are critical. |
| Humid and coastal | Coastal rooftops or high-humidity regions | 0.5–0.9 | Moisture ingress and corrosion risks increase dispersion in outcomes. |
| Early-generation or stressed assets | Older plants or those with known component issues | 0.8–1.5 | May show specific failure modes rather than smooth degradation trends. |
Qualitative comparison of median annual degradation in different climates and asset vintages.
Source: Energy Solutions synthesis of public field studies and portfolio benchmarks; values are indicative only.
Degradation is accelerated by a combination of environmental stressors—UV exposure, temperature cycling, humidity, mechanical loads—and design decisions such as mounting configuration, ventilation and cable management. Systems operating in desert or tropical climates typically experience higher rates than those in mild, coastal environments, even when using similar module technologies.
Design choices that reduce operating temperatures, limit moisture ingress and minimise mechanical stress can materially influence long-term performance. Simple details, such as avoiding shading from parapets, ensuring adequate drainage on flat roofs and managing cable strain relief, can reduce the likelihood of hotspots, insulation damage and connector failures that manifest as step changes in performance.
Modern performance warranties often quote linear degradation limits—such as 2–3 % in the first year followed by 0.4–0.6 % per year thereafter. These figures can be misread as predictions rather than thresholds beyond which a claim may be considered. In practice, proving that an observed shortfall is due to module degradation rather than other factors can be time-consuming and requires careful testing.
Warranty enforcement also involves logistics: shipping modules for lab testing, coordinating plant downtime and navigating evidentiary requirements. As a result, many owners treat warranties as a backstop for severe, systemic issues rather than as a tool for fine-tuning portfolio performance. This makes it even more important to set realistic expectations up front and to focus on preventive measures.
Financial models typically apply a single annual degradation rate to net generation. A more nuanced approach distinguishes between module-related degradation and other performance losses, and may model early-year stabilisation separately from long-run wear-out. Sensitivity analysis around degradation assumptions can highlight how robust a project's economics are to uncertainty in long-term performance.
For corporate buyers using solar to hedge electricity costs, degradation interacts with tariff structures and escalation assumptions. Lower-than-expected output may modestly raise effective unit costs but could still leave projects deeply in-the-money relative to grid prices. The key is to test portfolios against a range of credible scenarios rather than a single central case.
| Assumed Annual Degradation | Approximate Output After 10 Years | Cumulative Loss vs. No Degradation | Qualitative Financial Impact |
|---|---|---|---|
| 0.3 % | ~97 % of year-one output | ~3 % | Typically manageable within debt and hedge structures. |
| 0.5 % | ~95 % of year-one output | ~5 % | Common central case for modern assets. |
| 0.8 % | ~93 % of year-one output | ~7 % | May start to affect DSCR and equity returns in tighter structures. |
| 1.0 % | ~90 % of year-one output | ~10 % | Material for projects with thin margins or short PPA tails. |
Indicative percentage of initial output remaining after 10 years under different annual degradation assumptions.
Source: Energy Solutions scenario analysis; values are rounded and illustrative.
Robust monitoring is essential to distinguish gradual degradation from operational issues that can be addressed through maintenance. High-resolution data, combined with normalisation for weather and grid events, allows owners to detect abnormal trends early. Periodic on-site testing—IV curves, thermography, insulation resistance—can then be used to pinpoint root causes.
When underperformance is material, forensic analysis can inform negotiations with suppliers and insurers as well as internal design standards for future projects. Even if no claim is pursued, insights into which components, configurations or contractors correlate with higher degradation can improve procurement decisions across a portfolio.
At portfolio scale, degradation shapes not just energy yields but also refinancing options, covenant compliance and how investors perceive risk. Aggregated fleets of small rooftop systems can be particularly sensitive: individual sites may be too small to justify intensive investigation, yet collectively their performance moves corporate emissions and cost trajectories.
Corporates that report against science-based targets or internal carbon prices have an additional layer of exposure. If realised performance falls systematically short of modelled trajectories due to unrecognised degradation, gaps may need to be filled through additional procurement or offsets. Treating degradation as a managed variable rather than a fixed input helps avoid these surprises.
| Portfolio Type | Characteristics | Sensitivity to Degradation |
|---|---|---|
| Single flagship asset | Large plant, long-term PPA, strong monitoring | High focus on the asset, but easier to diagnose and manage. |
| Distributed rooftop fleet | Dozens of small sites, mixed designs and owners | High aggregation risk; small deviations per site can add up materially. |
| Mixed technology portfolio | Different module types and vintages | Requires differentiated assumptions and monitoring approaches. |
Qualitative view of how sensitive different portfolio archetypes are to underestimating degradation.
Source: Energy Solutions judgement based on observed portfolio behaviour; scores are qualitative.
Managing degradation risk starts at the design and procurement stage: selecting components with proven field histories, ensuring appropriate testing regimes and aligning EPC incentives with long-term performance. Contract structures can embed expectations around monitoring quality, data access and response times when issues are detected.
During operations, disciplined O&M, targeted cleaning, periodic inspections and benchmark comparisons across the portfolio all contribute to keeping assets on track. Where degradation is higher than expected but still within warranty limits, owners may choose to implement mitigation measures—such as selective repowering—rather than relying solely on lengthy claim processes.
The questions below reflect recurring themes in conversations with asset owners, lenders and corporate energy buyers. They are intended to clarify typical expectations rather than prescribe a single "correct" assumption for every project.
Many portfolios use 0.4–0.6 % per year for modern crystalline silicon modules in temperate climates, with higher values in harsher environments. The right number for a specific project should reflect technology, location, design and operating practices.
Some technologies exhibit an initial stabilisation or "light-induced degradation" effect in the first year, after which rates settle. Warranties often reflect this through a slightly larger first-year allowance followed by a lower linear rate. Models can mirror this pattern where data support it.
Warranties provide important protection against severe underperformance, but they do not remove the need for active monitoring and management. Proving a claim can be complex, and not all performance shortfalls will cross contractual thresholds, especially once other loss factors are considered.
Many sophisticated owners review fleet-level assumptions every few years as new data accumulates, adjusting project evaluations and risk metrics as evidence improves. For large portfolios, periodic back-testing of modelled vs. realised performance is a valuable governance practice.
Degradation is only one component of long-term performance. Soiling, downtime, curtailment and inverter losses can be of similar magnitude. Models and monitoring approaches should consider the combined effect rather than treating degradation in isolation.
Emerging cell architectures and materials may offer improved stability, but field data is still accumulating. Until long-term evidence is available, many owners apply cautiously optimistic assumptions, updating them as real-world data from similar climates and applications becomes available.
Repowering decisions depend on residual PPA life, site constraints, current module prices and grid conditions. In some cases, targeted replacement of worst-performing strings or inverters can restore output cost-effectively; in others, accepting higher degradation and adjusting expectations is more rational.