The Compliance Clock Starts May 15, 2026.
On May 15, 2026, a registration milestone takes effect that will change the compliance posture of hundreds of inverter-based resource (IBR) facilities across North America.
Many owners and operators of non-BES IBR facilities meeting the Category 2 threshold will, for the first time, be added to the NERC Compliance Registry as Category 2 entities and subject to enforceable Reliability Standards. As of NERC’s latest data, 626 facilities meet the new criteria. Of those, nearly half had not yet been covered by registration notifications at the time of the last update.
For many, this is their first direct relationship with NERC. Whether operating solar, wind, or battery systems, many of these sites were designed and commissioned years before this category existed. That is where the real challenge begins. Registration is administrative; what follows is not. The gap between current facility status and NERC compliance maturity is larger than many owners realize.
This is an honest look from a protection and controls (P&C) engineering perspective at where the gaps live, why they exist, and how to close them.
What Category 2 Registration Actually Means
The Category 2 threshold applies to non-BES IBR facilities with an aggregate inverter nameplate capacity of 20 MVA or more, connected at 60 kV or above. Two details in that definition matter more than they appear to:
- “Aggregate”: A single 15 MVA solar facility might not trigger registration alone. But if it shares a common point of connection with a 10 MVA battery, the combined 25 MVA crosses the threshold. Both facilities become subject to registration, regardless of ownership.
- “Common Point of Connection”: This is typically the interconnection point at 60 kV+. However, physical configurations in hybrid plants or phased developments can introduce ambiguity.
These details matter because some facility owners may still assume they are below the threshold when, in aggregate, they are not.
Day-One Standards: What Applies on May 15
NERC identified eight Reliability Standards that apply to Category 2 entities immediately: BAL-001-TRE-2, IRO-010-5, MOD-032-1, PRC-012-2, PRC-017-1, TOP-003-6.1, VAR-001-5, and VAR-002-4.1.
For first-time registrants, even this initial set introduces obligations many have never formally managed. MOD-032-1, for example, requires that facility data used in planning models be provided to planners. That sounds straightforward until you discover the dynamic model handed over during construction no longer matches the firmware version running in the field. VAR-001-5 and VAR-002-4.1 involve voltage schedule compliance and reactive power obligations, requiring verified operational capability—not just a paper study.
The Broader Roadmap: What Comes After Day One
The full scope of GO/GOP obligations does not land on May 15, but the landscape is moving fast.
PRC-029-1, establishing mandatory ride-through performance, was approved in July 2025 with a U.S. effective date of October 1, 2026. For Category 2 IBRs, the design requirements must be met by January 1, 2027. This replaces legacy provisions with a performance-based framework that relies on actual disturbance data. Similarly, PRC-030-1 (also October 2026) requires root-cause evaluation for unexpected output changes.
The practical implication: do not wait for a formal compliance date to begin the engineering. By the time a standard is enforceable, the work to comply should be substantially complete.
Where the Engineering Gaps Live
Many Category 2 facilities were built for “interconnection compliance,” not “NERC reliability compliance.” Interconnection establishes what you need to connect; NERC establishes what you must sustain, validate, and prove on an ongoing basis.
1. Inverter Settings and Ride-Through Alignment
Many IBR facilities were commissioned with inverter trip settings configured by the OEM or EPC based on manufacturer defaults or study assumptions. When PRC-029-1 becomes enforceable, you must demonstrate the facility can ride through disturbances without tripping or momentary cessation. If your settings rationale involves “the OEM set those” without a documented link to ride-through requirements, that is a gap.
2. Protection Coordination
Interconnection-era coordination studies often fail to address conditions NERC standards examine. Were the studies updated after firmware changes? Do they account for the current configuration, or initial design assumptions? Is the rationale documented so an auditor can understand it? P&C coordination is now an ongoing obligation, not a one-time deliverable.
3. Planning Model Fidelity
Inverter firmware updates, control system tuning, and equipment degradation create divergence between the model and the field. If the model does not match the field, the facility may appear compliant on paper while behaving differently during an actual event—a major liability under the new standards.
4. Document Control and Configuration Governance
This is the hardest gap to close. Over a facility’s life, multiple parties (developers, EPCs, OEMs) touch the configuration. Original settings may exist only on a laptop returned to a contractor years ago. Under NERC, the registered entity is accountable. Building a traceable chain from design to as-left commissioning is the foundation of compliance.
A Hypothetical That Is Not Very Hypothetical
Consider a 35 MVA solar facility with a co-located 10 MVA BESS. It was commissioned in 2021 by an EPC using OEM defaults. In 2026, the owner registers as a Category 2 GO/GOP.
When a consultant reviews readiness, they find the settings files, but the firmware has been updated twice since 2021. The protection study exists but doesn’t include the BESS addition. The dynamic model is with the utility, but no one knows if it reflects the current firmware. This scenario is common—and it illustrates why the engineering work is substantially more involved than the registration itself.
What P&C Engineers Should Be Doing Now
- Within 30 Days: Confirm registration status. Locate current inverter settings, coordination studies, and dynamic models. Identify which of the eight “day-one” standards apply and assess existing documentation.
- Within 60 Days: Compare trip settings against PRC-029-1 ride-through requirements. Misalignment takes time to resolve. Review the protection coordination study for currency against current fault study data.
- Within 90 Days: Validate the dynamic model against actual behavior. Establish a document control framework that creates traceability between design, settings, and as-left state. Define internal ownership for settings authority and model submissions.
The Larger Shift
This is a structural change in how IBRs are integrated into the North American grid. For years, many facilities operated in the space “between” the interconnection agreement and the bulk power system. That era is ending.
The engineering maturity required for this level of accountability is significantly higher than what the old framework demanded. The owners who begin that work now will be in the strongest position. Those who treat registration as the finish line will discover that the real work is just beginning.
Madjer Santos, PE, P.Eng., PMP, MBA Principal Engineer and Manager | Protection and Control (P&C