Thirty-two years between the pole line and the control room

Mandate

Bring information and operational technology under one accountable executive after a 2018 review of control-system connections, then modernise metering, automation and storm resilience within a regulated capital plan.

Outcomes

• Closed fourteen always-on supplier connections into control systems; isolated-operation drills grew from nine hours in 2022 to seventy-two in 2025.
• Delivered a C$41.6m automation and covered-conductor programme; in the March 2025 ice storm 37,000 customers were restored automatically within five minutes.
• Began a feeder-sequenced replacement of 287,000 meters; 121,000 installed by June 2026, deferring C$19m of transformer replacements.
• Cut outage detection for metered customers from 38 minutes to about six.
• Introduced back-testing of every asset-health model before it informs the distribution system plan.

Decisions in context

The chief technology officer role was created after a review found more connections into our operational systems than anyone had documented, and the board wanted one executive accountable for both corporate and grid technology. My first two years went on knowing and closing those connections and on making the control room able to work alone. The February 2022 storm then shifted the agenda to resilience, and I spent much of that year persuading our board, and arguing with our largest shareholder's council, that automated switching would protect more customers per dollar than burying the lines in two town centres. Since 2023 the meter replacement has been the largest programme in my portfolio. I also sit on the board of our fibre affiliate and work with a neighbouring First Nation's development corporation on a jointly owned substation. I am not a director of the holding corporation or of the regulated distributor.

Reason for the move

Current appointment; completing the meter programme and the technology evidence for the 2027 cost-of-service application.

Mandate

Replace a control system installed in 1999, introduce an advanced distribution management system and start automating switching on the longest rural feeders.

Outcomes

• Commissioned the advanced distribution management system in 2018, four months late and within 6% of budget.
• Automated switching on the first 31 rural feeders, cutting customer-minutes lost on them by 27% over two winters.
• Rebuilt protection settings on 140 feeders, retiring settings that dated from the 1980s.
• Commissioned the 2018 external review of control-system connections that led to the creation of the chief technology officer role.

Decisions in context

I came back to Ontario wanting to work on a distribution grid again, and Quillmere needed someone to replace a control system that had outlived its supplier. The project was harder than the contract suggested. The network model inherited from the old system was inaccurate in hundreds of places, and we spent most of a year walking feeders to correct it before the new system could be trusted to suggest switching. I insisted on that, and it is why the project was four months late. Alongside it I began automating switching on our longest rural feeders and rebuilt protection settings that nobody had reviewed for decades. I also asked for an external review of every connection into our operational systems, because I knew from my years with a supplier what we were likely to find. Its findings changed the shape of the company's technology leadership.

Reason for the move

Appointed chief technology officer when the board combined information and operational technology under one executive.

Mandate

Run the site's power systems reliably, and from 2012 establish whether and how the site could capture a million tonnes of carbon dioxide a year.

Outcomes

• Raised cogeneration availability from 91% to 96% through protection and maintenance changes.
• Recommended a C$31m pilot instead of a C$1.4bn flue-gas capture plant; the pilot captured about 9,800 tonnes.
• Measured solvent losses at 2.3 times the supplier's estimate, revising the full-scale cost to C$171 a tonne avoided.
• Supported steam-to-oil ratio reductions from 3.1 to 2.7, avoiding about 190,000 tonnes a year.

Decisions in context

I went to Alberta to work on a large industrial power system, and for three years that was the job: a 170-megawatt cogeneration plant, a site electrical network in deep cold and a protection scheme that had to keep steam generation running when the plant tripped. In 2012 our parent announced its capture ambition and I was asked to lead the technology work. It was the most commercially uncomfortable assignment of my career. The engineering was interesting, but the figures did not support the announcement, and my role became explaining why to people who had already made a public commitment. I recommended a pilot and efficiency work instead of a plant. The pilot's results vindicated the caution and made the economics worse, which nobody enjoyed. When the oil price fell, the programme stopped, and my family and I decided it was time to go home to Ontario.

Reason for the move

The capture programme was suspended after the oil price fall of late 2014; I returned to Ontario for family reasons.

Mandate

Manage metering and protection engineering, then deliver the provincially required smart meter programme for 96,000 customers.

Outcomes

• Installed 96,000 smart meters between 2007 and 2009, on schedule and 4% under budget.
• Moved residential and small-business customers onto time-of-use billing by mid-2009.
• Reduced estimated bills from about 11% to under 1% of bills issued.
• Standardised protection settings across the distributor's eleven substations.

Decisions in context

I joined Ardmoor to return to a distributor after four years with a supplier, and spent my first three years on metering and protection. When the province decided that every home and small business should have a smart meter, the programme came to me. We delivered it well by the measures we had set: on time, under budget and with estimated bills almost eliminated. I learnt how to manage installation contractors, customer complaints and a collection system that behaved differently in the field from the laboratory. I also learnt, more slowly, that we had defined success too narrowly. Our meters served billing and time-of-use pricing, and almost none of their data reached the engineers running the grid. That lesson shapes the replacement programme I lead today. I left because I wanted to work on a large industrial power system before deciding where my career would settle.

Reason for the move

Recruited to an oil-sands producer to work on a large industrial power system.

Mandate

Design and commission substation automation and protection systems for distributors, transmitters and industrial plants.

Outcomes

• Commissioned automation in 37 substations for eleven customers.
• Led the company's first project to replace relay-panel control wiring with networked controllers.
• Wrote the commissioning checklist the company used until 2008.

Decisions in context

I joined Fenwright because I wanted to see grid technology from the side that builds it. I spent four and a half years designing and commissioning protection and control systems, first as an applications engineer and then running projects. I learnt more about protection logic, communications and testing than any utility could have taught me in the same time. I also completed my master's degree in the evenings. The part of the job that stayed with me most was support. We routinely left modems and later network connections into customers' substations so that our engineers could change settings remotely, and customers were grateful. Few of them kept a register of those connections. When, fifteen years later, I asked for a review of every path into Quillmere's operational systems, I knew from this period exactly what kinds of doors we would find.

Reason for the move

Returned to a distributor to work on its metering and protection systems.

Mandate

Gain the experience required for licensure, then take responsibility for distribution design and protection settings.

Outcomes

• Licensed as a professional engineer in Ontario in 1998.
• Reviewed and reset protection on all nine of the commission's feeders after a nine-hour lockout in 1996.
• Spent eleven days on mutual-aid switching and restoration in eastern Ontario after the January 1998 ice storm.

Decisions in context

Larchfield was a small commission with a general manager, two line crews and one engineer, so I learnt the whole of distribution at once. I designed pole lines and service connections, sized transformers and, in storms, wrote switching orders. In February 1996 a recloser on a rural feeder locked out a township for nine hours because of a spruce limb, and when I traced the cause I found settings nobody had reviewed in a decade. The general manager let me review and reset protection on every feeder, which became my first real project. In January 1998 I joined a mutual-aid crew in eastern Ontario after the ice storm, where inaccurate records made every switching sequence slower. I left that autumn convinced that I needed to understand the technology itself, not only how utilities used it.

Reason for the move

Joined a protection and automation manufacturer to learn grid technology from the supplier's side.