Understanding NERC MOD-026-2

Updated to reflect FERC approval of MOD-026-2 and finalized implementation timelines.

Consolidation and Expansion of Dynamic Model Verification Standards

The North American Electric Reliability Corporation (NERC) has approved a major update to dynamic model verification and validation requirements. MOD-026-2 consolidates and replaces MOD-026-1 and MOD-027-1, unifying voltage/reactive power and frequency/active power control into a single, comprehensive standard.

Driven by FERC Order No. 901, MOD-026-2 strengthens modeling requirements for Inverter-Based Resources (IBRs) such as solar, wind, and battery storage. It also expands modeling capabilities for synchronous generators, condensers, and other transmission equipment.

This standard represents a significant shift in reliability compliance—and ENTRUST’s power system experts are ready to support asset owners through every phase of implementation.

Comparison with MOD-026-1 and MOD-027-1

Prepared: October 2025

Updated: January 2026

Subject: Verification and Validation of Dynamic Models and Data

Executive Summary

MOD-026-2 consolidates and replaces MOD-026-1 (excitation/volt-var control) and MOD-027-1 (turbine/governor control) into a single, comprehensive standard for dynamic model verification and validation. The primary driver is FERC Order No. 901, which mandates better modeling of Inverter-Based Resources (IBRs) such as solar, wind, and battery storage facilities. Additionally, MOD-026-2 expands modeling capabilities by allowing Transmission Planners to optionally require limiting and protective function models for synchronous generators and condensers.

Key Dates Summary

Milestone	Timeframe	Description
Ballot Approval	October 2025	MOD-026-2 ballot approved
FERC Approval	Q1 2026	Approved by FERC (Order No. 901)
Effective Date	April 1, 2026	First day of the first quarter following FERC approval
R1 & R7 Compliance	April 1, 2027	TP/PC develop requirements; TP provides data on request
R2-R6 Compliance	April 1, 2029	Generator/Transmission Owners submit verified models
Full Implementation	April 1, 2030	FERC Order No. 901 deadline
MOD-026-1 Retirement	March 31, 2026	Immediately prior to MOD-026-2 effective date
MOD-027-1 Retirement	March 31, 2026	Immediately prior to MOD-026-2 effective date

View FERC Order No. 901 and filing details, NERC MOD-026-2 Filing/Order Docket No. RD26-3-000

https://elibrary.ferc.gov/eLibrary/search

IMPLEMENTATION TIMELINE

Effective Date (T₀) → April 1, 2026

↓

R1 & R7 Compliance (T₀ + 12 months) → April 1, 2027

Transmission Planner/Planning Coordinator develop model requirements • Transmission Planner provides current models upon request

↓

R2, R3, R4, R5, R6 Compliance (T₀ + 36 months) → April 1, 2029

Generator/Transmission Owners submit verified models
Model review and acceptance process
Change management procedures

Submittal Timeline:

Existing Facilities – Within 10 calendar years of most recent transmittal, or MOD-026-2 R2-R6 compliance date (whichever is later)

New Facilities – Compliance date for R2-R6 or 365 days after commissioning (whichever is later).

Key Changes and Impacts

1. CONSOLIDATION

Previous Approach:

MOD-026-1: Generator excitation control systems and plant volt/var control
MOD-027-1: Turbine/governor and load control or active power/frequency control

New Approach:

MOD-026-2: Single standard covering both voltage/reactive power AND frequency/active power control

Impact:

Streamlined compliance process
Single submission to Transmission Planner
Reduced administrative burden
Consistent requirements across control functions

2. EXPANDED SCOPE

Facility Types Covered:

Facility Type	Previous Coverage	MOD-026-2 Coverage
Synchronous Generators	✓ Core functions	✓ Core functions + limiters / protection per TP request
BES Inverter-Based Resources	✗ Limited/Generic	✓ Explicit & Comprehensive
Non-BES IBRs ≥20 MVA	✗ Not covered	✓ Explicit & Comprehensive
HVDC Systems (LCC & VSC)	✗ Limited	✓ Explicit Requirements
FACTS Devices	✗ Limited	✓ Explicit Requirements
Synchronous Condensers	✓ Core functions	✓ Core functions + limiters / protection per TP request

Applicability Criteria (per MOD-026-2 Section 4):

Functional Entities:

Generator Owner
Planning Coordinator
Transmission Owner
Transmission Planner

Facilities:

Synchronous Generating Units and Plants (BES Inclusion I2):

Individual synchronous generating units meeting Inclusion I2 criteria:
Connected at ≥100 kV with gross individual nameplate rating >20 MVA
Synchronous generating plants/facilities meeting Inclusion I2 criteria:
Connected at ≥100 kV with gross plant/facility aggregate nameplate rating >75 MVA

Dynamic Reactive Resources (BES Inclusion I5) >20 MVA:

Static or dynamic devices dedicated to supplying/absorbing reactive power connected at ≥100 kV, or through dedicated transformer with high-side ≥100 kV
Includes: Synchronous condensers, Flexible Alternating Current Transmission System (FACTS) devices

High-Voltage Direct Current (HVDC) Systems:

Line Commutated Converter (LCC)
Voltage Source Converter (VSC)

Inverter-Based Resources:

BES Inverter-Based Resources (all sizes)
Non-BES Inverter-Based Resources
Aggregate nameplate capacity ≥20 MVA connected through system designed primarily for delivering such capacity to common point of connection at voltage ≥60 kV

Non-Synchronous Generating Plants (E.g. Type 1 & 2 Wind via BES Inclusion I4):

Dispersed power producing resources aggregating to >75 MVA (gross nameplate rating) connected through system designed primarily for delivering such capacity to common point of connection at voltage ≥100 kV or above
Includes both: The individual resources, AND The system delivering capacity from aggregation point to common point of connection

Detailed Comparison Table

Feature	MOD-026-1	MOD-027-1	MOD-026-2
Functional Scope	Excitation control, voltage regulation, PSS, plant volt/var	Turbine/governor, load control, active power/frequency	Both combined into single standard
Applicable Entities	Generator Owner, Transmission Planner	Generator Owner, Transmission Planner	+ Transmission Owner, Planning Coordinator
IBR Coverage	Generic/limited mention	Generic/limited mention	Comprehensive – explicit requirements
EMT Models	Not required	Not required	Required for IBRs, HVDC, FACTS
Positive Sequence Models	Required	Required	Required (+ optional limiters/protection for synchronous)
Verification Period	10 years	10 years	10 years (unchanged)
Model Verification	Implied/informal	Implied/informal	Explicitly defined and required
Model Validation	Required	Required	Required + enhanced documentation
GO/TO Change Notification	180 calendar days	180 calendar days	180 calendar days (unchanged)
Response Timeline	90 calendar days	90 calendar days	120 calendar days*
Equivalent Unit Provision (synchronous only)	≤350 MVA, same components	≤350 MVA, same components	≤350 MVA, same components (unchanged)
Low Capacity Factor Exemption	≤5% over 3 years	≤5% over 3 years	≤5% over 3 years (unchanged)
Jointly Developed Requirements	No	No	Yes – TP & PC must jointly develop (R1)

*120 days for TP response to new model transmittal (R5), GO response to unacceptability R6).
TP to provide existing model within 90 days of request (R7).

3. NEW REQUIREMENT: ELECTROMAGNETIC TRANSIENT (EMT) MODELS FOR IBR

Requirement R3 (NEW in MOD-026-2)

What’s Required:

Generator Owners and Transmission Owners must provide EMT models for:

Inverter-Based Resources (solar, wind, battery storage)
FACTS devices
HVDC systems (both LCC and VSC types)

Exclusions:

Legacy facilities where original equipment manufacturer no longer supports EMT models
Legacy facilities NOT identified by Transmission Planner as requiring EMT models (per R1, Part 1.2.1)

EMT Model Components (R3.1):

Must include integrated plant model with components representing:

IBR unit(s)
Collector system
Auxiliary control devices (acting on voltage/frequency)
Power plant controller
Generator step-up transformer(s)
Main power transformer(s)
Enabled protective functions that directly trip units/facility
Limiting functions that limit active/reactive output

Required Documentation (R3.2-R3.5):

Model Verification- Configurable parameters match design/settings
Model Validation- Comparison with measured behavior during:

Voltage excursion or staged test events
Frequency excursion or staged test events

Unit-Level Testing* (R3.4) – Factory/Hardware-in-Loop testing for large signal disturbances [*typically performed by OEM]
Cross-Validation (R3.5) – Comparison between EMT and positive sequence model responses

This represents a significant new technical and cost burden for IBR facilities.

4. DUAL MODELING REQUIREMENT FOR IBRs

Applicable IBR facilities must provide BOTH:

Requirement R2: Positive Sequence Dynamic Models

Traditional phasor-domain models
Used for bulk system stability studies
10-year verification cycle

Requirement R3: EMT Models

Time-domain electromagnetic transient models
More detailed representation
Includes fast dynamics and switching behavior
10-year verification cycle (same as R2)

Requirement R3.5: Model Comparison

Documentation comparing responses between both model types
Demonstrates consistency for large signal disturbances

5. CLARIFIED TERMINOLOGY

MOD-026-2 introduces formal definitions (adopted by NERC Board August 2025):

Term	Definition	Previous Standards
Model Verification	Process of confirming model structure and parameters are representative of equipment design and settings by reviewing documentation	Used informally, not formally defined
Model Validation	Process of comparing simulation results with measurements to assess how closely model behavior matches measured behavior	Used informally, not formally defined

Impact: Clear distinction between:

Verification = checking against design documentation
Validation = checking against actual performance measurements

Note that per these definitions, validation data (i.e. from an external party) can be an input to verification.

6. ENHANCED MODEL REQUIREMENTS

Comparison of Requirements:

Aspect	MOD-026-1/027-1	MOD-026-2
Voltage/Reactive Power Validation	Voltage excursion test required	Same, plus enhanced documentation
Frequency/Active Power Validation	Frequency excursion test required	Same test required, with updated thresholds (reduced for most interconnections)
IBR Unit-Level Validation [typically performed by OEMs in factory]	Not addressed	Factory/HIL testing documentation required (R3.4)
Protective Function Verification – Synchronous	Not addressed	Optional per TP requirements (Table 1.1 – NEW)
Protective Function Verification – IBRs	Not addressed	Required (explicitly listed in Table 1.2)
Limiting Function Verification – Synchronous	Optional/implied	Optional per TP requirements (Table 1.1 – NEW)
Limiting Function Verification – IBRs	Not addressed	Required (explicitly listed in Table 1.2)
EMT vs. Positive Sequence Verification	N/A	Benchmark (comparison) required (R3.5)

Frequency Excursion Thresholds (changed from MOD-027-1):

Facility must be operating in frequency-responsive mode with frequency deviation (nadir) from scheduled frequency ≥:

Interconnection	Threshold
Eastern	0.04 Hz
ERCOT	0.08 Hz
Western	0.08 Hz
Quebec	0.30 Hz

Note: MOD-026-2 reduced thresholds for Eastern (0.05→0.04 Hz), ERCOT (0.10→0.08 Hz), and Western (0.10→0.08 Hz) interconnections, making it easier to find qualifying frequency events for validation purposes. Quebec’s threshold was increased (0.15→0.30 Hz).

User Guidance by Asset Owners

1. Determine Applicability

Action Items:

Review MOD-026-2 Section 4.2 (Facilities) carefully
Identify newly applicable units, particularly:
BES Synchronous or Inverter-Based Resources (any size)
Non-BES IBRs ≥20 MVA connected at ≥60 kV
Non-synchronous generating plants meeting BES definition
HVDC systems (LCC and VSC)
FACTS devices >20 MVA

2. EMT Model Preparation – IBR Only (CRITICAL PATH)

Immediate Actions (HIGH PRIORITY):

Legacy equipment may qualify for exemption if manufacturer no longer provides support

Model Acquisition: Contact Equipment Manufacturers

Identify OEM support status of equipment.
If possible, obtain EMT models or model information for:
IBR inverter units
Power plant controller
Transformers (GSU and main power saturation curves)

Testing Requirements:

Budget for testing costs
Schedule testing during commissioning for new facilities

Model Verification:

Collect equipment design specifications
Obtain control system settings documentation
Maintain software/firmware version records

Timeline:

Begin ASAP (do not wait for Transmission Planner requirements)
Lead time for manufacturer EMT models: months typical
Preliminary analysis and test coordination: 3-6 months
Target completion: April 2027 (24 months before April 1, 2029 R3 compliance deadline)

3. Timeline Planning

Recommended Project Schedule:

Timeframe

Activities

Year 1

(April 2026 – March 2027)

• Monitor for Transmission Planner model requirements (R1 due after 1 year)

• Initiate manufacturer contact for EMT models

• Review facility applicability

• Identify equivalent units (if applicable)

Year 2

(April 2027 – March 2028)

• Receive TP model requirements

• Obtain EMT and positive sequence models

• Schedule validation testing

• Compile verification documentation

Year 3

(April 2028 – March 2029)

• Complete validation testing

• Prepare comparison documentation (R3.5 for IBRs)

• Quality review of submittals

• Submit to Transmission Planner by end of timeline

Ongoing

• Monitor equipment changes

• 180-day notification for changes altering dynamic response (R4)

• Respond to TP comments within 120 days (R3)

Common Questions & Answers

Q1: If I have multiple identical wind turbines, do I need an EMT model for each turbine?

A: No. MOD-026-2 allows aggregate modeling for units <20 MVA in a generating plant. You may provide:

Individual unit model, OR
Aggregate unit model representing multiple identical units

The key is that the model must represent the facility’s dynamic behavior at the point of interconnection. Typically, one representative turbine model is used with appropriate scaling.

Q2: If I have multiple types of wind turbines or inverters, do I need an EMT model for each turbine?

A: Yes. Each IBR unit type must have explicit representation as well as parameterization. Each OEM should be contacted.

Q3: What if my IBR Unit (wind turbine or inverter) has an EMT model available, but my Power Plant Controller OEM does not have a model available?

A: The controls experts at ENTRUST can build custom PPC models based on documentation and measured results, then use this as input to R3.

Q3: What is the best way to get data for validation (comparison between measurement and model results)?

A: Staged testing is the most effective manner to validate models. The control experts at ENTRUST will design a test procedure for the specific nature of your on-site controls.

Q4: My IBR facility was commissioned in 2020. Do I need to provide EMT models?

A: It depends:

If Transmission Planner identifies your facility under R1, Part 1.2.1: Yes, EMT model required
If Transmission Planner does NOT identify your facility: No EMT model required (only positive sequence)
If original equipment manufacturer no longer supports EMT models: Exempt from R3

Check with your Transmission Planner after they publish model requirements (by January 1, 2027).

Q5: We have 4 identical 30 MVA gas turbines. Can we verify just one?

A: Yes, if ALL conditions are met:

Same MVA nameplate rating (✓ 30 MVA each)
Nameplate ≤350 MVA (✓)
Same components and settings (must verify)
Same physical location (must verify)

Process:

Verify one unit per MOD-026-2 requirements
Provide written explanation for equivalent units
Must verify a different unit each 10-year cycle

Q6: What happens if the Transmission Planner rejects our model?

A: Follow the R6 process:

Transmission Planner provides (within 120 days):

Written notification model is “not usable”
Technical description of issues
Supporting evidence

You must respond (within 90 days) with ONE of:

Updated model and documentation (per R2/R3)
Technical justification for maintaining current model
Plan to perform model verification

If you submit updated model:

Transmission Planner has 120 days to review
Process repeats until model is accepted

Q7: Do we need to notify the Transmission Planner about every software update?

A: Only if it alters dynamic response characteristics.

Examples that REQUIRE notification:

Inverter control software update changing voltage control algorithm
Power Plant Controller reactive droop or gain changes
Protective function threshold changes

Examples that DO NOT require notification:

HMI software updates
Monitoring system updates
Data historian software

Q8: How do I know which protective and limiting functions to include?

A: Wait for Transmission Planner requirements (R1, due 1 year after the quarter following FERC approval).

The Transmission Planner will specify which functions from Attachment 1 must be modeled:

Table 1.1 for synchronous machines
Table 1.2 for IBRs, FACTS, HVDC

—

Additional Resources

NERC Standards & Documents:

MOD-026-2 Standard (Final Draft October 2025)
MOD-026-2 Implementation Plan
MOD-026-2 Technical Rationale Document
FERC Order No. 901 (October 2023)
NERC Project 2020-06 webpage

Related Standards and Projects:

MOD-032-1: Data for Power System Modeling
MOD-033-2: Steady-State and Dynamic System Model Validation
Project 2022-02: Uniform Modeling Framework for IBR
Project 2021-01: System Model Validation with IBRs

Definitions:

NERC Glossary of Terms
BES Definition (with Inclusions I2, I4, I5)

Technical References:

IEEE 421.5: Excitation System Models for Power System Stability Studies
IEEE Task Force Reports on IBR Modeling
NERC GADS Data Reporting Instructions (Appendix F – Capacity Factor)

Conclusion

MOD-026-2 represents a paradigm shift in reliability standard requirements for dynamic modeling, primarily driven by the proliferation of Inverter-Based Resources on the Bulk Electric System. The standard:

✓ Consolidates two previous standards into one comprehensive requirement

✓ Expands scope to explicitly cover IBRs, HVDC, and FACTS

✓ Introduces EMT modeling requirements for power-electronic-based facilities

✓ Clarifies distinction between verification and validation

✓ Maintains 10-year verification cycle with proven flexibility provisions

Critical Success Factors:

Early manufacturer engagement for EMT models
Adequate budget allocation for testing and model acquisition
Staff training on EMT modeling and IBR technology
Proactive data collection through recording equipment
Organized documentation management for long-term compliance

Immediate Next Steps:

For Generator/Transmission Owners:

Begin facility applicability assessment ASAP
Contact manufacturers for EMT model availability ASAP
Budget for compliance costs in FY2026-2029 (major expenditures in FY2027-2029)
Contact ENTRUST for testing and model integration/validation Q1 2027
Monitor for Transmission Planner requirements publication (April 1, 2027)

Timeline: With an effective date of April 1, 2026 and full compliance required by April 1, 2030, Generator and Transmission Owners have exactly 4 years to complete all model verification, validation, and submission activities. Preparation activities should begin immediately to ensure adequate time for manufacturer engagement, model acquisition, testing, and validation.

For questions or support:
Jerry Thompson
Sr. Engineer II, Power Generation
jerry@entrustsol.com
+1 (720) 826-8077

Ali_ENTRUST

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