Geothermal ^^not getting any love^^

BC Hydro Electricity Imports shape CleanBC claims as Powerex trades cross-border electricity, blending hydro with coal and gas supplies, affecting emissions, grid carbon intensity, and how electric vehicles and households assess "clean" power.

Key Points

Powerex buys power for BC Hydro, mixing hydro with coal and gas, shifting emissions and affecting CleanBC targets.

✅ Powerex trades optimize price, not carbon intensity

✅ Imports can include coal- and gas-fired generation

✅ Emissions affect EV and CleanBC decarbonization claims

British Columbians naturally assume they’re using clean power when they fire up holiday lights, juice up a cell phone or plug in a shiny new electric car. 

That’s the message conveyed in advertisements for the CleanBC initiative launched by the NDP government, amid indications that residents are split on going nuclear according to a survey, which has spent $3.17 million on a CleanBC “information campaign,” including almost $570,000 for focus group testing and telephone town halls, according to the B.C. finance ministry.

“We’ll reduce air pollution by shifting to clean B.C. energy,” say the CleanBC ads, which feature scenic photos of hydro reservoirs. “CleanBC: Our Nature. Our Power. Our Future.” 

Yet despite all the bumph, British Columbians have no way of knowing if the electricity they use comes from a coal-fired plant in Alberta or Wyoming, a nuclear plant in Washington, a gas-fired plant in California or a hydro dam in B.C. 

Here’s why. 

BC Hydro’s wholly-owned corporate subsidiary, Powerex Corp., exports B.C. power when prices are high and imports power from other jurisdictions when prices are low. 

In 2018, for instance, B.C. imported more electricity than it exported — not because B.C. has a power shortage (it has a growing surplus due to the recent spate of mill closures and the commissioning of two new generating stations in B.C.) but because Powerex reaps bigger profits when BC Hydro slows down generators to import cheaper power, especially at night.

“B.C. buys its power from outside B.C., which we would argue is not clean,” says Martin Mullany, interim executive director for Clean Energy BC. 

“A good chunk of the electricity we use is imported,” Mullany says. “In reality we are trading for brown power” — meaning power generated from conventional ‘dirty’ sources such as coal and gas. 

Wyoming, which generates almost 90 per cent of its power from coal, was among the 12 U.S. states that exported power to B.C. last year. (Notably, B.C. did not export any electricity to Wyoming in 2018.)

Utah, where coal-fired power plants produce 70 per cent of the state’s energy amid debate over the costs of scrapping coal-fired electricity, and Montana, which derives about 55 per cent of its power from coal, also exported power to B.C. last year. 

So did Nebraska, which gets 63 per cent of its power from coal, 15 per cent from nuclear plants, 14 per cent from wind and three per cent from natural gas.   

Coal is responsible for about 23 per cent of the power generated in Arizona, another exporter to B.C., while gas produces about 44 per cent of the electricity in that state.  

In 2017, the latest year for which statistics are available, electricity imports to B.C. totalled just over 1.2 million tonnes of carbon dioxide emissions, according to the B.C. environment ministry — roughly the equivalent of putting 255,000 new cars on the road, using the U.S. Environmental Protection Agency’s calculation of 4.71 tonnes of annual carbon emissions for a standard passenger vehicle. 

These figures far outstrip the estimated local and upstream emissions from the contested Woodfibre LNG plant in Squamish that is expected to release annual emissions equivalent to 170,000 new cars on the road.

Import emissions cast a new light on B.C.’s latest “milestone” announcement that 30,000 electric cars are now among 3.7 million registered vehicles in the province.

BC Electric Vehicles Announcement Horgan Heyman Mungall Weaver
In November of 2018 the province announced a new target to have all new light-duty cars and trucks sold to be zero-emission vehicles by the year 2040. Photo: Province of B.C. / Flickr

“Making sure more of the vehicles driven in the province are powered by BC Hydro’s clean electricity is one of the most important steps to reduce [carbon] pollution,” said the November 28 release from the energy ministry, noting that electrification has prompted a first call for power in 15 years from BC Hydro.

Mullany points out that Powerex’s priority is to make money for the province and not to reduce emissions.

“It’s not there for the cleanest outcome,” he said. “At some time we have to step up to say it’s either the money or the clean power, which is more important to us?”

Electricity bought and sold by little-known, unregulated Powerex
These transactions are money-makers for Powerex, an opaque entity that is exempt from B.C.’s freedom of information laws. 

Little detailed information is available to the public about the dealings of Powerex, which is overseen by a board of directors comprised of BC Hydro board members and BC Hydro CEO and president Chris O’Reilly. 

According to BC Hydro’s annual service plan, Powerex’s net income ranged from $59 million to $436 million from 2014 to 2018. 

“We will never know the true picture. It’s a black box.” 

Powerex’s CEO Tom Bechard — the highest paid public servant in the province — took home $939,000 in pay and benefits last year, earning $430,000 of his executive compensation through a bonus and holdback based on his individual and company performance.  

“The problem is that all of the trade goes on at Powerex and Powerex is an unregulated entity,” Mullany says. 

“We will never know the true picture. It’s a black box.” 

In 2018, Powerex exported 8.7 million megawatt hours of electricity to the U.S. for a total value of almost $570 million, according to data from the Canada Energy Regulator. That same year, Powerex imported 9.6 million megawatt hours of electricity from the U.S. for almost $360 million. 

Powerex sold B.C.’s publicly subsidized power for an average of $87 per megawatt hour in 2018, according to the Canada Energy Regulator. It imported electricity for an average of $58 per megawatt hour that year. 

In an emailed statement in response to questions from The Narwhal, BC Hydro said “there can be a need to import some power to meet our electricity needs” due to dam reservoir fluctuations during the year and from year to year.

‘Impossible’ to determine if electricity is from coal or wind power
Emissions associated with electricity imports are on average “significantly lower than the emissions of a natural gas generating plant because we mostly import electricity from hydro generation and, increasingly, power produced from wind and solar,” BC Hydro claimed in its statement. 

But U.S. energy economist Robert McCullough says there’s no way to distinguish gas and coal-fired U.S. power exports to B.C. from wind or hydro power, noting that “electrons lack labels.” 

Similarly, when B.C. imports power from Alberta, where generators are shifting to gas and 48.5 per cent of electricity production is coal-fired and 38 per cent comes from natural gas, there’s no way to tell if the electricity is from coal, wind or gas, McCullough says.

“It really is impossible to make that determination.” 

Wyoming Gilette coal pits NASA
The Gillette coal pits in Wyoming, one of the largest coal-producers in the U.S. Photo: NASA Earth Observatory

Neither the Canada Energy Regulator nor Statistics Canada could provide annual data on electricity imports and exports between B.C. and Alberta. 

But you can watch imports and exports in real time on this handy Alberta website, which also lists Alberta’s power sources. 

In 2018, California, Washington and Oregon supplied considerably more power to B.C. than other states, according to data from Canada Energy Regulator. 

Washington, where about one-quarter of generated power comes from fossil fuels, led the pack, with more than $339 million in electricity exports to B.C. 

California, which still gets more than half of its power from gas-fired plants even though it leads the U.S. in renewable energy with substantial investments in wind, solar and geothermal, was in second place, selling about $18.4 million worth of power to B.C. 

And Oregon, which produces about 43 per cent of its power from natural gas and six per cent from coal, exported about $6.2 million worth of electricity to B.C. last year. 

By comparison, Nebraska’s power exports to B.C. totalled about $1.6 million, Montana’s added up to $1.3 million,  Nevada’s were about $706,000 and Wyoming’s were about $346,000.

Clean electrons or dirty electrons?
Dan Woynillowicz, deputy director of Clean Energy Canada, which co-chaired the B.C. government’s Climate Solutions and Clean Growth Advisory Council, says B.C. typically exports power to other jurisdictions during peak demand. 

Gas-fired plants and hydro power can generate electricity quickly, while coal-fired power plants take longer to ramp up and wind power is variable, Woynillowicz notes. 

“When you need power fast and there aren’t many sources that can supply it you’re willing to pay more for it.”

Woynillowicz says “the odds are high” that B.C. power exports are displacing dirty power.

Elsewhere in Canada, analysts warn that Ontario's electricity could get dirtier as policies change, raising similar concerns.

“As a consumer you never know whether you’re getting a clean electron or a dirty electron. You’re just getting an electron.” 

Related News

• Electricity Forum News

• Power Generation News

Western Lithium Supply Localization is accelerating as EV battery makers diversify from China, boosting lithium hydroxide sourcing in North America and Europe, amid Covid-19 disruptions and rising prices, with geothermal brines and local processing.

Key Points

An industry shift to source lithium and processing near EV hubs, reducing China reliance and supply chain risk.

✅ EV makers seek North American and European lithium hydroxide

✅ Prices rise amid Covid-19 and logistics constraints

✅ New extraction: geothermal and oilfield brine projects

The global outbreak of coronavirus will accelerate efforts by western carmakers to localise supplies of lithium for electric car batteries, according to US producer Livent.

The industry was keen to diversify away from China, which produces the bulk of the world’s lithium, a critical material for lithium-ion batteries, said Paul Graves, Livent’s chief executive.

“It’s a conversation that’s starting to happen that was not happening even six months ago,” especially in the US, the former Goldman Sachs banker added.

China produced about 79 per cent of the lithium hydroxide used in electric car batteries last year, according to consultancy CRU, a supply chain that has been disrupted by the virus outbreak and EV shortages in some markets.

Prices for lithium hydroxide rose 3.1 per cent last month, their first increase since May 2018, according to Benchmark Mineral Intelligence, due to the impact of the Covid-19 bug.

Chinese lithium producer Ganfeng Lithium, which supplies major carmakers from Tesla to Volkswagen, said it had raised prices by less than 10 per cent, due to higher production costs and logistical difficulties.

“We can get lithium from lots of places . . . is that really something we’re prepared to rely upon?” Mr Graves said. “People are going to relook at supply chains, including battery recycling initiatives that enhance resilience, and relook at their integrity . . . and they’re going to say is there something we need to do to change our supply chains to make them more shockproof?”

General Motors last week said it was looking to source battery minerals such as lithium and nickel from North America for its new range of electric cars that will use cells made in Ohio by South Korea’s LG Chem.

“Some of these critical minerals could be challenging to obtain; it’s not just cobalt you need to be concerned about but also battery-grade nickel and lithium as well,” said Andy Oury, a lead engineer for batteries at GM. “We’re doing all of this with an eye to sourcing as much of the raw material from North America as possible.”

However, George Heppel, an analyst at CRU, warned it would be difficult to compete with China on costs. “China is always going to be the most competitive place to buy battery raw materials. That’s not likely to change anytime soon,” he said.

Livent, which extracts lithium from brines in northern Argentina, is looking at extracting the mineral from geothermal resources in the US and also wants to build a processing plant in Europe.

The Philadelphia-based company is also working with Canadian start-up E3 Metals to extract lithium from brines in Alberta's oil and gasfields for new projects in Canada.

“We’ll look at doing more in the US and more in Europe,” said Mr Graves, underscoring evolving Canada-U.S. collaboration across EV supply chains.

Related News

• Electricity Forum News

• EV Infrastructure News

UK Energy Price Cap drives household electricity bills and gas prices, as Ofgem adjusts unit rates amid natural gas shortages, Russia-Ukraine disruptions, inflation, recession risks, and limited storage; government support offers only short-term relief.

Key Points

The UK Energy Price Cap limits per-unit gas and electricity charges set by suppliers and adjusted by Ofgem.

✅ Reflects wholesale natural gas costs; varies quarterly

✅ Protects consumers from sudden electricity and heating bill spikes

✅ Does not cap total annual spend; usage still determines bills

The government organization that controls the cost of energy in Great Britain recently increased what is known as a price cap on household energy bills. The price cap is the highest amount that gas suppliers can charge for a unit of energy.

The new, higher cost has people concerned that they may not be able to pay for their gas and electricity this winter. Some might pay as much as $4,188 for energy next year. Earlier this year, the price cap was at $2,320, and a 16% decrease in bills is anticipated in April.

Why such a change?

Oil and gas prices around the world have been increasing since 2021 as economies started up again after the coronavirus pandemic. More business activities required more fuel.

Then, Russia invaded Ukraine in late February, creating a new energy crisis. Russia limited the amount of natural gas it sent to European countries that needed it to power factories, produce electricity and keep homes warm.

Some energy companies are charging more because they are worried that Russia might completely stop sending gas to European countries. And in Britain, prices are up because the country does not produce much gas or have a good way to store it. As a result, Britain must purchase gas often in a market where prices are high, and ministers have discussed ending the gas-electricity price link to ease bills.

Citibank, a U.S. financial company, believes the higher energy prices will cause inflation in Britain to reach 18 percent in 2023, while EU energy inflation has also been driven higher by energy costs this year. And the Bank of England says an economic slowdown known as a recession will start later this year.

Public health and private aid organizations worry that high energy prices will cause a “catastrophe” as Britons choose between keeping their homes warm and eating enough food.

What can government do?

As prices rise, the British government plans to give people between $450 and $1,400 to help pay for energy costs, while some British MPs push to further restrict the price charged for gas and electricity. But the help is seen by many as not enough.

If the government approves more money for fuel, it will probably not come until September, as the energy security bill moves toward becoming law. That is the time the Conservative Party will select a new leader to replace Prime Minister Boris Johnson.

The Labour Party says the government should increase the amount it provides for people to pay for fuel by raising taxes on energy companies. However, the two politicians who are trying to become the next Prime Minister do not seem to support that idea.

Giovanna Speciale leads an organization called the Southeast London Community Energy group. It helps people pay their bills. She said the money will help but it is only a short-term solution to a bigger problem with Britain’s energy system. Because the system is privately run, she said, “there’s very little that the government can do to intervene in this.”

Other European countries are seeing higher energy costs, but not as high, and at the EU level, gas price cap strategies have been outlined to tackle volatility. In France, gas prices are capped at 2021 levels. In Germany, prices are up by 38 percent since last year. However, the government is reducing some taxes, which will make it easier for the average person to buy gas. In Italy, prices are going up, but the government recently approved over $8 billion to help people pay their energy bills.
 

Related News

• Electricity Forum News

• Energy Policy News

Alberta Solar Energy Expansion confronts high installation costs, grid integration and storage needs, and environmental impact, while incentives, infrastructure upgrades, and renewable targets aim to balance reliability, land use, and emissions reductions provincewide.

Key Points

Alberta Solar Energy Expansion is growth in solar tempered by costs, grid limits, environmental impact, and incentives.

✅ High capex and financing challenge utility-scale projects

✅ Grid integration needs storage, transmission, and flexibility

✅ Site selection must mitigate land and wildlife impacts

Alberta's push towards expanding solar power is encountering significant financial and environmental hurdles. The province's ambitious plans to boost solar power generation have been met with both enthusiasm and skepticism as stakeholders grapple with the complexities of integrating large-scale solar projects into the existing energy framework.

The Alberta government has been actively promoting solar energy as part of its strategy to diversify the energy mix in a province that is a powerhouse for both green energy and fossil fuels today and reduce greenhouse gas emissions. Recent developments have highlighted the potential of solar power to contribute to Alberta's clean energy goals. However, the path forward is fraught with challenges related to costs, environmental impact, and infrastructure needs.

One of the primary issues facing the solar energy sector in Alberta is the high cost of solar installations. Despite decreasing costs for solar technology in recent years, the upfront investment required for large-scale solar farms remains substantial, even as some facilities have been contracted at lower cost than natural gas in Alberta today. This financial barrier has led to concerns about the economic viability of solar projects and their ability to compete with other forms of energy, such as natural gas and oil, which have traditionally dominated Alberta's energy landscape.

Additionally, there are environmental concerns associated with the development of solar farms. While solar energy is considered a clean and renewable resource, the construction of large solar installations can have environmental implications. These include potential impacts on local wildlife habitats, land use changes, where approaches like agrivoltaics can co-locate farming and solar, and the ecological effects of large-scale land clearing. As solar projects expand, balancing the benefits of renewable energy with the need to protect natural ecosystems becomes increasingly important.

Another significant challenge is the integration of solar power into Alberta's existing energy grid. Solar energy production is variable and dependent on weather conditions, especially with Alberta's limited hydro capacity for flexibility, which can create difficulties in maintaining a stable and reliable energy supply. The need for infrastructure upgrades and energy storage solutions is crucial to address these challenges and ensure that solar power can be effectively utilized alongside other energy sources.

Despite these challenges, the Alberta government remains committed to advancing solar energy as a key component of its renewable energy strategy. Recent initiatives include financial incentives and support programs aimed at encouraging investment in solar projects and supporting a renewable energy surge that could power thousands of jobs across Alberta today. These measures are designed to help offset the high costs associated with solar installations and make the technology more accessible to businesses and homeowners alike.

Local communities and businesses are also playing a role in the growth of solar energy in Alberta. Many are exploring opportunities to invest in solar power as a means of reducing energy costs and supporting sustainability efforts and, increasingly, to sell renewable energy into the market as demand grows. These smaller-scale projects contribute to the overall expansion of solar energy and demonstrate the potential for widespread adoption across the province.

The Alberta government has also been working to address the environmental concerns associated with solar energy development. Efforts are underway to implement best practices for minimizing environmental impacts and ensuring that solar projects are developed in an environmentally responsible manner. This includes conducting environmental assessments and working with stakeholders to address potential issues before projects are approved and built.

In summary, while Alberta's solar energy initiatives hold promise for advancing the province's clean energy goals, they are also met with significant financial and environmental challenges. Addressing these issues will be crucial to the successful expansion of solar power in Alberta. The government's ongoing efforts to support solar projects through incentives and infrastructure improvements, coupled with responsible environmental practices, will play a key role in determining the future of solar energy in the province.

Related News

• Electricity Forum News

• Renewable Energy News

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.

Related News

• Electricity Forum News

• Utility Operations News

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.

Related News

• Electricity Forum News

• Energy Policy News