St. Albert’s proposed solar farm would cover its loan payments, make money, and green the environment in most scenarios, a Gazette analysis suggests, but experts say the city should do more research before puts down the money to build it.
City council approved the project charter for a $26.1-million 15-megawatt solar farm on June 21, and is now considering a bylaw to borrow up to $33.75 million over 20 years to fund its construction.
A feasibility study commissioned from the energy firm ATCO presented to council stated the farm would make the city money while also reducing greenhouse-gas emissions.
City utilities and environment manager Kate Polkovsky told The Gazette the farm’s operating costs had been pegged at $120,000 a year (inclusive of the cost to replace its inverters in 15 years and to dismantle it in 35), while its annual loan payments (inclusive of interest) would be $1.6 million. The farm’s project charter said the project would make a net $41 million over its lifetime.
The Gazette has received calls and letters since then questioning the business case for the farm, with some calling the assumptions behind it overly optimistic. The Gazette worked with a group of solar and electrical system experts to analyze the business case for our readers.
Which numbers are right?
One major challenge in evaluating the solar farm is knowing which facts to use.
The farm’s project charter, ATCO’s June 21 presentation, the July 5 Municipal Energy Corporation feasibility study, and a last-minute update chart provided to council (but not the public at large) on June 21 all contained facts on the farm, but these facts often contained gaps or seemed to contradict each other.
Polkovsky said these different numbers were the result of different reports being written at different points in ATCO’s analysis.
“We were trying to get this to council as quick as possible,” she said, adding that administration could have used a couple more months to do their analysis.
Polkovsky said the figures in the project charter and the last-minute update (available at bit.ly/3xsp879) were the most accurate. The Gazette used these sources where possible in its analysis.
Council heard on June 21 that the farm would consist of 34,350 bifacial (double-sided) solar modules that would produce about 21,800 megawatt-hours of electricity in Year One.
Gordon Howell of Howell-Mayhew Engineering, who has decades of experience designing domestic-scale solar energy projects and runs the Utility-Scale Solar PV in Alberta Facebook page, said ATCO’s estimates of the farm’s production were reasonable, given the technology used and the amount of sun St. Albert receives. It was unclear, however, if this estimate accounted for the fact that solar modules degrade over time (the industry standard is by 1.3 per cent after one year and 0.5 per cent a year thereafter).
ATCO reps incorrectly stated on June 21 that the farm would power “25,000” homes a year based on Year-One production. The correct figure, assuming an average 1,800-square-foot Alberta home uses 8,900 kWh/year, is 2,449 homes — equivalent to about 9.4 per cent of the homes in St. Albert as of the 2018 census. Howell said most industry officials use a figure of 7,200 kWh/year/home, which would put the farm’s output at closer to 3,000 homes (about 11.6 per cent of St. Albert’s homes).
The city said the array was projected to cost $26.1 million to build, or $33.75 million once you applied a 25 per cent contingency factor.
Mikhail Ivanchikov of Dandelion Renewables (who has built solar farms in Alberta, including the one in Bon Accord, in sub-20 MWh range) said a 15-to-20 MWh solar farm would cost about $30 million to build, with operating costs depending on the technology used. The COVID-19 pandemic has caused a shortage of solar modules, though, and made accurate cost predictions more difficult.
While city officials had not calculated the farm’s carbon offset, the U.S. EPA’s greenhouse-gas calculator suggests that producing 21,800 MWh of solar electricity would offset some 15,449 tonnes of greenhouse-gas emissions — equivalent to that produced by burning 205 tanker trucks of gasoline.
*The proposed location for the farm is the Badger Lands — an 80-acre chunk of city-owned land north of Villeneuve Road. ATCO recommended the site as it was flat, accessible, city-owned, near a substation, and contaminated with salt.
In an email, city spokesperson Julian Cashen said the Badger Lands were classified as a Brownfield site, as part of it had been used for snow storage, resulting in contamination. Brownfields cannot legally be used for residential, commercial, or industrial purposes unless they are cleaned up; the city has pegged the Badger Land’s cleanup bill at between $15.5 million and $25 million, after which it would still have to be serviced. Brownfields can host solar farms, though, and grants are available if you put solar on them.*
How it makes money
The solar farm’s business case presents three sources of revenue: electricity sales, carbon credits, and the Alberta Electric System Operator (AESO).
The AESO pays solar producers the Distributed Generation Credit for helping to meet the province’s peak electricity demands, Howell said. Polkovsky said ATCO reps believe this credit will be phased out in six years and replaced by a lesser non-wires alternative source of revenue. Nick Clark, who has 40 years of experience in Alberta’s utilities market through his company UtilityNet, said the AESO is expected to submit its recommendation on this credit this October.
Carbon credits were based on federal and provincial carbon taxes. Those taxes sit at $40 a tonne now and, according to the federal government, would reach $170/tonne by 2030. By producing zero-carbon electricity, St. Albert would gain carbon credits it could use to offset its own carbon pollution or sell to others. Polkovsky said the business case assumes carbon credits would continue until at least 2035.
Using the EPA’s estimates on carbon offsets and figures from the last-minute update, The Gazette has determined that ATCO estimated the farm would make $64 to $67 per tonne from carbon taxes.
While the federal government could cancel the carbon tax, that is unlikely given Canada’s obligations under the Paris Agreement and national and international calls for action on global heating, said Rebecca Nadel, director of the Business Renewables Centre of Canada (a branch of the Pembina Institute that deals with renewable energy). This suggests ATCO’s estimates on carbon revenue are conservative.
The business case proposes that St. Albert sell its power for 16 years under a power purchasing agreement (PPA) and for 18 years on the open market. The city did not have a PPA for the farm as of June 21.
A PPA is a deal where a company buys power from a producer at a fixed rate to hedge against future price hikes and gain environmental benefits, Nadel said. Telus, Shell, Pembina Pipeline, Labatt, and Bimbo Canada (a bakery company) have all signed major PPAs in recent years to meet their environmental goals.
Market or merchant sale prices are highly variable, with Alberta’s average annual pool price ranging from $18.28 to $133.22/MWh from 2000 to 2020, Clark said. AESO data suggests prices have averaged about $75/MWh in the last 365 days and $60.41 in the last 20 years (2000-2020).
Polkovsky and city strategic services director Paul Pearson were unable to disclose many basic pieces of information about the business case, including the power price, carbon price, and interest rate used in it. The Municipal Energy Corporation (MEC) study has these numbers, but the last-minute update used different ones.
With power rates, Pearson said ATCO used a complex and proprietary variable-rate model developed by the company Boost to forecast energy prices, the output of which could not be expressed with one number.
“It’s incredibly complicated,” he said of energy pricing.
“There just aren’t those solid numbers out there to dig into.”
While power prices do fluctuate wildly on any given day, The Gazette was unable to determine why the Boost model could not summarize its predictions into an annual average power price. Information from ATCO’s June 21 presentation implies that the business case used an average annual price of $50 to $69 per megawatt hour (MWh).
By dividing the farm’s expected electricity revenue by its output, The Gazette determined that the city expected to earn $68.94 to $78.56 per MWh through electricity sales — 14 and 30 per cent above the 20-year average pool price.
The results
Based on the timeframe shown in the last-minute update, The Gazette ran the proposed solar farm through 48 different 35-year scenarios from 2021-2056, with the farm under construction for the first two years, to determine if it would make any net revenue. The scenarios projected the farm's net revenues at different power price points and under problem situations where ATCO was massively, improbably wrong in one of its predictions.
The price points used were the base case/ATCO price (using revenue projections from the last-minute update), 20-year average price ($60.41/MWh), and half the 20-year average price ($30.21/MWh). The 20-year average price was considered pessimistic but probable (as it is within the historic range), while the half-price one was deemed improbable, as average annual power-pool prices have dipped below $33 twice in the last 20 years.
Problem situations included doubled operating costs ($240,000 instead of $120,000), maximized capital cost (where the array costs $33.75 million instead of $26.1 million; annual payments for a 20-year loan obtained through the Alberta Loans to Local Authorities calculator on July 10 using default interest rates), and no non-power revenue (where carbon credits and AESO-related revenue vanish overnight).
Since it was unclear if ATCO’s 21,800 MWh figure accounted for panel degradation, The Gazette ran half of these scenarios with production fixed at that amount and half with industry standard levels of degradation. The Gazette did not test for other production levels, as Howell had judged the farm's energy output to be reasonable.
The Gazette found that the farm would make money in 28 of 48 scenarios, with average annual net revenues ranging from $29,400 (no degradation, half price, double cost) to $1 million (ATCO price, no problems). The farm would make money even in an improbable half-price scenario if no problems occurred. It would also be profitable under average prices if any one of the problem scenarios occurred individually or if the operating and capital problems happened together. The farm would lose money in almost all half-price scenarios and in every case where all three problems occurred at once.
The farm would prevent 14,000 to 15,000 tonnes of greenhouse-gas emissions per year under any scenario.
The Gazette was unable to determine how the farm could make $41 million in net revenue based on the information provided by the city. In an email, Pearson said this figure was based on Boost’s proprietary model, the results of which could not be reproduced “using simple math.”
“This is one of the areas where we have to trust the experts we’ve brought on to do this analysis,” he said.
Hedging our bets
Howell said there is little economic risk to St. Albert’s proposed solar farm provided it goes with an experienced designer. He said he is not aware of any utility-scale solar PV project in Alberta that has failed to make money.
Clark said the numbers used in ATCO’s estimates appeared to be conservative, and that ATCO is a proven expert in this field. He called solar farms a wise investment that served as a hedge against inflation and a tangible commitment to the environment.
Bon Accord built a solar farm last year, and Mayor Greg Mosychuk said it is currently cranking out power as planned.
“It’s basically paying for itself right now,” he said, and would be fully paid off in nine years.
“If St. Albert can build the size (of farm) they want to build, yeah, they’re looking at a revenue-generator.”
Ivanchikov said municipalities should strongly consider building solar farms, and noted that the Bon Accord array would be net-positive in terms of revenue (i.e. the array’s energy savings would exceed the cost of its annual loan payments) after one year.
“Municipalities care about the long term,” he said, and solar farms can shield them against spikes in power prices and help them show environmental leadership.
Still, there are steps St. Albert can take to tilt the odds in its favour.
ATCO is in the business of building solar farms and may have biased its business case in favour of construction, Howell said. He advised the city to commission a second study on the solar farm to validate ATCO’s predictions.
Ivanchikov said the city should seek grants to improve the farm’s potential rate of return. One possibility would be the federal Smart Renewables and Electrification Pathways Program, which covers up to 10 per cent of a solar farm’s capital cost.
While he supported putting this farm on an otherwise useless Brownfield, Ivanchikov said the city should do the geotechnical work for this farm as soon as possible, as ground conditions could easily scupper the project.
A spreadsheet showing The Gazette’s analysis is available at bit.ly/3r7nqWd.
