Passing the CAISO IBR Model Review: From the Flat Run to PRC-029 Ride-Through

A technical guide to the California ISO's August 2026 Dynamic Model Review Guideline for inverter-based resources, the Dynamic Model Validation Procedure and its PSLF toolkit, and the control-mode, frequency-response, voltage-regulation, and ride-through requirements a positive-sequence model must satisfy before it enters a CAISO interconnection study or the WECC base case

Executive Summary

In August 2026 the California ISO, together with the Participating Transmission Owners and the merchant transmission companies in its footprint, issued a revised Dynamic Model Review Guideline for Inverter-Based Interconnection Requests and Operational Resources and a companion Dynamic Model Validation Procedure. Together with a small PSLF EPCL toolkit and a PRC-029 ride-through spreadsheet, these documents define what a positive-sequence model of a solar, wind, storage, or hybrid plant must contain and how it will be tested before it is accepted into a CAISO interconnection study, the Section 10 generator data process, or the WECC base case.

The guideline is not new in concept; it descends from the WECC Inverter-Based Resources Power Plant Modeling and Validation Guideline and has been in place since 2020. What changed in 2026 is consequential. The repc_b plant controller has been retired by WECC and cannot be used in new submissions. The reec_d and reec_e electrical controllers are now required wherever momentary cessation must be modeled, and the new wtgt_b drive-train model is preferred for Type 4 wind. The ride-through section has been rewritten around PRC-029-1, which becomes enforceable on October 1, 2026, and the guideline now states the voltage and frequency envelopes explicitly, requires compliance to be demonstrated at the high-voltage side of the main transformer, and requires the trip settings in the lhvrt and lhfrt protection models to sit outside the must-ride-through zone without touching it.

The validation procedure operationalizes the guideline. It places a Thevenin voltage source at the point of interconnection, sets its reactance to produce a chosen short-circuit ratio, and runs six standard simulations: a 20-second flat run with an automated extraction of every control setting; a three-phase fault at the POI at SCR 3 and again at SCR 2; a plant-controller voltage or reactive-power reference step; a frequency reference step; and a play-back of the PRC-029-1 voltage envelope from an infinitely strong source. Each run has pass criteria, and the guideline's Table 1 warns that the older regc_a converter model is not suitable where the SCR is around 2 to 3 or less, which means a plant that submits regc_a will very likely fail the SCR 2 bump test and be asked to move to regc_b.

This guide walks through the guideline section by section — usability, power flow equivalencing, model selection, MVA base scaling, primary frequency response, automatic voltage regulation, and ride-through — then through the toolkit and each test's acceptance criteria. It documents several defects we found in the toolkit itself, and closes with how Keentel Engineering prepares and validates IBR models so they clear the CAISO review the first time, followed by a 25-question FAQ.

1. Why the CAISO Rewrote Its IBR Model Guidance in 2026

The August 2026 revision is the fourth release of a guideline first issued in October 2020 and updated twice in 2021, when the droop parameters were clarified and "plant V and local V" was added as a valid control mode. The 2026 revision history lists three drivers: new WECC-approved models, the retirement of repc_b, and PRC-029-1 compliance. Behind those three items sit the reliability events that have shaped IBR modeling for a decade — the loss of solar generation in the 2016 Blue Cut fire and subsequent Southern California disturbances, the Odessa events in Texas, and the pattern in every NERC disturbance report that the models used in planning did not predict what the inverters actually did.



The guideline is explicit that mathematically only the converter (REGC) and electrical control (REEC) models are needed to run a simulation, but that the purpose of modeling is to capture how the plant actually behaves. Every model that represents a real control — the plant controller, the wind drive-train and pitch controls, the ride-through protection — is therefore required where the corresponding control exists. A monitored branch must always be defined in the plant controller model, and it must be oriented from the generator toward the grid.

The guideline is co-authored by the CAISO and eight transmission owners: DCR Transmission, GridLiance West, Horizon West Transmission, LS Power Grid California, PG&E, SDG&E, SCE, and Valley Electric Association. That authorship matters. The PTOs run the interconnection studies and the MOD-032 base case processes, so a model that satisfies the guideline is reviewed to the same criteria whether the POI is in the SCE, PG&E, or SDG&E territory, and whether the reviewer is the PTO or the CAISO.

2. Model Usability: The Three Gates Every Submission Must Clear

Before anyone looks at control performance, the model must be usable in GE PSLF, the platform the CAISO and its PTOs use for dynamic simulation. The guideline sets three gates.

The 20-second flat-run criterion is stricter than the older 10-second convention used in the CAISO Section 10 acceptance test, and it is checked automatically by the validation toolkit, which also writes a parameter-error report during the same run. A model that passes the flat run has demonstrated only that it is internally consistent; it has not yet demonstrated that it behaves correctly.

3. Building the Power Flow Model: Explicit, Equivalent, and Hybrid

The power flow representation follows the WECC single-generator and multiple-generator equivalents. From the point of interconnection inward, the model must include an explicit interconnection transmission line, explicit representation of every substation (main step-up) transformer, an equivalent collector system, an equivalent pad-mounted transformer with a scaled MVA rating, an equivalent generator scaled to the plant's total capacity, and explicit representation of every plant-level reactive compensation device, modeled as a fixed or switched shunt or, for FACTS devices, as a generator.

Where inverters and pad-mounted transformers are supplied as integrated units and the manufacturer's test data and control inputs are taken at the integrated unit's terminal, the pad-mount is not modeled separately; the equivalent generator represents the integrated unit.

3.1 How many equivalent generators?

The number of equivalents is determined by the number of main substation transformers, the collector systems behind each, and the mix of inverter makes and settings. Each substation transformer is explicit. Identical inverters behind one transformer become one equivalent collector, one equivalent pad-mount, and one equivalent generator. Different inverters with the same control and protection settings may also be combined into one equivalent. Where inverters with different settings sit behind the same transformer, each inverter type with at least 10 MVA installed gets its own equivalent generator and pad-mount; types below 10 MVA may be aggregated with another type.

3.2 Hybrid plants

For AC-coupled hybrids, where each fuel type has its own inverters, each fuel type is modeled explicitly with its own equivalent generator, pad-mount, and collector. The reactive capability requirement applies to the hybrid plant as a whole; an individual fuel type need not meet it alone. For DC-coupled hybrids, where solar and storage share inverters, a single equivalent generator represents the inverters as seen from the AC side, and a negative Pmin on that generator represents the maximum charging power if the battery can charge from the grid.

4. Choosing the Dynamic Models: REGC, REEC, REPC, and the Retirement of REPC_B

The dynamic model is a chain. The REPC plant controller processes voltage, reactive power, frequency, and active power at the monitored point and issues real (Pref) and reactive (Qref) power references. The REEC electrical controller converts those references, with terminal voltage feedback, into real (Ipcmd) and reactive (Iqcmd) current commands. The REGC generator/converter model turns the current commands into injected current. The lhvrt and lhfrt models trip the plant on defined voltage and frequency conditions. For Type 3 wind, the wtgt, wtga, wtgp, and wtgq models add the drive-train, aerodynamics, pitch, and torque controls that shape the response; for Type 4 wind only the drive-train model applies.

Three selection rules deserve emphasis. Plant-level power factor control is acceptable only in coordination with inverter-level voltage regulation, so that the plant as a whole meets the voltage regulation requirement in Section 7. For hybrid interconnection requests, repc_d is mandatory so that the plant-level limits are enforced across the storage and generation equivalents. And any plant that uses or must represent momentary cessation — including legacy plants that are permitted to — must use reec_d or reec_e, because the older reec_a and reec_c cannot represent the blocking logic.

5. MVA Base, Pmax, and the Plant-Level Scaling Rules

The equivalent generator's Pmax in the power flow is the sum of the individual inverter MW outputs needed to achieve the desired MW at the POI, and the guideline notes that individual inverter MW output is often below rated MW because of the common practice of oversizing inverters. The equivalent generator's MVA base is the sum of the individual inverter MVA ratings. Because nearly every dynamic parameter is in per unit on the generator MVA base, the base in the .dyd must equal the base in the .epc; the validation toolkit flags any generator whose power flow Pmax is equal to or greater than its dynamic MVA base as an error.

Two plant-controller models carry their own base rules. In repc_a, the puflag parameter selects whether pbranch and qbranch are on the model MVA base (puflag = 1) or the system 100 MVA base (puflag = 0). The guideline recommends puflag = 1, and the toolkit issues a warning whenever puflag = 0 is found. In repc_d, the plant MVA base MVAplt may be entered as a fixed value, in which case every parameter is on that base, or set to zero, in which case the model computes MVAplt at initialization and at every time step as the sum of the MVA bases of all downstream units whose status is 1.



The repc_d distribution gains Kwi (reactive) and Kzi (active) determine how the plant reference is apportioned among downstream units. For almost every plant they should all be set to 1, which the model interprets as apportionment in proportion to MVA base: two 100 MVA units behind a 200 MVA plant controller asked for 0.1 pu each pick up 10 MW. Where the K values are not all 1, the largest must be normalized to 1 and the others are interpreted as fractions of the largest unit's response, subject to the constraint that the MVA-weighted sum of the K values divided by MVAplt equals 1.

6. Primary Frequency Response: Droop, Deadband, and the Base-Load Flag

IBRs that executed a Generation Interconnection Agreement, or filed an unexecuted one at FERC, on or after May 15, 2018 must provide active-power primary frequency response with 5 percent droop for both under- and over-frequency and a maximum deadband of ±36 mHz, consistent with FERC Order 842. The guideline translates this into power flow and dynamic settings.



In the power flow, the base-load flag on the generator record declares the plant's operating headroom. BL = 0 means Pgen can move up and down, the expected setting for storage and permissible for solar or wind that carries headroom. BL = 1 means Pgen can move down only, the typical and, for planning, the most appropriate setting for solar and wind, which are normally dispatched at maximum available output. BL = 2 means Pgen is fixed and is not compliant with the requirement. The base-load flag governs availability; the dynamic model governs capability.

The droop constants ddn and dup are in per unit of power per per-unit frequency deviation on the generator nameplate base; 20 corresponds to 5 percent droop. The deadbands fdbd1 (over-frequency) and fdbd2 (under-frequency) are ±0.0006 pu, which is ±36 mHz at 60 Hz. A guideline enhancement distinguishes capability from availability: ddn and dup represent what the inverters can do irrespective of headroom, while the BL flag represents whether headroom exists; when BL = 1 the simulation blocks upward response by setting Pmax equal to Pgen. Plants with agreements before May 15, 2018 have no PFR obligation and should model the field settings as they are.

7. Automatic Voltage Regulation: The Seven Control-Mode Combinations

IBRs subject to FERC Order 827 must operate in automatic voltage control mode. In the WECC generic models that behavior is set by three flags in the electrical controller and one in the plant controller. pfflag selects local power factor control (1) or voltage/reactive control (0). vflag selects local voltage control (0) or reactive power control (1). qflag selects constant power factor or reactive power control (0) or voltage control (1). refflag in the plant controller selects plant-level reactive power control (0), plant-level voltage control (1), or plant-level power factor control (2). The guideline's Table 3 lists every valid combination and states that anything else is invalid.

The pattern is simple once seen: voltage regulation must exist somewhere in the chain. Plant-level voltage control (refflag = 1) satisfies it alone. Plant-level reactive power or power factor control satisfies it only if the inverters themselves regulate voltage through the local Q/V loop (vflag = 1, qflag = 1). A plant that holds constant Q or constant PF at the POI with no inverter-level voltage loop is not providing automatic voltage regulation, however precisely it holds its set point. The parameters that coordinate the plant and inverter loops and that reviewers examine are repc vfrz, reec vdip and vup, reec kqv, and the local voltage PI gains kvp and kvi. Existing IBRs not subject to Order 827 model their field settings.

8. Ride-Through: Reactive Current Injection, Momentary Cessation, and PRC-029-1

8.1 The CAISO tariff performance requirements

Projects that executed an interconnection agreement or replaced their inverters on or after April 30, 2019 must meet the CAISO's inverter-based interconnection requirements. Momentary cessation — ceasing to inject current during a fault without mechanical isolation — is prohibited unless the transient high voltage reaches 1.20 pu or more. During transient low voltage the inverters must inject reactive current in direct proportion to the per-unit voltage decrease at the inverter terminals, reaching full rated reactive current when the terminal voltage falls to 0.50 pu. Between 1.10 and 1.20 pu the plant must continue to operate and absorb reactive current. When voltage returns to the 0.90–1.10 pu normal band the inverters must return to active current injection at a ramp of at least 100 percent per second, completing the transition within one second; return from any permitted momentary cessation above 1.20 pu must also complete within one second. Active power reaching 95 percent of its pre-fault value is the guideline's definition of return to normal, and the regc rrpwr parameter must therefore be no less than 1.0 pu/s.

8.2 How the requirements map to reec parameters

The reactive current limit must be non-zero throughout the transient low-voltage region and at least 1.0 pu below 0.5 pu voltage. With pqflag = 0 (Q priority), the reactive current limit must be at least 2 × (1.0 − V) for voltages between 0.5 and 1.0 pu and at least 1.0 pu below 0.5 pu; if the VDL1 table is used to shape the limit, its points must lie on or above that line. Plants that operate in P priority under normal and high-voltage conditions and switch to Q priority under low voltage may still be modeled with pqflag = 0, because priority only matters when the total current demand exceeds the inverter limit, which normally happens only under low voltage. Where P priority must be retained, the guideline shows how to achieve the same effective Q injection with pqflag = 1 by shaping the VDL2 table so that Ip is limited to zero at 0.5 pu, 0.8 at 0.7 pu, 0.98 at 0.9 pu, and 1.0 at 1.0 pu; because the effective Q limit is then the square root of Imax² minus Ip², the resulting Iqmax reproduces the Q-priority curve.

The quantity of reactive current injected can be set either through the voltage-dip logic — vdip between 0 and 1.0, typically 0.9, with kqv ≥ 2 — or, with the dip logic disabled, through the local voltage loop with qflag = 1 and kvp ≥ 2. For transient high voltage, vup = 1.1 with a non-zero kqv gives a non-zero reactive current limit in the right direction between 1.1 and 1.2 pu.

Legacy projects that executed agreements before April 29, 2019 and that use momentary cessation must model it truthfully with reec_d or reec_e, and the guideline recommends the blocking thresholds be as favorable as the equipment allows: vblkl as low as possible and no higher than 0.9, vblkh as high as possible and no lower than 1.1, and tblk_delay as small as possible.

8.3 PRC-029-1

PRC-029-1 takes effect on October 1, 2026 and applies to Bulk Electric System IBRs and to non-BES IBRs that have or contribute to an aggregate nameplate of 20 MVA or more connected through a system designed to deliver that capacity to a common point at 60 kV or above. Consistent with FERC Order 901, a limited, documented exemption is available for legacy IBRs whose hardware must be physically replaced and cannot be reconfigured by software; all future IBRs must comply. The guideline reproduces the ride-through envelopes and, for the first time, embeds them into the model review.

Three modeling consequences follow. First, the monitored bus in the lhvrt and lhfrt records must reflect the actual measurement point, but compliance is demonstrated at the high-voltage side of the main transformer; the guideline shows the record with the generator terminal as the model bus and the 230 kV bus as the monitored bus. Second, the trip thresholds dvtrp and dftrp and their timers dttrp must lie outside the must-ride-through zone and must not coincide with or touch the envelope — a trip point of 1.10 pu at 1.0 s is not acceptable because it sits on the boundary. Third, the per-unit voltage base is the nominal transmission voltage unless the PC, TP, or TO specifies otherwise, so a plant monitored at a 500 kV bus on a 525 kV nominal system uses vref = 1.05 in the lhvrt record and a play-back profile scaled by 1.05.

In the permissive region below 0.10 pu the IBR may either continue injecting current or enter current blocking, but it must resume injection within 5 cycles of the voltage returning to the mandatory or continuous region.

9. The Validation Toolkit: Thevenin Source, SCR Sweep, and Six Standard Runs

The CAISO validation procedure tests a plant model in isolation before it is placed in the WECC full-loop case. The plant's power flow is modified so that the POI bus becomes the swing bus (type 0) and an infinite generator is attached to it. In dynamics that generator carries a gthev Thevenin-source model whose MVA base is set by a pre-run EPCL to the sum of the MVA bases of every in-service plant generator and whose reactance xth is set to the reciprocal of the desired short-circuit ratio. With xth = 0.33 the POI has an SCR of about 3 on the plant's MVA base; xth = 0.5 gives SCR 2; xth = 0.0001 gives an effectively infinite source for the play-back test. The package ships pre-run files for SCR 1, 2, 2.5, 3, 4, 5, 10, and 1000.

The pre-run EPCL also rebases the repc_b plant limits (for legacy plants that still carry that model) so that the reference change tests apply to the plant's dispatched point rather than its nameplate. The main program, IBR_model_test_v2.p, is a DYTOOLS-style stability processor that reads a runs file, loads the .sav and the Thevenin and plant .dyd files, runs the pre-run EPCL, initializes, applies either a disturbance EPCL or a play-back CSV, runs to the end time, and stores channels. It runs in both PSLF Classic and the Advanced UI, and the runs file name is hard-coded.

The runs file also fixes the simulation parameters: a quarter-cycle time step of 0.0041667 s, a 40-second end time, plot intervals of one step throughout, the bad-data fix flag on, and the model-status check on. Every run uses the same .sav and plant .dyd; only the Thevenin file, the pre-run, and the disturbance change.

9.1 Dispatch scenarios

The procedure requires the plant to be tested at more than one dispatch where the technology warrants it. Wind and solar are dispatched slightly below Pmax, leaving about 10 percent headroom so the frequency step can show upward response. A stand-alone BESS is tested near Pmax, near Pmin (charging), and at Pgen = 0 to prove voltage and frequency control at zero active power. A hybrid is tested with the BESS discharging and other generators off, the BESS charging (if grid-charging is allowed) and others off, the BESS off and others on, the BESS discharging with others on at a net MW below the plant limit, and the BESS charging with others on at net zero, to prove the coordination the repc_d model is supposed to provide. Each dispatch is a separate .sav and a separate set of runs.

9.2 The play-back profiles

The ride-through test does not simulate a fault; it plays a voltage waveform into the infinite source so that the POI voltage follows the PRC-029-1 envelope exactly. The "other IBR" profile holds 1.0 pu for one second, drops to zero for 0.32 s, steps to 0.25 pu until 2.2 s, 0.5 pu until 4 s, 0.7 pu until 7 s, 0.9 pu until 20 s, returns to 1.0 pu, then at 30 s steps to 1.2 pu for one second, drops to 1.1 pu, and holds to 40 s. The wind profile is the same shape with the shorter wind durations: zero for 0.16 s, 0.25 pu until 2.2 s, 0.5 pu until 3.5 s, and 0.7 pu until 4 s. The 500 kV variants multiply every voltage by 1.05. The plant passes if it remains connected and continues to produce active and reactive output through the entire profile.



The frequency ride-through is not simulated. The lhfrt settings are instead checked against the PRC-029-1 frequency envelope in the companion spreadsheet, which also carries LVRT and HVRT sheets for wind and for all other IBR: the reviewer pastes the interconnection customer's dvtrp, dttrp, dftrp, and vref values from the .dyd and the sheet plots them against the envelope.

10. Reading the Results: What Reviewers Look For in Each Test

The automated settings extractor deserves a closer look because it is the first thing a CAISO or PTO reviewer opens. For every generator it records Pmax and MVA base, the P/Q priority flag, the derived control mode string (constant power factor, constant Q, plant-level Q, plant-level V, plant-level PF, local V, plant-level Q and local Q/V, and so on), every flag and gain in the reec and repc, the base-load flag, the frequency-response parameters, the regc low-voltage power logic parameters (lvplsw, brkpt, zerox), rrpwr, the plant Pmax and Pmin, and the repc_d distribution gains. It appends notes where voltage or Q gains are zero, where rrpwr is below 1, and where no plant controller exists. In a separate file it lists parameter checks: MVA base not above Pmax; regc accel outside 0.7–1.0; reec Qmax or Qmin on the machine base narrower than the power flow limits; trv = 0; vdip ≥ 1 or vup ≤ 1; repc emax below 0.05 or emin above −0.05; a zero deadband; puflag = 0; a repc Pmax more than 5 MW from the power flow Pmax; and, for repc_b plants, a suspicious 100 MW limit and droop constants below 5 percent on the plant Pmax base.

11. Defects and Ambiguities We Found in the Toolkit

Keentel ran the published EPCL through a line-by-line review. The toolkit is fit for purpose, but a submitter who relies on it uncritically should know the following.

12. How Keentel Engineering Gets IBR Models Through Review

Keentel Engineering prepares, validates, and defends positive-sequence and EMT models for utility-scale solar, wind, storage, and hybrid plants in the CAISO footprint and across the Western Interconnection, and delivers studies on PSLF, PSS®E, PSCAD/EMTDC, DIgSILENT PowerFactory, ASPEN OneLiner, and ETAP across 4 kV to 765 kV. Our objective on a CAISO model submission is a package that passes the six standard runs at the first review.

Keentel specifies and interprets field tests; the tests themselves are performed by accredited testing contractors. Some analysis platforms and work scopes may be carried by Keentel's subconsultants under Keentel's direction. To discuss a model submission, contact Keentel Engineering at (813) 389-7871 or contact@keentelengineering.com, or schedule a 15-minute call at calendly.com/keentel-engineering/15min.

References and Further Reading

Primary sources are listed first. Links were current at publication in September 2026.

CAISO

• California ISO et al., Dynamic Model Review Guideline for Inverter Based Interconnection Requests and Operational Resources, white paper, August 2026 (revision history 10/15/2020, 5/18/2021, 6/2/2021, 8/6/2026). www.caiso.com/library
• California ISO, CAISO Dynamic Model Validation Procedure for Inverter-Based Resources (CAISO/TIP/RT), with the accompanying PSLF EPCL test package (IBR_model_test_v2.p, CheckREModels_v2.p, prerun_setGThevn.p, Runs_IBR_Tests.runs) and the PRC-029 Ride-Through Requirements spreadsheet. www.caiso.com/library
• California ISO, Electromagnetic Transient Modeling Requirements, April 2021; Business Practice Manual for Transmission Planning Process, Section 10.
• CAISO tariff filings: FERC Order 827 compliance (ER17-114, October 2016); automatic voltage regulator requirements (ER17-490, December 2016); inverter-based interconnection requirements including momentary cessation and transient data recording (ER19-1153, accepted July 2019).

WECC and NERC

• WECC Modeling and Validation Work Group, Inverter-Based Resources Power Plant Modeling and Validation Guideline, 2026; WECC Approved Dynamic Models, May 2026; WECC memoranda on RES modeling updates (February 2023 Rev 27b; January 2024). www.wecc.org
• NERC, PRC-029-1 Frequency and Voltage Ride-through Requirements for Inverter-based Resources, effective October 1, 2026; Project 2020-02 implementation plan for PRC-024-4 and PRC-029-1. www.nerc.com
• NERC Inverter-Based Resource Performance Subcommittee, Reliability Guideline: Power Plant Model Verification for Inverter-Based Resources, September 2018; Reliability Guideline: Performance, Modeling, and Simulations of BPS-Connected Battery Energy Storage Systems and Hybrid Power Plants, June 2023.

FERC



• FERC Order No. 827 (reactive power requirements for non-synchronous generation, 2016); Order No. 842 (primary frequency response, 2018); Order No. 901 (reliability standards for inverter-based resources, October 2023).
  

Frequently Asked Questions

Disclaimer

This document is published by Keentel Engineering for general technical information and educational purposes. It summarizes publicly posted California ISO, WECC, NERC, and FERC materials as they stood in September 2026. Those documents, the CAISO Tariff and Business Practice Manuals, and the NERC Reliability Standards control over any summary here and are revised periodically. Readers must verify every requirement, parameter range, and date against the current controlling document before relying on it.



Nothing in this document constitutes a compliance determination, legal advice, or engineering services for any specific facility. Model acceptance is determined by the CAISO and the applicable Participating Transmission Owner; PRC-029-1 compliance is determined by the Compliance Enforcement Authority. Parameter values quoted are the guideline's requirements and examples, not recommendations for any particular plant.

The observations on the CAISO EPCL toolkit are Keentel's own reading of the published code and are offered to assist users; they have not been confirmed by the CAISO.

Keentel Engineering provides electrical engineering and NERC Operations and Planning compliance support services. Field testing of generating units is performed by accredited testing contractors. Some analysis platforms and work scopes may be carried by Keentel's subconsultants under Keentel's direction; Keentel does not share its study methodologies, workflows, or tool configurations.

Keentel Engineering is not affiliated with, endorsed by, or sponsored by the California Independent System Operator, any of the transmission owners named, the Western Electricity Coordinating Council, the North American Electric Reliability Corporation, the Federal Energy Regulatory Commission, or any software vendor. GE PSLF, PSS®E, PSCAD, DIgSILENT PowerFactory, ASPEN OneLiner, and ETAP are trademarks of their respective owners and are named for identification only; Keentel adopts no vendor performance claim.

Keentel Engineering makes no warranty, express or implied, as to the accuracy, completeness, or fitness for any purpose of the information in this document, and accepts no liability for any loss arising from its use.

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