An engineer who learnt to ask who owns the setting

The first lesson I learnt about grid technology came from a recloser that did exactly what it had been set to do. In February 1996 I was a junior distribution engineer at Larchfield Hydro-Electric Commission, a municipal utility serving about 14,000 customers in northern Ontario. A spruce limb fell across a rural feeder in a snowstorm. The recloser on that line tried three times to clear the fault and then locked out an entire township for nine hours, while a crew drove sixty kilometres to find a branch they removed in twenty minutes. Nobody had made a mistake. The settings had been chosen in another decade for another load, and nobody had looked at them since. I have distrusted settings that nobody owns ever since.

I had joined Larchfield in June 1994, a month after finishing a bachelor's degree in electrical engineering at Dunmorrow University. A utility of that size gives a young engineer everything at once: pole-line design, transformer sizing, protection settings, customer connections and, in a storm, the switching orders. In January 1998 I spent eleven days with a Larchfield crew on mutual aid in eastern Ontario after the ice storm, writing switching sequences on a clipboard in a truck because the host utility's records did not match what stood on the poles. I came home convinced that the most valuable thing a utility owns, after its people, is an accurate picture of its own network.

That conviction took me, in October 1998, to Fenwright Automation, a private manufacturer of substation protection and control systems near Toronto. I commissioned automation for utilities and industrial plants in Ontario and Quebec, and I completed a part-time master's degree in power systems at Carronbridge University. I also learnt something less comfortable. To support our customers we routinely left dial-up modems, and later network links, into their substations so that our engineers could change settings from the office. It was good service. It was also a door the utility often did not know was open. Years later, sitting on the other side of that arrangement, I knew exactly where to look.

In April 2003 I joined Ardmoor Hydro, a municipally owned distributor in southern Ontario, as senior metering and protection engineer. When the province decided that every home and small business should have a smart meter by the end of the decade, I became manager of our programme. We installed 96,000 meters between 2007 and 2009, on schedule and slightly under budget, and I was proud of it. The disappointment came later. The meters were justified mainly as a way to change how customers used electricity through time-of-use prices, and the data they produced was hourly, collected once a day and almost never used to run the grid. We had bought an instrument for the bill. Fifteen years later I am replacing that generation, and I have tried hard not to make the same choice twice.

In August 2009 I moved to Alberta to join Kelsvar Oil Sands Corporation, which produced bitumen by steam-assisted gravity drainage and ran a 170-megawatt cogeneration plant for its own steam and power. I wanted to work on a large industrial power system, and I did. From 2012 I also led the company's carbon capture work. Our parent company had announced an ambition to capture a million tonnes a year in Canada, and my team's job was to say how. Our studies put the cost of capturing carbon dioxide from the steam generators' flue gas at about C$146 a tonne avoided, at a time when the provincial compliance price was C$15. I recommended a pilot rather than a plant. Some colleagues regarded that as timidity, and I understand why. When oil prices fell in late 2014 the programme was suspended, and in 2015 I came back to Ontario with my family.

I joined Quillmere in September 2015 as vice-president of grid modernisation and system control. We replaced a control system installed in 1999, introduced an advanced distribution management system and began automating switching on our longest rural feeders. In 2018 an external review found that our operational systems had more connections to the outside world than anyone had documented, several of them supplier links of the kind I had once installed myself. The board decided to bring information and operational technology under one executive, and I was appointed chief technology officer in April 2019.

Since then three things have shaped my work: freezing rain, which damaged our network badly in 2022 and again in March 2025; the possibility of an attack that takes away the systems we use to run the grid; and the end of life of the meters installed fifteen years ago. Each time I have argued for spending that is less visible than the alternative: automated switches instead of buried cable in two town centres, rehearsals of running the grid by hand instead of another layer of monitoring software, and a meter programme sequenced by what feeders need rather than what suits the installer's routes.

I am a licensed professional engineer in Ontario and I still read protection settings for pleasure. Colleagues would say that I ask who owns a number before I ask whether it is right, that I prefer a failed drill to an untested plan and that I am slower than some would like to declare a programme finished. I am working on the last of those.

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