Thirty-three years of utility systems, from paper maps to a cooperative's technology estate

Mandate

Establish which business systems Merrowind's operations depend on and protect them, renew the shared technology service used by member cooperatives and replace its 1990s billing system before vendor support ends.

Outcomes

• Moved fourteen operations-essential systems into a separate enclave; a planned test in November 2024 restored all of them from offline copies in 19 hours.
• Converted ten cooperatives and 120,000 accounts to the new billing platform in three waves, with first-cycle exceptions no higher than 0.6%.
• Reduced transformer connectivity errors in the shared outage model from about 11% to under 2%; correct first-device predictions rose from 58% to 87%.
• Built the large-load register that resolved 9.6 GW of data-centre enquiries into 41 projects and 4.1 GW, of which 610 MW had signed facilities agreements by June 2026.

Decisions in context

I joined Merrowind to answer a question its board had asked after the 2021 pipeline attack: could an attack on our office systems stop us operating? Answering it took a year and changed my remit. My team now runs corporate technology, cyber security across business and operational systems in partnership with our operations and compliance staff, data and analytics, and the shared service that provides billing, outage management, mapping and security monitoring to fourteen member cooperatives. I have led the enclave for operations-essential systems, the connectivity programme after the 2023 ice storm, the billing replacement and the large-load register. I report to our chief executive, present cyber risk to the audit and risk committee twice a year, design the board's annual tabletop exercise and took the large-load register to the full board in 2025. I am not a director of Merrowind or of any member cooperative.

Reason for the move

Current appointment; completing the final billing wave and the large-load contract requirements.

Mandate

Replace an outsourced billing and enrolment platform that was producing errors and calls, and give the business systems it could change without a vendor's release cycle.

Outcomes

• Moved 410,000 accounts to an in-house billing and enrolment platform in 2017 with first-cycle exceptions of 0.8%.
• Reduced billing-related calls per thousand customers by 37% between 2016 and 2019.
• Held 61,000 bills affected by incomplete meter data after the February 2021 storm rather than send estimates, and paired the corrected bills with payment-plan offers.
• Supported the transfer of the customer book to the acquiring retailer in June 2021 without a missed bill cycle.

Decisions in context

Corvallen was a retail business in which technology was most of the operation. Customers enrolled online, switched readily and judged us mainly on the bill, which depended on meter data sent by the regulated wires utilities through the market's data exchange. When I arrived, billing ran on an outsourced platform whose vendor released changes twice a year, and bill errors drove about a third of our calls. I led the move to a platform we controlled, with parallel bill runs and a team of billing analysts who sat beside the call centre. During the February 2021 storm the decisions were about cash and fairness at once: wholesale losses were mounting, meter data was late, and I recommended holding bills rather than estimating them. I reported through those weeks to the risk committee of the sponsor's board of managers. The sale of the customer book that summer ended the role.

Reason for the move

The sponsor sold the customer book to a larger retailer in mid-2021 after storm losses, and my role ended with the transfer.

Mandate

Take over a billing replacement that was behind schedule, bring it into service and then stabilise billing.

Outcomes

• Took the new billing system live in October 2012; about 38,000 bills were delayed or estimated in the first two cycles.
• Presented the conversion review to the audit committee in 2013 and led the stabilisation plan.
• Brought estimated bills back below 0.5% of each cycle by mid-2013.
• Worked with the rates department to reduce active rate and rider combinations from more than 900 to 410 by 2014.

Decisions in context

I inherited a billing replacement eighteen months into its life, with a vendor, an integrator and a business that each believed another party owned the design. I reorganised the programme around a single test plan and brought the system live in October 2012, later than planned and, as it turned out, not ready. The first two cycles produced about 38,000 delayed or estimated bills and several hundred complaints to the state commission. I presented the review to the audit committee, and the finding I owned was that we had converted every rate and rider combination without asking which were still needed. The stabilisation that followed took most of 2013: manual review queues, extra call-centre staff and a programme with the rates department to retire combinations nobody used. The episode is the reason I now insist that boards retire rate codes before conversion begins.

Reason for the move

Recruited by Corvallen Energy Services to lead technology at a retail electricity provider.

Mandate

Replace the control centre's energy management system and extend SCADA communications to every transmission substation.

Outcomes

• Replaced the energy management system in 2006 with a staged cutover and no loss of control-centre visibility.
• Extended SCADA communications to all 118 transmission substations.
• Prepared the control-centre systems for the first mandatory cyber security standards for the bulk power system, approved by federal regulators in 2008.

Decisions in context

This was my largest operational technology role. Hollensby's control centre ran on an energy management system near the end of its life, and several transmission substations still reported only by telephone. I led the replacement with a staged cutover, running old and new systems side by side for eleven weeks, and extended communications to every transmission substation. Towards the end of the period the first mandatory cyber security standards for the bulk power system were approved, and I helped define which of our control-centre systems they covered and what had to change. The work taught me the discipline of operating technology, where nothing goes live without a way back, and that discipline was the reason I was asked to take over billing. I left control systems reluctantly, and I still think the habits of a control room are useful on the business side.

Reason for the move

Asked to take over the billing replacement programme.

Mandate

Extend SCADA to the district's substations and modernise its operations communications.

Outcomes

• Extended SCADA monitoring and control from 9 to 46 substations.
• Replaced the district's radio network for crews and substations.
• Took the operations systems through the 2000 date change without a service interruption.

Decisions in context

Wessendine gave me my first full control-system programme and my first elected board. The district was customer-owned, its directors were farmers, merchants and a retired teacher, and they asked about our SCADA spending in terms of what their neighbours would notice. I extended monitoring and control from nine substations to forty-six, replaced the radio network the crews depended on and, from 2000, supervised the five technicians who maintained the district's operations technology. I studied for my master's degree in the evenings, which gave me the vocabulary of information systems to go with what I knew about protection relays and radio paths. The district was small enough that I saw every consequence of my work, and good enough to teach me that an elected board is a strength when management reports to it plainly.

Reason for the move

Recruited by Hollensby Electric Company to run a larger control-centre system.

Mandate

Design line extensions and system improvements, then supervise staking and build the cooperative's first substation monitoring.

Outcomes

• Designed about 600 line extensions to farms, grain facilities and oil leases.
• Built the cooperative's first remote monitoring link to its 12 substations in 1996.
• Converted the paper system maps for two of five districts to a digital format.

Decisions in context

Ossory Creek was where I learnt what a cooperative is for. I designed line extensions for members who had often waited months for them, walked the routes with landowners and learnt to estimate a job from a pickup truck. The cooperative's knowledge of its own network lived on paper maps and in the heads of its line foremen, and an ice storm in my second winter showed me how quickly the two could disagree. I persuaded the manager to let me build a radio link to our substations, the cooperative's first remote monitoring, and began converting two districts' maps to a digital format. When I left for Nebraska I took with me a lasting respect for line crews and a habit of checking records against the line itself. That habit returned with me to Merrowind twenty-three years later.

Reason for the move

Moved to a larger utility to specialise in control systems.