When a grid operator tells a generator to reduce output, the physical result is straightforward: less electricity reaches the market. What happens under a corporate power purchase agreement can be considerably less clear. A curtailment instruction from an independent system operator or regional transmission organization does not, by itself, determine whether a renewable energy developer can claim force majeure, avoid a delivery obligation, or shift the financial consequences to its customer. Those outcomes depend on the contract, including how force majeure is defined, how curtailment is allocated, what mitigation is required, and whether grid congestion or an operator directive was a risk the parties expressly assigned when the agreement was signed. That distinction is becoming harder for corporate energy buyers to ignore as congestion, transmission constraints, and changing operating conditions increase the number of ways electricity production can diverge from what a project was expected to deliver.
Curtailment Does Not Describe a Single Event
California provides one of the clearest examples of why the word curtailment alone is not enough. CAISO's market reporting separates system-level and local renewable curtailment and further distinguishes economic curtailment from reductions involving self-scheduled resources. CAISO continues to track solar and wind curtailment separately in its 2026 daily renewable reports. Those distinctions matter commercially. A project dispatched downward because of an economic bid is not necessarily experiencing the same event as a generator unable to deliver because of a transmission-security constraint. A reliability instruction, local congestion, transmission outage, or an economic response to negative pricing may all result in reduced project output, but they do not necessarily receive identical treatment under a PPA. The contract has to determine which party owns each risk. For buyers, the relevant question is no longer simply whether the agreement contains a force majeure provision. It is whether that provision actually covers the circumstances preventing delivery.
Grid Orders Can Be Beyond a Generator's Control
Force majeure provisions commonly revolve around events outside a party's reasonable control, but grid rules demonstrate how complicated that concept can become. MISO's Generator Interconnection Agreement defines force majeure to include any order, regulation, or restriction imposed by governmental, military, or lawfully established civilian authorities, or any other cause beyond a party's control, while explicitly excluding negligence or intentional wrongdoing by the party claiming relief. That does not mean MISO's definition automatically governs a corporate PPA. It illustrates something more important for procurement teams: the grid agreement governing the project and the commercial agreement governing the buyer may address disruption differently, and the buyer needs to understand both. A seller may have obligations to the transmission provider or ISO/RTO under one set of documents while having separate delivery, notice, mitigation, and force majeure obligations to its corporate counterparty under another. Calling an event grid ordered does not resolve that contractual chain.
Reliability Events Are Not Theoretical
The issue is particularly relevant because grid operators actively use emergency and transmission-security procedures that can alter normal market operations. On July 2, 2026, PJM used emergency procedures as extreme heat, generation outages, and transmission constraints pushed the system to a preliminary all-time peak of 168,158 MW. PJM called on emergency demand response and said every available generator was needed to serve the system. In the BGE, Pepco, and Dominion transmission zones, PJM also issued an Emergency Use of Backup Generator Warning, preparing large-load customers for possible curtailment to backup generation; the corresponding Action that would have required customers to switch was ultimately not needed. PJM maintained Maximum Generation and Load Management alerts into the following days and again activated demand-response resources as it managed the continuing heat event.
ERCOT illustrates how narrow and technical the triggering grid condition can be. On May 27, 2026, ERCOT curtailed both its North and East DC ties after identifying transmission-security violations that could be fully or partially resolved by reducing DC-tie load; those restrictions were lifted less than three hours later. Neither event establishes that a particular corporate PPA experienced force majeure. They show why buyers cannot treat every grid intervention as one standardized category of contractual risk.
The Contract Determines Where the Loss Lands
For procurement teams, the most consequential provisions may sit outside the headline force majeure clause. A corporate buyer needs to know how the agreement treats grid-ordered curtailment, economic curtailment, transmission outages, congestion, interconnection restrictions, and changes in ISO/RTO operating rules. The contract should also make clear what happens after the event occurs: whether the seller has to mitigate the disruption, who bears the financial consequences of lost renewable energy certificates or other environmental attributes, who receives any curtailment compensation, how quickly the seller must provide notice, and at what point prolonged or repeated disruption creates termination or renegotiation rights. For physical PPAs, that may include replacement-power obligations or delivery shortfalls. For virtual PPAs, the corporate buyer may not depend on physical delivery to keep a facility operating, but lower project output can still change contract settlements and the volume of associated environmental attributes. A force majeure clause that excuses performance without clearly addressing those adjacent economic rights can leave substantial exposure unresolved.
Procurement Needs to Underwrite the Grid
Corporate energy procurement has traditionally concentrated on the project and counterparty: developer creditworthiness, expected generation, pricing, commercial operation dates, environmental attributes, and contract duration. Grid conditions increasingly belong in the same underwriting process. CAISO's reporting shows that renewable curtailment can result from both systemwide conditions and local congestion. PJM's summer 2026 emergency actions show that system operators can impose materially different operating instructions as reliability conditions change. ERCOT's DC-tie curtailment protocol confirms how transmission-security violations can trigger targeted restrictions on short notice. The contract has to translate those grid realities into commercial consequences. For companies procuring renewable energy across several regions, legal review cannot stop with confirming that standard force majeure language appears in every agreement. Counsel and procurement teams need to test the provision against the actual market where the project operates, including what happens when interconnection or delivery timing itself becomes the disputed event.
What happens if the ISO orders the project down? What happens if transmission is unavailable?
What happens when congestion makes delivery uneconomic?
And which of those events has the company already agreed to absorb?
Those are increasingly underwriting questions, not boilerplate. A grid operator decides what the power system needs in real time. The PPA decides who pays when that decision prevents the contract from performing as expected.
