A power system study is not a deliverable. It is a decision. The load flow result sizes the transformer. The short circuit result rates the breaker. The arc flash result is the boundary between a near-miss and a fatality.
Load flow, short circuit, arc flash, relay coordination, harmonic analysis, transient stability, EMT modeling, and grounding — every study performed by a licensed PE, referenced to the governing standard, in the platform your ISO or utility actually accepts.
A load flow study built on a stale ISO base case produces voltage results that look acceptable on paper but won't reflect operating conditions on energisation day. The ISO curtails generation until reactive compensation is added — equipment, installation, re-commissioning, and lost revenue during curtailment.
A short circuit study that omits a parallel transmission path during network reduction understates fault current. The breaker rated for 40kA against an actual 48kA fault doesn't fail on the first event. It operates outside its rating every time the system reaches that level — until it fails catastrophically, and the investigation traces back to the study.
The study that saves money by cutting corners costs money the moment the grid finds the corner that was cut.
We do not use stale base cases, unverified model parameters, or estimates where measurement is required. Every study supports grid interconnection applications and substation design engineering that depends on getting these results right the first time.
Tell us your project type and voltage level. We'll scope the exact study set — not a generic package — in one call.
Each study below covers its engineering purpose, the governing standard, the software platform we use, and the specific output it produces. Click any study to see the full technical reference.
A load flow study calculates real power, reactive power, and voltage magnitude at every bus under defined operating conditions — the foundation study most other analyses build from. Every interconnection application, substation design, and transmission planning exercise starts here.
The study evaluates normal (N-0), single contingency (N-1), and in some cases double contingency (N-1-1) conditions, identifying thermal overloads, voltage outside the ANSI C84.1 range, and reactive power deficits. For IBR projects, the reactive capability demonstrated here becomes the technical obligation written into the interconnection agreement. See our load flow and voltage analysis services page for queue-specific detail.
| Governing Standard | ANSI C84.1 (voltage limits), IEEE Std 399-1997 (Brown Book — industrial facility analysis), ISO-specific study guide for interconnection. |
|---|---|
| Primary Software | PSS/E (utility and ISO transmission studies), ETAP (industrial and substation studies), DIgSILENT PowerFactory, PowerWorld Simulator. |
| Study Inputs Required | Current ISO base case power flow file (.sav/.raw), transformer nameplate data (MVA, kV, %Z, vector group), generator data including reactive capability curve and exciter model, line impedance and thermal ratings, load data by bus. |
| What Results Show | Bus voltage magnitude and angle at every node, real and reactive power flow on every line and transformer, thermal loading as a percentage of rated capacity, reactive power margin, and N-1 contingency violations requiring mitigation. |
| When It's Required | Interconnection application, substation design transformer sizing, transmission planning N-1 compliance per NERC TPL standards, reactive compensation sizing, generation dispatch studies. |
A short circuit study calculates fault current magnitude during three-phase, single line-to-ground, line-to-line, and double line-to-ground faults — determining whether every breaker, disconnect, and CT has adequate interrupting and withstand rating. Underrated equipment doesn't necessarily fail immediately, but it operates outside its design envelope on every fault until it does.
For interconnection projects, this study also establishes the new resource's fault contribution to the network — critical for IBR projects, where contribution is limited by inverter current control to roughly 1.0–1.2 per unit. Full detail: short circuit fault analysis services.
| Governing Standard | ANSI/IEEE C37.010 (high-voltage breakers), ANSI/IEEE C37.13 (low-voltage breakers), IEC 60909 (international calculation method), IEEE Std 141-1993 (Red Book — industrial facilities). |
|---|---|
| ANSI vs IEC Method | ANSI uses a multiplying factor approach with separate first-cycle and interrupting duty calculations. IEC 60909 uses an equivalent voltage source method. Both are valid; we apply the method the utility's design requirements call for and document the approach clearly. |
| Primary Software | ETAP, ASPEN OneLinere (protective device coordination integration), SKM Power Tools, DIgSILENT PowerFactory. |
| Study Inputs Required | Network single-line with all sources, utility source impedance at point of supply, transformer %Z and X/R ratio, motor data for industrial studies, cable impedance, generator subtransient reactance, and IBR fault contribution model. |
| What Results Show | Maximum and minimum fault current at every bus across all fault types, first-cycle and interrupting duty versus equipment ratings, X/R ratio at each fault point, and identification of equipment with inadequate ratings. |
| When It's Required | Every new substation or major modification, interconnection application fault contribution data, adding generation to an existing system, equipment upgrade decisions, NERC FAC-008 facility ratings validation. |
An arc flash study calculates incident energy in cal/cm² at each piece of equipment and establishes the boundary within which PPE is required — not optional engineering, but a legal and safety obligation under NFPA 70E and OSHA 29 CFR 1910.269. The result depends not just on fault current but on how fast the protective device clears the arc, which means arc flash and relay coordination studies are never independent: when relay settings change, the arc flash study must be updated.
IEEE 1584-2018 changed the calculation methodology significantly from 2002. A pre-2018 study is working with incident energy values that don't reflect the current standard, and PPE requirements may be wrong in either direction. Full detail: arc flash hazard study services.
| Governing Standard | IEEE Std 1584-2018 (calculation methodology), NFPA 70E-2024 (PPE category table), OSHA 29 CFR 1910.269 (electric power generation, transmission, distribution). |
|---|---|
| The 2018 Change | Introduced a multi-variable model accounting for equipment type, conductor gap, electrode configuration, and enclosure dimensions — parameters the 2002 edition ignored. Results can shift higher or lower for the same system, sometimes changing PPE category. |
| Critical Requirement | The study must use as-installed relay settings — not design intent. If the in-service settings differ from the coordination study, the arc flash result based on the coordination study is wrong. We collect relay readouts from installed relays before calculating. |
| Primary Software | ETAP Arc Flash Module, SKM Power Tools (CAPTOR), EasyPower. |
| What Results Show | Incident energy at each piece of equipment at working distance, arc flash boundary, required PPE category per NFPA 70E Table 130.5(G), and equipment exceeding 40 cal/cm² where energised work may be prohibited regardless of PPE. |
| When It's Required | Before any energised electrical work, after any protective device setting change, after generation additions that change fault current, after equipment replacements, and for any facility still operating under a pre-2018 study. |
Relay coordination ensures that when a fault occurs, the closest protective device operates first — isolating the minimum amount of system — while the next upstream device backs it up if the primary fails. This selectivity is established through time-current characteristic (TCC) curves with a typical coordination margin of 0.3 to 0.4 seconds between devices.
For IBR projects, limited fault contribution means traditional overcurrent protection may not see the IBR-fed fault current it needs to operate correctly — directional relays, voltage-restrained elements, or differential protection are often required. Full detail: protective relay coordination services.
| Governing Standard | IEEE Std C37.112 (inverse-time overcurrent relays), IEEE Std C37.230 (distribution line protection), NERC PRC-001-1.1, NERC PRC-024-3/024-4 (generator relay settings within the no-trip zone). |
|---|---|
| Primary Software | ASPEN OneLinere (industry standard for transmission and substation coordination), ETAP Protective Device Coordination, SKM Power Tools (CAPTOR), CAPE. |
| Study Inputs Required | Single-line with all protective devices identified, TCC curves for all relays/reclosers/fuses, CT ratios and saturation data, existing in-service relay settings, short circuit fault current at all buses, utility source protection requirements, and IBR fault current curve across the operating range. |
| Protection Architecture | Differential (87) for transformers and buses, distance (21) for transmission lines, directional overcurrent (67) for IBR applications, and under/overvoltage (27/59) and frequency (81) elements coordinated with IEEE 2800-2022 ride-through requirements. |
| What Results Show | TCC curve plots confirming selectivity, relay setting sheets for every device, quantified time margin between device pairs, identification of coordination failures, and settings satisfying both coordination and NERC PRC-024 no-trip zone requirements. |
| When It's Required | Every new substation or generation interconnection, any protective device setting change, addition of distributed generation or storage, NERC PRC-024 compliance review. |
Solar inverters, wind turbine inverters, BESS converters, VFDs, and arc furnaces all inject harmonic currents into the system. The real danger is resonance: every network has natural resonant frequencies, and when a harmonic current coincides with one, the resulting voltage distortion can amplify dramatically — a 2% baseline distortion becoming 15% at resonance, enough to cause transformer heating, capacitor failures, and relay maloperation.
IEEE Std 519-2022 sets the voltage and current distortion limits referenced by ERCOT, CAISO, PJM, and MISO interconnection requirements. Full detail: harmonic distortion analysis services.
| Governing Standard | IEEE Std 519-2022 (current version, updated from 2014 and 1992), IEC 61000-3-6, IEEE Std 1547-2018 (DER harmonic limits). |
|---|---|
| Key Limits | Voltage THD at the PCC: 5% for systems ≤1kV, 2.5% for 1–69kV, 1.5% for 69–161kV, 1.0% above 161kV. Current distortion limits depend on the Isc/IL ratio at the PCC and the system voltage level. |
| Primary Software | ETAP Harmonic Analysis module, PSCAD (detailed resonance studies), DIgSILENT PowerFactory, SKM Power Tools. |
| Frequency Scan | An impedance scan calculates the driving-point impedance across the harmonic frequency range. Resonant peaks indicate where amplification will occur; harmonic sources are then applied at those frequencies to calculate resulting distortion. |
| Filter Design | Where IEEE 519 violations are identified, passive harmonic filters — tuned LC circuits — are designed with careful detuning to avoid exciting other system resonances as configuration changes shift them over time. |
| When It's Required | Solar, wind, and BESS interconnection applications, industrial facilities with VFDs or rectifiers, adding power factor correction capacitors to a system with existing harmonic sources, unexplained transformer heating or capacitor failures. |
Transient stability evaluates whether generators remain in synchronism following a large disturbance — a three-phase fault, a generator trip, a major load rejection — through a time-domain simulation of generator, excitation, governor, and plant control dynamics over seconds to minutes. For IBR projects without physical inertia, the question shifts: can the plant provide the active and reactive response needed to support voltage and frequency through the disturbance without creating oscillatory instability with other generators?
Large IBR projects connecting to weak grids — low short circuit ratio environments — almost always require this analysis, often paired with EMT. Full detail: transient stability study services.
| Governing Standard | NERC TPL-001-5, NERC TPL-002-1 (Category P1 through P7 events), IEEE Std 1110-2002 (synchronous generator modeling practices). |
|---|---|
| Primary Software | PSS/E (PSSNSIM time-domain solver — industry standard), DIgSILENT PowerFactory (RMS simulation), PSCAD (when EMT-level accuracy is needed for IBR dynamics). |
| IBR-Specific Considerations | IBRs have no rotational inertia. High IBR penetration means low effective system inertia, which means high rate-of-change-of-frequency (RoCoF) following generation loss — capable of triggering under-frequency load shedding before primary frequency response can arrest the decline. |
| SSR Screening | Wind projects connecting to series-compensated transmission lines must screen for sub-synchronous resonance — an interaction between the turbine mechanical system and line electrical resonance that can damage shaft components. ERCOT has specific SSR screening requirements for series-compensated areas. |
| What Results Show | Rotor angle, terminal voltage, active/reactive power, and frequency plots per generator per contingency; stability margin by contingency category; critical clearing time analysis. |
| When It's Required | ISO system impact study above the size threshold (typically ≥20MW at most ISOs), NERC TPL compliance for transmission owners, high-IBR penetration scenarios, large load interconnection with dynamic load characteristics. |
EMT analysis models instantaneous electrical behavior at the microsecond timescale — far below what RMS phasor tools like PSS/E or ETAP can represent. Where load flow and stability tools assume sinusoidal currents changing slowly over time, PSCAD models individual switching events in inverter power electronics and the control system response at switching-frequency timescale.
With IBRs exceeding 60% of generation capacity in some local areas at peak periods, this is no longer an exotic specialty — CAISO, ERCOT, and the Western Interconnection have issued guidance or requirements for EMT modeling in high-IBR scenarios. Full detail: EMT analysis and PSCAD modeling services.
| Governing Standard | No single NERC standard mandates EMT universally — it's ISO-specific. CAISO requires it for certain IBR scenarios; ERCOT PGRR and WECC guidance define when it's required. IEEE 2800-2022 §9 allows EMT model validation as an alternative to physical factory testing. |
|---|---|
| When RMS Isn't Enough | Sub-synchronous control interactions with series-compensated lines, control interactions between adjacent IBR plants on a weak grid, fast voltage transients during fault ride-through, and harmonic resonance near the inverter switching frequency. |
| Primary Software | PSCAD/EMTDC (Manitoba Hydro International — industry standard), DIgSILENT PowerFactory (EMT solver), MATLAB/Simulink (control design and HIL testing). |
| IBR Model Types | Manufacturer-provided detailed EMT model (most accurate, sometimes black-box), WECC composite load model with EMT representation, generic WECC/EPRI models, and average-value models adequate for most interconnection purposes. |
| What It Reveals | Stability in weak grid conditions (SCR <1.5 at POI), dynamic interaction between adjacent IBR plants, transient overvoltage during ride-through, harmonic performance at switching frequency, and effectiveness of proposed control adjustments. |
| When It's Required | CAISO interconnection for high-penetration IBR scenarios, ERCOT where PGRR/ISO guidance requires it, WECC interconnection in high-IBR areas, weak grid locations (SCR <1.5–2.0) regardless of ISO requirement. |
A grounding grid provides the low-impedance path for fault current to earth and limits step and touch voltage at the surface to safe levels for personnel. Step voltage is the difference between two points on the ground a pace apart during a fault; touch voltage is the hand-to-foot difference a person would feel touching an energised metallic object. IEEE Std 80-2013 defines the tolerable limits for both.
An inadequate grid produces step and touch voltages that exceed tolerable limits — a risk that isn't theoretical; OSHA records electrical fatalities in the power industry every year, many attributable to grounding design that was never formally assessed. Full detail: grounding system engineering services.
| Governing Standard | IEEE Std 80-2013 (AC substation grounding safety), IEEE Std 81-2012 (measuring earth resistivity and ground impedance), IEEE Std 367 (ground potential rise). |
|---|---|
| Primary Software | CDEGS (SES Technologies — industry standard), ETAP Grounding module, WinIGS. |
| Soil Resistivity | The study begins with Wenner or Schlumberger four-pin soil resistivity measurements per IEEE Std 81-2012. We review all soil resistivity reports before accepting them — inadequate measurement density or incorrect pin spacing are common issues that invalidate the resulting soil model. |
| What Results Show | Grid resistance to remote earth, ground potential rise (GPR) during a fault, step and touch voltage distribution across the substation, comparison against IEEE 80 tolerable limits, and recommendations for grid additions or surface treatment. |
| GPR & Telecom | IEEE Std 367 specifies evaluating and mitigating GPR effects on telecommunications cables entering the substation — less critical for fibre SCADA, but a real hazard for legacy metallic telephone pairs or copper control cables. |
| When It's Required | Every new substation or major modification, substation expansions adding fault current contribution, any substation never formally assessed per IEEE 80-2013, NERC FAC-001 facility connection compliance. |
We review existing ETAP, PSS/E, or DIgSILENT models before accepting them as a study basis. An unverified model is worse than starting fresh.
ISOs, utilities, and regulators have specific software requirements for submitted study deliverables. A study performed in a platform the ISO doesn't accept must be rerun before submission is valid. We work in every major platform US utilities and ISOs use.
| Software | Developer | Primary Use | ISOs / Utilities That Accept It |
|---|---|---|---|
| PSS/E | Siemens PTI | Transmission load flow, short circuit, transient stability, dynamic model submission | ERCOT, PJM, CAISO, MISO, NYISO, ISO-NE, SPP — the primary platform for ISO interconnection submissions |
| PSCAD / EMTDC | Manitoba Hydro Intl. | EMT analysis, IBR dynamic model validation, SSR screening, full-resolution harmonic resonance | CAISO (required for certain IBR scenarios), ERCOT, WECC — the industry standard for EMT analysis |
| ETAP | Operation Technology | Industrial and substation studies: load flow, short circuit, arc flash, coordination, harmonics, grounding | Widely accepted by US utilities for substation design studies; meets IEEE and ANSI methodology requirements |
| DIgSILENT PowerFactory | DIgSILENT GmbH | Load flow, short circuit, stability, EMT, harmonics — full-capability platform | ISO-NE (DDMS integration), some WECC utilities, international and multi-jurisdiction studies |
| ASPEN OneLinere | Advanced Systems | Protective relay coordination, short circuit, fault study — leading protection engineering platform | Widely accepted by US utilities; integrates directly with relay setting calculation and TCC plotting |
| SKM Power Tools | SKM Systems Analysis | Load flow, short circuit, arc flash, relay coordination, harmonics — full study suite | Accepted by US utilities; widely used in industrial facility studies and NFPA 70E compliance work |
| CDEGS | SES Technologies | Grounding analysis: soil modeling, grid design, step/touch voltage, GPR, EMI/EMF | IEEE 80 compliant; accepted for substation grounding and transmission line/pipeline EMI studies |
| CAPE | Electrocon Intl. | Protective relay coordination and short circuit analysis for large protection portfolios | Used by major US transmission owners and utilities for transmission-level protection engineering |
The quality of a study is determined by the quality of its inputs. We do not use placeholder data or manufacturer-typical values where measured or nameplate values are available.
Current ISO base case power flow file dated within 12 months, single-line diagram reflecting current configuration, transformer nameplate data, generator MW/MVAR limits and droop setting, proposed POI bus identification.
All load flow data above, utility source impedance at point of supply (requested from the utility in writing), transformer impedance, cable impedance, motor data for industrial studies, IBR fault contribution curve from the manufacturer.
Short circuit results, all protective device settings actually in service (not design intent), CT ratios and burden, fuse time-current curves, equipment enclosure classification per IEEE 1584-2018, working distance per NFPA 70E Table 130.5(C).
Short circuit results at all buses, existing in-service relay settings, CT ratios and accuracy class, relay models and manufacturer TCC curves, utility source protection requirements, IBR fault current versus terminal voltage curve.
Single-line with all capacitor banks and cable data, harmonic current injection spectrum from the inverter manufacturer at multiple loading points, cable lengths and cross-sections for the collector system, location and rating of all PFC capacitor banks.
Validated dynamic models in the ISO-required format, exciter and governor parameters, plant-level control block diagram for IBR projects, load model type, contingency list from the ISO study guide or NERC TPL standard.
Manufacturer-provided EMT model files with parameterisation data, plant-level control block diagram (white-box preferred), transformer leakage inductance, collector cable parameters, Thevenin equivalent grid impedance at the POI.
Soil resistivity measurements with a minimum of 6 sets at spacings from 0.5m to 30m, site plan with proposed dimensions and layout, maximum symmetrical ground fault current and earth split factor, fault clearing time from the coordination study.
We review third-party power system studies as part of interconnection technical review and NERC compliance assessments — and we find the same six errors often enough to know what to look for.
We review studies prepared by other firms during interconnection technical reviews, due diligence, and NERC compliance assessments. These appear often enough that every owner who hasn't personally reviewed their underlying studies should know about them.
The grid in the study area changes as new generation connects and old generation retires; an 18-month-old base case may miss hundreds of megawatts of new capacity.
Voltage results that don't reflect current conditions. Reactive compensation sized inadequately. ISO study review flags the discrepancy and requires re-study.
Network reduction incorrectly eliminates a transmission path that contributes fault current, understating the calculated fault current at the study bus.
Breakers, switches, and CTs rated on the reduced calculation may be inadequate for actual fault conditions — equipment failure with real personnel safety consequences.
Relay settings adjusted during commissioning or afterward for operational reasons, with the arc flash study never updated to match.
Incident energy that doesn't reflect actual clearing time. If the installed relay is slower than assumed, the real incident energy is higher than the label states — an engineer working under-protected.
Long underground collector cable runs carry significant shunt capacitance that interacts with system inductance to create resonant frequencies — easy to omit in a simplified model.
Resonance at a frequency the model missed entirely. Transformer heating, capacitor failures, and IEEE 519 violations the study never predicted.
The submitted model represents only inverter-level control with generic manufacturer parameters, missing the plant-level controller that coordinates reactive power and curtailment across all inverters.
ISO system impact study results don't accurately predict the plant's response to disturbances. Post-commissioning performance misses the prediction; the ISO may impose additional studies or operating constraints.
A single measurement set at one spacing is inadequate for sites with two-layer or multi-layer soil structures where resistivity changes significantly with depth.
A grid designed against an incorrect soil model — under-designed for high-resistivity shallow soil, or over-designed for the opposite. Both are engineering failures of the study itself.
Every study follows this process regardless of type. Only the timeline within each step changes with complexity and data completeness.
We define the exact study scope — type, system boundaries, contingency cases, applicable standards, deliverable format — and issue a data request specifying every input, its required format, and accuracy. We don't begin modelling until critical inputs are confirmed available and credible.
Every input is reviewed for completeness and credibility before the model is built. Nameplate data is cross-checked against manufacturer sheets; relay settings are confirmed current from the installed relay, not the coordination file. Where data is missing or questionable, we stop and resolve the gap.
The study runs in the specified platform across all contingency cases. We review preliminary results against engineering expectations before finalising — an unexpected result is always investigated, because it's either a discovery or an error, and both require attention.
A second licensed PE reviews the model, methodology, and results independently of the engineer who ran the study. Findings are resolved before the report is written. We don't issue studies that haven't been through this step — it's what separates an engineering study from a software output.
The report is written for its specific audience and purpose — an ISO submission, a utility design review, a NERC compliance audit, or an owner's due diligence review — each with different format and methodology documentation requirements.
The draft is delivered for review with a technical walkthrough call covering results, implications, and recommendations. Comments are addressed and the final report issued. For ISO submissions, we support the process and respond to any technical questions that follow.
Required study sets depend on project type, size, voltage level, and the specific ISO or utility requirement. This matrix shows typical requirements for the project types we support most.
| Project Type | Load Flow | Short Circuit | Arc Flash | Relay Coord. | Harmonic | Trans. Stability | EMT | Grounding |
|---|---|---|---|---|---|---|---|---|
| Utility-Scale Solar (>20MW) | R | R | R | R | R | Rec | Cond* | R |
| Utility-Scale Wind (>20MW) | R | R | R | R | R | Rec | Cond* | R |
| Utility-Scale BESS (>20MW) | R | R | R | R | R | Rec | Cond* | R |
| Co-Located Solar + BESS | R | R | R | R | R | R | Cond* | R |
| HV Substation (New) | R | R | R | R | Rec | Rec | — | R |
| Industrial Facility (MV Supply) | R | R | R | R | R | — | — | R |
| Transmission Line (New) | R | R | — | R | — | R | — | R |
| Large Load (>50MW) | R | R | R | R | R | R | Cond* | R |
| Brownfield Substation Upgrade | R | R | R | R | Rec | Rec | — | Rec |
Timeline depends on study type, system complexity, and data completeness. As a general guide: load flow and short circuit studies take 2 to 4 weeks. Arc flash takes 3 to 6 weeks — often limited by collecting as-installed relay settings from the field. Relay coordination runs 4 to 8 weeks for a substation with a moderate number of relays. Harmonic analysis takes 3 to 6 weeks, transient stability 4 to 8 weeks, EMT analysis 6 to 12 weeks (manufacturer model procurement is typically the critical path), and grounding studies 3 to 6 weeks after soil resistivity measurements are received.
Yes, with a caveat. We review the existing model before accepting it as the basis for a new study — verifying it reflects current system configuration, that parameters match current nameplate or measured data, that the ISO base case is current vintage, and that the model structure fits the study type. If we identify issues, we'll document them and discuss whether to update the model or start fresh. Using an incorrect model is worse than starting from scratch, because it produces results that appear credible but are wrong.
Yes. All power system study reports are prepared by a licensed Professional Engineer and available with a PE stamp in the applicable state. Most utility interconnection applications and all arc flash studies for OSHA and NFPA 70E compliance require a PE-stamped report. We confirm the PE license requirements for your specific project and jurisdiction at the start of the engagement.
RMS phasor-based tools — PSS/E, ETAP, DIgSILENT in RMS mode — model the system at the fundamental 60Hz frequency assuming sinusoidal voltages and currents, and are adequate for most load flow, short circuit, and stability analyses. EMT tools like PSCAD model instantaneous waveforms including inverter switching behavior at the microsecond timescale. EMT is required when the phenomenon occurs at timescales RMS can't capture: inverter control interactions, sub-synchronous resonance, fast ride-through transients, and harmonic resonance near switching frequency. For most US ISO studies an RMS dynamic model is sufficient; EMT is additionally required by CAISO for certain IBR scenarios, by ERCOT where PGRR specifies it, and as best practice for IBR projects in weak grid conditions (SCR <1.5–2.0).
Yes, and several NERC standards directly require study deliverables. FAC-008-5 requires facility ratings calculated using a documented methodology — typically load flow and short circuit studies. MOD-026-2 and MOD-032-2 require dynamic models validated against measured plant data. PRC-019-2 requires a coordination analysis between voltage regulator limits, protection settings, and reactive capability. PRC-024-3 and PRC-024-4 require relay settings within the no-trip zone, validated through a relay coordination study. We prepare deliverables in the format required for NERC compliance evidence, with methodology documentation that survives audit scrutiny.
"The study that was done correctly is the one nobody notices. Good engineering is invisible. Its absence is not."
Tell us your project type, the study type you need, and your submission deadline. We will tell you exactly what data we need and how long it takes.
