Ask a solar IPP CFO what their biggest uninsured financial risk is and they will probably say merchant price exposure. Or grid curtailment. Or maybe a category 4 weather event that their property all-risk policy does not fully cover.
They will not say commissioning delay risk.
They should.
Because commissioning delay, the failure to achieve commercial operation date under an LD-bearing PPA or capacity market contract, is the single most common, single most expensive, and single most uninsured financial risk in the solar development lifecycle. And the industry has somehow normalised it into a line item called “project contingency” and moved on.
The numbers, plainly
Commissioning delays on utility-scale solar are common rather than exceptional. Punch lists, grid-operator test windows and certification packs all have to land on the same date, and when one slips, COD slips with it. For a worked example of how close a project can come, see how one 80 MW project ended up 19 days from a seven-figure LD bill.
The cost is easy to calculate and hard to hedge. LD exposure = daily LD rate × days late, up to the cap in the contract. Modern PPAs and capacity market contracts set LD rates to reflect the revenue the offtaker is losing, not the cost the IPP is incurring, so on a large project even a few weeks of delay can run into seven figures. Pull the daily rate and cap from your own PPA before you size contingency.
Is this insured? Almost always not. Construction all-risk policies cover physical damage to the works. They do not cover delay in start-up (DSU) unless explicitly endorsed, and even endorsed coverage usually carries a deductible period measured in weeks, plus exclusions for interconnection delays and utility process failures, which are among the most frequent real causes of delay.
What this means: in the most common delay scenario, a slip of a few weeks caused by a combination of punch list velocity failure, utility interconnection process delays and commissioning test failures, the LD exposure is almost entirely unhedged.
Why this risk is underpriced
I have spoken with underwriters at several major construction and renewable energy insurers about this gap. The uncomfortable consensus is that the risk is underpriced not because it is small, but because it is predictable. Predictable risks are supposed to be managed by the insured, not transferred to the insurer.
In other words, the insurance market’s view is that commissioning delay risk is controllable, and the failure to control it is an operational management failure, not an insurable event.
That view is correct. It means the risk premium for poor commissioning management is borne entirely by the IPP and EPC contractor.
The problem is that controlling commissioning delay risk requires something most projects do not have: a real-time, continuously updated model of commissioning velocity, test completion, punch list trajectory, and utility interconnection progress, integrated and tracked against the COD date with enough lead time to intervene.
Without that visibility, the risk is not controlled. It is observed, after the fact.
The five causes
When commissioning delays on utility-scale projects are traced back to their root cause, the same five categories come up again and again:
- Punch list velocity failure. Items are identified but close too slowly. This is preventable with velocity tracking and early escalation, the core of disciplined punch list tracking from defect to closeout.
- Utility interconnection delays. Documentation incompleteness and test sequencing errors with the grid operator. This is preventable with early cross-referencing of project documentation against the utility’s current commissioning requirements.
- Equipment non-conformances. Inverter failures, relay configuration issues, and SCADA communication errors discovered at load. This is preventable with pre-commissioning drone thermal validation.
- Documentation failures. Missing or incorrectly formatted certificates when the commissioning pack is assembled. This is preventable with continuous documentation monitoring.
- Weather and access. The only category that is genuinely unpredictable, and the smallest contributor.
The pattern is consistent: four of the five causes are visible, predictable and preventable weeks before they affect COD. Only weather and access is genuinely outside the team’s control. The rest stay invisible only because nobody is looking at the right data in a connected way.
How to measure commissioning delay risk before it hits COD
You do not need a new system to start. Commissioning delay risk can be tracked with four leading indicators that most project teams already hold in separate spreadsheets:
- Punch list burn-down versus required rate: open items divided by working days to the interconnection test date. If the closure rate needed to clear the list is above the rate the crews are achieving, the date is already at risk.
- Utility documentation status: every document the grid operator requires, checked against its current template and submission deadline, not the template from the last project.
- Test completion and first-pass yield: the share of commissioning tests passed first time. Repeated failures on inverters, protection relays or SCADA points signal equipment non-conformances that will surface again at energisation.
- Certification pack completeness: missing or wrongly formatted certificates found during continuous checks rather than in the final week.
Each indicator can be expressed as days of float to COD. Combined, they give a COD probability that can be reported weekly to the IPP, the EPC and the lender’s technical adviser, and a modelled LD exposure when the probability drops. That is the discipline that AI-assisted solar commissioning software automates: baselining, quality control and handover evidence in one place.
What the agent does
ClearSpot’s Commissioning Risk Intelligence agent, part of the ClearSpot agentic AI platform, monitors commissioning progress across all five delay-risk dimensions simultaneously: punch list velocity, utility document status, test completion rates, drone thermal findings, and equipment certification status.
It does not generate weekly reports for humans to interpret. It maintains a live COD probability model that updates continuously as new data comes in, and it escalates the moment the trajectory diverges from a clean COD outcome.
When punch list closure velocity drops below the rate required to achieve the interconnection test date, the agent does not wait for Friday’s status meeting. It flags it immediately, identifies the specific items driving the velocity shortfall, and models the LD exposure at current velocity.
ClearSpot’s mesh combines autonomous AI agents with autonomous drones. In commissioning, drone inspection workflows are the fastest way to close uncertainty around equipment non-conformances before they become test failures. The agent dispatches targeted drone surveys based on electrical anomaly signals, turning a “schedule a site visit” loop measured in weeks into a “drone survey and defect classification” loop measured in hours.
To be direct, it works as an insurance policy against the industry’s largest uninsured risk, with one difference: it prevents the event rather than paying for it after.
Insurance context
For broader industry context, the IEA PVPS O&M guidelines and the NREL best-practices reference both reinforce the value of rigorous commissioning, documentation, and lifecycle risk management in utility-scale PV.
There is a longer conversation here for renewable energy insurers.
As AI-driven commissioning risk management becomes standard practice, the risk profile of well-instrumented projects diverges significantly from the industry average. A project managed through real-time commissioning risk intelligence has a demonstrably lower probability of COD delay, measurable, auditable, and underwritable.
The industry should be pricing that difference. DSU/ALOP coverage for projects with verified real-time risk management should be cheaper than for projects without it. The data exists to support that pricing.
Until that market evolves, the benefit accrues entirely to the IPP and EPC teams that build the management capability, in the form of avoided LDs that never appear in an insurance claim because they were prevented.
Closing thought
Does your organisation explicitly price commissioning delay risk in project contingency, or is it absorbed into general schedule buffer? I am curious how this risk is actually accounted for in project economics.
Frequently Asked Questions
It is the financial risk that a solar project misses its commercial operation date (COD) and triggers liquidated damages under a PPA or capacity market contract.
Construction all-risk policies cover physical damage, not delay in start-up, unless specifically endorsed. Endorsed cover usually has a deductible period and excludes interconnection and utility process delays.
Punch list velocity failure, utility interconnection delays, equipment non-conformances and documentation failures cause most delay-days. Weather and access is the only category that is genuinely unpredictable.
Multiply the daily LD rate in the PPA or capacity contract by the number of days late, up to the contractual cap. Use your own contract rate rather than an industry average.
ClearSpot’s Commissioning Risk Intelligence agent tracks punch list velocity, utility documentation, test completion, drone thermal findings and certification status, and escalates as soon as the COD trajectory slips.
The IEA PVPS O&M guidelines and the NREL best-practices reference for photovoltaic operation and maintenance both cover commissioning, documentation and lifecycle risk management.