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Understanding NERC PRC-029-1: Frequency and Voltage Ride-Through for Inverter-Based Resources 

NERC PRC-029-1 establishes mandatory performance requirements for how inverter-based resources (IBRs) must behave during grid voltage and frequency disturbances. The standard applies to resources including solar photovoltaic facilities, Type 3 and Type 4 wind, battery energy storage systems, and VSC-HVDC-connected resources that are sources of active power.
At the center of the standard is ride-through: the requirement for a plant or facility to remain connected and continue operating through defined voltage or frequency disturbances rather than tripping offline. PRC-029-1 also goes beyond simply requiring an IBR to stay connected. Under certain conditions, the resource must actively exchange current to support voltage and recover active power following a disturbance. 

The 60-Second Version 

• What it is: A new, mandatory NERC Reliability Standard that sets performance requirements for how inverter-based resources, including solar PV, most modern wind, battery storage, and HVDC-connected plants, must behave during grid voltage and frequency disturbances. 

• The core idea: Ride-through means the plant or facility must stay connected and continue supporting the grid through a disturbance rather than tripping offline. NERC now defines it formally: “the plant/facility remains connected and continues to operate through voltage or frequency system disturbances.” 

• Why now: A series of disturbances, including Blue Cut in 2016 and Odessa in 2021 and 2022, saw well over a thousand megawatts of solar drop offline during faults that the grid should have been able to absorb. FERC Order No. 901 directed NERC to address these and similar issues; PRC-029 is the centerpiece of the response. 

• Who it applies to: Generator Owners of BES IBRs, along with larger non-BES IBRs with an aggregate nameplate capacity of at least 20 MVA connected at 60 kV or greater. 

• When: PRC-029-1 was approved by FERC through Order No. 909 on July 24, 2025. It becomes effective October 1, 2026 for BES IBRs, with applicable non-BES IBRs following later. Compliance is phased, with design and capability obligations preceding performance obligations. 

• The key nuance: Ride-through does not simply mean “do not trip.” Under the right conditions, an IBR must actively inject current to support voltage and recover active power quickly. 

Key Terms 

Before getting into the requirements, it helps to define several terms used throughout PRC-029-1. 

• Per unit (pu): A way of expressing a value as a fraction of nominal. For example, 1.0 pu represents 100% of normal voltage, 0.90 pu represents 90%, and 1.20 pu represents 120%. 

• Active vs. reactive power: Active power is the transfer of energy that performs actual work, while reactive power is the invisible push that holds voltage up — every bit as physically real. During a voltage sag, PRC-029-1 generally requires the plant to prioritize voltage-supporting reactive current in the applicable operating region. NERC uses the term “Real Power” for active power; the terms mean the same thing in this context. 

• Wind Types 1–4: Type 3 and Type 4 wind turbines are modern turbine technologies that connect to the grid through power electronics and are addressed by PRC-029-1. Type 1 and Type 2 wind turbines remain under PRC-024-4. 

• High side of the main power transformer (MPT): The reference point used for the standard’s ride-through criteria. This is the transformer that steps the collection system up to transmission voltage. Protection elsewhere in the plant still applies; the ride-through criteria are simply referenced at this point. 

• Phase-locked loop (PLL): A control loop an IBR uses to synchronize with the grid’s voltage angle and frequency. Loss of PLL synchronism was identified as the single largest cause of the 2021 Odessa event, and PRC-029-1 prohibits tripping on PLL loss of synchronism. 

• Anti-islanding: A protective function that trips an IBR when it believes it has become electrically isolated from the grid. It can misoperate during sharp phase changes when a fault clears. 

• Momentary cessation: The temporary halting of current injection during a disturbance without fully disconnecting. In its uncontrolled, open-ended form it drove the historical events; PRC-029-1 prohibits momentary cessation throughout the must-ride-through zone. Most modern IBR units have moved away from the practice, though it can still be found on some legacy devices. 

Why PRC-029-1 Was Developed 

Historically, much of the grid’s protection philosophy was developed around synchronous generators. IBRs behave differently: their response during and immediately after a fault is set by software, controls, and protection settings, not rotating mass. Similarly, IBRs lack the thermal inertia of machines built from large quantities of copper and steel and cannot sustain current injection over long periods of time. Early IBR fleets were often programmed conservatively — at the first sign of trouble many inverters would stop injecting current or trip offline to protect themselves and others. During the paradigm shift between distributed generation and Bulk-Electric System (BES) applications, the control philosophy was not directly re-investigated. At scale, these sets of behaviors become a reliability problem: 

• During the 2016 Blue Cut Fire, faults on a 500 kV line in Southern California led to approximately 1,200 MW of solar PV reducing output — the largest contributor being inverters tripping on erroneous instantaneous frequency measurements, with momentary cessation compounding the issue. 

• During the 2021 Odessa Disturbance, a single fault led to a reduction of more than 1,100 MW of solar, with loss of phase-locked-loop synchronism, the single largest cause (roughly 389 MW). 

• During the 2022 Odessa Disturbance — the largest event of its kind — a single fault resulted in a non-consequential loss of more than 1,700 MW of solar from sites up to roughly 200 miles away, with approximately 2,555 MW of total generation affected when conventional generation was included. The largest causes were inverter AC overcurrent tripping (roughly 445 MW) and anti-islanding protection (roughly 385 MW); notably, some plants that tripped on loss of PLL synchronism in 2021 tripped on anti-islanding in 2022. 

These events did not result in blackouts, but they demonstrated how an otherwise survivable grid fault could cause significant generation losses. In October 2023, FERC issued Order No. 901 directing the development of enforceable requirements addressing IBR ride-through, monitoring, and corrective action. PRC-029-1, developed under NERC Project 2020-02, addresses the ride-through performance component. 

Who Does PRC-029-1 Apply To? 

The responsible entity under PRC-029-1 is the Generator Owner (GO). 

Facilities covered by the standard include: 

• All BES inverter-based resources 

• Larger non-BES inverter-based resources that have or contribute to an aggregate nameplate capacity of at least 20 MVA and are connected through a system designed primarily to deliver that capacity to a common point of connection at 60 kV or greater 

Applicable IBR technologies include utility-scale solar PV, Type 3 and Type 4 wind, battery energy storage systems, and VSC-HVDC-connected resources that are sources of active power. 

How PRC-029-1 Relates to PRC-024 

IBRs were previously addressed under PRC-024, which covers generator frequency and voltage protection settings. 

When PRC-029-1 takes effect, PRC-024-3 is retired. PRC-024-4 continues to cover synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers, while IBR ride-through obligations move to PRC-029-1. 

Key PRC-029-1 Dates 

PRC-029-1 was approved by FERC through Order No. 909 on July 24, 2025. For BES IBRs, the standard becomes effective October 1, 2026. The implementation plan separates capability and design requirements from the later obligation to demonstrate actual performance using disturbance-monitoring data. 

Milestone	Date
FERC Order No. 909 approving PRC-029-1	July 24, 2025
Effective date and design/capability deadline for BES IBRs	October 1, 2026
Design/capability deadline for applicable non-BES IBRs	Later of January 1, 2027, or the effective date
R4 hardware-limitation documentation	Within 12 months of the effective date
Performance obligations based on disturbance data	Phase in with PRC-028-1
Evidence retention for R1–R3	36 months or since the last audit
Evidence retention for R4	5 years (or since the last audit, if longer)

What Does Ride-Through Mean? 

PRC-029-1 defines operating conditions in which an IBR must remain connected and conditions in which it may be permitted to trip. 

The must-ride-through zone covers conditions where the IBR is required to remain connected and meet the applicable performance requirements. Tripping in this zone is a violation, barring the specific exceptions described later. 

The may-ride-through zone covers more extreme conditions outside the defined operating regions where an IBR is permitted to trip to protect itself. 

The required behavior within the must-ride-through zone depends on the operating region and the type of disturbance. 

Voltage Ride-Through Requirements 

Voltage ride-through is addressed by Requirements R1 and R2 and Attachment 1. 

Voltage is measured as the RMS voltage at the high side of the main power transformer, and the required durations are cumulative within a rolling 10-second window. 

PRC-029-1 identifies three operating regions: 

Continuous Operating Region 

Within the normal operating band, approximately 0.90 to 1.05 per unit voltage, the IBR remains connected and operates normally, providing active and reactive power without a time limit. 

Mandatory Operating Region 

During defined voltage excursions outside the normal band, the IBR must remain connected and actively exchange current to support voltage for the required minimum duration. Reactive-power priority applies by default in this region. 

Permissive Operating Region 

At the deepest voltage sags, the IBR must remain connected and, by default, continue the same active current support required in the mandatory region. It may use current-blocking mode only when necessary to avoid tripping and must restart current exchange within five cycles after voltage recovers to a higher operating region. 

The permissive region does not mean the resource is permitted to trip. It permits a limited, bounded use of current-blocking under extreme low-voltage conditions, for a physical reason: at the near-zero voltages of this region there is no grid to push meaningful power into. That brief, self-correcting block is deliberately not the same thing as momentary cessation, which PRC-029-1 prohibits throughout the must-ride-through zone. 

Minimum Voltage Ride-Through Durations 

Voltage	Operating Region	Minimum Ride-Through: All Other IBRs	Minimum Ride-Through: Type 3/4 Wind
Greater than 1.20 pu	—	May trip	May trip
1.10–1.20 pu	Mandatory	1.0 s	1.0 s
1.05–1.10 pu	Continuous	1,800 s	1,800 s
0.90–1.05 pu	Continuous	No time limit	No time limit
Below 0.90 pu	Mandatory	6.0 s	3.0 s
Below 0.70 pu	Mandatory	3.0 s	2.5 s
Below 0.50 pu	Mandatory	1.20 s	1.20 s
Below 0.25 pu	Mandatory	0.32 s	0.16 s
Below 0.10 pu	Permissive	0.32 s	0.16 s

The durations are minimum ride-through times and are cumulative over any 10-second window. The standard also allows an IBR to trip after more than four excursions outside the continuous region within any 10 seconds. 

The final standard specifies voltage ride-through through tables rather than a published voltage curve. Because the required durations accumulate within a rolling window and differ between Type 3/4 wind and other IBRs, translating the requirements into a defensible voltage-versus-time profile for simulation requires deliberate engineering analysis. Demonstrating that a plant meets the requirement means building a sound, well-sourced dynamic model and testing its behavior against these specific durations and compositing rules — not guessing at an undefined envelope. 

Frequency Ride-Through Requirements 

Frequency ride-through is addressed by Requirement R3 and Attachment 2. 

Unlike voltage ride-through, the frequency criteria do not include a permissive region or current-blocking equivalent. The standard establishes a must-ride-through band and a may-trip region outside of that band. And unlike voltage, the standard publishes the frequency profile as an actual curve (see Figure 1). 

System Frequency	Requirement
Above 61.8 Hz	May trip
61.2–61.8 Hz	Ride through for at least 299 seconds
58.8–61.2 Hz	Ride through continuously
57.0–58.8 Hz	Ride through for at least 299 seconds
Below 57.0 Hz	May trip

An IBR does not have to ride through a frequency excursion if the rate of change of frequency exceeds 5 Hz per second, measured as an average over at least one-tenth of a second. The brief instant associated with fault occurrence and clearance is excluded from that measurement. 

Frequency is measured at the high side of the main power transformer over a short window, typically three to six cycles. The required durations are cumulative over any 10-minute period. 

 

Figure 1. PRC-029 frequency ride-through envelope (Attachment 2, Table 3 — all IBR). The black line marks the must-ride-through boundary; the white region outside it is where the resource may fail to ride through (trip). 

Ride-Through Means More Than “Don’t Trip” 

PRC-029-1 includes active performance obligations in addition to requiring an IBR to remain connected. 

Depending on operating conditions, an IBR must: 

• Support voltage with current. In the mandatory region, the plant must provide as much current as it can safely supply to support voltage on the affected phases, during both symmetrical and asymmetrical disturbances. 

• Prioritize appropriately. Reactive current is prioritized by default in the mandatory region unless the grid operator directs otherwise. In the narrower 0.90–0.95 pu continuous region, if a current or reactive limit prevents delivery of full active and reactive power, the applicable priority is established by the controller or direction from the appropriate transmission or reliability entity. 

• Recover active power quickly. When voltage returns to the continuous region, active power must return to the pre-disturbance or currently available level within 1.0 second, except during a frequency excursion where recovery follows the primary frequency controller unless otherwise directed. 

• Avoid creating an overvoltage during recovery. 

• Avoid certain instantaneous voltage-based trip settings. Settings based on instantaneously calculated voltage with filter lengths shorter than one cycle are not permitted. This is a direct answer to the erroneous-measurement failures seen in the historical events. 

Exceptions and the R4 Hardware-Limitation Exemption 

PRC-029-1 includes several built-in exceptions to the ride-through requirements. 

An IBR is not faulted for failing to ride through when: 

1. It had to electrically disconnect to clear a fault. 

1. Voltage at the high side of the main power transformer went outside an accepted hardware limitation documented under R4. 

1. A non-fault-initiated phase-angle jump greater than 25 electrical degrees occurred. In this situation, the IBR may use current-blocking to avoid tripping and is not penalized if it cannot ride through. 

1. Volts-per-Hz — a measure of magnetic over-stress on the transformer and other iron-core equipment — exceeded 1.1 pu for more than 45 seconds or 1.18 pu for more than 2 seconds. 

PRC-029-1 also provides a formal exemption pathway for certain older IBRs whose hardware cannot meet the required criteria and cannot be corrected through software or settings changes. 

For eligible equipment in service by the effective date, the Generator Owner must document: 

• The limitation 

• The hardware responsible for the limitation 

• Technical evidence supporting the limitation 

• Evidence that physical replacement would be required to correct it 

• Any plans to remedy the limitation, such as an estimated replacement date 

The documentation must be completed within 12 months of the effective date and shared with the applicable Planning Coordinator, Transmission Planner, Transmission Operator, Reliability Coordinator, and Compliance Enforcement Authority (CEA) — the NERC Regional Entity (or NERC) that audits and enforces the standard. Follow-up requests must be addressed within 90 days, and acceptance by the CEA must be communicated to the other applicable parties. The exemption is documented and temporary: when the hardware causing the limitation is replaced, the exemption no longer applies, and the hardware change must be communicated to the same entities within 90 days. 

An important distinction involves firmware. Functionally, a firmware update is a software update: if a firmware change alone can bring a unit into compliance, the R4 exemption generally does not apply — the owner is expected to obtain and apply it, so engage the OEM early. Watch this area closely, though: we have seen cases where the firmware update itself requires a hardware upgrade to run — and OEM recommendations structured in ways that obscure that a hardware change is what is actually needed. If a hardware upgrade is genuinely required to comply, the limitation is a hardware limitation and the R4 exemption applies. Obtain written documentation from the OEM stating plainly that the hardware upgrade is necessary — that is exactly the evidence R4 requires to show the limitation cannot be remedied by software or setting changes alone. 

Requirements R1, R2, and R3 carry a High Violation Risk Factor, while R4 carries a Lower Violation Risk Factor. Under the applicable Violation Severity Level tables, an actual real-event ride-through failure is categorized as Severe. 

What PRC-029-1 Compliance Looks Like in Practice 

The implementation plan separates capability/design obligations from later performance obligations. 

For BES IBRs, capability and design must be demonstrated by the October 1, 2026 effective date. For applicable non-BES IBRs, the deadline is the later of January 1, 2027, or the effective date. These obligations can be demonstrated through studies, dynamic simulations, and review of protection and control settings. 

Performance obligations arrive as disturbance monitoring is installed under PRC-028-1. Once the applicable monitoring is in place, an actual failure to ride through a real disturbance is a violation — High Violation Risk Factor, Severe Violation Severity Level — regardless of prior study results. The design study is the entry ticket, not a permanent safe harbor. 

A typical compliance path is: 

1. Confirm applicability. 

1. Obtain the manufacturer’s ride-through capability data and plant model. 

1. Study or simulate the plant against the voltage and frequency criteria. 

1. Set and document protection and controls. 

1. File any applicable R4 exemptions. 

1. Establish disturbance monitoring under PRC-028. 

1. Retain evidence and compare performance against actual events. 

Many BES sites may already have OEM capability information and plant models from interconnection work, with models previously validated under MOD-026 or MOD-027. For those facilities, PRC-029 work may begin with an existing validated model. Applicable non-BES sites may be more likely to require model development before performing the ride-through study. 

Verified vs. Validated Models 

PRC-029-1 defines performance expectations but does not specify the modeling platform or source that must be used. 

Two terms describe model confidence, and they are not interchangeable in NERC practice: 

• A verified model is built and checked against available information such as manufacturer data sheets, control settings, and design drawings. 

• A validated model has been compared against actual measurements from a staged test or recorded disturbance and reconciled to match the observed response. 

Validation therefore represents the stronger, measurement-backed claim. 

Positive-Sequence vs. EMT Modeling 

Ride-through studies generally use one of two modeling approaches: 

• Positive-sequence tools, such as PSS/E, are faster and commonly used for planning studies. 

• Electromagnetic transient (EMT) tools, such as PSCAD, provide greater detail for fast, unbalanced, and sub-cycle behavior such as phase jumps, asymmetrical faults, and current-blocking. 

The best-practice approach is a validated EMT model. That ideal, however, is ahead of where most owners are today. 

Where validated positive-sequence models already exist from prior MOD-026 or MOD-027 work, a pragmatic path is to base the PRC-029 ride-through demonstration on those models while building toward validated EMT models as MOD-026-2 requirements phase in. MOD-026-2 — which requires both validated positive-sequence and validated EMT models — took effect April 1, 2026 and phases its model obligations in through 2029 and 2030, which is why few resources have validated EMT models today. Note the timing gap for non-BES owners: MOD-026-2 covers non-BES IBRs at the same 20 MVA and 60 kV thresholds as PRC-029-1, but its model deadlines fall after the PRC-029-1 design deadline — and because non-BES IBRs were not covered by MOD-026-1, many have no validated model at all. For those facilities, plan for a model-development step before the ride-through study. 

How PRC-029-1 Fits Within the IBR Standards Family 

PRC-029-1 is one part of a larger set of standards addressing inverter-based resource reliability. 

• PRC-029-1: Ride-through performance. It defines how an IBR must behave during a disturbance. 

• PRC-024-4: Protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers. 

• PRC-028-1: Disturbance monitoring and reporting for IBRs. It provides the data used to evaluate PRC-029 performance. 

• PRC-030-1: Analysis and corrective action following unexpected IBR ride-through performance. 

In simple terms, PRC-029 establishes the expected performance, PRC-028 records what happened, and PRC-030 addresses corrective action when performance falls short. 

Frequently Asked Questions About PRC-029-1 

We own a 50 MW solar facility connected at 138 kV that is not classified as BES. Is it in scope? 

Yes. Non-BES IBRs are covered when they meet the threshold of at least 20 MVA aggregate capacity delivered to a common point of connection at 60 kV or greater — and a 50 MW site at 138 kV clears both comfortably: 50 MW is well above 20 MVA, and 138 kV is more than double 60 kV. Applicable non-BES IBRs simply get slightly more time: the design and capability deadline is the later of January 1, 2027, or the effective date. 

Is October 1, 2026 the full compliance deadline? 

For BES IBRs, October 1, 2026 is the effective date and the deadline for the capability/design obligation. The obligation to demonstrate actual performance using disturbance-monitoring data phases in later according to the PRC-028-1 schedule. 

Does ride-through only mean staying connected? 

No. Staying connected is necessary, but in the mandatory region the IBR must also actively provide current to support voltage and restore active power within the applicable recovery timeframe. 

What if older inverters physically cannot comply? 

For pre-effective-date IBRs with a genuine hardware limitation that cannot be remedied through software or settings changes, the R4 exemption process may apply. The limitation must be documented and supported with technical evidence. The exemption is temporary — it ends when the limiting hardware is replaced. 

What if the original equipment manufacturer is no longer in business? 

A defunct or unresponsive OEM does not automatically disqualify a resource from pursuing an R4 hardware-limitation exemption — the standard frames acceptable evidence as including, but not limited to, OEM documentation. Other technical documentation, including manuals, datasheets, and independent engineering analysis, may be used to demonstrate that the limitation is hardware-based. Note that disturbance records can show a unit failed to ride through, but not, on their own, that the cause is hardware rather than a setting. The filing deadline and recipients are the same as for any R4 exemption, and the exemption still ends when the hardware is replaced — which for an unsupported OEM usually means an eventual retrofit or repower. Because exemption guidance is still developing, confirm current evidence expectations with the applicable CEA. 

What evidence should be retained? 

For capability and design, acceptable evidence can include dynamic simulations, studies, plant protection settings, and control-setting design evaluations. Performance evidence can include sequence-of-event, dynamic disturbance, and fault-recorder data. R1–R3 evidence is retained for 36 months or since the last audit, while R4 evidence is retained for five years or since the last audit, whichever is longer. 

Does PRC-029-1 require a particular modeling platform? 

No. The standard does not specify the model source or simulation platform. Validated EMT modeling is the best practice; validated positive-sequence models can provide a practical starting point for facilities that already have them from prior MOD-026 or MOD-027 work. Many non-BES IBRs have no validated model yet — often the first step is developing one. 

What is the potential violation exposure? 

Requirements R1, R2, and R3 carry a High Violation Risk Factor, while R4 is Lower. Under the applicable Violation Severity Level tables, an actual real-event ride-through failure is categorized as Severe. Under the Energy Policy Act of 2005, violations of mandatory Reliability Standards are subject to civil penalties of up to $1 million per violation, per day — a statutory maximum that is adjusted for inflation and currently stands at $1,584,648 (18 C.F.R. § 385.1602(d)). In practice, penalties are set through NERC’s enforcement process and scale with the risk and severity of the violation and the entity’s compliance posture; most noncompliance is resolved at far lower amounts through mitigation-focused dispositions. 

Key Takeaways 

Three points summarize the primary compliance message: 

1. Ride-through means staying connected and supporting the grid, not simply avoiding a trip. 

1. Design and performance follow different timelines. The first obligation is to demonstrate through studies, settings, and engineering analysis that the resource is capable of meeting PRC-029-1. Real-event performance becomes an audited, enforceable obligation as disturbance monitoring is implemented. 

1. Compliance is an ongoing engineering effort. Dynamic modeling, simulation, protection and control design, and disturbance analysis continue beyond the initial effective date. 

How ENTRUST Can Help 

ENTRUST Solutions Group can support Generator Owners preparing for PRC-029-1 through ride-through studies and model validation. 

Would you like to know more about fulfilling PRC-029-1? 

Contact: 

Jerry Thompson — Engineering
jerry@entrustsol.com 

Celine St-Germain — Business Development, U.S.
CStGermain@entrustsol.com 

Thanh Nguyen — Business Development, Canada
TNguyen@entrustsol.com 

 

This page is an educational summary of NERC Reliability Standard PRC-029-1 and its implementation plan under Project 2020-02. It is not legal or compliance advice. Where a specific obligation matters, the official NERC standard and FERC order control. Event magnitudes and dates referenced are drawn from public NERC/ERCOT reports and are approximate.