While planning a new substation for a growing industrial park, the utility needed to assess voltage profiles across the network.

Perform a comprehensive load flow study to determine if existing infrastructure could support the added demand.

Used PSS/E to model the network, inputting forecasted loads, line impedances, and generator settings; iterated to achieve convergence and evaluated voltage drops and line loading.

Identified a 5 % voltage drop at the farthest bus, prompting the recommendation of a capacitor bank and a line upgrade, which prevented future reliability issues and saved the client $250k in unplanned outages.

During a design review for a wind farm integration project, the team debated generator types for the new turbines.

Explain the operational and construction differences between synchronous and induction generators to guide the selection.

Outlined that synchronous generators produce a constant frequency output, require excitation systems, and can operate as voltage sources; induction generators are slip‑ring or squirrel‑cage, rely on external reactive power, and act as current sources, often simpler and cheaper but need reactive support.

The team chose induction generators for the wind turbines due to lower cost and reduced maintenance, while planning capacitor banks for reactive support, aligning with project budget and performance goals.

The utility required a new 138 kV line to connect two substations in a flood‑prone region, with strict NERC reliability standards.

Develop a comprehensive protection scheme that ensures rapid fault clearance while meeting coordination and selectivity requirements.

Conducted a fault study using ETAP to calculate prospective fault currents; selected distance relays (48 %/67 % zones) at both ends, added a pilot protection (line differential) for high‑speed clearance; coordinated settings with adjacent line and transformer protections; incorporated reclosing logic per NERC PRC‑005‑2; added ground fault detection with zero‑sequence relays and integrated communication via IEC 61850 for remote tripping.

The scheme achieved a clearing time under 30 ms for phase faults and under 100 ms for ground faults, met all coordination margins, and passed the utility’s reliability audit, reducing expected outage duration by 40 % compared to legacy protection.

In 2022 I led a $12 M upgrade of a 115 kV substation that involved civil engineers, protection engineers, and procurement specialists.

Ensure the project stayed on the critical path, meet the utility’s deadline before the summer peak, and stay within budget.

Implemented a detailed Gantt chart, held weekly cross‑functional stand‑ups, used a RACI matrix to clarify responsibilities, and introduced a risk register that flagged supply‑chain delays; negotiated fast‑track shipping for critical transformers and secured an alternate vendor for surge arresters.

The upgrade was completed two weeks ahead of schedule, under budget by 3 %, and passed the post‑commissioning reliability test with zero defects, contributing to a 5 % reduction in outage frequency during the peak season.

During a month when three substation retrofits were slated for commissioning, each had overlapping resource demands.

Determine which tasks to address first to avoid bottlenecks and ensure all projects met their go‑live dates.

Applied the Eisenhower matrix to categorize tasks by urgency and impact, consulted stakeholder impact analyses, and used a weighted scoring model (impact × deadline × resource availability) to rank activities; communicated the priority list to all teams and re‑allocated resources accordingly.

All three retrofits were completed on time, with no overtime costs, and stakeholder satisfaction scores improved by 15 %.

Mid‑project on a 33 kV feeder automation rollout, material costs for smart switches rose 18 % due to supply shortages.

Contain the budget overrun while maintaining project scope and timeline.

Conducted a variance analysis to isolate cost drivers, renegotiated contracts with the vendor for volume discounts, identified alternative suppliers for non‑critical components, and re‑sequenced work to defer non‑essential items to the next fiscal year; presented a revised budget and mitigation plan to senior management with clear ROI justification.

Reduced the projected overrun from $500 k to $120 k, secured approval for the adjusted plan, and completed the automation rollout within the revised budget, delivering a 12 % improvement in fault detection speed.

Our region was preparing for the annual NERC compliance audit for the transmission fleet.

Implement processes that guarantee ongoing adherence to NERC PRC‑005‑2 and PRC‑010‑2 standards.

Established a compliance calendar mapping each standard to quarterly self‑assessments, integrated automated monitoring of key reliability metrics (SAIDI, SAIFI) into the SCADA system, conducted training workshops for operations staff, and performed internal audits with corrective action tracking in a centralized database.

The audit resulted in zero non‑compliance findings, and the region earned a commendation for proactive reliability management, contributing to a 3 % improvement in overall system availability.

During the erection of a new 230 kV tower, I noticed that the grounding rods were installed with insufficient depth, posing a shock risk for crews.

Mitigate the hazard before work resumed and ensure compliance with OSHA and IEEE grounding standards.

Immediately halted work, documented the issue with photos, convened a safety toolbox talk with the crew, coordinated with the contractor to redesign the grounding layout to meet the required 10 ft depth, and updated the site safety plan; performed a follow‑up inspection before resuming work.

The corrected grounding prevented any electrical incidents, the project stayed on schedule, and the incident was logged as a zero‑recordable event in the quarterly safety report.

The IEEE 1547 standard for interconnection was revised, affecting our distributed generation projects.

Ensure our design team incorporates the latest requirements without project delays.

Subscribe to IEEE and NEMA newsletters, attend the annual IEEE PES conference, participate in the local utility’s code‑update webinars, and maintain a shared knowledge base where updated clauses are logged; I also schedule quarterly review meetings to disseminate changes to the engineering team.

Our next DG project was completed with full compliance to the 2023 IEEE 1547 revision, avoiding re‑work and earning positive feedback from the client for proactive code adherence.