By James C. Crawford III, Managing Director & Senior Partner, Regulatory Energy Partners

Most of the Category 2 registration conversations treat May 15, 2026 as a finish line. Registration complete, check the box, move on.

It is not a finish line. It is an effective date. On May 15, eight existing NERC Reliability Standards become applicable and enforceable to every newly registered Category 2 Generator Owner and Generator Operator. No phase-in. No grace period. No “later of” trigger. The revised GO and GOP definitions take effect, and these standards attach.

The Eight Standards Applicable on May 15, 2026

Why These Eight, and Why as Written

These are not new standards. They have applied to registered GOs and GOPs for years — in some cases, for over a decade. What changed is the population they apply to. When FERC approved the revised Generator Owner and Generator Operator definitions on October 1, 2025, the definitional boundary expanded to include Category 2 IBR facilities: inverter-based resources with an aggregate nameplate capacity of 20 MVA or greater at a common point of connection at a voltage greater than or equal to 60 kV.

NERC Staff conducted a standards-wide review in October 2023 and reaffirmed the analysis in summer 2024. The review identified eight existing standards that could apply to Category 2 entities without modification — standards containing no exclusionary language referencing “BES” or other defined terms that would otherwise prevent applicability to non-BES IBR facilities. They apply as written, from the moment the definitions take effect. NERC’s Q2 2026 Compliance Dates Supplemental confirms that all eight carry a Category 2 IBR compliance date of May 15, 2026.

The compliance obligation is not triggered by a future standards development process. It is triggered by registration itself. SERC Reliability Corporation’s April 22 announcement of a May 6, 2026 orientation webinar for newly registered IBRs — framed as the shift “from awareness to execution” — is the second Regional Entity, after MRO’s March 26 communication, to publicly signal that the post-registration compliance posture is now the active conversation.

For the predominant May 15 population — existing Cat 2 IBRs already in commercial operation — registration and COD converge, and applicability and operational measurement coincide. For the smaller subset of entities registering before a facility reaches COD, the standards attach at registration, but operational obligations that depend on the facility actively injecting power — TOP-003 operational data, VAR voltage control, BAL-001-TRE-2 primary frequency response in ERCOT — are functionally measurable from COD forward. This is a measurement consequence, not a deferral rule. It is distinct from the explicit “later of” language embedded in PRC-028-1, PRC-029-1, and PRC-030-1, which Part 2 of this series addresses.

Data Obligations — MOD-032-1, TOP-003-6.1, IRO-010-5

Three standards in this block establish the same functional obligation: the entity is now a data provider to the functions that plan and operate the interconnection. The practical effect of registration is that the facility must be represented in planning models, operational telemetry, and Reliability Coordinator situational awareness.

MOD-032-1 requires GOs to provide steady-state, dynamics, and short-circuit modeling data to the Transmission Planner and Planning Coordinator on request, in the format and timeline those entities specify. TOP-003-6.1 directs GOPs to provide operational data to the Balancing Authority, Transmission Operator, and Reliability Coordinator per each function’s data specification. IRO-010-5 establishes the same obligation running to the Reliability Coordinator.

Two early gaps show up repeatedly in this block. The first is format. TPs specify modeling data in the format their planning software requires, and IBR entities frequently hold only OEM-supplied data in a different format — often a vendor black-box dynamics model where the TP requires a generic or user-defined model suitable for region-wide studies. Closing that gap is not a documentation exercise; it is a work order to the OEM, with cost and lead time. The compliance manager who assumes “we have the modeling data” and the TP who specifies what the model must be are not yet in the same conversation on Day 1.

The second is the directive posture of the relationship itself. The requesting functions hold the pen on specifications, and specifications arrive when those functions issue them — not necessarily on May 15. For a cohort this size, specifications will arrive in a backlogged sequence, and the response windows will not expand to accommodate an entity standing up its program. The Day-1 question is not “do we comply?” — it is “do we have the specification in hand, do we have the data in the format it requires, and have we established the working relationship before the formal request lands?”

Voltage and Reactive Control — VAR-001-5, VAR-002-4.1

VAR-001-5 establishes the framework for voltage schedules, reactive power capabilities, and voltage control responsibilities between GOPs and Transmission Operators. The GOP must operate within the voltage or reactive power schedule the TOP provides and must notify the TOP when it cannot maintain the schedule. VAR-002-4.1 directs the GOP to maintain voltage or reactive power output as directed, operate in automatic voltage regulation mode unless otherwise directed, and notify the TOP of status changes that could affect voltage control.

Both standards assume conventional generator architecture. For IBR facilities, voltage and reactive power control is an inverter and plant-controller function, and the standards’ AVR-mode assumptions do not map cleanly onto inverter-level operating modes. Documented procedures — the mapping between what the standard requires and how the plant achieves it — become the critical evidence. An auditor asking “show me your AVR mode documentation” for an IBR plant is asking a question the standard itself does not resolve. The entity resolves it, in writing, before Day 1.

The distinction between credible and insufficient AVR-mode documentation is specific. Insufficient is a policy statement that the plant “operates in automatic voltage regulation mode.” Credible is a plant-specific document that names the inverter manufacturer and plant controller, identifies which plant-level control mode implements the AVR equivalent — typically voltage control mode on the plant controller rather than reactive power mode — references the TOP-acknowledged voltage schedule the plant is operating to, documents the notification procedure for mode changes, and is supported by operations logs or commissioning records showing the mode was actually verified. Conventional generators have a discrete AVR that is on or off. IBR plants have a hierarchy of control modes, and the AVR equivalent is a configuration choice that differs across OEMs. A one-line policy statement is not evidence of that choice.

Protection Systems — PRC-012-2, PRC-017-1

PRC-012-2 establishes design, review, testing, and maintenance requirements for Remedial Action Schemes. PRC-017-1 addresses maintenance and testing for Special Protection Systems. For Category 2 entities, the applicability question is fact-specific: does the facility participate in a RAS, or include or participate in an SPS?

The documentation question is not whether the entity is generally aware of its RAS or SPS status. It is whether the entity has the determination in hand on Day 1 — a written confirmation from the Transmission Operator and Planning Coordinator that states, with specificity, whether the facility participates in any RAS or SPS and, if so, what the entity’s obligations are. “We don’t believe we have a RAS” is not a compliance position. A written determination is.

ERCOT Primary Frequency Response — BAL-001-TRE-2

BAL-001-TRE-2 is a Texas RE regional standard applicable exclusively to Category 2 entities registered within the ERCOT region. GOPs must provide primary frequency response consistent with the droop and deadband settings the standard specifies. For IBR facilities, frequency response is an inverter-level capability that must be configured, documented, and demonstrable — not a post-hoc calculation from SCADA data. Entities outside ERCOT have no obligation under this standard; the preceding seven remain the applicable set.

What Day 1 Looks Like

The person responsible for compliance at a newly registered Category 2 entity — whether that’s a dedicated compliance manager, an operations director who just inherited the role, or a developer standing up a program for the first time — sitting at their desk on May 16, 2026, needs the following in place:

1. A documented program that shows how the entity satisfies each applicable standard’s requirements — not a plan to build one, a functioning program.
2. Evidence collection procedures mapped to the specific requirements in each standard. When the audit comes, the question is not “do you comply?” — it is “show me the evidence that you comply.”
3. Designated roles and responsibilities — who owns each standard, who collects evidence, who responds to data requests from the RC, TOP, BA, TP, and PC.
4. Established contact with the Transmission Operator, Balancing Authority, Reliability Coordinator, Transmission Planner, and Planning Coordinator, including a current copy of each function’s data specification and a written RAS/SPS determination.

That is the operating reality for any entity registered on May 15. Entities audited in the second half of 2026 will be expected to demonstrate compliance from Day 1, not from a later readiness date of the entity’s choosing.

The through-line of these eight standards is not the count. It is that every one of them applies as written, to a facility type whose architecture does not fully match the standards’ underlying assumptions, under a regulatory posture that has already shifted from awareness to execution. Entities that treat May 15 as a compliance event are preparing for the wrong test. The test is whether Day-1 documentation withstands specific evidentiary challenges when the first CMEP touchpoint arrives — whether that’s a spot check, a self-certification, or the first scheduled compliance monitoring engagement under the COP cycle. The programs that survive that scrutiny are the ones built to answer the specific question — not the ones built to satisfy a generic applicability checklist.

What Comes Next in This Series

This article covers the eight standards applicable at registration. Part 2 addresses the three IBR-specific PRC standards — PRC-028-1, PRC-029-1, and PRC-030-1 — that are FERC-approved and carry their own compliance timelines beyond May 15, anchored by the “later of” rule that ties compliance to the later of standard effective date or commercial operation date. Part 3 addresses the CIP and virtualization track — FERC Orders 918 and 919, and CIP-002-8 — and what those mean for newly registered entities facing a 2028 compliance horizon.

For the broader Category 2 registration framework, REP’s earlier analysis is available here: NERC Category 2 Generator Registration: What IBR Owners and Operators Need to Know.

Regulatory Energy Partners works with existing and newly registered entities across the full compliance build — from initial program development and Day 1 readiness through CMEP preparation and ongoing compliance monitoring. For entities preparing for May 15 registration or building compliance programs around Category 2 obligations, contact REP at repenergy.us.