Regulators to rethink Idaho Power green tags

Canada Oil Recession Outlook analyzes the Russia-Saudi price war, OPEC discord, COVID-19 demand shock, WTI and WCS collapse, Alberta oilsands exposure, U.S. shale stress, and GDP risks from blockades and fiscal responses.

Key Points

An outlook on how the oil price war and COVID-19 demand shock could tip Canada into recession and strain producers.

✅ WTI and WCS prices plunge on OPEC-Russia discord

✅ Alberta oilsands face break-even pressure near 30 USD WTI

✅ RBC flags global recession; GDP hit from blockades, virus

A war between Russia and Saudi Arabia for market share for oil may have been triggered by the COVID-19 pandemic in China, but the oil price crash contagion that it will spread could have impacts that last longer than the virus.

The prospects for Canada are not good.

Plunging oil prices, reduced economic activity from virus containment, and the fallout from weeks of railway blockades over the Coastal GasLink pipeline all add up to “a one-two-three punch that I think is almost inevitably going to put Canada in a position where its growth has to be negative,” said Dan McTeague, a former Liberal MP and current president of Canadians for Affordable Energy. The situation “certainly has the makings” of a recession, said Ken Peacock, chief economist for the Business Council of British Columbia.

“At a minimum, it’s going to be very disruptive and we’re going to have maybe one negative quarter,” Peacock said. “Whether there’s a second one, where it gets labeled a recession, is a different question. But it’s going to generate some turmoil and challenges over the next two quarters – there’s no doubt about that.”

RBC Economics on March 13 announced it now predicts a global recession and cut its growth projections for Canada's economy in 2020 by half a per cent.

Oil price futures plunged 30% last week, dragging stock markets and currencies, including the Canadian dollar, down with them, even as a deep freeze strained U.S. energy systems. That drop came on top of a 17% decline in February, due to falling demand for oil due to the virus.

The latest price plunge – the worst since the 1991 Gulf War – was the result of Russia and the Organization of Petroleum Exporting Countries (OPEC), led by Saudi Arabia, failing to agree on oil production cuts.

The COVID-19 outbreak in China – the world’s second-largest oil consumer – had resulted in a dramatic drop in oil demand in that country, and a sudden glut of oil, with the U.S. energy crisis affecting electricity, gas and EV markets.

OPEC has historically been able to moderate global oil prices by controlling output. But when Russia refused to co-operate with OPEC and agree to production cuts, Saudi Arabia’s state-owned company, Aramco, announced it plans to boost its oil output from 9.7 million barrels per day (bpd) to 12.3 million bpd in April.

In response to that announcement, West Texas Intermediate (WTI) prices dropped 18% to below US$34 per barrel while the Canadian Crude Index fell 24% to US$21. Western Canadian Select dropped 39% to US$15.73.

The effect on Alberta oilsands producers was severe and immediate. Cenovus Energy Inc. (TSX:CVE) saw roughly $2 billion in market cap erased on March 9, when its stock dropped by 52%, which came on top of a 12% drop March 6.

The company responded the very next day by announcing it would cut spending by 32% in 2020, suspend its oil-by-rail program and defer expansion projects.

MEG Energy Corp. (TSX:MEG), which suffered a 56% share price drop on March 9, also announced a 20% reduction in its 2020 capital spending plan.

Peter Tertzakian, chief economist for ARC Energy Research Institute, wrote last week that Russia’s plan is to try to hurt U.S. shale oil producers, who have more than doubled U.S. oil production over the past decade.

Anas Alhajji, a global oil analyst, expects that plan could work. Even before the oil price shock, he had predicted the great shale boom in the U.S. was coming to an end.

“Shale production will decline, and the myth of ‘explosive growth’ will end,” he told Business in Vancouver. “The impact is global and Canadian producers might suffer even more if the oil that Saudi Arabia sends to the U.S. is medium and heavy. This might last longer than what people think.”

The question for Alberta is how Canadian producers can continue to operate through a period of cheap oil. Alberta producers do not compete on the global market. They serve a niche market of U.S. heavy oil refiners, and Biden-era policy is seen as potentially more favourable for Canada’s energy sector than alternatives.

“On the positive side, the industry is battle-hardened,” Tertzakian wrote. “Over the past five years, innovative companies have already learned to endure some of the lowest prices in the world.”

But he added that they need WTI prices of US$30 per barrel just to break even.

“But that’s an average break-even threshold for an industry with a wide variation in costs. That means at that level about half the companies can’t pay their bills and half are treading water.”

Just prior to the oil price plunge, the International Energy Agency (IEA) updated its 2020 forecast for global oil consumption from an 825,000 bpd increase in oil consumption to a 90,000 bpd decrease, due to the COVID-19 virus and consequent economic contraction and reduction in travel.

The IEA predicts global oil demand won’t return to “normal” until the second half of 2020. But even if demand does return to pre-virus levels, that doesn’t mean oil prices will – not if Saudi Arabia can sustain increased oil production at low prices, and evolving clean grid priorities could influence the trajectory too.

The oil plunge was greeted in Alberta with alarm. Alberta Premier Jason Kenney warned Alberta is in “uncharted territory” as consumers are urged to lock in rates and said his government might have to review its balanced budget and resort to emergency deficit spending.

While British Columbians – who pay some of the highest gasoline prices in North America – will enjoy lower gasoline prices at a time when prices are usually starting a seasonal spike, B.C.’s economy could feel knock-on effects from a recession in Alberta.

“We sell a lot of inputs, do a lot of trade with Alberta, so it’s important for B.C., Alberta’s economic health,” Peacock said, “and recent tensions over electricity purchase talks underscore that.”

Last week, the Trudeau government announced $1 billion in emergency funding to cope with the virus and waived a one-week waiting period for unemployment insurance.

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Manitoba-Minnesota Transmission Line connects Bipole III to Minnesota, raising export capacity, as NEB hearings weigh Indigenous rights, treaty obligations, environmental assessment, cumulative effects, and cross-border hydroelectric infrastructure impacts, land access, socio-economic concerns, and regulatory review.

Key Points

A cross-border hydro line linking Manitoba to Minnesota under review on Indigenous rights and environment concerns.

✅ Connects Bipole III to Minnesota to boost exports

✅ NEB hearings include Indigenous rights and treaty issues

✅ Environmental and access impacts debated in regulatory review

Concerned Indigenous groups asked the National Energy Board this week to take into consideration existing and future impacts and treaty rights, which have prompted a halt to Site C work elsewhere, when considering whether to OK a new hydro transmission line between Manitoba and Minnesota.

Friday was the last day of the oral traditional evidence hearings in Winnipeg on Manitoba Hydro's Manitoba-Minnesota Transmission project.

The international project will connect Manitoba Hydro's Bipole III transmission line to Minnesota and increase the province's electricity export capacity to 3185 MW from 2300 MW.

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During the hearings Indigenous groups brought forward concerns and evidence of environmental degradation, echoing Site C dam opponents in other regions, and restricted access to traditional lands.

Ramona Neckoway, a member of the Nelson House First Nation, talked about her concern about the scope of Manitoba Hydro's application to the NEB.

"It's only concerned with a narrow 213 km corridor and thus it erases the histories, socio-economic impacts and the environmental degradation attached to this energy source," said Neckoway.

Prior to the hearings the board stated it did not intend to assess the environmental and socio-economic impacts of upstream or downstream facilities associated with electricity production, even as a utilities watchdog on Site C stability raised questions elsewhere.

However, the board did hear evidence from upstream and downstream affected communities despite objection from Manitoba Hydro lawyers.

"Manitoba Hydro objected to us being here, saying that we are irrelevant, but we are not irrelevant," said Elder Tommy Monias from Cross Lake First Nation.

Manitoba Hydro representative Bruce Owen said, "We respect the NEB hearing process and look forward to the input of all interested parties."

The hearings provided a rare opportunity for First Nations communities, similar to Ontario First Nations urging action, to voice their concerns about the line on a federal level.

"One of the hopes is that this project can't be built until a system-wide assessment is made," said Dr. Peter Kulchyski, an expert witness for the southern chiefs organization and professor of Native Studies at the University of Manitoba.

Hearings continue

The line is already under construction on the American side of the border as the NEB public hearings continue until June 22 with cross examinations and final arguments from Manitoba Hydro and intervenor groups.

The NEB's final decision on the Manitoba-Minnesota transmission line, amid an energy board delay recommendation, will be made before March 2019.

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Hydro One CEO Mark Poweska aims to rebuild ties with Ontario's provincial government, investors, and communities, stabilize the executive team, boost earnings and dividends, and reset strategy after the scrapped Avista deal and regulatory setbacks.

Key Points

He plans to mend government and investor relations, rebuild the C-suite, and refocus growth after the failed Avista bid.

✅ Rebuild ties with Ontario government and regulators

✅ Stabilize executive team and governance

✅ Refocus growth after Avista deal termination

The incoming chief executive officer of Hydro One Ltd. said Thursday that he aims to rebuild the relationship between the Ontario electrical utility and the provincial government, as seen in COVID-19 support initiatives, as well as ties between the company and its investors.

Mark Poweska, the former executive vice-president of operations at BC Hydro, was announced as Hydro One’s new president and CEO in March. His hiring followed a turbulent period for Toronto-based Hydro One, Ontario’s biggest distributor and transmitter of electricity, with large-scale storm restoration efforts underscoring its role.

Hydro One’s former CEO and board of directors departed last year under pressure from a new Ontario government, the utility’s biggest shareholder. Earlier this year, the company’s plan for a $6.7-billion takeover fell apart over concerns of political interference and the utility clashed with the new provincial government and Progressive Conservative Premier Doug Ford over executive compensation levels, amid rate policy debates such as no peak rate cuts for self-isolating customers.

Hydro One facing $885 million charge as regulator upholds tax decision forcing it to share savings with customers

Shares of Hydro One were up more than eight per cent year-to-date on Wednesday, closing at $21.74. However, the stock price was up only six per cent from Hydro One’s 2015 initial public offering price, something its incoming CEO seems set on changing.

“One of my first priorities will be to solidify the executive team and build relationships with the Government of Ontario, our customers, informed by customer flexibility research, and communities, indigenous leaders, investors, and our partners across the electricity sector,” Poweska said Thursday on a conference call outlining Hydro One’s first-quarter results. “At the same time, I will be working to earn the trust and confidence of the investment community.”

Hydro One reported a profit of $171 million for the three months ended March 31, while peers such as Hydro-Québec reported pandemic-related losses as the sector adapted. Net income for the first quarter was down from $222 million a year earlier, which was due to $140 million in costs related to the scrapping of Hydro One’s proposed acquisition of U.S. energy company Avista Corp.

Hydro One Ltd. appointed Mark Poweska as President and CEO.

In January, Hydro One said the proposed takeover of Spokane, Wash.-headquartered Avista, an approximately $6.7-billion deal announced in July 2017, was being called off. As a result, Hydro One said it would pay Avista a US$103 million break fee.

Revenues net of purchased power for the first quarter rose to $952 million, up by 15.4 per cent compared to last year, Hydro One said, helped by higher distribution revenues. Adjusted profit for the quarter, which removes the Avista-related costs, was $311 million, up from $210 million a year ago.

The company is hiking its quarterly dividend to 24.15 cents per share, up five per cent from the last increase in May 2018, while also launching a pandemic relief fund for customers.

Poweska is taking over for acting president and CEO Paul Dobson this month, and the new executive will be charged with revamping Hydro One’s C-suite.

The company’s chief operating officer, chief legal officer, and chief corporate development officer have all departed this year. The company’s chief human resource officer has retired as well, although Poweska did announce Thursday that he had appointed acting chief financial officer Chris Lopez as CFO.

“Hydro One’s significant bench strength and management depth will ensure stability and continuity during this period of transition, as the sector pursues Hydro-Québec energy transition as well,” the company said in its first-quarter earnings press release.

Ontario remains Hydro One’s biggest shareholder, owning approximately 47 per cent of the company.

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Alberta Renewable Energy Market is accelerating as wind and solar prices fall, corporate PPAs expand, and a deregulated, energy-only system, AESO outlooks, and TIER policy drive investment across the province.

Key Points

An open, energy-only Alberta market where wind and solar growth is driven by corporate PPAs, AESO outlooks, and TIER.

✅ Energy-only, deregulated grid enables private investment

✅ Corporate PPAs lower costs and hedge power price risk

✅ AESO forecasts and TIER policy support renewables

By Chris Varcoe, Calgary Herald

A few things are abundantly clear about the state of renewable energy in Alberta today.

First, the demise of Alberta’s Renewable Electricity Program (REP) under the UCP government isn’t going to see new projects come to a screeching halt.

In fact, new developments are already going ahead.

And industry experts believe private-sector companies that increasingly want to purchase wind or solar power are going to become a driving force behind even more projects in Alberta.

BluEarth Renewables CEO Grant Arnold, who spoke Wednesday at the Canadian Wind Energy Association conference, pointed out the sector is poised to keep building in the province, even with the end of the REP program that helped kick-start projects and triggered low power prices.

“The fundamentals here are, I think, quite fantastic — strong resource, which leads to really competitive wind prices . . . it’s now the cheapest form of new energy in the province,” he told the audience.

“Alberta is in a fundamentally good place to grow the wind power market.”

Unlike other provinces, Alberta has an open, deregulated marketplace, which create opportunities for private-sector investment and renewable power developers as well.

The recent decision by the Kenney government to stick with the energy-only market, instead of shifting to a capacity market, is seen as positive for Alberta's energy future by renewable electricity developers.

There is also increasing interest from corporations to buy wind and solar power from generators — a trend that has taken off in the United States with players such as Google, General Motors and Amazon — and that push is now emerging in Canada.

“It’s been really important in the U.S. for unlocking a lot of renewable energy development,” said Sara Hastings-Simon, founding director of the Business Renewable Centre Canada, which seeks to help corporate buyers source renewable energy directly from project developers.

“You have some companies where . . . it’s what their investors and customers are demanding. I think we will see in Alberta customers who see this as a good way to meet their carbon compliance requirements.

“And the third motivation to do it is you can get the power at a good price.”

Just last month, Perimeter Solar signed an agreement with TC Energy to supply the Calgary-based firm with 74 megawatts from its solar project near Claresholm.

More deals in the industry are being discussed, and it’s expected this shift will drive other projects forward.

There is increasing interest from corporations to buy solar and wind energy directly from generators.

“The single-biggest change has been the price of wind and solar,” Arnold said in an interview.

“Alberta looks really, really bright right now because we have an open market. All other provinces, for regulatory reasons, we can’t have this (deal) . . . between a generator and a corporate buyer of power. So Alberta has a great advantage there.”

These forces are emerging as the renewable energy industry has seen dramatic change in recent years in Alberta, with costs dropping and an array of wind and solar developments moving ahead, even as solar expansion faces challenges in the province.

The former NDP government had an aggressive target to see green energy sources make up 30 per cent of all electricity generation by 2030.

Last week, the Alberta Electric System Operator put out its long-term outlook, with its base-case scenario projecting moderate demand growth for power over the next two decades. However, the expected load growth — expanding by an average of 0.9 per cent annually until 2039 — is only half the rate seen in the past 20 years.

Natural gas will become the main generation source in the province as coal-fired power (now comprising more than one-third of generation) is phased out.

Renewable projects initiated under the former NDP government’s REP program will come online in the near term, while “additional unsubsidized renewable generation is expected to develop through competitive market mechanisms and support from corporate power purchase agreements,” the report states.

AESO forecasts installed generation capacity for renewables will almost double to about 19 per cent by 2030, with wind and solar increasing to 21 per cent by 2039.

Another key policy issue for the sector will likely come within the next few weeks when the provincial government introduces details of its new Technology Innovation and Emissions Reduction program (TIER).

The initiative will require large industrial emitters to reduce greenhouse gas emissions to a benchmark level, pay into the technology fund, or buy offsets or credits. The carbon price is expected to be around $20 to $30 a tonne, and the system will kick in on Jan. 1, 2020.

Industry players point out the decision to stick with Alberta’s energy-only market along with the details surrounding TIER, and a focus by government on reducing red tape, should all help the sector attract investment.

“It is pretty clear there is a path forward for renewables here in the province,” said Evan Wilson, regional director with the Canadian Wind Energy Association.

All of these factors are propelling the wind and solar sector forward in the province, at the same time the oil and gas sector faces challenges to grow.

But it doesn’t have to be an either/or choice for the province moving forward. We’re going to need many forms of energy in the coming decades, and Alberta is an energy powerhouse, with potential to develop more wind and solar, as well as oil and natural gas resources.

“What we see sometimes is the politics and discussion around renewables or oil becomes a deliberate attempt to polarize people,” Arnold added.

“What we are trying to show, in working in Alberta on renewable projects, is it doesn’t have to be polarizing. There are a lot of solutions.

“The combination of solutions is part of what we need to talk about.”

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DOE Wind Energy Funding backs 13 R&D projects advancing offshore wind, distributed energy, and utility-scale turbines, including microgrids, battery storage, nacelle and blade testing, tall towers, and rural grid integration across the United States.

Key Points

DOE Wind Energy Funding is a $28M R&D effort in offshore, distributed, and utility-scale wind to lower cost and risk.

✅ $6M for rural microgrids, storage, and grid integration.

✅ $7M for offshore R&D, nacelle and long-blade testing.

✅ Up to $10M demos; $5M for tall tower technology.

The U.S. Department of Energy announced that in order to advance wind energy in the U.S., 13 projects have been selected to receive $28 million. Project topics focus on technology development while covering distributed, offshore wind growth and utility-scale wind found on land.

The selections were announced by the DOE’s Assistant Secretary for the Office of Energy Efficiency and Renewable Energy, Daniel R. Simmons, at the American Wind Energy Association Offshore Windpower Conference in Boston, as New York's offshore project momentum grows nationwide.

Wind Project Awards

According to the DOE, four Wind Innovations for Rural Economic Development projects will receive a total of $6 million to go toward supporting rural utilities via facilitating research drawing on U.K. wind lessons for deployment that will allow wind projects to integrate with other distributed energy resources.

These endeavors include:

Bergey WindPower (Norman, Oklahoma) working on developing a standardized distributed wind/battery/generator micro-grid system for rural utilities;

Electric Power Research Institute (Palo Alto, California) working on developing modeling and operations for wind energy and battery storage technologies, as large-scale projects in New York progress, that can both help boost wind energy and facilitate rural grid stability;

Iowa State University (Ames, Iowa) working on optimization models and control algorithms to help rural utilities balance wind and other energy resources; and

The National Rural Electric Cooperative Association (Arlington, Virginia) providing the development of standardized wind engineering options to help rural-area adoption of wind.

Another six projects are to receive a total of $7 million to facilitate research and development in offshore wind, as New York site investigations advance, with these projects including:

Clemson University (North Charleston, South Carolina) improving offshore-scale wind turbine nacelle testing via a “hardware-in-the-loop capability enabling concurrent mechanical, electrical and controller testing on the 7.5-megawatt dynamometer at its Wind Turbine Drivetrain Testing Facility to accelerate 1 GW on the grid progress”; and

The Massachusetts Clean Energy Center (Boston) upgrading its Wind Technology Testing Center to facilitate structural testing of 85- to 120-meter-long (roughly 278- to 393-foot-long) blades, as BOEM lease requests expand, among other projects.

Additionally, two offshore wind technology demonstration projects will receive up to $10 million for developing initiatives connected to reducing wind energy risk and cost. One last project will also be granted $5 million for the development of tall tower technology that can help overcome restrictions associated with transportation.

“These projects will be instrumental in driving down technology costs and increasing consumer options for wind across the United States as part of our comprehensive energy portfolio,” said Simmons.

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25% Tariff on Canadian Imports threatens New York energy markets, disrupting hydroelectric power and natural gas supply chains, raising electricity prices, increasing gas costs, and intensifying trade tensions, policy uncertainty, and cross-border logistics risks.

Key Points

A U.S. policy imposing 25% duties on Canadian goods, risking higher New York electricity and natural gas costs.

✅ Hydroelectric and gas imports face costlier cross-border flows

✅ Higher utility bills for NY households and businesses

✅ Supply chain volatility and policy uncertainty increase

President Donald Trump announced the imposition of a 25% tariff on all imports from Canada, citing concerns over drug trafficking and illegal immigration. This decision has raised significant concerns among experts and residents in New York, who warn that the tariff could lead to increased electricity and gas prices in the state.

Impact on New York's Energy Sector

New York relies heavily on energy imports from Canada, particularly electricity and natural gas. Canada is a major supplier of hydroelectric power to the northeastern United States, including New York, with its electricity exports at risk amid trade tensions. The imposition of a 25% tariff on Canadian goods could disrupt this supply chain, leading to higher energy costs for consumers and businesses in New York. Justin Wilcox, an energy analyst, stated, "If the tariff is implemented, it could lead to increased costs for electricity and gas, affecting both consumers and businesses."

Potential Economic Consequences

The increased energy costs could have broader economic implications for New York, and some experts advise against cutting Quebec's exports to avoid exacerbating market volatility. Higher electricity and gas prices may lead to increased operational costs for businesses, potentially resulting in higher prices for goods and services, while tariff threats have boosted support for Canadian energy projects that could reshape regional supply. This could exacerbate the cost-of-living challenges faced by residents and strain the state's economy.

Political and Diplomatic Reactions

The tariff has also sparked political and diplomatic reactions, including threats to cut U.S. electricity exports from Ontario that raised tensions. New York Governor Kathy Hochul expressed concern over the potential economic impact, stating, "We are closely monitoring the situation and are prepared to take necessary actions to protect New York's economy." Additionally, Canadian officials have expressed their disapproval of the tariff, and Ontario Premier Doug Ford's Washington meeting underscored ongoing discussions, emphasizing the importance of the trade relationship between the two countries.

Historical Context

This development is part of a broader pattern of trade tensions between the United States and its neighbors. In 2018, the U.S. imposed tariffs on Canadian steel and aluminum, leading to retaliatory measures from Canada. The current situation underscores the ongoing challenges in international trade relations, where a recent tariff threat delayed Quebec's green energy bill and highlighted the potential domestic impacts of such policies.

The imposition of a 25% tariff on Canadian imports by President Trump has raised significant concerns in New York regarding potential increases in electricity and gas prices. Experts warn that this could lead to higher costs for consumers and businesses, with broader economic implications for the state. As the situation develops, it will be crucial to monitor the responses from both state and federal officials, as well as how Canadians support tariffs on energy and minerals may influence policy, and the potential for diplomatic negotiations to address these trade tensions.

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