A shifting landscape in renewables

The global energy sector is being transformed through a drive toward clean energy, including commitments to net-zero emissions
A shifting landscape in renewables

In early August Petronas Canada and Japan-based Itochu Corp. announced they were joining forces to study the feasibility of building a US$1.3-billion petrochemical facility in central Alberta. This facility would produce low-carbon ammonia, a source of hydrogen fuel, for export to Asian markets.

And in March, fuel cell maker Plug Power Inc. announced it plans to build a green hydrogen production plant in south-central Pennsylvania with Brookfield Renewable Partners L.P.

Hydrogen is just one alternative energy source that is gaining attention and market share. Even before the COVID-19 pandemic struck last year, the global energy sector was transforming through an international drive toward clean energy, including government and industry commitments to “net-zero” carbon emissions.

Indeed, the emergence of the novel and fast-spreading coronavirus and economic downturn were not the primary drivers of the push toward greening the energy industry. Instead, this move has more to do with “the commitment across the globe, after the Paris Climate Accords, when you had the nations around the world commit to net-zero by 2050, and then companies in the private sector following suit, … saying ‘we’re going to hit net zero by 2030,’” says Janet Howard, a partner in Fasken Martineau DuMoulin LLP in Toronto.

“They are taking steps to figure out how they transition so that they’re introducing new sources of power.”

A shifting landscape in renewables

Mike Richmond, an energy partner in McMillan LLP in Toronto, says he notices “a seismic shift in electricity policy every decade or so.” From 1996 to 2006, “the industry was all about non-utility generation — basically, gas plants and coal plants — and those were supported by government contracts, government procurements or Crown corporation utility procurements.” This policy was driven by economics, he says. From 2006, for the next 10 to 12 years, “it was almost exclusively wind and solar projects being built, supported by government power purchase agreements and RFPs.” The driver “was purely environmental.”

Now, “I’m seeing a lot of geothermal heating and cooling at a large scale, … and a lot of energy storage, whether that’s large-scale batteries, or compressed air energy storage, or other pretty innovative technologies,” he says. “But all of those are attempts to get power or energy [and] to avoid paying the grid costs. We’re now back to an economic driver, but they’re not supported by government contracts. They’re supported by private-sector purchasers.”

A surge in government policies encouraging carbon pricing and the use of lower-emitting technologies is not “a here today, gone tomorrow trend,” says Glenn Zacher, an energy partner in the Toronto office of Stikeman Elliott LLP.

“All indications are that climate change is a focal point of governments and societies everywhere, manifested in significant metrics including large pension funds earmarking billions in investments in this area, and to some extent, reducing investments in companies and sectors that emit a lot of carbon.”

Across the country, hydrogen is the “it” fuel, Zacher says. B.C., Manitoba and Quebec are rich in hydro resources, so they have no imperative to decarbonize supply mixes. In those provinces, “there is a lot of focus around exporting low-carbon energy to the U.S.,” for example, from Quebec to New York and New England.

Ontario, which had a mix of hydro and nuclear, and coal at one time, “has been almost the poster child in North America over the last 10 or 15 years for absolutely transforming the sector,” Zacher adds. The province got rid of its coal plants and “effectively wrote off billions of dollars,” brought in its Green Energy Act in 2009 and its Feed-in-Tariff Program in the same year, brought in lower-emitting wind and solar and other renewable fuels, as well as refurbishing non-emitting nuclear plants.

“A lot of the heavy lifting that has been done in Ontario came at huge price tag for electricity ratepayers and taxpayers, so there’s not a lot of need or appetite for to go through another round of large procurements at a high price,” Zacher says. But there is a lot of activity in distributed energy resources (DERs) or distributed generation. This approach involves electricity-producing resources or controllable loads connected to a local distribution system or a host facility within the local distribution system.

DERs may include solar panels, combined heat and power plants, electricity storage, small natural gas-fuelled generators, electric vehicles and controllable loads, such as HVAC systems and electric water heaters. Using this approach can help reduce demand during peak periods. Distributed generation typically involves small-scale technologies, including solar, wind and hydro.

One example would be drawing energy from electric vehicles, which can be parked in a garage during the day and charged overnight, says Dennis Langen, a partner in Stikeman Elliott’s Calgary office. “You can draw from your EV battery to also power your appliances during the day, or your house, effectively. In a perfect world, if everyone were doing that, then the large generation and transmission facilities … wouldn’t work overtime during the day, perhaps — but at night, they may work to help charge.”

In Alberta, there is a focus on distributed energy resources, but that’s happening concurrently with solar and wind generation. Although wind has been growing over the past 15 years, “solar is seeing the most uptake now,” he says.

The Alberta Utilities Commission has just finished looked at “a whole protocol system,” says Hazel Saffery, a partner in Dentons Canada LLP in Calgary, on the distribution connected generation called the Distribution System Inquiry. Released in February, the final report examined the need to modernize Alberta’s distribution system and studied the rapid advancement of technologies such as battery storage, rooftop solar, electric vehicles, combined heat and power systems, and smart metering.

And several of Alberta’s renewable generators have been helped by Distribution Connected Generation (DCG) credits, says Saffery.

“That’s been a big driver over the last five years, … because if you’re not connecting to the transmission grid, [but rather to] the distribution system, you’re able to get a credit back from your distribution wires provider, and that’s been quite significant. It makes the financials work.”

Three major electricity distribution companies in Alberta offer DCG credits through their tariffs.

However, in June, the Alberta Utilities Commission announced its plan to phase out DCG credits over four years. This move was because the provision of the credit “unnecessarily increases the payments ratepayers make for transmission service, and these additional payments are not offset by a proven quantifiable benefit to the ratepayers,” the AUC wrote in its decision.

Several parties have made applications to appeal and review and vary this decision, says Saffery, with the leave to appeal decisions likely to be issued by the fall.

A move toward hydrogen

Canada’s “Hydrogen Strategy for Canada: Seizing the Opportunities for Hydrogen,” released in December, focusses on “blue hydrogen as a bridge,” says Howard, due to the country’s large natural gas/oil reserve. Blue hydrogen is sourced from natural gas, while green energy is sourced from electricity. Both can be processed into pure hydrogen and exported for use as energy.

Once the infrastructure and supply chain develop for hydrogen, Howard says he expects to see efforts to produce green hydrogen. The oil-and-gas-rich western Canadian provinces will continue to focus on blue hydrogen and Quebec on green hydrogen because of its abundance of water and its hydroelectricity.

In April, four provinces — Alberta, Saskatchewan, Ontario and New Brunswick — signed a memorandum of understanding to support small-scale nuclear power technology development. With increased nuclear capacity, “you can generate way more volumes of hydrogen,” says Howard.

Ontario produces the most nuclear energy in Canada, with six power stations, and its Bruce generating station is the largest operating nuclear power plant in the world. As well, Ontario Power Generation’s Atura Power subsidiary, which is the province’s largest fleet of combined-cycle turbine gas plants, will be playing a leadership role in establishing the supply of low-carbon hydrogen in the region.

Brookfield hydroelectric facility in Pennsylvania projects about 15 metric tons of emissions-free liquid hydrogen produced per day. And Hydro-Québec’s green energy project, announced in January, is the first such in Canada. For that project, Thyssenkrupp Uhde Chlorine Engineers’ Green Hydrogen product division won an engineering contract to install an 88-megawatt water electrolysis plant for Hydro-Québec in Varennes, Quebec. This plant will produce 11,100 metric tons of green hydrogen annually.

And it’s not only “end users” focussed on alternative energies, says Howard, but institutional investors such as BlackRock and Goldman Sachs.

“There’s a real acknowledgement that if you are not, as a company, focussed on the ESG-related risks inherent in your operations, your profitability will suffer,” she says.

“And that’s meaningful. It’s not people just wanting to go green for the sake of being good corporate citizens. It’s people recognizing that there are jurisdictions in the world where changing weather patterns are impacting supply chains.”