When the Model Becomes the Evidence: Responding to APS’s PRC-029-1 Dynamic Model Update Notice

PRC-029-1 voltage ride-through envelope for PV, BESS, and other non-wind inverter-based resources (NERC Attachment 1, Table 2).

Arizona Public Service has issued notice to interconnecting and operating inverter-based resources in its territory requiring updated, validated dynamic models demonstrating compliance with NERC PRC-029-1, with submittals due September 15, 2026.

Generator Owners who read that notice as a routine model refresh will under-scope the work. The notice is a combined MOD-032-1 data request and a PRC-029-1 performance demonstration, and the second half changes what counts as evidence. This article walks through what the standard actually requires, where the submittals we see most often fail, and what a defensible package looks like.

1. The evidentiary shift: from settings verification to simulated performance

Under PRC-024, a Generator Owner could largely discharge its obligation by demonstrating that protective relay settings were placed outside the “no trip” envelope. The evidence was a settings sheet and a coordination study. The question being asked was “are your trip thresholds in the right place?”

PRC-029-1 asks a different question: when the grid does this, what does your plant actually do?

That question cannot be answered by a settings review, because a plant can trip — or, just as consequentially, stop injecting current — for reasons that have nothing to do with a relay threshold. Inverter-level fault-handling logic, plant-controller loop gains, phase-locked loop behavior under a distorted or weak-grid condition, DC-side limits, and firmware-embedded protective functions all sit upstream of the relay and none of them appear on a settings sheet.

The consequence for the APS submittal is direct: the model is the evidence. If the model does not represent as-left field configuration, the demonstration proves nothing about the facility — and a reviewer who benchmarks positive-sequence response against EMT response will find the discrepancy.

2. What PRC-029-1 actually requires

2.1 The three operation regions

PRC-029-1 divides the voltage plane into three regions, and the obligation differs in each:

This structure is why “momentary cessation is banned” is an imprecise summary. Current blocking is permitted — but only inside the permissive region, and only with a bounded restart. Cessation anywhere in the mandatory region is a performance failure, and that is where the majority of legacy fleets have a problem.

2.2 Voltage ride-through — and the table split that gets missed



Attachment 1 contains two tables, not one. Type 3/4 wind and wind hybrid resources are held to shorter durations than everything else. PV, BESS, PV+BESS hybrids, and VSC-HVDC-connected resources fall under the second table:

PV, BESS, and other non-wind IBR

Type 3/4 wind and wind hybrid

Two implementation details carry more weight than they first appear to:

• Voltage is referenced at the high side of the main power transformer, not at the inverter terminals. A plant that passes at the POI can still fail at the inverter, and vice versa, once collector impedance and MPT/GSU vector group and tap position are represented properly. Studies run at the inverter terminal answer a question nobody asked.

• Durations are cumulative within a ten-second window. A single ride-through event is the easy case. Sequential faults, reclose attempts, and evolving faults accumulate against the same budget, and a plant that clears each individual event may still exceed the cumulative allowance.

2.3 Frequency ride-through and RoCoF

Frequency is measured over a 3–6 cycle window, and durations are cumulative within a ten-minute period — a different window than the voltage tables use.

RoCoF: tripping is permitted only where the absolute RoCoF magnitude exceeds 5 Hz/s, computed as an average rate of change over a window of at least 0.1 seconds. That averaging window is doing real work in the requirement. An instantaneous df/dt calculation on a fault-adjacent waveform will produce excursions far above 5 Hz/s that the standard does not treat as qualifying, and a RoCoF element configured without an equivalent averaging window will trip on events the plant was obligated to ride through.

Phase angle jump: a minimum withstand of 25 electrical degrees. R1 carves out phase angle changes above 25° that arise from non-fault switching events.

2.4 Two recovery clocks, routinely conflated

This is the most common technical error we encounter in draft submittals:

These are separate obligations with separate clocks. Compressing them into a single “restore active power within five cycles” commits the facility to a performance target roughly four times more aggressive than the standard imposes — and we have seen that error drive unnecessary controller retunes and, in one case, an unnecessary hardware conversation with an OEM.



The reciprocal error is equally costly: assuming the 1.0-second real-power clock covers the current-restart obligation, and overlooking a plant that sits blocked for 15 cycles after voltage recovery.

3. Why positive-sequence models alone will not close the APS request

Positive-sequence tools — PSS®E, PSLF — remain the backbone of interconnection-wide study work, and APS needs current, MOD-032-1-conformant positive-sequence models in its base cases. But a phasor-domain model with a typical half-cycle time step and an assumed balanced fundamental-frequency network cannot represent several of the phenomena PRC-029-1 is specifically written around:

• PLL dynamics under phase angle jump. The 25° withstand requirement is a synchronization question. A positive-sequence model with an idealized angle reference cannot demonstrate loss-of-synchronism margin.
• Weak-grid and low-SCR control interaction. Sub-synchronous control interaction, controller-network resonance, and small-signal instability at low short-circuit ratio are invisible in phasor domain and are precisely the conditions under which fleets have tripped in real events.
• Unbalanced faults and negative-sequence response. Single-line-to-ground faults dominate real disturbance statistics, and negative-sequence current injection behavior is an EMT question.
• Inverter-internal protection and fault-handling logic. Hardware current limits, DC-link excursions, and firmware-embedded protective functions frequently live only in the manufacturer’s EMT black-box.

The practical rule we apply: positive-sequence demonstrates the plant meets the envelope; EMT demonstrates the model is telling the truth. Where the two disagree, the disagreement itself is the finding — and it is almost always traceable to a control path the positive-sequence model does not represent.

4. Case study: BESS ride-through failure hidden by a “current” model

The following consolidates work performed for a U.S. utility-scale storage facility. Identifying details have been removed.

Facility

A standalone battery energy storage facility interconnected at transmission voltage in a non-ISO utility jurisdiction, in commercial operation, subject to BES IBR obligations.

Starting position

The Generator Owner held a positive-sequence model package and an EMT model, both delivered during the interconnection study cycle and both nominally “current.” The facility’s compliance team reasonably assumed the model refresh would be a documentation exercise.

What the model reconciliation found

• Firmware drift. The inverter firmware in the field had advanced two revisions past the version the supplied EMT black-box represented. Two protective parameters had changed default values between revisions.
• PPC model divergence from as-left settings. The plant controller model carried commissioning-era voltage regulation droop and reactive loop gains. The as-left settings recorded in the commissioning package differed materially, following a post-COD tuning visit that had never been reflected back into the model.
• A protective element inside the mandatory region. A plant-level undervoltage element was set at 0.65 pu with a 2.0-second delay. Under the applicable table, the facility is obligated to ride through voltages below 0.70 pu for 3.00 seconds. The element sat inside the region the plant was required to survive — an exposure a settings-versus-PRC-024-envelope review had previously cleared, because the older envelope did not reach there.

What only EMT surfaced

With the corrected firmware parameters and as-left PPC gains represented, positive-sequence simulation showed the plant clearing the full ride-through set. EMT simulation of the same disturbance set at the minimum credible short-circuit ratio showed a poorly damped oscillation in the reactive control loop following fault clearance, converging slowly enough that a second disturbance inside the cumulative ten-second window would have driven the plant into current blocking within the mandatory region.

Resolution

The undervoltage element was reset outside the mandatory region with coordination verified against the plant’s remaining protection scheme. The reactive loop gains were retuned, with the retune validated in EMT and then propagated back into the positive-sequence parameter set. The updated firmware parameters were obtained from the OEM under the existing model NDA and incorporated into both model representations.

Deliverable

A benchmarked model package — positive-sequence and EMT responses overlaid across the full disturbance set, with the applicable ride-through envelope plotted on each — plus a settings gap register documenting each discrepancy found, the change made, and the verification evidence supporting it.



The generalizable finding: all three root causes were model fidelity problems, not plant capability problems. The facility was physically capable of compliant performance throughout. What it lacked was a model that demonstrated it, and a settings review conducted against the right envelope. A submittal built on the original model package would have been internally consistent, professionally presented, and wrong.

5. Requirement R4: narrower than most Generator Owners assume

R4 provides relief where physical hardware limitations prevent ride-through compliance. Three boundaries on it are frequently misread:

It is available only to IBRs in service at the enforcement date. Facilities still progressing through interconnection studies cannot plan around R4. They must be designed to comply, and a project team treating R4 as a backstop during facilities study is building on a provision that will not be there.

It covers voltage ride-through only. There is no exemption pathway for frequency ride-through or RoCoF. A facility that cannot hold through 5 Hz/s, or cannot maintain synchronism through a 25° phase jump, does not obtain relief under R4 for that limitation.

It is a documentation and communication obligation, not an application for approval. R4.1 requires documentation within twelve months identifying the limitation, the specific requirement affected, the hardware responsible, technical verification that only physical replacement resolves it, and a remediation plan — specific as to which voltage band(s) and duration(s) cannot be satisfied. R4.2 requires that documentation to go to the Planning Coordinator, Transmission Planner, Transmission Operator, Reliability Coordinator, and the Compliance Enforcement Authority, excluding proprietary manufacturer information. Follow-up information requests carry a 90-day response obligation (R4.2.1), CEA acceptance copies a 90-day distribution obligation (R4.2.2), and hardware replacement a 90-day notification obligation after which the exemption lapses (R4.3).

The documentation standard is the part that catches teams out. “The OEM says it cannot do this” is not technical verification. What is required is an engineering demonstration that the constraint is physical, and that no firmware, parameter, or control modification resolves it.

6. Compliance timeline

APS’s date is positioned deliberately ahead of the October 1 BES milestone, which leaves review and remediation time inside the compliance window rather than after it. Generator Owners should treat it as firm.

7. How Keentel supports Generator Owners on this request

Our dynamic modeling and NERC compliance practice delivers the full submittal package:

Model development and reconciliation

• Positive-sequence dynamic models in PSS®E and PSLF, with MOD-032-1 data sheets refreshed to as-built and as-left configuration
• EMT models in PSCAD, including plant controller representation and manufacturer black-box integration under NDA
• Firmware and parameter reconciliation against field records, commissioning documentation, and OEM revision histories
• Model quality review against applicable regional and interconnection-wide modeling criteria

PRC-029-1 performance demonstration

• Full voltage ride-through simulation set against the applicable Attachment 1 table, including cumulative-duration sequences
• Frequency ride-through and RoCoF testing with correctly windowed RoCoF computation
• Phase angle jump and PLL stability assessment
• Low-SCR and weak-grid control interaction screening
• Reactive current priority and post-disturbance recovery verification against the R2.3 five-cycle and R2.5 one-second obligations
• Positive-sequence to EMT benchmarking with documented reconciliation of any divergence

Protection and controls review

• Inverter, plant controller, and plant protection settings reviewed against the PRC-029-1 envelope
• Gap register with recommended settings changes and coordination verification
• R4 limitation assessment and, where applicable, documentation prepared to the R4.1 evidentiary standard

Submittal and compliance support

• Model verification and benchmarking report formatted to the transmission provider’s data request
• Evidence retention package structured for audit
• Support through reviewer comment cycles
  

Talk to us about your submittal

Keentel Engineering supports Generator Owners through NERC IBR compliance — dynamic model development and validation in PSS®E, PSLF, and PSCAD, PRC-029-1 ride-through demonstration, protection and controls review, and submittal preparation for transmission provider data requests.



If your facilities received the APS notice, the constraint is calendar, not scope. Contact us to scope your package.

8. Technical FAQ