When the City of Medicine Hat first discussed investment into the Saamis Solar project, the plan was for a much smaller stake than buying the whole thing. The sun shines through the windows at Medicine Hat city hall in this file photo.--NEWS FILE PHOTO
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City power officials originally sought to purchase only the power and lockup carbon credits from a planned private-sector solar field in Medicine Hat, the News has learned.
But, officials found the financial arrangement commonly used by private companies would not fit the site or be a good fit for the Medicine Hat power company.
Instead, negotiations with DP Energy turned toward buying the project, and building in phases to supply power directly to the local grid, said energy division managing director Rochelle Pancoast, rather than seeing it exported, or simply collecting carbon credits from projects elsewhere.
“At that point (power purchase agreement) just becomes financial, which doesn’t make sense for us,” said Pancoast. “We are targeting physical energy as well, and by owning it, we control the scale (of phases) to the amount of energy we need.”
Pancoast is scheduled to address council’s energy committee today with an outline of the city’s announced purchase of the Saamis Solar Park, planned for 1,600 acres of vacant land in the city’s north end, in relation to an ongoing “clean energy strategy.”
Launched two years, ago, the strategy calls for deep analysis, small steps and maintaining options as the sector rapidly changes ahead of net-zero transition over the next 10 to 25 years.
The large step of taking over the 325-megawatt capacity solar field – to augment the city’s existing 299-megawatt gas-fired capacity – has been criticized by some as too large.
The Medicine Hat Utility Ratepayers Association has said full transparency is required and called for a pause as larger energy business review is completed.
Former MLA Drew Barnes called the purchase “a knee jerk reaction.”
“By entering a Power Purchase Agreement (PPA) we could cherry pick the best rates,” Barnes told the News. “We absolutely have to remain flexible or the province and the feds will continue to carbon tax us.”
Pancoast said reconfiguring the site – to provide physical power back to the city along with planned export line to the provincial grid – was deemed to be cost prohibitive.
“It was not a viable option, at which point we expressed a desire to take ownership,” said Pancoast, adding that a number of renewable projects in the region have approached the city about entering into power purchase agreements.
The Business Renewables Centre promotes the arrangement as a way for corporations to lower carbon emissions and aid green power development.
By purchasing low-carbon power production at some point on the provincial grid, a company theoretically offsets higher-carbon power used in its operations and the related carbon credits offset levy fees.
Amazon, Budweiser, Pembina Pipelines, banks and other corporations have all signed PPAs with wind and solar producers in southeast Alberta, but the practice hasn’t extended to utilities in Alberta’s private, non-Crown power sector.
Atco, Capital Power and Transalta Utilities have all built or bought renewable projects that produce power as their main line of business.
Crown power providers in Saskatchewan and elsewhere also commonly sign long-term PPAs with private renewable developers as a way to reduce carbon footprint, but those provide physical power to their distribution systems directly for customers.
The City of Edmonton has a PPA with Capstone Energy, which is building the WildRose2 wind facility near Seven Persons, and the City of Calgary is currently tendering bids for wind-power providers.
Both large cities also own power providers – Enmax, Epcor and Edmonton holds shares in Capital Power – but PPAs relate to offsetting municipal power use, not the carbon footprint of their arm’s-length utilities.
Applications to the Alberta Utilities Commission argue that an initial 75-megawatt phase, potentially online in 2027, would help the city utility maintain enough surplus power in peak demand in summer and satisfy a key condition of its power generation charter without adding more gas fired generation at similar cost.
The difference would be lower operating cost, carbon credit income and potentially lower financing charges if federal grants and low-interest loans for green power projects are accessed, say officials.
