Renewable energy tops 10 percent of U.S. production

COVID-19 Impact on U.S. Power Demand shows falling electricity load, lower wholesale prices, and resilient utilities in competitive markets, with regional differences tied to weather, renewable energy, stay-at-home orders, and hedging strategies.

Key Points

It outlines reduced load and prices, while regulatory design and hedging support utility stability across regions.

✅ Load down in NY, New England, PJM; weather drives South up.

✅ Wholesale prices fall 8-10% in key markets.

✅ Decoupling, contracts, hedging support utility earnings.

On March 27, Bloomberg New Energy Finance (BNEF) released a report on electricity demand and wholesale market prices impact from COVID-19 fallout. The model compares expected load based largely on weather with actual observed electricity demand changes.

So far, the hardest hit power grid is New York, with load down 7 and prices off by 10 percent. That’s expected, given New York City is the current epicenter of the US health crisis.

Next is New England, with 5 percent lower demand and 8 percent reduced wholesale prices for the week from March 19-25. BNEF says the numbers could go higher following advisories and orders issued March 24 for some 70 percent of the region’s population to stay at home.

Demand on the biggest grid in the US, the PJM (Pennsylvania/Jersey/Maryland), is 4 percent lower, with prices dropping 8 percent, as recent capacity auction payouts fell sharply. BNEF believes there will be more impact as stay at home orders are ramped up in several states.

California’s power demand for March 19-25 was 5 percent below what BNEF’s model expects without COVID-19 impact. That reflects a full week of stay-at-home orders from Governor Newsom issued March 19.

Health officials in Los Angeles and elsewhere expect a spike in COVID-19 cases in coming weeks. But BNEF’s model now actually projects rising electricity load for the state, due to what it calls "freakishly mild weather a year ago."

Rounding out the report, power demand is up for a band of southern states stretching from Florida to the desert Southwest, with weather more than offsetting public response to COVID-19 so far. BNEF says the Northwest’s grid "has not yet been highly impacted," while the Southeast is "generally in line" with pre-virus expectations.

Clearly, all of this data can change quickly and radically. Only California and New York are currently in full shutdown mode. Following them are New England (70 percent), the Midwest (65 percent), Texas (50 percent), PJM (50 percent) and the Northwest (50 percent).

In contrast, only small parts of Florida, the Southeast and Southwest are restricting movement. That could mean a big future increase for shut-ins, with heightened risks of electricity shut-offs that burden households and a corresponding impact on power demand.

Also, weather will play a major role on what happens to actual electricity demand, just as it always does. A very hot summer, for example, could offset virus-related shut-ins, just as it apparently is now in states like Texas. And it should be pointed out that regions vary widely by exposure to recession-sensitive sources of demand, such as heavy industry.

Most important for investors, however, is the built in protection US utility earnings enjoy from declining power demand, even amid broader energy crisis pressures facing the sector. For one thing, US power grids in California, ERCOT (Texas), MISO (Midwest), New England, New York and PJM have wholesale power markets, where producers compete for sales and the lowest bidder sets the price.

In those states, most regulated utilities don’t produce power at all. In fact, companies’ revenue is decoupled entirely from demand in California, as well as much of New England. In the roughly three-dozen states where utilities still operate as integrated monopolies, demand does affect revenue, and in many regions flat electricity demand already persists. But the cost of electricity is passed through directly to customers, whether produced or purchased.

A number of US electric companies have invested in renewable energy facilities as part of broader electrification trends nationwide. These sell their output under long-term contracts primarily with other utilities and government entities.

This isn’t a risk free business: For the past year, generators selling electricity to bankrupt PG&E Corp (PCG) have had their cash trapped at the power plant level as surety for lenders. But even PG&E has honored its contracts. And with states continuing aggressive mandates for renewable energy adoption, growth doesn’t appear at risk to COVID-19 fallout either.

The wholesale price of power from natural gas, coal and many nuclear plants was already sliding before COVID-19, due to renewables adoption and low natural gas prices, even as coal and nuclear disruptions raise reliability concerns. But here too, big producers like Exelon Corp (EXC) and Vistra Energy (VST) have employed aggressive price hedging near term, with regulated utilities and retail businesses protecting long-term health, respectively.

Bottom line: It’s early days for the COVID-19 crisis and much can still change. But so far at least, the US power industry is absorbing the blow of reduced demand, just as it’s done in previous crises.

That means future selloffs in the ongoing bear market are buying opportunities for best in class electric utilities, not a reason to sell. For top candidates, see the Conrad’s Utility Investor Portfolios and Dream Buy List in the March issue. 

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Hydro One investment risk reflects Ontario government influence, board shakeup, Avista acquisition uncertainty, regulatory hearings, dividend growth prospects, and utility M&A moves in Peterborough, with stock volatility since the 2015 IPO.

Key Points

Hydro One investment risk stems from political control, governance turnover, regulatory outcomes, and uncertain M&A.

✅ Ontario retains near-50% stake, affecting autonomy and policy risk

✅ Board overhaul and CEO exit create governance uncertainty

✅ Avista deal, OEB hearings, local utility M&A drive outcomes

Hydro One may be only half-owned by the province on Ontario but that’s enough to cause uncertainty about the company’s future, thus making for an investment risk, says Douglas Kee of Leon Frazer & Associates.

Since its IPO in November of 2015, Hydro One has seen its share of ups and downs, including a Q2 profit decline earlier this year, mostly downs at this point. Currently trading at $19.87, the stock has lost 11 per cent of its value in 2018 and 12 per cent over the last 12 months, despite a one-time gain boosting Q2 profit that followed a court ruling.

This year has been a turbulent one, to say the least, as newly elected Ontario premier Doug Ford made good this summer on his campaign promise re Hydro One by forcing the resignation of the company’s 14-person board of directors along with the retirement of its chief executive, an event that saw Hydro One shares fall amid the turmoil. An interim CEO has been found and a new 10-person board and chairman put in place, but Kee says it’s unclear what impact the shakeup will ultimately have, other than delaying a promising-looking deal to purchase US utility Avista Corp, with the companies moving to ask the U.S. regulator to reconsider the order.

Douglas Kee’s take on Hydro One stock

“We looked at Hydro One a couple of times two years ago and just decided that with the Ontario government’s still owning a big chunk of the company … there are other public companies where you get the same kind of yield, the same kind of dividend growth, so we just avoided it,” says Kee, managing director and chief investment officer with Leon Frazer & Associates, to BNN Bloomberg.

“The old board versus the new board, I’m not sure that there’s much of an improvement. It was politics more than anything,” he says. “The unfortunate part is that the acquisition they were making in the United States is kind of on hold for now. The regulatory procedures have gone ahead but they are worried, and I guess the new board has to make a decision whether to go ahead with it or not.”

“Their transmissions side is coming up for regulatory hearings next year, which could be difficult in Ontario,” says Kee. “The offset to that is that there are a lot of municipal distributions systems in Ontario that may be sold — they bought one in Peterborough recently, which was a good deal for them. There may be more of that coming too.”

Last month, Hydro One reached an agreement with the City of Peterborough to buy its Peterborough Distribution utility which serves about 37,000 customers for $105 million. Another deal to purchase Orillia Power Distribution Corp for $41 million has been cancelled after an appeal to the Ontario Energy Board was denied in late August. Hydro One’s sought-after Avista Corp acquisition is reported to be worth $7 billion.

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Hydro-Québec Unified Corporate Structure advances the energy transition through integrated planning, strategy, infrastructure delivery, and customer operations, aligning generation, transmission, and distribution while ensuring non-discriminatory grid access and agile governance across assets and behind-the-meter technologies.

Key Points

A cross-functional model aligning strategy, planning, and operations to accelerate Quebec's low-carbon transition.

✅ Four groups: strategy, planning, infrastructure, operations.

✅ Ensures non-discriminatory transmission access compliance.

✅ No staff reductions; staged implementation from Feb 28.

As Hydro-Que9bec prepares to play a key role in the transition to a low-carbon economy, the complexity of the work to be done in the coming decade requires that it develop a global vision of its operations and assets, from the drop of water entering its turbines to the behind-the-meter technologies marketed by its subsidiary Hilo. This has prompted the company to implement a new corporate structure that will maximize cooperation and agility, including employee-led pandemic support that builds community trust, making it possible to bring about the energy transition efficiently with a view to supporting the realization of Quebecers’ collective aspirations.

Toward a single, unified Hydro

Hydro-Québec’s core mission revolves around four major functions that make up the company’s value chain, alongside policy choices like peak-rate relief during emergencies. These functions consist of:

1. Developing corporate strategies based on current and future challenges and business opportunities
2. Planning energy needs and effectively allocating financial capital, factoring in pandemic-related revenue impacts on demand and investment timing
3. Designing and building the energy system’s multiple components
4. Operating assets in an integrated fashion and providing the best customer experience by addressing customer choice and flexibility expectations across segments.

Accordingly, Hydro-Québec will henceforth comprise four groups respectively in charge of strategy and development; integrated energy needs planning; infrastructure and the energy system; and operations and customer experience, including billing accuracy concerns that can influence satisfaction. To enable the company to carry out its mission, these groups will be able to count on the support of other groups responsible for corporate functions.

Across Canada, leadership changes at other utilities highlight the need to rebuild ties with governments and investors, as seen with Hydro One's new CEO in Ontario.

“For over 20 years, Hydro-Québec has been operating in a vertical structure based on its main activities, namely power generation, transmission and distribution. This approach must now give way to one that provides a cross-functional perspective allowing us to take informed decisions in light of all our needs, as well as those of our customers and the society we have the privilege to serve,” explained Hydro-Québec’s President and Chief Executive Officer, Sophie Brochu.

In terms of gender parity, the management team continues to include several men and women, thus ensuring a diversity of viewpoints.

Hydro-Québec’s new structure complies with the regulatory requirements of the North American power markets, in particular with regard to the need to provide third parties with non-discriminatory access to the company’s transmission system. The frameworks in place ensure that certain functions remain separate and help coordinate responses to operational events such as urban distribution outages that challenge continuity of service.

These changes, which will be implemented gradually as of Monday, February 28, do not aim to achieve any staff reductions.

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Maritime Link Subsea Cable enables HVDC grid interconnection across the Cabot Strait, linking Nova Scotia with Newfoundland and Labrador to import Muskrat Falls hydroelectric power and expand renewable energy integration and reliability.

Key Points

A 170-km HVDC subsea link connecting Nova Scotia and Newfoundland and Labrador for Muskrat Falls power and renewables

✅ 170-km HVDC subsea route across Cabot Strait

✅ Connects Nova Scotia and Newfoundland and Labrador grids

✅ Enables Muskrat Falls hydro and renewable energy trade

The longest sub-sea electricity cable in North America now connects Nova Scotia and Newfoundland and Labrador, according to the company behind the $1.7-billion Maritime Link project.  

The first of the project's two high-voltage power transmission cables was anchored at Point Aconi, N.S., on Sunday. 

The 170-kilometre long cable across the Cabot Strait will connect the power grids in the two provinces. The link will allow power to flow between the two provinces, as demonstrated by its first electricity transfer milestone, and bring to Nova Scotia electricity generated by the massive Muskrat Falls hydroelectric project in Labrador. 

Ultimately, the Maritime Link will help Nova Scotia reach the renewable energy goals set out by the federal government, said Rick Janega, the president and CEO of Emera Newfoundland and Labrador, whose subsidiary owns the Maritime Link.

"If not for the Maritime Link then really the province would not have the ability to meet those requirements because we're pretty much tapped out of all the hydro in province and all the wind generation without creating new interconnections like the Maritime Link," said Janega. 

Not everyone wanted the link 

Fishermen in Cape Breton had objected to the Maritime Link. They were concerned about how the undersea cable might affect fish in the area. 

The laying of the cable and other construction closed a three-kilometre long and 600-metre wide swath of ocean bottom to fishermen for the entire 2017 lobster season.  

But the company came to an agreement to compensate a group of 60 Cape Breton lobster and crab fishermen affected by the project this season. The terms of the compensation deal were not released. 

Long cable, big job

The transmission cable runs northwest of the Marine Atlantic ferry route between North Sydney, N.S., and Port aux Basques, N.L. 

Installation of the second cable is set to begin in June, a major step comparable to BC Hydro's Site C transmission milestone achieved recently. The entire link should be completed by late 2017 and should go into full service by January 2018.

"We're quite confident as soon as the Maritime Link is in service there will be energy transactions between Nova Scotia Power and Newfoundland Hydro. Both utilities have already identified opportunities to save money and exchange energy between the two provinces," said Janega.

That's two years before power is expected to flow from the Muskrat Falls hydro project. The Labrador-based power generating facility has been hampered by delays.

Those kinds of transmission project delays are expected for such a large project, said Janega, and won't stop the Maritime Link from being used. 

"With the Maritime Link going in service this year providing Nova Scotia the opportunity that it needs to be able to reach carbon reductions and to adapt to climate change and to increase renewable energy content and we're very pleased to be at this state today," said Janega.

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Alberta Lithium Brine can power EV batteries via direct lithium extraction, leveraging oilfield infrastructure and critical minerals policy to build a low-carbon supply chain with clean energy, lower emissions, and domestic manufacturing advantages.

Key Points

Alberta lithium brine is subsurface saline water rich in lithium, extracted via DLE to supply EV batteries.

✅ Uses direct lithium extraction from oilfield brines

✅ Leverages Alberta infrastructure and skilled workforce

✅ Supports EV battery supply chain with lower emissions

After a most difficult several months, Canadians are cautiously emerging from their COVID-19 isolation and confronting a struggling economy.
There’s a growing consensus that we need to build back better from COVID-19, and to position for the U.S. auto sector’s pivot to electric vehicles as supply chains evolve. Instead of shoring up the old economy as we did following the 2008 financial crisis, we need to make strategic investments today that will prepare Canada for tomorrow’s economy.

Tomorrow’s energy system will look very different from today’s — and that tomorrow is coming quickly. The assets of today’s energy economy can help build and launch the new industries required for a low-carbon future. And few opportunities are more intriguing than the growing lithium market.

The world needs lithium – and Alberta has plenty

It’s estimated that three billion tonnes of metals will be required to generate clean energy by 2050. One of those key metals – lithium, a light, highly conductive metal – is critical to the construction of battery electric vehicles (BEV). As global automobile manufacturers design hundreds of new BEVs, demand for lithium is expected to triple in the next five years alone, a trend sharpened by pandemic-related supply risks for automakers.

Most lithium today originates from either hard rock or salt flats in Australia and South America. Alberta’s oil fields hold abundant deposits of lithium in subsurface brine, but so far it’s been overlooked as industrial waste. With new processing technologies and growing concerns about the security of global supplies, this is set to change. In January, Canada and the U.S. finalized a Joint Action Plan on Critical Minerals to ensure supply security for critical minerals such as lithium and to promote supply chains closer to home, aligning with U.S. efforts to secure EV metals among allies worldwide.

This presents a major opportunity for Canada and Alberta. Lithium brine will be produced much like the oil that came before it. This lithium originates from many of the same reservoirs responsible for driving both Alberta’s economy and the broader transportation fuel sector for decades. The province now has extensive geological data and abundant infrastructure, including roads, power lines, rail and well sites. Most importantly, Alberta has a highly trained workforce. With very little retooling, the province could deliver significant volumes of newly strategic lithium.

Specialized technologies known as direct lithium extraction, or DLE, are being developed to unlock lithium-brine resources like those in Canada. In Alberta, E3 Metals* has formed a development partnership with U.S. lithium heavyweight Livent Corporation to advance and pilot its DLE technology. Prairie Lithium and LiEP Energy formed a joint venture to pilot lithium extraction in Saskatchewan. And Vancouver’s Standard Lithium is already piloting its own DLE process in southern Arkansas, where the geology is very similar to Alberta and Saskatchewan.

Heavy on quality, light on emissions

All lithium produced today has a carbon footprint, most of which can be tied back to energy-intensive processing. The purity of lithium is essential to battery safety and performance, but this comes at a cost when lithium is mined with trucks and shovels and then refined in coal-heavy China.

As automakers look to source more sustainable raw materials, battery recycling will complement responsible extraction, and Alberta’s experience with green technologies such as renewable electricity and carbon capture and storage can make it one of the world’s largest suppliers of zero-carbon lithium.

Beyond raw materials

The rewards would be considerable. E3 Metals’ Alberta project alone could generate annual revenues of US$1.8 billion by 2030, based on projected production and price forecasts. This would create thousands of direct jobs, as initiatives like a lithium-battery workforce initiative expand training, and many more indirectly.

To truly grow this industry, however, Canada needs to move beyond its comfort zone. Rather than produce lithium as yet another raw-commodity export, Canadians should be manufacturing end products, such as batteries, for the electrified economy, with recent EV assembly deals underscoring Canada’s momentum. With nickel and cobalt refining, graphite resources and abundant petrochemical infrastructure already in place, Canada must aim for a larger piece of the supply chain.

By 2030, the global battery market is expected to be worth $116 billion annually. The timing is right to invest in a strategic commodity and grow our manufacturing sector. This is why the Alberta-based Energy Futures Lab has called lithium one of the ‘Five big ideas for Alberta’s economic recovery.’  The assets of today’s energy economy can be used to help build and launch new resource industries like lithium, required for the low-carbon energy system of the future.

Industry needs support

To do this, however, governments will have to step up the way they did a generation ago. In 1975, the Alberta government kick-started oil-sands development by funding the Alberta Oil Sands Technology and Research Authority. AOSTRA developed a technology called SAGD (steam-assisted gravity drainage) that now accounts for 80% of Alberta’s in situ oil-sands production.

Canada’s lithium industry needs similar support. Despite the compelling long-term economics of lithium, some industry investors need help to balance the risks of pioneering such a new industry in Canada. The U.S. government has recognized a similar need, with the Department of Energy’s recent US$30 million earmarked for innovation in critical minerals processing and the California Energy Commission’s recent grants of US$7.8 million for geothermal-related lithium extraction.

To accelerate lithium development in Canada, this kind of leadership is needed. Government-assisted financing could help early-stage lithium-extraction technologies kick-start a whole new industry.

Aspiring lithium producers are also looking for government’s help to repurpose inactive oil and gas wells. The federal government has earmarked $1 billion for cleaning up inactive Alberta oil wells. Allocating a small percentage of that total for repurposing wells could help transform environmental liabilities into valuable clean-energy assets.

The North American lithium-battery supply chain will soon be looking for local sources of supply, and there is room for Canada-U.S. collaboration as companies turn to electric cars, strengthening regional resilience.
 

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U.S. coal-fired generation 2021 rose as higher natural gas prices, stable coal costs, and a recovering power sector shifted the generation mix; capacity factors rebounded despite low coal stocks and ongoing plant retirements.

Key Points

Coal output rose 22% on high gas prices and higher capacity factors; a 5% decline is expected in 2022.

✅ Natural gas delivered cost averaged $4.93/MMBtu, more than double 2020

✅ Coal capacity factor rose to ~51% from 40% in 2020

✅ 2022 coal generation forecast to fall about 5%

We expect 22% more U.S. coal-fired generation in 2021 than in 2020, according to our latest Short-Term Energy Outlook (STEO). The U.S. electric power sector has been generating more electricity from coal-fired power plants this year as a result of significantly higher natural gas prices and relatively stable coal prices, even as non-fossil sources reached 40% of total generation. This year, 2021, will yield the first year-over-year increase in coal generation in the United States since 2014, highlighted by a January power generation jump earlier in the year.

Coal and natural gas have been the two largest sources of electricity generation in the United States. In many areas of the country, these two fuels compete to supply electricity based on their relative costs and sensitivity to policies and gas prices as well. U.S. natural gas prices have been more volatile than coal prices, so the cost of natural gas often determines the relative share of generation provided by natural gas and coal.

Because natural gas-fired power plants convert fuel to electricity more efficiently than coal-fired plants, record natural gas generation has at times underscored that advantage, and natural gas-fired generation can have an economic advantage even if natural gas prices are slightly higher than coal prices. Between 2015 and 2020, the cost of natural gas delivered to electric generators remained relatively low and stable. This year, however, natural gas prices have been much higher than in recent years. The year-to-date delivered cost of natural gas to U.S. power plants has averaged $4.93 per million British thermal units (Btu), more than double last year’s price.

The overall decline in electricity demand in 2020 and record-low natural gas prices led coal plants to significantly reduce the percentage of time that they generated power. In 2020, the utilization rate (known as the capacity factor) of U.S. coal-fired generators averaged 40%. Before 2010, coal capacity factors routinely averaged 70% or more. This year’s higher natural gas prices have increased the average coal capacity factor to about 51%, which is almost the 2018 average, a year when wind and solar reached 10% nationally.

Although rising natural gas prices have resulted in more U.S. coal-fired generation than last year, this increase in coal generation will most likely not continue as solar and wind expand in the generation mix. The electric power sector has retired about 30% of its generating capacity at coal plants since 2010, and no new coal-fired capacity has come online in the United States since 2013. In addition, coal stocks at U.S. power plants are relatively low, and production at operating coal mines has not been increasing as rapidly as the recent increase in coal demand. For 2022, we forecast that U.S. coal-fired generation will decline about 5% in response to continuing retirements of generating capacity at coal power plants and slightly lower natural gas prices.

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