Distributed Generation & Utility-Scale Solar

Foreword

Foreword

This professional reference is one of a series Energy Compliance, Inc. publishes for registered entities and the people who run their compliance programs.

I've spent more than thirty years on every side of the bulk electric system. I've operated control centers as a Reliability Coordinator, Transmission Operator, and Power System Operator. I've audited grid facilities and signed off on findings as a senior compliance auditor. I've worked enforcement matters from inside the regulator's process. For the last several years I've advised registered entities directly through the firm I founded.

The entities that do reliability well share a common habit. They take the standards seriously without confusing them with reliability itself. They know that a NERC Reliability Standard is a floor, not a ceiling. They know that compliance is something an auditor evaluates, but reliability is something a system either delivers or doesn't. They prepare for audits by building programs that survive real questions, not binders that look thick.

That's the perspective these references try to share. Each one focuses on a single topic: a standard family, an operational function, a regulatory framework, or an emerging industry challenge. Each one walks through how the topic actually works.

These references are written for the compliance manager who wants to understand the system, not just memorize requirements. For the legal counsel who has to brief a board honestly. For the senior operator who's been told that compliance and reliability are the same thing and suspects they aren't. And for the new compliance hire who got handed a binder and told good luck.

These references aren't marketing material disguised as content. They're the result of three decades of doing this work and watching it succeed and fail. I've written them in the same voice I use in a control room or in front of a Regional Entity audit team: direct, evidence-grounded, honest about what the standards do and do not require.

Energy Compliance exists because most of the consulting offered to registered entities today is structured for billable hours rather than for outcomes. Every engagement is overseen by a senior practitioner. We don't bring five people to a meeting that needs one. We automate the work that should be automated. We apply senior judgment to the work that requires it. If that approach matches what you're looking for in a compliance partner, the back of this reference has our contact information.

If not, the reference still belongs to you. Take what's useful. Apply it well. And remember the only test that ultimately matters: when the system needs to perform, does it?

Rob Smith

Founder and Principal, Energy Compliance, Inc.

Executive Summary

Executive Summary

Distributed generation generally doesn't get registered. Utility-scale solar does. The line between them isn't technology; it's functional impact on the bulk system. The same panel can be DG at one site and BES at another. What changes is the configuration, the interconnection, and the role the asset plays in reliability. Get the line wrong and the compliance surprises start at COD.

• The IBR registration initiative has every owner of a mid-sized solar plant asking the same question: do I have to register? Since May 15, 2026, owners and operators of non-BES IBRs of 20 MVA or more, delivering to a common point at 60 kV or above, are registered as Category 2 GOs and GOPs. The answer is more nuanced than a single nameplate threshold.
• Facilities that aggregate at a common point of connection can collectively meet the criteria. Owners who didn't model the aggregation register surprised.
• The operator can only manage what the operator can see. Invisible DG is invisible to the operator's reliability decisions.
• DG and utility-scale solar are similar technically and different functionally. The framework treats them differently because the reliability roles differ.
• T&D coordination used to be informal. DG growth made it formal. The standards are catching up: FERC Order No. 901 brings IBR-DERs in the aggregate into data sharing, model validation, and planning and operational studies.
• Ride-through is now a mandatory performance requirement. PRC-029-2 took effect October 1, 2026, alongside PRC-030-1 for unexpected IBR events, with phased compliance: Category 2 design obligations begin January 1, 2027.
• In my view, audit attention on DG and solar is increasing, and Regional Entity posture has shifted from accommodating new technology to enforcing standards consistently.

Chapter 1

Overview of Distributed Generation, Utility-Scale Solar, and Inverter-Based Technology

1.1 What This Reference Covers

This reference sorts distributed generation (DG) and utility-scale solar by what they do on the system: where they connect, what they control, and what happens to the bulk system when they misbehave. Both use inverters. That shared technology is where the similarity ends for reliability purposes. The difference shows up in visibility, controllability, and system response, and those are what a reliability program has to account for.

The discussion applies NERC Reliability Standards and related documents to inverter-based resources (IBRs) by operating function and reliability impact, not by technological makeup. It covers registration, applicability, and who is responsible for which resource configurations, and it clears up some common misunderstandings about how distribution reliability and bulk system reliability relate.

This is context and background, not engineering, operations, or compliance advice. The goal is a clear picture of the boundaries, responsibilities, and reliability implications for IBRs on the North American power system as the rules stand in October 2026.

1.2 A Resource Mix That Changed Underneath the Framework

The resources grid operators use to run the system have changed drastically over the last twenty years. Distributed energy resources (DER) and utility-scale solar are a larger and larger part of the grid in North America. Technology, policy, and falling prices all drove that growth. The reliability impact, though, comes from how those resources interact with existing reliability practices and standards.

For a century, conventional generation meant synchronous machines. Their behavior during a disturbance came from physics: rotating mass, magnetic fields, natural response. Power electronics changed that. Solar plants do not behave like synchronous machines, and much of the planning and operating practice built around those machines rested on assumptions about inertia, fault current, and dynamic performance that no longer hold for an inverter. A high-IBR grid requires reliability analysis to focus on how the system as a whole behaves, and less on the capability of any one resource.

1.3 Same Inverter, Different Role

DG usually means resources connected at distribution voltage, close to load: rooftop and small ground-mount PV, small aggregated resources, and other small plants that mostly serve local load. Utility-scale solar typically connects at transmission voltage through a dedicated step-up transformer and is operated as part of the generation fleet. Both run on inverters. Where they sit on the grid determines how visible they are, how much control the operator has, and what reliability obligations follow.

DG can affect the bulk system through aggregation and through its effect on net load, yet much of it sits outside the Reliability Standards. Utility-scale solar is under direct regulatory authority because of its size, its transmission connection, and its participation in grid operations. Keeping operational impact and regulatory scope separate in your head is the key to everything that follows.

1.4 Function First, and Where the Framework Had to Move

The reliability framework is function-based. Obligations attach to registered functions and the Facilities those functions own or operate, not to fuel or technology. That principle still holds. What changed is that function alone stopped being enough. The disturbance record in Chapter 10 showed fleets of inverters tripping or ceasing output together on normally cleared faults, and the framework moved in response:

• FERC's 2022 IBR Registration Order (181 FERC ¶ 61,124) directed NERC to register owners and operators of non-BES IBRs that have a material impact on the Bulk-Power System. That produced the Category 2 GO and GOP criteria in Chapter 5.
• FERC Order No. 901 (October 19, 2023) directed new or modified Reliability Standards for IBRs covering performance, data sharing, model validation, and planning and operational studies, with all of them due at FERC by November 4, 2026.
• NERC has since adopted IBR-specific standards developed in response, including PRC-028-1 (disturbance monitoring), PRC-029-2 (ride-through), and PRC-030-1 (unexpected IBR event mitigation), and revised MOD-026-2 to cover IBR models.

The earlier edition of this reference said no revisions to the Reliability Standards had been needed. That is no longer true. The framework is still technology-neutral in structure, but it now carries performance requirements written specifically for inverters.

Chapter Summary

Distributed generation and utility-scale solar are a normal part of the modern electric system. Despite differences in size, interconnection, and regulatory treatment, both are handled through function-based and impact-based approaches. Since 2022 those approaches have been extended with new registration criteria and IBR-specific standards. Focus on the system concepts and operating practices tied to resource responsibility and behavior, and on the new obligations that now attach to IBRs by name.

From the Field

The framework is still function-based. What changed is how many functions now reach an inverter. Start with the registration question, then the standards list, then the settings. Owners who start with the settings answer the wrong question first.

Chapter 2

Distinguishing Distributed Generation from Utility-Scale Resources

2.1 Where It Connects, What It Does

A clear line between DG and utility-scale solar is the starting point for integrating IBRs into the reliability framework. The two use the same technology, but they differ in location, operation, and regulatory treatment, and each of those differences drives the reliability responsibility and monitoring that apply.

DER is defined by its connection to a distribution system and its proximity to load. It serves local load, offsets net load on transmission and distribution lines, and supports distribution-level goals. It is managed through distribution-level means and is not scheduled through bulk system dispatch. A single installation is effectively undetectable from a transmission control center.

Utility-scale solar connects at transmission voltage, or through dedicated step-up transformation directly to the bulk system. These plants are designed, studied, and operated as part of the generation fleet. Their output, availability, and performance figure into system operations, planning studies, and reliability analyses.

2.2 The Bright Lines

In reliability terms the distinction is not about technology or nameplate alone. It is about the role the resource plays and the impact if it fails. The NERC definitions put numbers on that role:

The BES definition excludes facilities used in the local distribution of electric energy. Most DG never gets near any of these thresholds on its own, and it is not individually registered because it does not perform a bulk system function on a standalone basis.

2.3 DER Now Has a NERC Definition

For years "DER" was an industry term without a NERC Glossary entry. That changed. The NERC Glossary now defines Distributed Energy Resource, effective April 1, 2026, as a generator or energy storage technology connected to a distribution system that can provide Real Power in non-isolated parallel operation with the Bulk-Power System, including one behind an end-use customer's meter. A defined term matters because standards can now refer to DER data and DER modeling without arguing over what the words mean. It does not, by itself, make a DER owner a registered entity.

2.4 How Each Shows Up in Studies

The distinction drives visibility and control. Transmission Operators have direct telemetry and control relationships with utility-scale solar and can coordinate its response to system conditions. Distributed solar shows up as net load change and voltage effects, and as aggregate response only where an operational interface exists.

Planning practice differs too. Utility-scale solar is modeled explicitly in transmission planning and operational studies. DG is handled several ways depending on the tool and the study: folded into the load forecast, represented as an aggregated net load, or represented with an aggregated profile that gives more granularity than a forecast alone. In general, DG is treated as a load modifier rather than as an individually modeled generator.

2.5 A Moving Boundary

The boundary between DG and utility-scale solar has shifted and is still shifting. Technology, interconnection practice, and new aggregation models all push on it. Distribution-connected resources are affecting the system in ways DG traditionally didn't, and some are operated in ways that look like traditional generation. Utility-scale projects are being built closer to load and in hybrid configurations.

The framework handles that through registration criteria, applicability thresholds, and functional definitions rather than fixed resource categories. A resource, or an aggregate of resources, comes into the framework when it meets the criteria for bulk system impact and functional responsibility. The Category 2 criteria are the clearest example: they reach below the BES definition to 60 kV and 20 MVA because FERC found that IBRs below the BES thresholds, individually and in the aggregate, can materially affect the Bulk-Power System (IBR Registration Order, 181 FERC ¶ 61,124).

Chapter Summary

The distinctions between distributed generation and utility-scale solar come from interconnection, operational duty, and reliability responsibility, not technology. The BES definition, the Category 2 registration criteria, and the new NERC definition of DER put numbers on those distinctions. They drive visibility, control, and monitoring requirements as the share of inverter-based generation grows.

From the Field

The DG and utility-scale distinction matters because the regulatory framework treats them differently. Same technology, different obligations. A 5 MW solar facility connected behind a customer meter is not the same regulated thing as a 5 MW solar facility connected to the transmission grid, and a 25 MVA plant on a 69 kV tap is not the same regulated thing it was before May 2026. Configuration determines applicability.

Chapter 3

Inverter-Based Generation Operating Characteristics and System Behavior

3.1 Programmed, Not Physical

Inverter-based generation behaves in ways synchronous generation never did, in steady state and especially during disturbances. A synchronous generator is coupled to the grid through rotating mass. Its response to a transient comes from electromechanical interaction and inherent characteristics: stored inertia, fault current, natural frequency response.

An inverter interacts with the grid by switching power electronics based on real-time computation. Its response to voltage and frequency changes is set by its programming: control modes, protection settings, and ride-through logic. Two inverters from different manufacturers, or the same inverter in different operating modes, can respond differently to the same event. The settings that left the factory are no longer just engineering choices. They are reliability choices.

3.2 Fault Current

Fault current contribution from an IBR is much lower than from a synchronous machine and is limited by the inverter's current rating and controls. That has direct implications for protective relaying and coordination in networks with high IBR penetration. Chapter 8 covers the protection side.

3.3 Frequency and Reactive Response

Frequency response is different as well. Inverters can be controlled to provide frequency response, but not in the intrinsic way a spinning machine does. The magnitude, rate, and duration of an IBR's frequency response depend on its control strategy and on operating conditions.

Reactive behavior follows the same pattern. An IBR can supply reactive power very quickly and precisely, within the limits its control strategy and current rating allow. Understanding those control strategies, and what high IBR penetration does to voltage stability and synchronization, is a core planning task.

3.4 The Aggregate Matters More Than the Unit

The aggregate behavior of IBRs almost always matters more than the behavior of any single unit. DG is made up of a large number of small, independently operated resources. Utility-scale plants are often made up of hundreds of inverters, commonly running the same firmware. When they share a control response to the same voltage dip, they act together, and the system sees one large event rather than many small ones.

3.5 From Outcome Requirements to Performance Requirements

For years the standards addressed inverter behavior indirectly, through system performance, operating coordination, and study requirements, without regulating inverter operation itself. That approach was outcome-focused, and it left gaps that the disturbance record exposed. Order No. 901 directed NERC to close them with performance requirements addressing ride-through, post-disturbance ramp rates, phase lock loop synchronization, and other known causes of IBR tripping or momentary cessation.

PRC-029-2, Frequency and Voltage Ride-through Requirements for Inverter-Based Resources, is the result for ride-through. It applies to Generator Owners of BES IBRs and of non-BES IBRs that meet the Category 2 criteria, and it became effective October 1, 2026, replacing PRC-029-1. Compliance is phased in: the design elements of R1 through R3 apply to Category 2 IBRs starting January 1, 2027, and the performance elements wait until the PRC-028-1 disturbance monitoring capability is in place. Inverter-based generation is now measured against explicit performance criteria, not only against the legacy assumptions built around synchronous machines.

Chapter Summary

Inverter-based generation responds to grid conditions and faults according to its controls, not its physics, and its behavior can differ sharply from synchronous generation. Large numbers of similar inverters acting together create system behaviors no single unit would. The framework treated that behavior through system-level studies for years. It now also sets mandatory ride-through requirements for registered IBRs through PRC-029-2, with the performance elements phased in as PRC-028-1 disturbance monitoring capability comes into place.

From the Field

Inverter-based generation behaves differently from synchronous generation in steady state and very differently during disturbances. Know your settings. If you can't produce them, you can't defend them.

Chapter 4

Visibility, Data Exchange, and Situational Awareness Considerations

4.1 Utility-Scale Solar in the Control Room

Integrating DG and utility-scale solar depends on the system operator keeping reliable situational awareness. Knowing resource status, performance, and operating condition is what lets operators manage normal and contingency conditions.

Utility-scale solar is typically brought into the control center through telemetry, supervisory control, and communication channels that give real-time visibility of output and grid conditions. Transmission Operators and Balancing Authorities use that data to understand conditions, manage transfers, and plan for system response. The requirements are much like those developed for other generation.

4.2 DG Through Net Load

DG presents a different visibility profile. Individual distributed resources are usually not observable to bulk system operators, particularly at lower distribution voltages. Their presence shows up indirectly: in net load behavior, in aggregated profiles, or in distribution data shared with transmission entities. That indirect visibility shapes how reliability assessments are done.

4.3 Transmission and Distribution Data Exchange

Data exchange between transmission and distribution utilities fills knowledge gaps between the entities involved in grid operations. Sharing aggregated feeder data and DER estimates for situational awareness does not extend transmission control onto the distribution system. It is coordination, and coordination and data exchange are part of the reliability framework.

That exchange is moving from good practice toward obligation. Order No. 901 directs NERC to develop standards for data sharing that cover registered IBRs, unregistered IBRs, and IBR-DERs in the aggregate. FERC also noted that unregistered IBRs and IBR-DERs, while not subject to the standards themselves, may have to provide data to their Transmission Owners and Distribution Providers under their interconnection agreements.

Situational awareness matters most in a few recurring circumstances with IBRs:

• Rapid changes in system conditions from weather or control actions.
• A sudden change in output from one large resource, or a coordinated change across many resources, that conventional real-time monitoring doesn't readily show.

4.4 When the Model and the Measurement Disagree

Entities must have situational awareness commensurate with the functions they are registered for, and they can achieve it in different ways. Visibility interacts with modeling and forecasting. Operations planning relies on assumptions about how IBRs will act, and those assumptions become operating instructions. When real-time measurements depart from the modeled inverter behavior during abnormal conditions, the operator's picture is wrong at exactly the wrong moment.

Visibility is a system-level issue shaped by technology, operations, and the control framework. The question is not whether the operator sees every resource. It is whether the operator has enough information to perform the registered function.

Chapter Summary

Visibility and situational awareness for IBRs depend on resource type and connection. Utility-scale solar and storage tend to be visible; distributed solar affects operations less directly. The obligation is awareness sufficient to perform registered functions, not complete visibility of every resource, and Order No. 901 is formalizing the data exchange that supports it.

From the Field

The operator can only manage what the operator can see. DG that's invisible to the operator is invisible to the operator's reliability decisions. Aggregated DG output moves with weather, time of day, and system conditions. If the operator can't see the aggregate, the operator is dispatching the rest of the resource mix on assumed DG availability. Visibility is a precondition for coordination. Without it, the framework can't enforce performance the operator can't measure.

Chapter 5

Functional Responsibility, Registration, and Applicability Frameworks

5.1 Responsibility Follows Function

Integrating DER and utility-scale solar into the reliability framework comes down to functional responsibility, registration, and applicability. Accountability for reliability performance is assigned by function. Entities are listed on the NERC Compliance Registry by the functions they perform for their facilities: Generator Owner, Generator Operator, Transmission Operator, Balancing Authority, and the rest. Obligations attach to those functions, not to resource types. That is how inverter-based resources enter the framework: through the registration of functional roles, not through a technology category.

5.2 Category 1 and Category 2

Utility-scale solar is more likely to meet the registration criteria because of its size, its connection, and its participation in the Bulk Power System. Once registered, the standards that apply depend on the functions performed and the Facilities involved.

The registration picture changed in 2026. The NERC definitions of Generator Owner and Generator Operator now have two categories. Category 1 is the traditional GO and GOP for generating Facilities. Category 2 covers owners and operators of non-BES IBRs that have or contribute to an aggregate nameplate of 20 MVA or more, delivered through a system designed primarily for that purpose to a common point of connection at 60 kV or above. NERC and the Regional Entities began processing Category 2 registrations in batches in August 2025 and continued through April 2026, and registrants were placed on the registry with an effective registration date of May 15, 2026.

5.3 Aggregation Counts

The criteria look at aggregate nameplate at a common point of connection, not at each project in isolation. WECC's registration FAQ is direct about it: if multiple facilities aggregate to 20 MVA or more at a common point of connection at 60 kV or above, all of them are Category 2 assets, and all of their owners and operators need to register. A project coming online in phases that meets the Category 2 criteria in early phases needs to start the registration conversation then, not when the final phase reaches COD. A GO that has not yet settled on its GOP is advised to register as both until that is resolved.

5.4 Applicability Is Set Requirement by Requirement

Applicability is determined at the standard and requirement level, and it is not the same for every registered function. A Category 2 registration does not make every GO and GOP standard applicable on day one. NERC found that many standards refer to the BES or to BES-based defined terms, which would exclude Category 2 IBRs, and it is assessing each standard individually. Its compliance-dates document (Rev. 1.5, August 4, 2026) sorts the standards into three groups: eight standards with a May 15, 2026 Category 2 date; IBR standards approved with no Category 2 date shown; and standards listed as "Requires Modification":

Check the current revision before you build a compliance calendar; NERC updates it quarterly.

5.5 DG Outside the Registry

Individual DG resources generally do not meet the registration thresholds. Customer-owned and third-party-owned DG are typical examples of non-registered resources. DG therefore sits outside the direct applicability of the Reliability Standards even where its aggregate effect is material. Aggregation through a central control system or a market program does not, by itself, bring a resource into registration. The resource has to meet the criteria.

Two similar inverter-based technologies get different treatment because they play different functional roles and have different impact. The framework limits direct reliability obligations to parties that control equipment contributing to bulk system dynamics, while Order No. 901's data and study directives reach the aggregate impact of dispersed resources.

Chapter Summary

Utility-scale solar falls under direct oversight because of its functional role. Since May 15, 2026, owners and operators of non-BES IBRs of 20 MVA or more at 60 kV or above do as well, registered as Category 2 GOs and GOPs, with applicability phased standard by standard. Individual DG stays outside, while its aggregate effect is handled through data sharing and studies.

From the Field

A facility's registration status drives its compliance scope, audit posture, and enforcement exposure. Treating it as paperwork misses what it establishes.

Chapter 6

Reliability Coordination Across Transmission and Distribution Boundaries

6.1 Who Has Authority

Coordination between transmission and distribution systems is a growing concern as DG and utility-scale PV expand. Inverter-based resources bring new operating characteristics and interdependencies, and they can be handled within existing lines of authority without redefining who is responsible for what.

Transmission reliability depends on Balancing Authorities, Transmission Operators, and Reliability Coordinators working in concert, with a shared understanding of conditions, solid communication, and established operating procedures. Large utility-scale solar plants tie into those procedures through defined interfaces and operating protocols. For DG the coordination is indirect. Distribution-connected inverters affect net load, voltage, and transmission flows, and they usually operate under distribution system control. Transmission and distribution utilities have to coordinate to manage that shared risk.

6.2 Coordination Without Unified Control

The need for coordination is well recognized. There is no requirement for unified control. Authority is assigned by registered function. A Transmission Operator has no direct control over a distribution-connected generator, and a distribution operator does not perform bulk system coordination functions. The two rely on information exchange, operating agreements, and communication channels.

That coordination matters in normal and abnormal conditions. Weather, environmental events, and control actions can drive rapid changes in inverter output. Information has to flow both ways without blurring the operational boundary.

6.3 The Reliability Coordinator's Wide-Area View

Reliability Coordinators perform wide-area coordination. The NERC Glossary defines the RC as the highest level of authority responsible for Reliable Operation of the BES, with the Wide Area view and the authority to prevent or mitigate emergencies in next-day analysis and real time. That authority is defined by function and scope, not by resource type. As IBR penetration grows, transmission entities have to account for effects that originate on the distribution system when they perform RC and TOP functions.

6.4 Where Coordination Breaks Down

Coordination problems show up when transmission and distribution make different assumptions about how resources behave and what can be seen, and the system response after a disturbance turns out different from what either assumed. The 2020 San Fernando disturbance is a clean example. NERC and WECC found that Southern California Edison saw net load increases of about 5 MW and 80 MW on the two fault events that it attributed to solar PV DER tripping, alongside the reductions at BPS-connected solar plants. Nobody in the transmission control room dispatched that DER, and it still moved.

6.5 The Standards Are Catching Up

Order No. 901's final milestone requires NERC to submit, by November 4, 2026, standards addressing planning and operational studies for registered IBRs, unregistered IBRs, and IBR-DERs in the aggregate. The framework is still built on clear lines of control, but T&D information exchange is becoming a standards question, not only a courtesy.

Chapter Summary

Coordination between transmission and distribution grows more important as the grid integrates more IBRs. It runs on communication and information sharing rather than central control. Current reliability concepts keep clear lines of control while adding coordination obligations for high DG and utility-scale solar penetration, and Order No. 901 is bringing IBR-DERs in the aggregate into the standards for data, models, and studies.

From the Field

The T&D boundary used to be a clean division. DG erased it. Reliability events now cross the boundary because the assets do. Coordination between TOPs and Distribution Providers was loosely structured before DG. It can't be anymore. Operating decisions on either side affect the other. The standards covering this coordination are still developing. Programs that wait for them to mature are operating in last cycle's framework.

Chapter 7

Modeling, Studies, and Reliability Assessment Context

7.1 Explicit Models and Net Load

Modeling and studies are how the industry understands what DG and utility-scale solar do to bulk system reliability. As inverter-based generation grows, the assumptions, model representations, and techniques used in planning and operational studies carry more weight.

Planning rests on models of how components will behave: how generators operate, how customer load behaves, and how the topology looks under different scenarios. Utility-scale solar is typically modeled explicitly, with assumptions about availability, output variability, and operating strategy, and those assumptions feed thermal, voltage, and stability evaluations. DG is usually accounted for through net load forecasts or aggregated profiles with distribution-related assumptions. That reflects both the small individual effect of each resource and its place in the system.

7.2 Models Built for Inverters

IBRs need different modeling approaches than synchronous machines. Models have to represent dynamic and fault response and the control features that drive aggregate behavior. MOD-026-2, Verification and Validation of Dynamic Models and Data, took effect April 1, 2026, and replaced MOD-026-1 and MOD-027-1. It applies to BES IBRs and to non-BES IBRs meeting the Category 2 criteria, and it brings electromagnetic transient (EMT) model requirements for IBRs into the Transmission Planner's dynamic model requirements.

7.3 Assessments and Uncertainty

Planning Coordinators and Transmission Planners run large numbers of assessments to test whether the system performs acceptably across expected and unexpected conditions, including periods of high IBR output. Operational studies cover near-term conditions and contingencies, and IBR variability adds uncertainty that has to be handled through forecasting, reserve management, and operating practice.

All models and studies are approximations. The discipline is to use conservative assumptions, run sensitivities, and keep updating the analysis as experience accumulates, rather than pretend to exact answers.

7.4 Guidance, Alerts, and Requirements

NERC reliability guidelines and technical reports on IBR modeling are advisory. They raise awareness and build consensus, but they are not mandatory requirements. NERC's own data shows the limits of that approach. In its May 20, 2025 Level 3 Alert on IBR performance and modeling, NERC, citing the findings of its earlier Level 2 Alert, stated that the voluntary recommendations in its guidelines were not being implemented by GOs and that many GOs did not have requested facility data readily available. The Level 3 Alert issued Essential Actions to Transmission Owners, Transmission Planners, Planning Coordinators, and registered GOs. Essential Actions are not Reliability Standards, but they are a clear signal of what NERC expects.

Chapter Summary

Models and studies are how the effect of DG and utility-scale solar on bulk system performance gets quantified. Utility-scale solar is modeled explicitly; DG is mostly represented in aggregate through net load and profiles. MOD-026-2 now sets dynamic and EMT model verification requirements for registered IBRs, and NERC's Level 3 Alert makes clear that voluntary guidance alone did not produce adequate models.

From the Field

Planning models that don't accurately represent DG produce planning conclusions that don't predict operational reality. Generic DG models give generic answers. The system has specific resources at specific locations with specific capabilities; the planning study has to reflect that. Model validation against real performance is the discipline that turns DG and solar studies into reliability tools, not engineering exercises.

Chapter 8

Protection, Control, and Performance Considerations

8.1 Protection Built on Synchronous Assumptions

Protection and control are central to reliable operation of the bulk system, and inverter-based generation affects both transmission and distribution protection. Existing protection schemes were developed around synchronous generators and radial power flow. IBRs bring different fault current behavior, bidirectional flow, and faster response, all of which can affect protection sensitivity, coordination, and selectivity at high penetration.

8.2 Utility-Scale Solar Plants

Utility-scale solar plants are usually protected with coordinated practices that apply to transmission systems. Their protection schemes are developed and reviewed in interconnection studies and planning work for compatibility with bulk system protection. The Facility interconnection standards, FAC-001 and FAC-002, are where those requirements and studies are anchored.

8.3 Distributed Generation

DG protection is different. Individual DG is often protected primarily for the equipment and for safety, and less for the power system. The effect of DG on protection elsewhere, especially transmission protection interacting with a tightly coupled distribution system, should not be overlooked. IEEE 1547-2018 is the IEEE standard for interconnection and interoperability of DER. It is not a NERC Reliability Standard.

8.4 Control Interaction

Control behavior matters as much as protection. Because IBRs respond according to programmed logic rather than physical behavior, control interaction among thousands of resources can affect voltage, frequency, and damping. Protection and control are acceptable from a reliability standpoint only if they do not degrade stability and they clear faults adequately. That judgment rests on analysis, event investigation, and operating experience.

8.5 The Standards That Now Apply by Name

Protection and performance for IBRs are no longer left to guidance. The standards a BES IBR owner deals with today:

These standards still require coordination, maintenance, and performance regardless of technology. What is new is that ride-through, disturbance monitoring, and post-event mitigation are now written specifically for inverters.

Chapter Summary

Inverter-based resources change how faults are cleared and analyzed, how resources are controlled, and how power flows. The reliability framework has moved from guidance to mandatory IBR performance and monitoring requirements: PRC-029-2 for ride-through, PRC-028-1 for disturbance monitoring, and PRC-030-1 for unexpected events, with PRC-024-4 now limited to synchronous and Type 1 and 2 wind resources.

From the Field

Owners and operators of DG and solar that meet registration thresholds are full registered entities. For BES solar the compliance scope tracks thermal generation; Category 2 scope is phased standard by standard. The compliance gap that is easiest to underestimate: protection coordination. PRC-relevant? Often yes. The standards apply by function, not by fuel. Documentation has to keep pace with operations. A solar plant that trips during a disturbance and doesn't analyze the trip in a documented way is a finding waiting to happen, and under PRC-030-1 the analysis is now a requirement.

Chapter 9

Oversight, Compliance Monitoring, and Risk-Based Governance

9.1 The Same CMEP

DG and utility-scale solar are overseen the same way as everything else in the Compliance Monitoring and Enforcement Program (CMEP): against approved Reliability Standards, with risk-based prioritization. To understand oversight of inverter-based generation, keep three things separate: the compliance obligation, the operational impact, and the characteristics of the technology.

Compliance monitoring evaluates whether registered entities meet the standards that apply to their functions and Facilities. For registered utility-scale solar, the monitoring processes are the same as for any other generation. The scope does not distinguish among technologies; it follows the functions and Facilities named in each standard.

9.2 Risk-Based Oversight

Risk-based oversight shapes how IBRs are treated in compliance activity. Regional Entities look at how registered entities account for IBR behavior in their planning, operations, and situational awareness where a requirement calls for it. The 2026 CMEP Implementation Plan, as NERC describes it in its ORCP and CMEP Annual Report published February 11, 2026, shifts focus from compliance evaluation toward proactive risk mitigation.

That report also shows where operations and planning noncompliance is being reported. The top ten O&P standards for 2025 include PRC-024, PRC-019, PRC-025, VAR-002, MOD-025, MOD-026, and MOD-027. These are the standards most often reported in 2025, and several have since been replaced for IBRs: PRC-024 by PRC-029-2, and MOD-027 by MOD-026-2.

9.3 Event-Driven Review

Event review is a central part of IBR oversight. After events involving solar or DG, the ERO and Regional Entities analyze the performance of affected facilities, and those reviews can lead to compliance follow-up where a requirement was not met. Two newer standards build event review into the obligations themselves. PRC-030-1 requires Generator Owners of BES and Category 2 IBRs to identify, analyze, and mitigate unexpected IBR performance. EOP-004-5, effective October 1, 2027, adds a reportable event type for IBR loss following a Disturbance, calculated by the Balancing Authority from telemetered IBR output.

9.4 Enforcement

Enforcement for inverter-based generation works the same as for any other resource. Noncompliance determinations rest on the requirement language and the evidence. The presence of IBRs does not change enforcement thresholds or requirements.

9.5 DG Outside Enforcement

Individual DG is not in the direct compliance scope, because the resource is not registered and does not perform a registered bulk system function. The Reliability Standards are not enforced against unregistered distributed resources. Their reliability effect reaches the framework another way: through the registered entities that plan and operate around them, and through data obligations in interconnection agreements. Compliance oversight ensures the mandatory obligations are met. Reliability performance still comes from coordination, awareness, and monitoring.

Chapter Summary

DG and utility-scale solar are managed through the existing CMEP and enforcement processes, according to the functions involved. Risk-based oversight focuses attention on IBR effects, and new standards now write event analysis and IBR loss reporting into the requirements. Individual DG remains outside enforcement; its aggregate effect is handled through the entities that plan and operate the system.

From the Field

"It's distributed generation, so the standards don't apply." That depends on the configuration. Facilities aggregating at a common point can collectively trigger registration. "We're under threshold so we're not subject." The threshold isn't always nameplate alone. Point of interconnection, voltage, and aggregation all factor in. "We installed inverters that meet IEEE standards." IEEE compliance is different from NERC compliance. Both may apply; meeting one doesn't satisfy the other.

Chapter 10

Disturbance Experience and Reliability Lessons Involving Solar Resources

10.1 What the Record Shows

Disturbance analysis is where the industry learned how DG and utility-scale solar actually interact with the bulk system. NERC's May 2025 Level 3 Alert summarizes it: since 2016, NERC has analyzed numerous major events totaling more than 15,000 MW of unexpected generation reduction, events that current planning processes did not predict and that NERC studies could not replicate. NERC has issued ten major event reports and four Level 2 Alerts on the subject. Three of the reports frame the story.

10.2 Common-Mode Behavior

The pattern repeats. Large numbers of inverters share the same control response to voltage and frequency changes, so they react together and shape how the system recovers. Momentary cessation, inverter-level tripping, and slow return to pre-disturbance output show up across events. Combined effects matter more than individual resource characteristics.

10.3 DG in the Event Data

Distribution-connected DG plays an indirect role in these events. Most of it is not identified in event data, but its effect on net load, voltage, and system behavior is often observable. Operators often cannot tell how much of a voltage response or flow change came from DG, especially where visibility is poor. At San Fernando, SCE did put a number on it.

10.4 Models Did Not Match Reality

Disturbances showed the gap between models and reality. Actual IBR response did not match planning and operational assumptions, which argues for more conservative assumptions and better dynamic and EMT modeling. Protection and control interactions with inverter behavior recur in the findings as well.

10.5 From Lessons to Requirements

NERC's disturbance reports do identify inverter behavior, settings, and controls as causes of the output reductions. They also document the conditions, operating practices, and responses around each event, which is what makes them useful. For years the response was guidance, outreach, and alerts. Order No. 901 turned those lessons into mandatory standards: ride-through in PRC-029-2, disturbance monitoring in PRC-028-1, and event mitigation in PRC-030-1. Operating experience will keep validating or correcting what the industry thinks it knows as DG and utility-scale solar become more widespread.

Chapter Summary

Disturbances involving DG and utility-scale PV forced a hard look at IBR stability, protection, and coordination. Event analysis documented common-mode inverter behavior that planning models missed, and it gave FERC and NERC the record that turned guidance into mandatory IBR performance, monitoring, and mitigation standards.

From the Field

In my view, audit attention on DG and solar is increasing, and Regional Entity posture has shifted from accommodating new technology to enforcing the standards consistently across all generation. Findings on DG and solar projects will keep clustering around protection settings, ride-through capability, and modeling accuracy, the same areas the disturbance reports keep pointing to. Self-Reports on DG and solar should increase as programs mature. The auditor will eventually find what the Self-Report could have surfaced first.

Chapter 11

Common Misconceptions About Distributed Generation and Utility-Scale Solar

There is a lot of confusion in the industry about the role of IBRs on the bulk electric system. Much of it is assumed knowledge rather than understanding rooted in how the framework works, and it gets in the way of good planning and evaluation, especially for DG and utility-scale solar.

11.1 "Inverter-Based Resources Are Not Reliable"

This is a myth. Reliable operation comes from system design, operations, and controls, whatever the resource type. Systems that include distributed resources and large utility-scale solar can perform reliably when they are designed, operated, and controlled with the characteristics of those resources in mind. The disturbance record is not proof that inverters are unreliable. It is proof that settings, controls, and models were not managed well enough.

11.2 "DER Must Be Held to the Same Standards as Utility Infrastructure"

Another common claim is that DER must be held to the same Reliability Standards as traditional utility infrastructure. The standards look at functional role and system-wide impact, not technology alone. In my view, applying the same standards to every DER because DER is a large share of the system would be neither well-defined nor enforceable. The framework's answer is to register what performs a bulk system function, including Category 2 IBRs, and to bring DER in the aggregate into data and studies.

11.3 "Inverter-Based Resources Don't Contribute to Reliability"

There is a prevailing notion that IBRs play no role in reliability operations. They are very different from the synchronous machines our understanding of reliability grew up around, but they can contribute, including fast reactive support and controllable frequency response, in ways the old doctrine didn't anticipate. Measure the grid's performance and assess the value of every resource that affects it.

11.4 "The Standards Never Needed to Change"

The earlier edition of this reference argued that more solar did not require changes to the Reliability Standards. The record overtook that argument. The framework did change, through the normal standards process: the IBR Registration Order, Order No. 901, and the PRC-028, PRC-029, PRC-030, and MOD-026-2 standards. What did not change is the structure. Obligations still attach to functions and Facilities.

11.5 "DG Visibility Gaps Are an Oversight Failure"

Some say DG visibility gaps reflect a failure of reliability monitoring and oversight. Visibility follows responsibility. The framework does not require visibility of every resource, only what each responsible entity needs to perform its registered functions.

11.6 "Modeling Uncertainty Means Reliability Uncertainty"

Modeling uncertainty is often confused with reliability uncertainty. All reliability studies depend on assumptions and approximations. IBRs created new modeling challenges, and the answer is conservative assumptions, validated models, and ongoing research, not throwing out established modeling practice.

11.7 Why the Corrections Matter

Correcting these misunderstandings keeps the debate on how networks actually perform and away from arbitrary judgments about technologies. Clarifying where DG and utility-scale solar sit in the reliability framework helps align stakeholder expectations and put effort where it does the most good: coordinating existing activities, raising awareness of the issues that matter, and enforcing established requirements for everyone involved.

Chapter Summary

Confusion about DG and utility-scale solar usually comes from treating technology as the source of the reliability obligation, or from assuming that more PV automatically means more requirements on everyone. The framework uses function-based, technology-neutral rules focused on grid performance and clear responsibilities, and since 2023 it has added IBR-specific performance requirements within that structure.

From the Field

The framework will continue to extend toward DER. The direction is clear; the pace is uncertain. Aggregated DER as a single capacity resource is the next reliability question. The standards aren't there yet. The market is. Programs that anticipate the framework's direction get ahead. Programs that wait for it to mature operate behind.

Chapter 12

Evolving Resource Mix and Reliability Framework Implications

12.1 No Longer Emerging

The rapid growth of distributed and utility-scale solar is a direct result of the shifting resource mix. What was once an emerging technology is now an established part of the generation mix, of grid operations and planning, and of reliability analysis and tools. The focus belongs on keeping the framework adaptable, not on tearing it down.

More IBRs mean more dynamic interaction among resources, loads, and networks. Variability, large-scale aggregation, and coordinated controls add complexity to what used to be straightforward. None of it overturns fundamental reliability principles: clear outcomes, coordination, and functional accountability.

12.2 DER Aggregation and the Market

The DG versus utility-scale distinction will keep evolving. Advanced grid management, communications, and control techniques will change what each category looks like. Resources that operate like traditional reliability resources are likely to be brought within the standards. Resources whose reliability effect runs only through net load and T&D coordination are likely to stay outside the formal standards.

Markets are moving faster than reliability rules here. FERC Order No. 2222 (September 17, 2020) requires RTOs and ISOs to let DER aggregations participate in their capacity, energy, and ancillary service markets, with a minimum aggregation size no larger than 100 kW, and requires coordination among the RTO or ISO, the aggregator, the distribution utility, and the retail regulator. An aggregation that clears a market as a resource raises the reliability question the standards have not yet fully answered: who is accountable for its performance on the bulk system.

12.3 What to Watch

• Order No. 901's final milestone: standards for planning and operational studies covering registered IBRs, unregistered IBRs, and IBR-DERs in the aggregate, due at FERC by November 4, 2026.
• EOP-004-5, effective October 1, 2027, with its new IBR loss event type.
• NERC's quarterly revisions of the compliance-dates document for Category 2 GOs and GOPs, including the CIP and EOP standards still listed as requiring modification.

12.4 Measured Change

Risk-based oversight focuses attention where it is most needed. Rooftop PV does not automatically call for more requirements, but it does require ongoing assessment of rules, guidelines, and practice. The changing mix also makes coordination across organizational and system boundaries more important. Transmission and distribution utilities, planners, operators, and market participants all need clear authority, communication, and a shared understanding of responsibilities.

Reliability frameworks are not static. They evolve through technical analysis, lessons from disturbances, and stakeholder input. The integration of IBRs into reliability roles is happening through analysis, coordination, and rigorous application of reliability principles, carried into new standards where the record demanded it, and not through relabeling roles and functions.

Chapter Summary

The growth of distributed and utility-scale solar brings new challenges without overturning fundamental reliability principles. The framework is accommodating the transition while keeping its accountability, risk-based, and performance-based structure, and it is adding IBR-specific requirements as the record warrants. Reliability integration is a system-wide effort that depends on coordination and understanding of the system, not on technology alone.

Glossary

Glossary

Balancing Authority (BA). The responsible entity that integrates resource plans ahead of time, maintains Demand and resource balance within a Balancing Authority Area, and supports Interconnection frequency in real time.

Bulk Electric System (BES). Unless modified by the inclusions and exclusions in the definition, all Transmission Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or higher, not including facilities used in the local distribution of electric energy.

Category 2 Generator Owner / Generator Operator. The entity that owns and maintains, or operates, non-BES Inverter-Based Resources that have or contribute to an aggregate nameplate capacity of 20 MVA or more, connected through a system designed primarily for delivering that capacity to a common point of connection at 60 kV or above.

Distributed Energy Resource (DER). A generator or energy storage technology connected to a distribution system that can provide Real Power in non-isolated parallel operation with the Bulk-Power System, including one connected behind the meter of an end-use customer supplied from a distribution system.

Distribution Provider (DP). Provides and operates the "wires" between the transmission system and the end-use customer, performing the distribution function at any voltage.

Generator Operator (GOP). The entity that operates generating Facilities and supplies energy and Interconnected Operations Services (Category 1), or operates qualifying non-BES Inverter-Based Resources (Category 2).

Generator Owner (GO). The entity that owns and maintains generating Facilities (Category 1), or owns and maintains qualifying non-BES Inverter-Based Resources (Category 2).

IBR-DER. FERC Order No. 901's term for IBRs connected to the distribution system that in the aggregate have a material impact on the Bulk-Power System.

Inverter-Based Resource (IBR). A plant or facility of individual devices that export Real Power through a power electronic interface such as an inverter or converter, operated together as a single resource at a common point of interconnection. Examples include solar PV, Type 3 and Type 4 wind, battery energy storage, and fuel cells.

Momentary cessation. A mode in which an inverter stays electrically connected but injects no current during voltage conditions outside its continuous operating range (as described in FERC Order No. 901).

Reliability Coordinator (RC). The entity that is the highest level of authority responsible for the Reliable Operation of the BES, with the Wide Area view and the operating tools, processes, and authority to prevent or mitigate emergencies in next-day analysis and real time.

Ride-through. A generating facility staying connected to and synchronized with the system during disturbances within defined ranges of frequency and voltage (as defined in FERC Order No. 2003 and cited in Order No. 901).

Transmission Operator (TOP). The entity responsible for the reliability of its local transmission system, which operates or directs the operation of the transmission Facilities.

Transmission Planner (TP). The entity that develops a long-term (generally one year and beyond) plan for the reliability of the interconnected bulk electric transmission systems within its portion of the Planning Authority area.

This glossary includes selected terms based on the NERC Glossary of Terms and FERC orders. It is for informational purposes only and is not a substitute for or authority on the definitions in the official NERC Glossary of Terms.

How Energy Compliance Can Help

How Energy Compliance Can Help

Every Energy Compliance engagement is overseen by a senior practitioner.

Registration and applicability analysis

BES, Category 2, or outside the registry: the answer turns on configuration, voltage, and aggregation. EC's registration and applicability analysis sorts it out, including which standards apply to a Category 2 registration and when.

Compliance program design and audit readiness

New Category 2 registrants need a program before they need an audit. EC provides compliance program design and improvement, NERC compliance program support, interpretation, and audit preparation, and RSAW production and data request strategy for PRC-028, PRC-029, PRC-030, and MOD-026 evidence. When an audit or enforcement matter arrives, EC provides audit and enforcement support (non-advocacy), audit defense with Notice of Penalty response and settlement posture, and mitigation planning and Self-Report development.

Senior advisory and program review

EC also provides NERC reliability and compliance advisory support and senior advisory on specific, complex reliability questions; reliability governance and program assessments; regulator-perspective program reviews; operational and engineering reliability alignment; training and executive briefings on reliability frameworks; and industry engagement in standards development and working-group participation. Each engagement is scoped to the entity's role, function, and bulk system impact.

WattOps Compliance

Ride-through documentation, disturbance records, and model submittals are evidence. WattOps Compliance is EC's NERC compliance evidence platform (wattopscompliance.com). EC will run one standard at one facility through WattOps at no cost (CIP standards excluded).

RenewOps

Solar and storage operators live on their operations data. RenewOps is EC's renewable operations monitoring and analytics platform, with a Data Center module.

If you aren't sure which side of the line your plant sits on, that is the conversation to have before your Regional Entity has it for you.

Website: energycomplianceinc.com · Email: [email protected]

Phone: 763.438.4427

About the Author

About the Author

Rob Smith is the Founder and Principal of Energy Compliance, Inc., with more than thirty years in the industry on every side of the system. He began in control-room operations as a Reliability Coordinator, Transmission Operator, and Power System Operator across RTO/ISO and utility control centers. On the regulator side, he was a senior compliance auditor and subject matter expert for NERC Reliability Standards. He audited grid facilities, evaluated mitigation adequacy, participated in risk-based oversight of utility mitigation activities, and supported the development of violation notifications and settlements in FERC-directed enforcement actions. He conducted a regulatory audit in the Sultanate of Oman against the Sultanate's Sector Law and Grid Code.

He founded Energy Compliance, Inc. to deliver senior regulator-side compliance authority without the layered staffing and billable-hour overhead of larger firms.

Education:

• MBA, Energy Management, University of Mary
• MSL, Compliance Law, Fordham Law University
• BAS, Energy Management, Bismarck State College
• BAS, Mechanical Engineering, Metallurgy minor, University of Florida
• BAS, Criminology, St. Petersburg College (State Law Enforcement Certification)
• AAS, Power Plant Technology, Bismarck State College
• AAS, Electrical Transmission System Technology, Bismarck State College

Certifications: NERC Lead Auditor training; previously NERC-certified at the Reliability Coordinator level; 1st Class A Boiler Engineer License, Minnesota.

About Energy Compliance, Inc.

About Energy Compliance, Inc.

Energy Compliance, Inc. is an independent consulting and advisory firm based in Bloomington, Minnesota, focused exclusively on electric reliability, cybersecurity reliability, and regulatory compliance for organizations connected to the North American Bulk Electric System.

We support registered entities, including Generator Owners and Operators, Transmission Owners and Operators, Reliability Coordinators, Balancing Authorities, and Distribution Providers. Our work spans NERC Reliability Standards, FERC orders, RTO/ISO market participation rules, Regional Entity oversight, and state regulatory frameworks.

We do this work differently than larger consulting firms. A senior practitioner with regulator-side experience oversees every engagement. We staff for outcomes, not billable hours. Our deliverables are written to be operationally executable and audit-defensible, structured for the auditor's question rather than the consultant's binder. Where automation can replace manual work, we build the automation. Where senior judgment is required, the senior is in the room.

Energy Compliance is not affiliated with, sponsored by, or endorsed by the North American Electric Reliability Corporation, the Federal Energy Regulatory Commission, or any Regional Entity.

Learn more at energycomplianceinc.com.

Sources and Authorities

Sources and Authorities

• Federal Energy Regulatory Commission, Order No. 901, Reliability Standards to Address Inverter-Based Resources, 185 FERC ¶ 61,042, Docket No. RM22-12-000 (issued October 19, 2023), 88 Fed. Reg. 74250 (October 30, 2023). https://www.govinfo.gov/content/pkg/FR-2023-10-30/pdf/2023-23581.pdf
• Federal Energy Regulatory Commission, Order No. 2222, Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators, 172 FERC ¶ 61,247, Docket No. RM18-9-000 (issued September 17, 2020). https://www.ferc.gov/sites/default/files/2020-09/E-1_0.pdf
• Federal Energy Regulatory Commission, FERC Order No. 2222: Fact Sheet (September 28, 2020). https://www.ferc.gov/media/ferc-order-no-2222-fact-sheet
• North American Electric Reliability Corporation, Glossary of Terms Used in NERC Reliability Standards (Bulk Electric System; Distributed Energy Resource, effective April 1, 2026; Generator Owner and Generator Operator, effective January 1, 2026; Inverter-Based Resource; Reliability Coordinator; Transmission Operator; Transmission Planner; Balancing Authority; Distribution Provider). https://www.nerc.com/glossary-of-terms
• North American Electric Reliability Corporation, Rules of Procedure, Appendix 5B, Statement of Compliance Registry Criteria, Revision 8 (effective June 27, 2024). https://www.nerc.com/globalassets/who-we-are/rules-of-procedure/appendix-5b.pdf
• North American Electric Reliability Corporation, Reliability Standards Compliance Dates for Generator Owners and Generator Operators, Inverter-Based Resource Registration Initiative Supplemental. https://nerc.com/pa/Stand/202401%20Rules%20of%20Procedure%20Definitions%20Alignment%20GO/ComplianceDatesforGOs_GOPS.pdf
• Western Electricity Coordinating Council, FAQ, Inverter-Based Resource (IBR) Registration Initiative, Category 2 Generator Owner (GO) and Generator Operator (GOP) Registration Process (2026). https://www.wecc.org/sites/default/files/documents/program/2026/faq-ibr-registration-initiative-category-2-go-and-gop-registration-process.pdf
• North American Electric Reliability Corporation, Reliability Standard PRC-029-2, Frequency and Voltage Ride-through Requirements for Inverter-Based Resources (effective October 1, 2026). https://www.nerc.com/globalassets/standards/reliability-standards/prc/prc-029-2.pdf
• North American Electric Reliability Corporation, Project 2025-05, PRC-029-2 Implementation Plan (citing Order No. 909, 192 FERC ¶ 61,076, July 24, 2025). https://www.nerc.com/globalassets/standards/projects/2025-05/final-posting/project-2025-05-implementation-plan_-7.26.2026-clean-version.pdf
• North American Electric Reliability Corporation, Reliability Standard PRC-030-1, Unexpected Inverter-Based Resource Event Mitigation (effective October 1, 2026). https://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-030-1.pdf
• North American Electric Reliability Corporation, Reliability Standard PRC-024-4, Frequency and Voltage Protection Settings for Synchronous Generators, Type 1 and Type 2 Wind Resources, and Synchronous Condensers (effective October 1, 2026). https://www.nerc.com/globalassets/standards/reliability-standards/prc/prc-024-4.pdf
• North American Electric Reliability Corporation, PRC Reliability Standards listing (PRC-024-4, PRC-028-1, PRC-029-2, PRC-030-1 status and effective dates). https://www.nerc.com/standards/reliability-standards/prc
• North American Electric Reliability Corporation, Reliability Standard PRC-019-2, Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection. https://www.nerc.com/globalassets/standards/reliability-standards/prc/prc-019-2.pdf
• North American Electric Reliability Corporation, Reliability Standard MOD-026-2, Verification and Validation of Dynamic Models and Data (effective April 1, 2026). https://www.nerc.com/globalassets/standards/reliability-standards/mod/mod-026-2.pdf
• North American Electric Reliability Corporation, Project 2020-06, MOD-026-2 Implementation Plan (retiring MOD-026-1 and MOD-027-1). https://www.nerc.com/globalassets/standards/projects/2020-06/final-ballot---mod-026/2020-06-mod-026-2-implementation-plan-clean_102025.pdf
• North American Electric Reliability Corporation, Reliability Standard EOP-004-5, Event Reporting (effective October 1, 2027). https://www.nerc.com/globalassets/standards/reliability-standards/eop/eop-004-5.pdf
• North American Electric Reliability Corporation, Reliability Standards FAC-001-4, Facility Interconnection Requirements, and FAC-002-4, Facility Interconnection Studies. https://www.nerc.com/globalassets/standards/reliability-standards/fac/fac-001-4.pdf ; https://www.nerc.com/globalassets/standards/reliability-standards/fac/fac-002-4.pdf
• North American Electric Reliability Corporation, Level 3 Alert, Essential Actions for Inverter-Based Resource Performance and Modeling (initial distribution May 20, 2025), as posted by the New York State Reliability Council. https://www.nysrc.org/wp-content/uploads/2025/06/5.3.1-Level-3-Alert-Essential-Actions-IBR-Performance-and-Modeling-Attachment-5.3.1.pdf
• North American Electric Reliability Corporation, ORCP and CMEP Annual Report (February 11, 2026). https://www.nerc.com/globalassets/programs/enforcement/cmep-and-vegetation-reports/2025-orcp-and-cmep-annual-report.pdf
• North American Electric Reliability Corporation and Western Electricity Coordinating Council, 1,200 MW Fault Induced Solar Photovoltaic Resource Interruption Disturbance Report (June 2017). https://www.nerc.com/globalassets/our-work/reports/event-reports/1200_mw_fault_induced_solar_photovoltaic_resource_interruption_final.pdf
• North American Electric Reliability Corporation and Western Electricity Coordinating Council, San Fernando Disturbance, Southern California Event: July 7, 2020, Joint NERC and WECC Staff Report (November 2020). https://www.nerc.com/pa/rrm/ea/Documents/San_Fernando_Disturbance_Report.pdf
• North American Electric Reliability Corporation and Texas Reliability Entity, Odessa Disturbance Report (September 2021). https://www.nerc.com/globalassets/our-work/reports/event-reports/odessa_disturbance_report.pdf
• Institute of Electrical and Electronics Engineers, IEEE Std 1547-2018, IEEE Standard for Interconnection and Interoperability of Distributed Energy Resources with Associated Electric Power Systems Interfaces. https://standards.ieee.org/standard/1547-2018.html