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Western Canada Hydropower Drought strains British Columbia and Manitoba as reservoirs hit historic lows, cutting hydroelectric output and prompting power imports, natural gas peaking, and grid resilience planning amid climate change risks this winter.

Key Points

Climate-driven reservoir lows cut hydro in B.C. and Manitoba, prompting imports and backup gas to maintain reliability.

✅ Reservoirs at multi-year lows cut hydro generation capacity

✅ BC Hydro and Manitoba Hydro import electricity for reliability

✅ Natural gas turbines used; climate change elevates drought risk

Severe drought conditions in Western Canada are compelling two hydroelectricity-dependent provinces, British Columbia and Manitoba, to import power from other regions. These provinces, known for their reliance on hydroelectric power, are facing reduced electricity production due to low water levels in reservoirs this autumn and winter as energy-intensive customers encounter temporary connection limits.

While there is no immediate threat of power outages in either province, experts indicate that climate change is leading to more frequent and severe droughts. This trend places increasing pressure on hydroelectric power producers in the future, spurring interest in upgrading existing dams as part of adaptation strategies.

In British Columbia, several regions are experiencing "extreme" drought conditions as classified by the federal government. BC Hydro spokesperson Kyle Donaldson referred to these conditions as "historic," and a first call for power highlights the strain, noting that the corporation's large reservoirs in the north and southeast are at their lowest levels in many years.

To mitigate this, BC Hydro has been conserving water by utilizing less affected reservoirs and importing additional power from Alberta and various western U.S. states. Donaldson confirmed that these measures would persist in the upcoming months.

Manitoba is also facing challenges with below-normal levels in reservoirs and rivers. Since October, Manitoba Hydro has occasionally relied on its natural gas turbines to supplement hydroelectric production as electrical demand could double over the next two decades, a measure usually reserved for peak winter demand.

Bruce Owen, a spokesperson for Manitoba Hydro, reassured that there is no imminent risk of a power shortage. The corporation can import electricity from other regions, similar to how it exports clean energy in high-water years.

However, the cost implications are significant. Manitoba Hydro anticipates a financial loss for the current fiscal year, with more red ink tied to emerging generation needs, the second in a decade, with the previous one in 2021. That year, drought conditions led to a significant reduction in the company's power production capabilities, resulting in a $248-million loss.

The 2021 drought also affected hydropower production in the United States. The U.S. Department of Energy reported a 16% reduction in overall generation, with notable decreases at major facilities like Nevada's Hoover Dam, where production dropped by 25%.

Drought has long been a major concern for hydroelectricity producers, and they plan their operations with this risk in mind. Manitoba's record drought in 1940-41, for example, is a benchmark for Manitoba Hydro's operational planning to ensure sufficient electricity supply even in extreme low-water conditions.

Climate change, however, is increasing the frequency of such rare events, highlighting the need for more robust backup systems such as new turbine investments to enhance reliability. Blake Shaffer, an associate professor of economics at the University of Calgary specializing in electricity markets, emphasized the importance of hydroelectric systems incorporating the worsening drought forecasts due to climate change into their energy production planning.

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Ontario Pumped Storage advances as Ontario's largest energy storage project, delivering clean electricity, long-duration capacity, and grid reliability for peak demand, led by TC Energy and Saugeen Ojibway Nation, with IESO review underway.

Key Points

A long-duration storage project in Meaford storing clean power for peak demand, supporting Ontario's emission-free grid.

✅ Stores clean electricity to power 1M homes for 11 hours

✅ Partnership: TC Energy and Saugeen Ojibway Nation

✅ Pending IESO review and OEB regulation decisions

In a bid to accelerate the province's ambitions for clean economic growth, TC Energy Corporation has announced significant progress in the development of the Ontario Pumped Storage Project. The Government of Ontario in Canada has unveiled a plan to address growing energy needs as a sustainable road map aimed at achieving an emission-free electricity sector, and as part of this plan, the Ministry of Energy is set to undertake a final evaluation of the proposed Ontario Pumped Storage Project. A decision is expected to be reached by the end of the year.

Ontario Pumped Storage is a collaborative effort between TC Energy and the Saugeen Ojibway Nation. The project is designed to be Ontario's largest energy storage initiative, capable of storing clean electricity to power one million homes for 11 hours. As the province strives to transition to a cleaner electricity grid by embracing clean power across sectors, long duration storage solutions like Ontario Pumped Storage will play a pivotal role in providing reliable, emission-free power during peak demand periods.

The success of the Project hinges on the approval of TC Energy's board of directors and a fruitful partnership agreement with the Saugeen Ojibway Nation. TC Energy is aiming for a final investment decision in 2024, as Ontario confronts an electricity shortfall in the coming years, with the anticipated in-service date being in the early 2030s, pending regulatory and corporate approvals.

“Ontario Pumped Storage will be a critical component of Ontario’s growing clean economy and will deliver significant benefits and savings to consumers,” said Corey Hessen, Executive Vice-President and President, TC Energy, Power and Energy Solutions. “Ontario continues to attract major investments that will have large power needs — many of which are seeking zero-emission energy before they invest. We are pleased the government is advancing efforts to recognize the significant role that long duration storage plays — firming resources, including new gas plants under provincial consideration, will become increasingly valuable in supporting a future emission-free electricity system.” 

The Municipality of Meaford also expressed its support for the project, recognizing the positive impact it could have on the local economy and the overall electricity system of Ontario. Additionally, various stakeholders, including LiUNA OPDC, LiUNA Local 183, and the Ontario Chamber of Commerce, lauded the potential for job creation, training opportunities, and resilient energy infrastructure as Ontario seeks new wind and solar power to ease a coming electricity supply crunch.

The timeline for Ontario Pumped Storage's progress includes a final analysis by the Independent Electricity System Operator (IESO) to confirm its role in Ontario's electricity system and in balancing demand and emissions during the transition, to be completed by 30 September 2023. Concurrently, the Ministry of Energy will engage in consultations on the potential regulation of the Project via the Ontario Energy Board, while debates over clean, affordable electricity intensify ahead of the Ontario election, with a final determination scheduled for 30 November 2023.

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Hydro One-Avista acquisition sparks Idaho regulatory scrutiny over foreign ownership, utility merger impacts, rate credits, and public interest, as FERC and FCC approvals advance and consumers question governance, service reliability, and long-term rate stability.

Key Points

A cross-border utility merger proposal with Idaho oversight, weighing foreign ownership, rates, and reliability.

✅ Idaho PUC review centers on public interest and rate impacts.

✅ FERC and FCC approvals granted; state decisions pending.

✅ Avista to retain name and Spokane HQ post-transaction.

“Please don’t sell us to Canada.” That refrain, or versions of it, is on full display at the Idaho Public Utilities Commission, which admittedly isn’t everyone’s go-to entertainment site. But it is vitally important for this reason: the first big test of the expansionist dreams of the politically tempest-tossed Hydro One, facing political risk as it navigates markets, rests with its successful acquisition of Avista Corp., provider of electric generation, transmission and distribution to retail customers spread from Oregon to Washington to Montana and Idaho and up into Alaska.

The proposed deal — announced last summer, but not yet consummated — marks the first time the publicly traded Hydro One has embarked upon the acquisition of a U.S. utility. And if Idahoans spread from Boise to Coeur d’Alene to Hayden are any indication, they are not at all happy with the idea of foreign ownership. Here’s Lisa McCumber, resident of Hayden: “I am stating my objection to this outrageous merger/takeover. Hydro One charges excessive fees to the people it provides for, this is a monopoly beyond even what we are used to. I, in no way, support or as a customer, agree with the merger of this multi-billion-dollar, foreign, company.”

#google#

Or here’s Debra Bentley from Coeur d’Alene: “Fewer things have more control over a nation than its power source. In an age where we are desperately trying to bring American companies back home and ‘Buy American’ is somewhat of a battle cry, how is it even possible that it would or could be allowed for this vital necessity … to be controlled by a foreign entity?”

Or here’s Spencer Hutchings from Sagle: “This is an incredibly bad idea.”

There are legion of similar emails from concerned consumers, and the Maine transmission line debate offers a parallel in public opposition.

The rationale for the deal? Last fall Hydro One CEO Mayo Schmidt testified before the Idaho commission, which regulates all gas, water and electricity providers in the state. “Hydro One is a pure-play transmission and distribution utility located solely within Ontario,” Schmidt told commissioners. “It seeks diversification both in terms of jurisdictions and service areas. The proposed Transaction with Avista achieves both goals by expanding Hydro One into the U.S. Pacific Northwest and expanding its operations to natural gas distribution and electric generation. The proposed Transaction with Avista will deliver the increased scale and benefits that come from being a larger player in the utility industry.”

Translation: now that it is a publicly traded entity, Hydro needs to demonstrate a growth curve to the investment community. The value to you and me? Arguable. This is a transaction framed as a benefit to shareholders, one that won’t cause harm to customers. Premier Kathleen Wynne is feeling the pain of selling off control of an essential asset. In his testimony to the commission, Schmidt noted that the Avista acquisition would take the province’s Hydro ownership to under 45 per cent. (The Electricity Act technically prevents the sale of shares that would take the government’s ownership position below 40 per cent, though acquisitions appear to allow further dilution. )

Stratospheric compensation, bench-marked against other chief executives who enjoy similarly outsized rewards, is part of this game. I have written about Schmidt’s unconscionable compensation before, but that was when he was making a relatively modest $4 million. Relative, that is, to his $6.2 million in 2017 compensation ($3.5 million of that is in the form of share based awards).

Should the acquisition of Avista be approved, amendments to the CIC, or change in control agreements, for certain named Avista executive officers will allow them to voluntarily terminate their employment without “good reason.” That includes Scott Morris, the company’s CEO, who will exit with severance of $6.9 million (U.S.) and additional benefits taking the total to a potential $15.7 million.

Back to the deal: cost savings over time could be achieved, Schmidt continued in his testimony, though he was unable to quantify those. The integration between the two companies, he promised, will be “seamless.” Retail customers in Idaho, Washington and Oregon would benefit from proposed “Rate Credits” equalling an estimated $15.8 million across five years, even as Hydro One seeks to redesign its bills in Ontario. Idahoans would see a one per cent rate decrease through that period.

While Avista would become a wholly owned Hydro subsidiary, it would retain its name, and its headquarters in Spokane, Wash. In the case of Idaho specifically, a proposed settlement in April, subject to final approval by the commission, stipulates agreements on everything from staffing to governance to community contributions.

Will that meet the test? It’s up to the commission to determine whether the proposed transaction will keep a lid on rates and is “consistent with the public interest.” Hydro One is hoping for a decision from regulatory agencies in all the named states by mid-August and a closing date by the end of September, though U.S. regulators can ultimately determine the fate of such deals. The Federal Energy Regulatory Commission granted its approval in January, followed last week by the Federal Communications Commission. Washington and Alaska have reached settlement agreements. These too are pending final state approvals.

The $5.3-billion deal (or $6.7 billion Canadian) is subject to ongoing hearings in Idaho, and elsewhere rate hikes face opposition as hearings begin. Members of the public are encouraged to have their say. The public comment deadline is June 27.

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EU Power Market Overhaul targets soaring electricity prices by decoupling gas from power, boosting renewables, refining price caps, and stabilizing grids amid inflation, supply shocks, droughts, nuclear outages, and intermittent wind and solar.

Key Points

EU plan to redesign electricity pricing, curb gas-driven costs, boost renewables, and protect consumers from volatility.

✅ Decouples power prices from marginal gas generation

✅ Caps non-gas revenues to fund consumer relief

✅ Supports grid stability with storage, demand response, LNG

While energy prices are soaring around the world, Europe is in a particularly tight spot. Its heavy dependence on Russian gas -- on top of droughts, heat waves, an unreliable fleet of French nuclear reactors and a continent-wide shift to greener but more intermittent sources like solar and wind -- has been driving electricity bills up and feeding the highest inflation in decades. As Europe stands on the brink of a recession, and with the winter heating season approaching, officials are considering a major overhaul of the region’s power market to reflect the ongoing shift from fossil fuels to renewables.

1. How is electricity priced? 
Unlike oil or natural gas, there’s no efficient way to save lots of electricity to use in the future, though projects to store electricity in gas pipes are emerging. Commercial use of large-scale batteries is still years away. So power prices have been set by the availability at any given moment. When it’s really windy or sunny, for example, then more is produced relatively cheaply and prices are lower. If that supply shrinks, then prices rise because more generators are brought online to help meet demand -- fueled by more expensive sources. The way the market has long worked is that it is that final technology, or type of plant, needed to meet the last unit of consumption that sets the price for everyone. In Europe this year, that has usually meant natural gas. 

2. What is the relationship between power and gas? 
Very close. Across western Europe, gas plants have been a vital part of the energy infrastructure for decades, with Irish price spikes highlighting dispatchable power risks, fed in large part by supplies piped in from Siberia. Gas-fired plants were relatively quick to build and the technology straightforward, at least compared with nuclear plants and burns cleaner than coal. About 18% of Europe’s electricity was generated at gas plants last year; in 2020 about 43% of the imported gas came from Russia. Even during the depths of the Cold War, there’d never been a serious supply problem -- until the relationship with Russia deteriorated this year after it invaded Ukraine. Diversifying away from Russia, such as by increasing imports of liquefied natural gas, requires new infrastructure that takes a lot of time and money.

3. Why does it work this way? 
In theory, the relationship isn’t different from that with coal, for example. But production hiccups and heatwave curbs on plants from nuclear in France to hydro in Spain and Norway significantly changed the generation picture this year, and power hit records as plants buckled in the heat. Since coal-fired and nuclear plants are generally running all the time anyway, gas plants were being called upon more often -- at times just to keep the lights on as summer temperatures hit records. And with the war in Ukraine resulting in record gas prices, that pushed up overall production costs. It’s that relationship that has made the surging gas price the driver for electricity prices. And since the continent is all connected, it has pushed up prices across the region. The value of the European power market jumped threefold last year, to a record 836 billion euros ($827 billion today).

4. What’s being considered? 
With large parts of European industry on its knees and households facing jumps in energy bills of several hundred percent, as record electricity prices ripple through markets, the pressure on governments and the European Union to intervene has never been higher. One major proposal is to impose a price cap on electricity from non-gas producers, with the difference between that and the market price channeled to relief for consumers. While it sounds simple, any such changes would rip up a market design that’s worked for decades and could threaten future investments because of unintended consequences.

5. How did this market evolve?
The Nordic region and the British market were front-runners in the 1990s, then Germany followed and is now the largest by far. A trader can buy and sell electricity delivered later on same day in blocks of an hour or even down to 15-minute periods, to meet sudden demand or take advantage of price differentials. The price for these contracts is decided entirely by the supply and demand, how much the wind is blowing or which coal plants are operating, for example. Demand tends to surge early in the morning and late afternoon. This system was designed when fossil fuels provided the bulk of power. Now there are more renewables, which are less predictable, with wind and solar surpassing gas in EU generation last year, and the proposed changes reflect that shift. 

6. What else have governments done?
There are also traders who focus on longer-dated contracts covering periods several years ahead, where broader factors such as expected economic output and the extent to which renewables are crowding out gas help drive prices. This year’s wild price swings have prompted countries including Germany, Sweden and Finland to earmark billions of euros in emergency liquidity loans to backstop utilities hit with sudden margin calls on their trading.

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FERC Hydropower Licensing Dispute centers on FERC authority, Clean Water Act compliance, state water quality certifications, Federal Power Act timelines, and Army Corps dams on West Virginia's Monongahela River licenses.

Key Points

An inquiry into FERC's licensing process and state water quality authority for hydropower at Monongahela River dams.

✅ Questions on omitted state water quality conditions

✅ Debate over starting Clean Water Act certification timelines

✅ Potential impacts on states' rights and licensing schedules

As federal lawmakers, including Democrats pressing FERC, plan to consider a bill that would expand Federal Energy Regulatory Commission (FERC) licensing authority, questions emerged on Tuesday about the process used by FERC to issue two hydropower licenses for existing dams in West Virginia.

In a letter to FERC Chairman Neil Chatterjee, Democratic leaders of the House Energy and Commerce Committee, as electricity pricing changes were being debated, raised questions about hydropower licenses issued for two dams operated by the U.S. Army Corps of Engineers on the Monongahela River in West Virginia.

U.S. Reps. Frank Pallone Jr. (D-NJ), the ranking member of the Subcommittee on Energy, Bobby Rush (D-IL), the ranking member of the Subcommittee on Environment, and John Sarbanes (D-MD), amid Maryland clean energy enforcement concerns, questioned why FERC did not incorporate all conditions outlined in a West Virginia Department of Environmental Protection water quality certificate into plans for the projects.

“By denying the state its allotted time to review this application and submit requirements on these licenses, FERC is undermining the state’s authority under the Clean Water Act and Federal Power Act to impose conditions that will ensure water quality standards are met,” the letter stated.

The House of Representatives was slated to consider the Hydropower Policy Modernization Act of 2017, H.R. 3043, later in the week. The measure would expand FERC authority over licensing processes, a theme mirrored in Maine's transmission line debate over interstate energy projects. Opponents of the bill argue that the changes would make it more difficult for states to protect their clean water interests.

West Virginia has announced plans to challenge FERC hydropower licenses for the dams on the Monongahela River, echoing Northern Pass opposition seen in New Hampshire.

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Ontario Electricity Rates update: OEB sets time-of-use and tiered pricing for residential customers, with kWh charges for peak, mid-peak, and off-peak periods reflecting COVID-19 impacts on demand, supply costs, and pricing.

Key Points

Ontario Electricity Rates are OEB-set time-of-use and tiered prices that set per-kWh costs for residential customers.

✅ Time-of-use: 21.7 peak, 15.0 mid-peak, 10.5 off-peak cents/kWh

✅ Tiered: 12.6 cents/kWh up to 1000 kWh, then 14.6 cents/kWh

✅ Average 700 kWh home pays about $2.24 more per month

Energy bills for the typical Ontario home are going up by about two per cent with fixed pricing coming to an end on Nov. 1, the Ontario Energy Board says. 

The province's electricity regulator has released new time-of-use pricing and says the rate for the average residential customer using 700 kWh per month will increase by about $2.24.

The change comes as Ontario stretches into its eight month of the COVID-19 pandemic with new case counts reaching levels higher than ever seen before.

Time-of-use pricing had been scrapped for residential bills for much for the pandemic with a single fixed COVID-19 hydro rate set for all hours of the day. The move, which came into effect June 1, was meant "to support families, small business and farms while Ontario plans for the safe and gradual reopening of the province," the OEB said at the time.

Ontario later set the off-peak price until February 7 around the clock to provide additional relief.

Fixed pricing meant customers' bills reflected how much power they used, rather than when they used it. Customers were charged 12.8 cents/kWh under the COVID-19 recovery rate no matter their time of use.

Beginning November, the province says customers can choose between time-of-use and tiered pricing options. Rates for time-of-use plans will be 21.7 cents/kWh during peak hours, 15 cents/kWh for mid-peak use and 10.5 cents/kWh for off-peak use. 

Customers choosing tiered pricing will pay 12.6 cents/kWh for the first 1000 kWh each month and then 14.6 cents/kWh for any power used beyond that.

The energy board says the increase in pricing reflects "a combination of factors, including those associated with the COVID-19 pandemic, that have affected demand, supply costs and prices in the summer and fall of 2020."

Asked for his reaction to the move Tuesday, Premier Doug Ford said, "I hate it," adding the province inherited an energy "mess" from the previous Liberal government and are "chipping away at it."

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