Alberta could begin assigning costs for power line upgrades to new power generation projects, according to Utilities Minister Nathan Neudorf.--News File Photo
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Alberta could move to regional system to decide who pays for upgrades to the power grid – a move that could hamper new rural generation projects, but potentially avoid transmission fee hikes that Albertans outside Medicine Hat pay, Utilities Minister Nathan Neudorf said on Thursday.
The change could also potentially drive development costs much higher in areas that are already “congested” – like southeast Alberta – where more power is produced at times than can be handled by existing export lines.
Neudorf told reporters that power demand is set to grow in the province, but generation should be located near existing capacity on power lines, or pay the price for line upgrades.
“How do we build more efficiently, more appropriately and use what we’ve got?” Neudorf said to reporters on a press call Thursday.
“It’s a balance between continued development and growth and the need in the province and affordability, and we think we’ve got that worked through.”
Bill 52 would allow grid administrators to begin determining how to assign charges for new line builds and upgrades, among other items. It was introduced in the legislature on Thursday, and, if approved, the final regulations and market changes are expected to take effect in 2027.
Line costs, currently incurred by line owners, are charged back to most Albertans as transmission amounts on bills, but the charge of up to $30 per month has been targeted by the United Conservatives as an affordability issue.
Hatters don’t pay the provincial distribution charge as the city power company typically does not import power. Local officials declined comment on Thursday’s late announcement until Friday.
They have said in the past that it doesn’t expect a proposed solar project would be subject to transmission upgrade costs for new facilities, as the Saamis Solar Park is being redesigned to connect to the local grid, not export lines.
Localized marginal pricing in the provincial grid would identify “areas of congestion and lets the market respond to that in a much more clear way than one price across the province,” as described by ministry officials.
Going forward regulators would examine a project’s relative surplus line capacity, then determine whether higher demand (from customers) or higher generation (from new facilities) is responsible. It would then assess costs to either, or a percentage to both.
“It would be unfair to ask a ratepayer, who is already burdened, to pay more for something they don’t technically need,” said Neudorf. “There’s a great degree of flexibility to our regulator to make sure there is an appropriate answer in individual cases.”
In remote areas, where wind and solar projects are typically located, those costs would likely fall to the generation owner when access and connection fees are paid.
There are seven wind or solar power facilities operating today in Cypress County, while nine others are approved by regulators but have not seen construction start.
Those developers cite the uncertainty as Alberta redesigns its market and transmission cost distribution systems as factors for delaying construction that would total several billion dollars.
A congestion report from the Alberta Electrical System Operator last fall stated that in the southeast hundreds of thousands of megawatt hours of production had been curtailed in recent years, each priced between $0 and $1,000.
Long-term transmission planning documents this year suggest more than $3 billion be spent upgrading and building new lines to shunt power to larger markets.
Hydrogen blending possible
Changes in Bill 52 would also set regulations to allow utility providers to offer hydrogen blending in natural gas supplied for home heating.
A Canadian Safety Association standard of 5 per cent would be allowed if utility companies can prove customer demand and acceptance.
