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Jay Grewal Manitoba Hydro Appointment marks the first woman CEO at the Crown utility, amid debt, rate increase plans, privatization debate, and Metis legal challenge, following board turmoil and Premier Pallister's strained relations.

Key Points

The selection of Jay Grewal as Manitoba Hydro's first woman CEO amid debt, rate hikes, and legal disputes.

✅ First woman CEO of Manitoba Hydro

✅ Faces debt, rate hikes, and project overruns

✅ Amid privatization debate and Metis legal action

The Manitoba government has appointed a new president and chief executive officer at its Crown-owned energy utility.

Jay Grewal becomes the first woman to head Manitoba Hydro, and takes over the top spot as the utility faces mounting financial challenges, rising electricity demand and turmoil.

Grewal has previously held senior roles at Capstone Mining Corp and B.C. Hydro, and is currently president of the Northwest Territories Power Corporation.

She will replace outgoing president Kelvin Shepherd, who recently announced he is retiring, on Feb. 4.

The utility was hit by the sudden resignations of nine of its 10 board members in March, who said they had been unable to meet with Premier Brian Pallister to discuss pressing issues like servicing energy-intensive customers facing the utility.

Manitoba Hydro is also in the middle of a battle between the Progressive Conservative government and the Manitoba Metis Federation over the cancellation of two agreements that would have given the Metis $87 million.

The federation has launched a legal challenge over one deal and says its likely going to do the same over the second agreement.

Grewal also takes over the utility at a time when it has racked up billions of dollars in debt building new generating stations and transmission lines. Manitoba Hydro has told the provincial regulatory agency it needs rate increases of nearly eight per cent a year for the next few years to help pay for the projects.

The utility also exports electricity, with deals such as SaskPower's purchase agreement expanding sales to Saskatchewan.

"Ms. Grewal is a proven leader, with extensive senior leadership experience in the utility, resource and consulting sectors," Crown Services Minister Colleen Mayer said in a written statement Thursday.

The Opposition New Democrats said Grewal's appointment is a sign the government wants to privatize Manitoba Hydro. Grewal's time at B.C. Hydro coincided with the privatization of some parts of that Crown utility, the NDP said.

The B.C. premier at the time, Gordon Campbell, was recently hired by Manitoba to review two major projects that ran over-budget and have added to the provincial debt.

NDP Leader Wab Kinew asked Pallister in the legislature Thursday to promise not to privatize Manitoba Hydro. Pallister would only point to a law that requires a referendum to be held before a Crown entity can be sold off.

"We stand by that (law)," Pallister said. "We believe Manitobans are the proper decision-makers in respect of any of the future structuring of Manitoba Hydro."

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Coal-to-Clean Energy Hubs leverage Bipartisan Infrastructure Law and Inflation Reduction Act funding to repurpose mine lands with microgrids, advanced nuclear, carbon capture, and rare earth processing, boosting energy security, jobs, and grid modernization.

Key Points

They are federal projects converting coal communities and mine lands into clean energy hubs, repurposing infrastructure.

✅ DOE demos on mine lands: microgrids, nuclear, carbon capture.

✅ Funding from BIL, CHIPS and IRA targets energy communities.

✅ Rare earths from coal waste bolster EV supply chains.

The Biden administration is channeling hundreds of millions of dollars in clean energy funding from recent legislation into its efforts to turn coal communities into clean energy hubs, the White House said.

The administration gave an update on its push across agencies to kick-start projects nationwide with funding Congress approved during Biden’s first two years in office. The effort includes $450 million from the Bipartisan Infrastructure Law that the Department of Energy will allocate to an array of new clean energy demonstration projects on former mine lands.

“These projects could focus on a range of technologies from microgrids to advanced nuclear to power plans with carbon capture,” Energy Secretary Jennifer Granholm said on a call with reporters Monday. “They’ll prove out the potential to reactivate or repurpose existing infrastructure like transmission lines and substations across an aging U.S. power grid, and these projects could spur new economic development in these communities.”

Among the projects the White House highlighted, it said $16 million from the infrastructure law will go to the University of North Dakota and West Virginia University to create design studies for the first-ever full-scale refinery facility in the U.S. that could extract and separate rare earth elements and minerals from coal mine waste streams. The materials are critical for electric vehicle-battery components that are currently heavily sourced from outside the U.S.

“Those efforts will pave the way toward building a first of its kind facility that produces essential materials for solar panels, wind turbines, EVs and more while cleaning up polluted land and water and creating good-paying jobs for local workers,” Granholm said.

Biden created an interagency working group focused on revitalizing coal-power communities through federal investments when he took office. In 2021, the group selected 25 priority areas ranging from West Virginia to Wyoming to focus on development, as high natural gas prices strengthened the case for clean electricity. There are nearly 18,000 identified mine sites across 1.5 million acres in the United States, according to the White House.

The massive effort fits into a broader Biden administration push to both fight climate change and support communities that have lost economic activity during a transition away from fossil fuel sources such as coal. While Biden’s most ambitious clean energy plans fell flat in Congress in the face of opposition from Republicans and some Democrats after the previous administration’s power plant overhaul, three major laws still unlocked funding for his administration to deploy.

Many of the initiatives are made possible through the Bipartisan Infrastructure Law, Chips and Science Act and the Inflation Reduction Act, even without a clean electricity standard on the books. The task force aims to make sure communities most affected by the changing energy landscape are taking maximum advantage of the federal benefits.

“Those new and expanded operations are coming to energy communities and creating good paying jobs,” Biden’s senior advisor for clean energy innovation and implementation John Podesta said on the call. “These laws can provide substantial federal support to energy communities like capping abandoned oil and gas wells, extracting critical minerals, building battery factories and launching demonstration projects in carbon capture or green hydrogen.”

The administration touted the potential benefits of the Inflation Reduction Act, a bill passed by Democrats to spur clean energy investments last year, even as early assessments show mixed results to date. At the time, U.S. consumers were dealing with decades-high inflation fueled in part by an energy crisis and high gas prices that drove debate — a point Republicans emphasized as the plan moved through Congress.

Deputy Treasury Secretary Wally Adeyemo said the Inflation Reduction Act aims to both “lower the deficit, as well as promote our energy security, lowering energy costs for consumers and combatting climate change.”

“As the Treasury works to implement the law, we’re focused on ensuring that all Americans benefit from the growth of the clean energy economy, particularly those who live in communities that have been dependent on the energy sector for job for a long time,” Adeyemo told reporters. “Economic growth and productivity are higher when all communities are able to reach their full potential.”

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Hinkley Point C delays highlight EDF cost overruns, energy security risks, and wholesale power prices, complicating UK net zero plans, Sizewell C financing, and small modular reactor adoption across the grid.

Key Points

Delays at EDF's 3.2GW Hinkley Point C push operations to 2031, lift costs to £46bn, and risk pricier UK electricity.

✅ First unit may slip to 2031; second unit date unclear.

✅ LSEG sees 6% wholesale price impact in 2029-2032.

✅ Sizewell C replicates design; SMR contracts expected soon.

Vincent de Rivaz, former CEO of EDF, confidently announced in 2016 the commencement of the UK's first nuclear power station since the 1990s, Hinkley Point C. However, despite milestones such as the reactor roof installation, recent developments have belied this optimism. The French state-owned utility EDF recently disclosed further delays and cost overruns for the 3.2 gigawatt plant in Somerset.

These complications at Hinkley Point C, which is expected to power 6 million homes, have sparked new concerns about the UK's energy strategy and its ambition to decarbonize the grid by 2050.

The UK government's plan to achieve net zero by 2050 includes a significant role for nuclear energy, reflecting analyses that net-zero may not be possible without nuclear and aiming to increase capacity from the current 5.88GW to 24GW by mid-century.

Simon Virley, head of energy at KPMG in the UK, stressed the importance of nuclear energy in transitioning to a net zero power system, echoing industry calls for multiple new stations to meet climate goals. He pointed out that failing to build the necessary capacity could lead to increased reliance on gas.

Hinkley Point C is envisioned as the pioneer in a new wave of nuclear plants intended to augment and replace Britain's existing nuclear fleet, jointly managed by EDF and Centrica. Nuclear power contributed about 14 percent of the UK's electricity in 2022, even as Europe is losing nuclear power across the continent. However, with the planned closure of four out of five plants by March 2028 and rising electricity demand, there is concern about potential power price increases.

Rob Gross, director of the UK Energy Research Centre, emphasized the link between energy security and affordability, highlighting the risk of high electricity prices if reliance on expensive gas increases.

The first 1.6GW reactor at Hinkley Point C, initially set for operation in 2027, may now face delays until 2031, even after first reactor installation milestones were reported. The in-service date for the second unit remains uncertain, with project costs possibly reaching £46bn.

LSEG analysts predict that these delays could increase wholesale power prices by up to 6 percent between 2029 and 2032, assuming the second unit becomes operational in 2033.

Martin Young, an analyst at Investec, warned of the price implications of removing a large power station from the supply side.

In response to these delays, EDF is exploring the extension of its four oldest plants. Jerry Haller, EDF’s former decommissioning director, had previously expressed skepticism about extending the life of the advanced gas-cooled reactor fleet, but EDF has since indicated more positive inspection results. The company had already decided to keep the Heysham 1 and Hartlepool plants operational until at least 2026.

Nevertheless, the issues at Hinkley Point C raise doubts about the UK's ability to meet its 2050 nuclear build target of 24GW.

Previous delays at Hinkley were attributed to the COVID-19 pandemic, but EDF now cites engineering problems, similar to those experienced at other European power stations using the same technology.

The next major UK nuclear project, Sizewell C in Suffolk, will replicate Hinkley Point C's design, aligning with the UK's green industrial revolution agenda. EDF and the UK government are currently seeking external investment for the £20bn project.

Compared with Hinkley Point C, Sizewell C's financing model involves exposing billpayers to some risk of cost overruns. This, coupled with EDF's track record, could affect investor confidence.

Additionally, the UK government is supporting the development of small modular reactors, while China's nuclear program continues on a steady track, with contracts expected to be awarded later this year.

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North American Grid Reliability faces extreme weather, climate change, demand spikes, and renewable variability; utilities, AESO, and NERC stress resilience, dispatchable capacity, interconnections, and grid alerts to prevent blackouts during heatwaves and cold snaps.

Key Points

North American grid reliability is the ability to meet demand during extreme weather while maintaining stability.

✅ Extreme heat and cold drive record demand and resource strain.

✅ Balance dispatchable and intermittent generation for resilience.

✅ Expand interconnections, capacity, and demand response to avert outages.

The recent alerts in Alberta's electricity grid during extreme cold have highlighted a broader North American issue, where power systems are more susceptible to being overwhelmed by extreme weather impacts on reliability.

Electricity Canada's chief executive emphasized that no part of the grid is safe from the escalating intensity and frequency of weather extremes linked to climate change across the sector.

“In recent years, during these extreme weather events, we’ve observed record highs in electricity demand,” he stated.

“It’s a nationwide phenomenon. For instance, last summer in Ontario and last winter in Quebec, we experienced unprecedented demand levels. This pattern of extremes is becoming more pronounced across the country.”

The U.S. has also experienced strain on its electricity grids due to extreme weather, with more blackouts than peers documented in studies. Texas faced power outages in 2021 due to winter storms, and California has had to issue several emergency grid alerts during heat waves.

In Canada, Albertans received a government emergency alert two weeks ago, urging an immediate reduction in electricity use to prevent potential rotating blackouts as temperatures neared -40°C. No blackouts occurred, with a notable decrease in electricity use following the alert, according to the Alberta Electric System Operator (AESO).

AESO's data indicates an increase in grid alerts in Alberta for both heatwaves and cold spells, reflecting dangerous vulnerabilities noted nationwide. The period between 2017 and 2020 saw only four alerts, in contrast to 17 since 2021.

Alberta's electricity grid reliability has sparked political debate, including proposals for a western Canadian grid to improve reliability, particularly with the transition from coal-fired plants to increased reliance on intermittent wind and solar power. Despite this debate, the AESO noted that the crisis eased when wind and solar generation resumed, despite challenges with two idled gas plants.

Bradley pointed out that Alberta's grid issues are not isolated. Every Canadian region is experiencing growing electricity demand, partly due to the surge in electric vehicles and clean energy technologies. No province has a complete solution yet.

“Ontario has had to request reduced consumption during heatwaves,” he noted. “Similar concerns about energy mix are present in British Columbia or Manitoba, especially now with drought affecting their hydro-dependent systems.”

The North American Electric Reliability Corporation (NERC) released a report in November warning of elevated risks across North America this winter for insufficient energy supplies, particularly under extreme conditions like prolonged cold snaps.

While the U.S. is generally more susceptible to winter grid disruptions, and summer blackout warnings remain a concern, the report also highlights risks in parts of Canada. Saskatchewan faces a “high” risk due to increased demand, power plant retirements, and maintenance, whereas Quebec and the Maritimes are at “elevated risk.”

Mark Olson, NERC’s manager of reliability assessments, mentioned that Alberta wasn't initially considered at risk, illustrating the challenges in predicting electricity demand amid intensifying extreme weather.

Rob Thornton, president and CEO of the International District Energy Association, acknowledged public concerns about grid alerts but reassured that the risk of a catastrophic grid failure remains very low.

“The North American grid is exceptionally reliable. It’s a remarkably efficient system,” he said.

However, Thornton emphasized the importance of policies for a resilient and reliable electricity system through 2050 and beyond. This involves balancing dispatchable and intermittent electricity sources, investing in extra capacity, enhancing macrogrids and inter-jurisdictional connections, and more.

“These grid alerts raise awareness, if not anxiety, about our energy future,” Thornton concluded.

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Alliant Energy Net-Zero Carbon Plan outlines carbon-neutral electricity by 2050, coal retirements by 2040, major solar and wind additions, gas transition, battery storage, hydrogen, and carbon credits to reduce emissions and lower customer costs.

Key Points

Alliant Energy's strategy to reach carbon-neutral power by 2050 via coal phaseout, renewables, storage, and offsets.

✅ Targets net-zero electricity by 2050

✅ Retires all coal by 2040; expands solar and wind

✅ Uses storage, hydrogen, and offsets to bridge gaps

Alliant Energy has joined a small but growing group of utilities aiming for carbon-neutral electricity by 2050.

In a report released Wednesday, the Madison-based company announced a goal of “net-zero carbon dioxide emissions” from its electricity generation along with plans to eliminate all coal-powered generation by 2040, a decade earlier than the company’s previous target.

Alliant, which is pursuing plans that would make it the largest solar energy generator in Wisconsin, said it is on track to cut its 2005 carbon emissions in half by 2030.

Both goals are in line with targets an international group of scientists warn is necessary to avoid the most catastrophic impacts of climate change. But reducing greenhouse gasses was not the primary motivation, said executive vice president and general counsel Jim Gallegos.

“The primary driver is focused on our customers and communities and setting them up … to be competitive,” Gallegos said. “We do think renewables are going to do it better than fossil fuels.”

Alliant has told regulators it can save customers up to $6.5 billion over the next 35 years by adding more than 1,600 megawatts of renewable generation, closing one of its two remaining Wisconsin coal plants and taking other undisclosed actions.

In a statement, Alliant chairman and CEO John Larsen said the goal is part of broader corporate and social responsibility efforts “guided by our strategy and designed to deliver on our purpose — to serve customers and build stronger communities.”

Coal out; gas remains
The goal applies only to Alliant’s electricity generation — the company has no plans to stop distributing natural gas for heating — and is “net-zero,” meaning the company could use some form of carbon capture or purchase carbon credits to offset continuing emissions.

The plan relies heavily on renewable generation — seen in regions embracing clean power across North America — including the addition of up to 1,000 megawatts of new Wisconsin solar plants by the end of 2023 and 1,000 megawatts of Iowa wind generation added over the past four years — as well as natural gas generators to replace its aging coal fleet.

But Jeff Hanson, Alliant’s director of sustainability, said eliminating or offsetting all carbon emissions will require new tools, such as battery storage or possibly carbon-free fuels such as hydrogen, and awareness of the Three Mile Island debate over the role of nuclear power in the mix.

“Getting to the 2040 goals, that’s all based on the technologies of today,” Hanson said. “Can we get to net zero today? The challenge would be a pretty high bar to clear.”

Gallegos said the plan does not call for the construction of more large-scale natural gas generators like the recently completed $700 million West Riverside Energy Center in Beloit, though natural gas will remain a key piece of Alliant’s generation portfolio.

Alliant announced plans in May to close its 400-megawatt Edgewater plant in Sheboygan by the end of 2022, echoing how Alberta is retiring coal by 2023 as markets shift, but has not provided a date for the shutdown of the jointly owned 1,100-megawatt Columbia Energy Center near Portage, which received about $1 billion worth of pollution-control upgrades in the past decade.

Alliant’s Iowa subsidiary plans to convert its 52-year-old, 200-megawatt Burlington plant to natural gas by the end of next year and a pair of small coal-fired generators in Linn County by 2025. That leaves the 250-megawatt plant in Lansing, which is now 43 years old, and the 734-megawatt Ottumwa plant as the remaining coal-fired generators, even as others keep a U.S. coal plant running indefinitely elsewhere.

Earlier this year, the utility asked regulators to approve a roughly $900 million investment in six solar farms across the state with a total capacity of 675 megawatts, similar to plans in Ontario to seek new wind and solar to address supply needs. The company plans to apply next year for permission to add up to 325 additional megawatts.

Alliant said the carbon-neutral plan, which entails closing Edgewater along with other undisclosed actions, would save customers between $2 billion and $6.5 billion through 2055 compared to the status quo.

Tom Content, executive director of the Citizens Utility Board, said the consumer advocacy group wants to ensure that ratepayers aren’t forced to continue paying for coal plants that are no longer needed while also paying for new energy sources and would like to see a bigger role for energy efficiency and more transparency about the utilities’ pathways to decarbonization.

‘They could do better’
Environmental groups said the announcement is a step in the right direction, though they say utilities need to do even more to protect the environment and consumers.

Amid competition from cheaper natural gas and renewable energy and pressure from environmentally conscious investors, U.S. utilities have been closing coal plants at a record pace in recent years, as industry CEOs say a coal comeback is unlikely in the U.S., a trend that is expected to continue through the next decade.

“This is not industry leadership when we’re talking about emission reductions,” said Elizabeth Katt Reinders, regional campaign director for the Sierra Club, which has called on Alliant to retire the Columbia plant by 2026.

Closing Edgewater and Columbia would get Alliant nearly halfway to its emissions goals while saving customers more than $250 million over the next decade, according to a Sierra Club study released earlier this year.

“Retiring Edgewater was a really good decision. Investing in 1,000 megawatts of new solar is game-changing for Wisconsin,” Katt Reinders said. “In the same breath we can say this emissions reduction goal is unambitious. Our analysis has shown they can do far more far sooner.”

Scott Blankman, a former Alliant executive who now works as director of energy and air programs for Clean Wisconsin, said Alliant should not run the Columbia plant for another 20 years.

“If they’re saying they’re looking to get out of coal by 2040 in Wisconsin I’d be very disappointed,” Blankman said. “I do think they could do better.”

Alliant is the 15th U.S. investor-owned utility to set a net-zero target, according to the Natural Resources Defense Council, joining Madison Gas and Electric, which announced a similar goal last year. Minnesota-based Xcel Energy, which serves customers in western Wisconsin, was the first large investor-owned utility to set such a target, as state utilities report declining returns in coal operations.

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Schott Green Electricity CPPA secures renewable energy via a solar park in Schleswig-Holstein, supporting decarbonization in German glass manufacturing; the corporate PPA with ane.energy delivers about 14.5 GWh annually toward climate-neutral production by 2030.

Key Points

Corporate PPA for 14.5 GWh solar in Germany, cutting Schott plant emissions and advancing climate-neutral operations.

✅ 14.5 GWh solar from Schleswig-Holstein via ane.energy

✅ Powers Mainz HQ and plants in GrFCnenplan, Mitterteich, Landshut

✅ Two-year CPPA covers ~5% of Schott's German electricity needs

Schott, a leading specialty glass manufacturer, is advancing its sustainability initiatives in step with Germany's energy transition by integrating green electricity into its operations. Through a Corporate Power Purchase Agreement (CPPA) with green energy specialist ane.energy, Schott aims to significantly reduce its carbon footprint and move closer to its goal of climate-neutral production by 2030.

Transition to Renewable Energy

As of February 2025, amid a German renewables milestone for the power sector, Schott has committed to sourcing approximately 14.5 gigawatt-hours of clean energy annually from a solar park in Schleswig-Holstein, Germany. This renewable energy will power Schott's headquarters in Mainz and its plants in Grünenplan, Mitterteich, and Landshut. The CPPA covers about 5% of the company's annual electricity needs in Germany and is initially set for a two-year term, reflecting lessons from extended nuclear power during recent supply challenges.

Strategic Implementation

To achieve climate-neutral production by 2030, Schott is focusing on transitioning from gas to electricity sourced from renewable sources like photovoltaics, alongside complementary pathways such as hydrogen-ready power plants being developed nationally. Operating a single melting tank requires energy equivalent to the annual consumption of up to 10,000 single-family homes. Therefore, Schott has strategically selected suitable plants for this renewable energy supply to meet its substantial energy requirements.

Industry Leadership

Schott's collaboration with ane.energy demonstrates the company's commitment to sustainability and its proactive approach to integrating renewable energy into industrial operations. This partnership not only supports Schott's decarbonization goals but also sets a precedent for other manufacturers in the glass industry to adopt green energy solutions, mirroring advances like green hydrogen steel in heavy industry.

Schott's initiative to power its German glass plants with green electricity underscores the company's dedication to environmental responsibility and its strategic efforts to achieve climate-neutral production by 2030, aligning with the national coal and nuclear phaseout underway. This move reflects a broader trend in the manufacturing sector toward sustainable practices and the adoption of renewable energy sources, even as debates continue over a possible nuclear phaseout U-turn in Germany.

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