NEWSROOM

Consolidation and Expansion of Dynamic Model Verification Standards 

Effective Date: January 1, 2026

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 

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
Regulatory Acceptance	Q4 2025	Accepted by end of 2025
Effective Date	January 1, 2026	First day of first quarter after Q4 2025 approval
R1 & R7 Compliance	January 1, 2027	TP/PC develop requirements; TP provides data on request
R2-R6 Compliance	January 1, 2029	Generator/Transmission Owners submit verified models
Full Implementation	January 1, 2030	FERC Order No. 901 deadline
MOD-026-1 Retirement	December 31, 2025	Immediately prior to MOD-026-2 effective date
MOD-027-1 Retirement	December 31, 2025	Immediately prior to MOD-026-2 effective date

IMPLEMENTATION TIMELINE 

January 1, 2026 → Effective Date (T₀) 

↓ 

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

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

↓ 

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

• Generator/Transmission Ownerssubmitverified 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: 

1. 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 

2. 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 

3. High-Voltage Direct Current (HVDC) Systems:

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

4. 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 

5. Non-Synchronous Generating Plants (E.g.Type 1 & 2 Wind viaBES 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 in Q1 2026 (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: January 2027 (24 months before January 1, 2029 R3 compliance deadline) 

 

3. Timeline Planning 

Recommended Project Schedule: 

Timeframe	Activities
January 2026 – December 2026 (Year 1)	Monitor for Transmission Planner model requirements (R1 due January 2027)  Initiate manufacturer contact for EMT models  Review facility applicability  Identify equivalent units (if applicable)
January 2027 – December 2027 (Year 2)	Receive TP model requirements (by January 2027)  Obtain EMT and positive sequence models  Schedule validation testing  Compile verification documentation
January 2028 – December 2028 (Year 3)	Complete validation testing  Prepare comparison documentation (R3.5 for IBRs)  Quality review of submittals  Submit to Transmission Planner by January 1, 2029
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 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.  

 

Q4: 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.   

 

Q5: My solar 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). 

Q6: 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 

Q7: What happens if the Transmission Planner rejects our model? 

A: Follow the R6 process: 

1. Transmission Planner provides (within 120 days): 
   • Written notification model is “not usable” 
   • Technical description of issues 
   • Supporting evidence 
2. 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 
3. If you submit updated model: 
   • Transmission Planner has 120 days to review 
   • Process repeats until model is accepted 

Q8: 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 

Q9: How do I know which protective and limiting functions to include? 

A: Wait for Transmission Planner requirements (R1, due by January 1, 2027). 

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 in Q1 2026 
• Contact manufacturers for EMT model availability in Q1 2026 
• Budget for compliance costs in FY2026-2029 (major expenditures in FY2027-2028) 
• Contact ENTRUST for testing and model integration/validation Q2 2027 
• Monitor for Transmission Planner requirements publication (by January 1, 2027) 

Timeline: With an effective date of January 1, 2026 and full compliance required by January 1, 2030, Generator and Transmission Owners have exactly 4 years to complete all model verification, validation, and submission activities. Preparation activities should begin immediately in Q1 2026 to ensure adequate time for manufacturer engagement, model acquisition, testing, and validation.